Acid Gas Removal in LNG process

Continuing the explanation about LNG, I will try to summary each of LNG process steps from reference I read. First is about Acid Gas Removal.

Acid gas such as CO2, H2S, and other sulfur compounds like mercaptant are need to be removed because they cause corrosion and reduce heating value (sales value) of the gas. Typically, gas sales contracts will permit up to 2-3% CO2 and 1/4 grain per 100 standard cubic feet/scf (approximately 4 ppm) H2S.

Below are explanation about some acid gas removal processes.

1. Solid Bed Absorption

Using a fixed bed of solid to remove acid gases through chemical reaction or ionic bonding and hold acid gases in the bed. After the bed is saturated with acid gases, the vessel is out of service and the bed is regenerated or replace. Thus, some spare capacity must be provided. Three commonly used processes under this category are:

  • Iron Sponge
  • Molecular Sieve
  • Zinc Oxide

2. Chemical Solvents

Chemical solvent processes use an aqueous solution of a weak base to chemically react with and absorb the acid gas in the natural gas stream. The absorption occurs as a result of driving force of the partial pressure from the gas to liquid. The reaction involved are reversible by changing the system temperature and pressure, or both.

Therefore, the aqueous base solution can be regenerated and thus circulated in a continue cycle. The majorities of chemical solvent processes use either an amine or carbonate solution which are:

  • MEA (Monoethanol Amine)
  • DEA (Diethanol Amine)
  • DGA (Diglycol Amine)
  • DIPA (Diisopropanol Amine)
  • K2CO3 (Potassium Carbonate)
  • Proprietary Carbonate (K2CO3 with activator or catalyst)

3. Physical Solvents

This process is based on solubility of H2S and/or CO2 within the solvent. Solubility is depends on partial pressure and temperature. Higher acid gas partial pressure and lower temperature increase the solubility H2S and CO2 in the solvent.

Most physical solvent processes are proprietary and are licensed by the company that developed the process such as:

  • Fluor Solvent
  • Sulfinol (Shell)
  • Selexol (Allied Chemical Company)
  • Rectisol (The German Lurgy Company and Linde A. G.)

4. Direct Conversion H2S to Sulfur

The release of H2S to atmosphere may be limited by environmental regulations. Usually acid gas is routed to incinerator or flare. Or otherwise, H2S can be oxidized to produce elemental sulfur by chemical reaction.

These processes are licensed and involve specialized catalyst and/or solvents. Some of the processes are:

  • Clause
  • Stretford (British Gas Corporation)
  • IFP (Institute Francais du Petrole)

5. Distillation

The Ryan- Holmes distillation process uses cryogenic distillation to remove acid gases from a gas stream. This process is applied to remove CO2 for LPG separation or where it is desired to produce CO2 at high pressure for reservoir injection.

6. Gas Permeation

This process is based on the mass transfer principles of gas diffusion through a permeable membrane. The driving force for the separation is differential pressure. Membrane system can effectively remove CO2 and water but not H2S.

The side of membrane that is rich in CO2 is normally operated of 10 to 20% of the feed pressure. Membrane are a relatively new technology. They are attractive economic alternative for treating CO2 from small streams (up to 10 MMscfd).

The most common process that is used are Iron Sponge and Amine Treating Unit. They will be explained in 2 next post :slight_smile:

DMAN-TPE-ENGPRO-008 Acid Gas Treating Design Manual

credits: Nika Yunitri