Syngas Cleanup and Conditioning
Raw synthesis gas (syngas) from the high temperature gas cooling (HTGC) system needs to be cleaned to remove contaminants including fine particulates, sulfur, ammonia, chlorides, mercury, and other trace heavy metals to meet environmental emission regulations, as well as to protect downstream processes. In the case of carbon sequestration, carbon dioxide (CO2) is also removed. Depending on the application, syngas may need to be conditioned to adjust the hydrogen-to-carbon monoxide (H2-to-CO) ratio to meet downstream process requirement. In applications where very low sulfur (<10 ppmv) syngas is required, converting carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be needed. Typical cleanup and conditioning processes include cyclone and filters for bulk particulates removal; wet scrubbing to remove fine particulates, ammonia and chlorides; solid absorbents for mercury and trace heavy metal removal; water gas shift (WGS) for H2-to-CO ratio adjustment; catalytic hydrolysis for converting COS to H2S; and acid gas removal (AGR) for extracting sulfur-bearing gases and CO2 removal.
Fine Particulate Removal
Raw syngas leaving the HTGC system in today’s commercial gasification plant is normally quenched and scrubbed with water in a trayed column for fine char and ash particulate removal prior to recycle to the slurry-fed gasifiers. For dry feed gasification, cyclones and candle filters are used to recover most of the fine particulate for recycle to the gasifiers before final cleanup with water quenching and scrubbing. In addition, fine particulates, chlorides, ammonia, some H2S, and other trace contaminants are also removed from the syngas during the scrubbing process. The scrubbed gas is then either reheated for COS hydrolysis and/or a sour WGS when required, or cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before further processing.
Spent water from the scrubber column is directed to the sour water treatment system, where it is depressurized and decanted in a gravity settler to remove fine particulates. Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as the filter cake, which is then either discarded or recycled to the gasifier depending on its carbon content. Water from the settler is recycled for gasification uses with the excess being sent to the wastewater treatment system for disposal.
COS Hydrolysis and Water-Gas-Shift
Most of the sulfur in the coal is converted to H2S during gasification. Depending on the gasification temperature and moisture content, approximately 3 to 10% of the sulfur is converted to COS. To generate low sulfur syngas, the COS in the product gas needs to be converted to H2S before sulfur removal via current commercial AGR processes. This is done by passing syngas from the water scrubber through a catalytic hydrolysis reactor where over 99% of the COS is converted to H2S. The scrubbed syngas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water.
In applications where a high syngas H2-to-CO ratio is needed, syngas from the water scrubber is passed through a multi-stage reactor containing sulfur-tolerant shift catalysts to convert CO and water into additional H2 and CO2. Normally, excess moisture is present in the scrubber syngas from slurry-fed gasifiers to drive the shift reaction to achieve the required H2-to-CO ratio. For most slurry-fed gasification systems, a portion of the syngas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2-to-CO ratio. Depending on the gasification process and the required H2-to-CO ratio, additional steam injection before the sour shift may be needed for dry-fed gasifiers. The scrubber syngas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water. Shifted syngas is cooled in the LTGC system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before going through the AGR system for sulfur removal.
Mercury and Trace Elements
Current commercial practice is to pass cooled syngas from LTGC through sulfided, activated carbon beds to remove over 90% of the mercury and a significant amount of other heavy metal contaminants. Due to the sulfur in the activated carbon, these beds are normally placed ahead of the AGR system to minimize the possibility of sulfur slipping back into and contaminating the cleaned syngas.
Acid Gas Removal (AGR)
Raw syngas exiting the particulate removal and gas conditioning systems, typically near ambient temperature at 100°F, is routed to the AGR system where H2S and CO2 are removed from the syngas using either physical or chemical solvent absorption. For chemical synthesis applications which require syngas with less than 1 ppmv sulfur, physical solvent processes such as Rectisol and Selexol are normally used. For power generation applications, which allow higher sulfur levels (approximately 10 to 30 ppmv sulfur), chemical solvent processes such as Methyl diethanolamine (MDEA) and Sulfinol are normally used. The physical solvent absorption processes operate under cryogenic temperatures while the chemical solvent absorption processes operate slightly above ambient temperature.
In both physical and chemical absorption processes, the syngas is washed with lean solvent in the absorber to remove H2S. Cleaned syngas from the AGR is sent to downstream systems for further processing. Rich solvent leaving the bottom of the absorber is sent to the regenerator, where the solvent is stripped with steam under low pressure to remove the absorbed sulfur. The concentrated acid gas stream exits the top of the stripper and is sent to the Sulfur Recovery Unit (SRU) for sulfur recovery. The regenerated lean solvent from the bottom of the stripper is cooled by a heat exchanger against the rich solvent, followed by water cooling before being sent back to the absorber to start the absorption process again. The physical solvent processes tend to co-absorb more CO2 than 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 Vol% H2S in order to feed the Claus SRU.
Because of the need for refrigeration, as well as more complex solution flashing arrangements, physical solvent processes are two to four times more costly than MDEA-based 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 overall net power output may be similar between the two types of AGR processes.