Gas Treating & Sweetening Equipment

Packaged or field-erected systems using aqueous alkanolamine solvents (MEA, DEA, MDEA, formulated/selective amines) to absorb H2S and CO2 in a contactor and regenerate the solvent in a stripper. The workhorse technology for bulk acid gas removal.

High-pressure trayed or packed columns where sour gas flows countercurrent to lean solvent so acid gas transfers into the liquid. Tower internals (trays, structured or random packing) set mass-transfer efficiency and turndown.

Non-regenerative units that inject liquid scavengers (e.g., triazine) or pass gas through solid scavenger media to remove low concentrations of H2S. Common for spot treating, lower-volume streams, and pipeline polishing.

Low-pressure columns with a reboiler that apply heat to drive absorbed H2S and CO2 out of the rich solvent, restoring lean-solvent capacity. Includes reflux, reboiler, and lean/rich heat-exchange equipment.

Fixed-bed reactors packed with iron-oxide or zinc-oxide media that react with H2S to form metal sulfides. Used as batch-replaceable beds for low-throughput or remote applications requiring high H2S removal.

Once-through chemical treatment using liquid (e.g., triazine) or solid scavengers to remove low concentrations of H2S without a regeneration loop. Suited to low-throughput wells, tail-gas polishing, or remote sites.

Consumable amines, solvent additives, antifoams, and reaction catalysts that determine selectivity, capacity, and degradation rate of treating systems. Selected to balance H2S/CO2 selectivity against energy and circulation cost.

Polymeric membrane modules that separate CO2 (and some H2S) from natural gas by selective permeation driven by pressure differential. Favored for bulk CO2 removal, high-CO2 feeds, and locations where solvent handling is impractical.

Solvent formulations and configurations—typically MDEA-based or hindered amines—tuned for deep H2S removal while allowing controlled CO2 slip. Used where partial CO2 retention or higher acid-gas selectivity improves downstream economics.

Processes that absorb H2S into a chelated-iron or similar solution and oxidize it directly to elemental sulfur, combining sweetening and sulfur recovery. Suited to small-to-mid H2S loads below the economic threshold of a Claus plant.

Fixed-bed systems using materials such as iron sponge (iron oxide) or molecular sieves to capture H2S, mercaptans, or residual sulfur compounds. Often used for polishing, dehydration-coupled service, or small sour streams.

Equipment that receives the concentrated acid gas from regeneration, including routing to Claus sulfur recovery units, acid-gas reinjection, or incineration/flare. Manages the safe disposition of removed H2S and CO2.

Claus thermal/catalytic units and tail-gas treating systems that convert recovered acid gas H2S to elemental sulfur and minimize residual sulfur emissions. Installed downstream of amine units handling significant H2S volumes.

Mechanical and carbon filters plus reclaimers that remove particulates, hydrocarbons, and degradation products from the circulating amine. Maintaining solvent quality controls foaming, corrosion, and treating performance.

Column internals—trays, structured/random packing, mist eliminators, and distributors—that govern mass transfer in absorbers and strippers. Specified to maximize acid gas pickup while limiting foaming and solvent carryover.