Methods and systems for gas separation of syngas applying differences in water solubilities of syngas components, the method including producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas to create a hydrogen product stream and a byproduct stream by solubilizing components in water that are more soluble in water than hydrogen; injecting the byproduct stream into a reservoir containing mafic rock; and allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

Systems and methods for preventing formation of carbonyl sulfide in the production of sweet gas using an amine-lean aqueous solution and metal oxide adsorbent material. In embodiments, a method may include producing, via an amine absorption column supplied with a raw gas stream that includes fractions of hydrogen sulfide (H.sub.2S), carbon dioxide (CO.sub.2), and carbon monoxide (CO), (1) a sweet gas stream that includes the fractions of the CO and (2) an amine-rich aqueous solution that includes the H.sub.2S and CO.sub.2. The method may include heating the amine-rich aqueous solution to produce a heated amine-rich aqueous solution. The method may include producing, via an amine regenerator supplied with the heated amine-rich aqueous solution (1) an acid gas stream that includes the H.sub.2S and CO.sub.2 and (2) an amine-lean aqueous solution. The method may include producing, via adsorption in a metal oxide adsorbent vessel, an effluent stream that includes the CO.sub.2.

A system and method for processing unconditioned syngas first removes solids and semi-volatile organic compounds (SVOC), then removes volatile organic compounds (VOC), and then removes at least one sulfur containing compound from the syngas. Additional processing may be performed depending on such factors as the source of syngas being processed, the products, byproducts and intermediate products desired to be formed, captured or recycled and environmental considerations.

The invention relates to a gas scrubbing process and plant for purifying raw synthesis gas by physical absorption in methanol. A raw synthesis gas stream which includes hydrogen and carbon monoxide as desired constituents and water and acid gases as undesired constituents is admixed with methanol and subsequently cooled below the freezing point of water. According to the invention a liquid phase including methanol and water is separated from the cooled raw synthesis gas stream. Acid gases are removed from the remaining gaseous phase by physical absorption in methanol at elevated pressure. Separating the water from the raw synthesis gas stream before the absorption of the acid gases prevents larger amounts of water passing into the methanol circuit of the gas scrubbing process. This achieves savings in resources and certain plant parts may be smaller than is customary.

A scrubbing solution for removing contaminants, including particularly hydrogen sulfide, from a fluid. The scrubbing solution includes at least one scrubbing reagent which has a primary or secondary amine and an acid, which may be phosphoric acid. The fluid being scrubbed is passed through the scrubbing solution. The contaminants react with the scrubbing reagent securing them in the scrubbing solution. The fluid being scrubbed and the scrubbing solution are then separated. The scrubbing solution is heated and, if the scrubbing solution is under pressure, the pressure is reduced. The acid facilitates thorough removal of the contaminants, and especially the hydrogen sulfide, from the scrubbing solution. The scrubbing solution is then ready for reuse. Because the scrubbing solution is rendered substantially free of hydrogen sulfides, it can absorb other sulfide contaminants that might not otherwise be absorbed.

This disclosure provides a method for treating natural gas comprising causing at least some of a sour natural gas stream comprising hydrocarbon gas and hydrogen sulfide to contact an amine or pass through a separation system. A sweet natural gas stream comprising hydrocarbon gas and a waste gas stream comprising hydrogen sulfide are formed by contacting the sour natural gas with an amine or by passing it though a separation device. At least some of the hydrogen sulfide in the waste gas stream is oxidized, forming an exhaust gas stream comprising sulfur dioxide, which is then contacted with water or reactant and water solution or slurry to destroy or convert SO.sub.2 into a less environmentally harmful compound.

A system and method for processing unconditioned syngas first removes solids and semi-volatile organic compounds (SVOC), then removes volatile organic compounds (VOC), and then removes at least one sulfur containing compound from the syngas. Additional processing may be performed depending on such factors as the source of syngas being processed, the products, byproducts and intermediate products desired to be formed, captured or recycled and environmental considerations.

A petroleum residue stream is heated and reacted with an oxygen stream and a carbon dioxide stream in a gasification unit to produce syngas. At least a portion of the carbon monoxide is converted into carbon dioxide to produce shifted syngas. At least a portion of the shifted syngas is separated to produce a syngas feed stream. At least a portion of the syngas feed stream is converted into methanol. At least a portion of the methanol is converted into one or more alkenes (olefins). At least a portion of the methanol is reacted with carbon monoxide to produce acetic acid. Carbon dioxide produced in the process can be recycled to the gasification unit to facilitate the production of the syngas.

A method for maintaining solvent quality in a gas treating system involves calculating, by an advisory system for continuous monitoring of the gas treating system, a water content deficit in the solvent of the gas treating system, calculating, by the advisory system, a water makeup rate compensating for the water content deficit, and displaying, in an interactive user interface of the advisory system, the water makeup rate.

A composite amine absorbent according to the present invention is an absorbent for absorbing CO.sub.2 or H.sub.2S, or both of CO.sub.2 and H.sub.2S in a gas. The absorbent is obtained by dissolving (1) a linear monoamine, (2) a diamine, and (3) propylene glycol alkyl ether, for example, represented by the following chemical formula (I) in water. In the composite amine absorbent, the components complexly interact, and the synergistic effect thereof provides good absorbability of CO.sub.2 or H.sub.2S, or both of CO.sub.2 and H.sub.2S and good releasability of CO.sub.2 or H.sub.2S absorbed during regeneration of the absorbent. Furthermore, the amount of water vapor in a reboiler 26 used during regeneration of the absorbent in a CO.sub.2 recovery unit 12 can be reduced.
R.sup.1—O—(R.sup.2—O).sub.n—R.sup.3  (I)