Syngas Contaminant Removal and Conditioning

Acid Gas Removal (AGR)

    Fluidized Bed Gasifiers
source: Electric Power Research Institute


Acid gases produced in gasification processes mainly consist of hydrogen sulfide (H2S), carbonyl sulfide (COS), and carbon dioxide (CO2). Syngas exiting the particulate removal and gas conditioning systems, typically near ambient temperature at 100°F, needs to be cleaned of the sulfur-bearing acid gases to meet either environmental emissions regulations, or to protect downstream catalysts for chemical processing applications. For integrated gasification combined cycle (IGCC) applications, environmental regulations require that the sulfur content of the product syngas be reduced to less than 30 parts per million by volume (ppmv) in order to meet the stack gas emission target of less than 4 ppmv sulfur dioxide (SO2)1. In IGCC applications, where selective catalytic reduction (SCR) is required to lower NOx emissions to less than 10 ppmv, syngas sulfur content may have to be lowered to 10 to 20 ppmv in order to prevent ammonium bisulfate fouling of the heat recovery steam generator's (HRSG) cold end tubes. For fuels production or chemical production, the downstream synthesis catalyst sulfur tolerance dictates the sulfur removal level, which can be less than 0.1 ppmv.

Acid Gas Removal Processes
orange arrow MDEA
orange arrow Rectisol
orange arrow Selexol
orange arrow Sulfinol

Conventional processes for removing acid gases typically involve their countercurrent absorption from the syngas using a regenerative solvent in an absorber column. This process approach of gas-liquid contacting to remove acid gases is very commonly used in a wide range of process industries, including refining, chemicals, and natural gas production. However, because of the significantly different required degrees of acid gas removal that depend on the application, the choice of solvents varies significantly:

  • For chemical synthesis applications which require syngas with less than 1 ppmv sulfur, physical solvent processes such as Rectisol and Selexol are normally used which allow essentially total removal of sulfur; these may operate at depressed temperatures (Rectisol operates at -40°C). 
  • For power generation applications, which allow higher sulfur levels (approximately 10 to 30 ppmv sulfur), chemical solvent processes such as Methyl diethanolamine (MDEA) are normally used. Many but not all of these utilize amine-type solvents.
  • Mixtures of chemical and physical solvents, also known as hybrid or composite solvents are also possible; Sulfinol is a well-known example.
Acid Gas Removal Technologies
Acid Gas Removal Technologies (click to enlarge)

In both physical and chemical absorption processes, the syngas is washed with lean solvent in the absorber to remove H2S. Cleaned syngas is sent to downstream systems for further processing. Acid gas-rich solvent leaving the bottom of the absorber is sent to the regenerator, where the solvent is stripped with steam under low pressure (reboiling) to remove the absorbed sulfur. The concentrated acid gas stream, rich in H2S, exits the top of the regenerator and is sent to the Sulfur Recovery Unit (SRU) for sulfur recovery. The SRU consists of a Claus plant, in which the H2S is converted to sulfur, a salable byproduct. The regenerated lean solvent from the bottom of the regenerator is cooled by a heat exchanger against the rich solvent, followed by water cooling before being recycled back to the top of the absorber to start the absorption process cycle again.

The physical solvent processes tend to co-absorb more CO2 than chemical/amine processes such as MDEA. Multiple step depressurization of the rich solvent, supplemented with nitrogen stripping, is employed by the physical solvent processes to reject sufficient CO2 to concentrate the acid gas from the regenerator overhead to at least 15 to 25 volume% H2S in order to feed the Claus SRU.

Because of the need for refrigeration (e.g. Rectisol), and in general more complex solution flashing arrangements, physical solvent processes are two to three times more costly than chemical solvent processes. While the physical solvent processes have higher power consumption than the chemical solvent processes, the chemical processes have higher steam consumption which translates to reduced power output from the power train. Thus, impact on overall net power output may be similar between the two types of AGR processes.

Depending on the solvent used, COS may first need to be converted to H2S via a COS hydrolysis unit. Also, it is important to note that H2S and CO2 can be removed either simultaneously or selectively, depending on the raw syngas composition and conditions, and the end syngas specifications.

Chemical Solvents
Chemical solvents include primary, secondary and tertiary amines, and alkaline salts such as potassium carbonate. Through acid-base reactions, aqueous solutions of these basic compounds capture and remove acid gases by forming weak chemical bonds with dissolved acid gases in the absorber. The bonds are broken by heat in the regenerator to release the acid gases and regenerate the solvent for reuse. Chemical solvent absorption processes normally operate at slightly above ambient temperature. Chemical solvents are more effective for low acid gas partial pressure applications than physical solvents.

Physical Solvents
Physical solvents are organic solvents that have a high affinity for acid gases. In general, the physical solvents demand relatively high syngas pressures, high partial pressure of the acid gases, and/or low operating temperature in the absorber (in some cases cryogenic temperatures below –150°C, –238°F or 123 K), for good performance. Solvent, rich with acid gases from the absorber, is then subjected to multistage controlled pressure decreases, followed with hot stripping in the regenerator, to release the acid gases and regenerate the solvent for reuse.

Mixed Solvent Systems
Mixtures of amine chemical solvents and physical solvents take advantage of the high treated-gas purity performance of chemical solvents, and the low energy requirement associated with flash regeneration of physical solvents. In general, such mixtures are effective over a wide range of acid gas partial pressures at near-room temperatures, allowing both improved acid gas absorption at high partial pressures, and with the amine portion allowing AGR under very low partial pressures as the case may be. Also, they feature higher solubility of COS and organic sulfur compounds than aqueous amines alone.

There are over 30 AGR processes available commercially, but only four of these have been demonstrated or implemented in the 18 commercial-size coke or coal-based gasification plants worldwide, as reported by SFA Pacific in 2002:2 Rectisol, Selexol, Sulfinol, and MDEA. Half of these18 plants are for liquid fuelsmethanolSNG or ammonia production, while the other half are IGCC applications.

Eight of the nine chemical production plants, in operation as of 2002, use Rectisol (typically operates at -40°F to -80°F), and one uses Selexol (typically operates at 20°F to 40°F). This is consistent with the general perception that physical solvent-based AGR is normally selected to protect synthesis catalysts against poisoning from sulfur and other trace contaminants in chemical production from coal applications. While Rectisol is more costly, it is preferred for treating coal-based syngas because it allows for very deep sulfur removal (<0.1 ppmv H2S plus COS), and also because it can remove HCN, NH3, and many metallic trace contaminants (including iron- and nickel-carbonyls, and mercury) to provide additional catalyst protection.

References/Further Reading


Cost and Performance Baseline for Fossil Energy Power Plants study, Volume 1: Bituminous Coal and Natural Gas to Electricity (Nov 2010)

2. Process Screening Analysis of Alterative Gas Treating and Sulfur Removal for Gasification (Dec 2002)
Revised Final Report, SFA Pacific, Inc.

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