Gas Sweetening

KASRAVAND offers a range of solutions to remove acid gas components (CO2 and/or H2S) from natural gas customized to meet each client’s specific process requirements. The most common methods for acid gas removal are via amines, physical solvents, or membranes, the choice of which depends on the levels of impurities to be removed.



KASRAVAND works with major solvent suppliers such as Ineos, BASF and Dow and membrane providers such as UOP to ensure each plant is optimized to:

  • Meet sales gas CO2 and H2S specifications
  • Remove impurities to minimize foaming
  • Operating efficiency
  • Materials compatibility
  • Minimize solvent losses

If you do not wish to use proprietary solvents then KASRAVAND will optimize your gas sweetening plant for use with readily available, generic solvents.

The Amine Treating Unit removes CO2 and H2S from sour gas. Specific types and blends of amines and solvents such as MEA, DEA, MDEA, DGA, and proprietary chemicals such as Sulfinol – Shell, Ucarsol – Union Carbide, GAS/SPEC® – INEOS Oxide, FLEXSORB® – ExxonMobile, together with specific process designs provide different combinations of CO2 and H2S removals according to client requirements and specifications.

KASRAVAND provides the analysis, recommending the most cost effective solution.

H2S & CO2 are removed from the gas stream in the Amine Contactor. The Amine is regenerated in the Amine Regenerator, and recycled to the Amine Contactor. The sour gas streams enter the bottom of the Amine Contactor. The cooled lean amine is trim cooled and enters the top of the contactor column. The sour gas flows upward counter-current to the lean amine solution. An acid-gas-rich-amine solution leaves the bottom of the column at an elevated temperature, due to the exothermic absorption reaction. The sweet gas, after absorption of H2S by the amine solution, flows overhead from the Amine Contactor.

The Rich Amine Surge Drum allows separation of hydrocarbon from the amine solution. Condensed hydrocarbons flow over a weir and are pumped to the drain.

 Rich Amine Flash Drum surge drum should read flash drum.The stripping of H2S and CO2 in the Amine Regenerator regenerates the rich amine solution. The Rich Amine Flash Drum supplies the necessary heat to strip H2S and CO2 from the rich amine, using steam as the heating medium.

 Acid gas, primarily H2S and water vapor from the regenerator is cooled in the Amine Regenerator Overhead Condenser. The mixture of gas and condensed liquid is collected in the Amine Regenerator Overhead Accumulator. The uncondensed gas is sent to Sulfur Recovery.

 The Amine Regenerator Reflux Pump pumps the condensate in the Regenerator Accumulator, mainly water, to the top tray of the Amine Regenerator. A portion of the pump discharge is sent to the sour water tank.

 Lean amine solution from the Amine Regenerator is cooled in the Lean/Rich Exchanger. A slipstream of rich amine solution passes through a filter to remove particulates and The lean amine is further cooled in the Lean Amine Air Cooler, before entering the Amine Contactor.

If you need more information please contact to our technical department.

The amine concentration in the absorbent aqueous solution is an important parameter in the design and operation of an amine gas treating process. Depending on which one of the following four amines the unit was designed to use and what gases it was designed to remove, these are some typical amine concentrations, expressed as weight percent of pure amine in the aqueous solution:

  • Monoethanolamine: About 20 % for removing H2S and CO2, and about 32 % for removing only CO2.
  • Diethanolamine: About 20 to 25 % for removing H2S and CO2
  • Methyldiethanolamine: About 30 to 55% % for removing H2S and CO2
  • Diglycolamine: About 50 % for removing H2S and CO2

The choice of amine concentration in the circulating aqueous solution depends upon a number of factors and may be quite arbitrary. It is usually made simply on the basis of experience. The factors involved include whether the amine unit is treating raw natural gas or petroleum refinery by-product gases that contain relatively low concentrations of both H2S and CO2 or whether the unit is treating gases with a high percentage of CO2 such as the offgas from the steam reforming process used in ammonia production or theflue gases from power plants.

Both H2S and CO2 are acid gases and hence corrosive to carbon steel. However, in an amine treating unit, CO2 is the stronger acid of the two. H2S forms a film of iron sulfide on the surface of the steel that acts to protect the steel. When treating gases with a high percentage of CO2, corrosion inhibitors are often used and that permits the use of higher concentrations of amine in the circulating solution.

Another factor involved in choosing an amine concentration is the relative solubility of H2S and CO2 in the selected amine.

 The choice of the type of amine will affect the required circulation rate of amine solution, the energy consumption for the regeneration and the ability to selectively remove either H2S alone or CO2 alone if desired. For more information about selecting the amine concentration, the reader is referred to Kohl and Nielsen's book.

Activated MDEA or aMDEA uses piperazine as a catalyst to increase the speed of the reaction with CO2. It has been commercially successful