An amine treating unit removes hydrogen sulfide (H2S) and carbon dioxide (CO2) from natural gas - the acid gases that make gas sour, toxic, and corrosive. Turning sour gas into sweet, pipeline-quality gas is a core step in gas processing. This guide explains how an amine unit absorbs acid gas, how the amine is regenerated, and what an operator monitors.
Amine Treating Unit in one line: An amine treating unit sweetens natural gas by contacting it with an aqueous amine solution that chemically absorbs H2S and CO2. The rich amine is then heated in a stripper to release the acid gases and regenerate the amine, which is cooled and recirculated - producing sweet gas that meets pipeline and safety limits.
Raw gas containing H2S is called sour gas. H2S is acutely toxic, corrodes steel (and causes sulfide stress cracking), and produces sulfur dioxide when burned, so pipelines strictly limit it - commonly to about 4 parts per million (a quarter grain per 100 standard cubic feet in the US). CO2 is not toxic but is corrosive in the presence of water, lowers the heating value of the gas, and can freeze in cryogenic processing, so it too must be reduced to specification. Removing these acid gases is called sweetening.
Amine absorption is the dominant sweetening method. Different amines are chosen for the job: MEA and DEA are general-purpose, while MDEA can be formulated to selectively remove H2S while slipping some CO2 through - useful when only H2S needs to meet spec. The removed acid gas stream is then routed to a sulfur recovery unit, an incinerator, or acid gas injection depending on volume and regulation.
The process mirrors a glycol unit in layout but works by chemical reaction rather than physical absorption. Sour gas enters the bottom of the absorber (contactor) and rises through trays while lean amine is pumped in at the top and flows down. The amine reacts with and captures H2S and CO2; sweet gas leaves the top, and rich amine loaded with acid gas leaves the bottom.
The rich amine goes to regeneration. It passes through a flash tank to release absorbed hydrocarbons, is preheated by cross-exchange with hot lean amine, and enters the stripper (regenerator). There a reboiler boils the solution, and the heat reverses the reaction, driving the H2S and CO2 out of the amine as an acid gas stream that leaves the top of the stripper through a reflux condenser. The regenerated lean amine is cooled and pumped back to the absorber, closing the loop. A reclaimer periodically cleans degraded amine and heat-stable salts out of the system.
Critical variables are the absorber and stripper pressures, levels, and temperatures, the amine circulation rate, the lean amine loading and concentration, the reboiler duty, and the treated (sweet) gas H2S and CO2 content, usually watched with an online analyzer. Foaming, amine losses, corrosion, and heat-stable salt buildup are the recurring problems, and low circulation or a cold reboiler quickly leads to off-spec sour gas.
These points come from field instruments into a PLC or DCS. A cloud SCADA like Merobix reads the digitized tags over Modbus, DNP3, or OPC UA and trends reboiler temperature, amine circulation, absorber level, and treated-gas H2S across a plant, alarming when the treated gas approaches its H2S limit or the regeneration section drifts - so operators correct the unit before sour gas reaches the sales line. Because H2S is a life-safety hazard, this monitoring is safety-critical, not just a quality concern.
It removes the acid gases hydrogen sulfide (H2S) and carbon dioxide (CO2). H2S is toxic and corrosive and must be cut to about 4 ppm for pipeline gas; CO2 is corrosive with water and lowers heating value. Removing these turns sour gas into sweet, pipeline-quality gas - a process called sweetening.
Amine treating chemically removes acid gases (H2S and CO2) to sweeten the gas. Glycol dehydration physically absorbs water vapor to dry the gas. They are separate conditioning steps and a gas plant often runs both - amine sweetening first to remove acid gas, then glycol dehydration to remove water.
Because the H2S being removed is acutely toxic and the treated gas must meet a strict H2S limit before it enters the sales line. If circulation drops or regeneration falters, the unit can let sour gas slip through. Continuous monitoring of amine circulation, reboiler temperature, and treated-gas H2S lets operators catch a problem before dangerous, off-spec gas leaves the plant.
This page references the protocol specifications published by the organizations below. Editions, product capabilities, and documentation change over time - confirm current requirements and specifications directly with the source.
Last reviewed: July 27, 2026. Merobix is not affiliated with, endorsed by, or sponsored by these organizations; their names are used only to identify the standards and products discussed.
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