Amine units are the backbone of acid gas removal in natural gas processing, and they do an excellent job on hydrogen sulfide and carbon dioxide.
See our technical breakdown article on Amine Plants to learn more.
What surprises operators new to sulfur management is how often mercaptans walk straight through an amine unit and show up downstream, especially in the heavier gas-to-liquids fractions. This article explains how amine sweetening works, why mercaptans slip through, why the problem gets worse for heavier streams, and why processors add a catalytic polishing step at the back end to scrub out the final sulfur.
How Amine Sweetening Works
An amine unit removes acid gases by contacting the sour gas with an aqueous alkanolamine solution in an absorber. The amine is a weak base, and the acid gases are weak acids, so the two react through an acid-base mechanism. Hydrogen sulfide protonates the amine almost instantly, and carbon dioxide is absorbed as well, either directly with primary and secondary amines or more slowly through a bicarbonate pathway with tertiary amines. The rich amine, now loaded with acid gas, flows to a regenerator where heat strips the H2S and CO2 back out, and the lean amine is recycled to the absorber.
The choice of amine sets the behavior. Methyldiethanolamine (MDEA), a tertiary amine, is prized for selectively absorbing H2S while slipping much of the CO2, which is useful when CO2 removal is not required or when feeding a downstream sulfur recovery unit. Primary and secondary amines such as MEA and DEA are less selective and pull more CO2. In every case, though, the absorber is optimized around the acid-base capture of H2S and CO2, and that optimization is exactly why mercaptans are handled poorly.
What Mercaptans Are and Why They Behave Differently
Mercaptans, or thiols, are organic sulfur compounds with the general form R-SH. The lightest are methyl mercaptan and ethyl mercaptan; heavier ones extend up through propyl, butyl, and larger chains. They are toxic, corrosive, and intensely odorous, and like H2S they count against the total sulfur specification for sales gas and liquid products.
The reason they do not behave like H2S in an amine unit comes down to two properties. First, mercaptans are much weaker acids than hydrogen sulfide, so the acid-base reaction that captures H2S so efficiently barely engages them. Most amines remove few to no mercaptans for this reason. Second, mercaptans are highly soluble in hydrocarbons. Rather than partitioning into the aqueous amine, they prefer to stay dissolved in the gas and, even more so, in any liquid hydrocarbon phase present.
Why Mercaptans Slip Through, Especially in Heavier Gas-to-Liquids Streams
Put those two properties together and the slip mechanism becomes clear. Because the amine chemistry does not react with them and because they would rather dissolve in hydrocarbon than in water, mercaptans pass through the absorber largely untouched and remain in the treated stream.
The Heavier-Is-Worse Pattern
Mercaptan solubility in hydrocarbon rises with molecular weight and with the heaviness of the liquid phase. Light mercaptans are volatile enough that some leave with the gas, but heavier mercaptans preferentially dissolve into condensate and natural gas liquids. When a plant recovers NGL or condensate, the mercaptans concentrate in the propane, butane, and heavier cuts rather than the residue gas. That is why a sweet-looking residue gas can still produce off-spec liquid products: the sulfur followed the liquids.
This partitioning is the core challenge for gas-to-liquids and liquids-rich plants. The amine unit can hit its H2S target and the residue gas can look clean, yet the mercaptans have simply migrated into the value streams the plant is trying to sell. Downstream, those mercaptans cause more than a specification problem. They can contribute to polymeric fouling and can contaminate or degrade solvent systems, and they leave fractionated products such as LPG unable to meet sales sulfur limits.
A related complication occurs at the molecular sieve dehydration beds that often sit downstream of the amine unit. Mercaptans co-adsorb on the sieve along with water, then desorb during regeneration, producing mercaptan spikes in the regeneration gas that have to be dealt with somewhere. The sieve helps a little but does not solve the problem, and it can become a bottleneck.
Why Processors Add a Catalytic Polisher at the End
Because the amine unit is chemically the wrong tool for mercaptans, plants that must hit tight total sulfur specs add a dedicated polishing step after the amine and dehydration stages. The most common is a catalytic oxidation process, widely known by the Merox trade name, that converts mercaptans into disulfides.
The Polishing Chemistry
In this step the hydrocarbon or gas stream is contacted with caustic in the presence of a catalyst, classically cobalt phthalocyanine, usually the sulfonated form. The caustic deprotonates the mercaptan to form a mercaptide ion, and the catalyst then uses air or oxygen to oxidize that mercaptide into a disulfide. The governing reaction converts two mercaptan molecules and oxygen into a disulfide and water. Disulfides are far less volatile, far less odorous, and much easier to separate, so the sulfur can be removed from the product as disulfide oil or otherwise rejected.
The polisher can be configured as an extraction process, where mercaptans are pulled into a caustic stream that is then catalytically regenerated and reused, or as a fixed-bed sweetening process, where the catalyst sits on a solid support and the stream passes over it. Extraction physically removes the sulfur from the product, while fixed-bed conversion turns it into disulfide in place. The right choice depends on which stream is being treated and where the sulfur must ultimately go.
Why this sits at the back end
Placing the polisher last is deliberate. The bulk H2S and CO2 are far cheaper to remove with amine first, which protects the catalyst from being overwhelmed and avoids wasting oxidation capacity on hydrogen sulfide. By the time the stream reaches the polisher, what remains is mainly the mercaptan sulfur the amine could not touch, so the catalytic step does exactly the fine-sweetening job it is suited for. The result is a finished product that meets total sulfur specifications across both the gas and the liquids.
Other Mercaptan Management Options
Catalytic caustic polishing is the classic answer, but it is not the only one. Consider the Pro3 Nano mixed metal oxide system, it can effectively remove remaining mercaptans, H2S, and sulfur compounds missed in the amine unit. Plant designers weigh capital cost, operating cost, hydrocarbon losses, and waste handling, particularly disulfide oil and spent caustic disposal, when choosing among these.
Key Takeaways
Amine units are an excellent choice at removing H2S and CO2 because those are acidic enough to react with the amine, but mercaptans are weak acids that prefer to dissolve in hydrocarbons, so they slip through. The heavier the stream, the more the mercaptans concentrate in condensate and NGL rather than the residue gas, which is why liquids-rich and gas-to-liquids plants see off-spec products even when the gas looks clean. A polisher at the back end like Q2’s Pro 3 Nano system oxidizes or adsorbs those remaining mercaptans, H2S or sulfur compounds, finishing the sulfur removal the amine unit started.
Frequently Asked Questions
Do amine units remove mercaptans?
Mostly no. Amine solvents are optimized to react with the acidic H2S and CO2, but mercaptans are much weaker acids and are highly soluble in hydrocarbons, so most amines remove few to none of them. A dedicated mercaptan removal step is usually required to meet total sulfur specifications.
Why do mercaptans end up in NGL and condensate?
Mercaptan solubility in hydrocarbon increases with molecular weight, so heavier mercaptans preferentially dissolve into the liquid phases. When a plant recovers natural gas liquids and condensate, the mercaptans concentrate in the propane, butane, and heavier cuts rather than leaving with the residue gas.
Why is the polisher placed after the amine unit instead of before?
Removing the bulk H2S and CO2 with amine first is cheaper and protects the catalytic step from being overwhelmed by hydrogen sulfide. By the time the stream reaches the polisher, the main remaining contaminant is the mercaptan sulfur the amine could not capture, which is exactly what the catalytic step is designed to finish.
Q2 Technologies provides advanced technology solutions to the energy sector. To learn more about how we support midstream operators, refiners, and producers, visit www.q2technologies.com.
