The present disclosure is directed to systems and methods for reforming methane into hydrogen and a hydrocarbon fuel. In example embodiments, the methane reformer integrates a photocatalytic steam methane reforming (P-SMR) system with a subsequent photocatalytic dry methane reforming (P-DMR) system.

The present invention relates to a process for removing acid compounds contained in a gaseous effluent which consists in bringing a gaseous effluent into contact, in the absorption column, with an absorbent solution comprising water, between 20% and 28% by weight of pentamethyldipropylenetriamine and between 5% and 35% by weight of N-methyldiethanolamine.

The present disclosure relates to methods and systems for sweetening natural gas may utilize a water wash to achieve a reduction in raw natural gas stream contaminants (e.g., particulate contaminants and/or chemical contaminants) and/or to recover solvent used for removing H.sub.2S and CO.sub.2 from the natural gas. For example, a method may include contacting a first natural gas stream with a first water stream in a co-current contacting system to produce a second natural gas stream and a second water stream, wherein the first natural gas stream comprises natural gas, an acid gas, and a contaminate, and wherein a concentration of the contaminate in the second natural gas stream is less than a concentration of the contaminate in the first natural gas stream; and removing at least a portion of the acid gas from the second natural gas stream.

To provide a carbon dioxide separation composition which is excellent in carbon dioxide desorption efficiency (desorption amount/absorption amount) and durability to nitrogen oxides, and a method for separating carbon dioxide.

A carbon dioxide separation composition, containing at least one amine compound selected from the group consisting of an amine compound represented by the following formula (1):

##STR00001## wherein R.sup.1 to R.sup.3 each independently represent a hydrogen atom or a C.sub.1-4 alkyl group, and an amine compound represented by the following formula (2):

##STR00002## wherein R.sup.10, R.sup.11, R.sup.12, R.sup.13 and R.sup.14 each independently represent a hydrogen atom, a C.sub.1-4 alkyl group, a hydroxy group, a hydroxymethyl group, a 2-hydroxyethyl group or a C.sub.1-4 alkoxy group, a and b are each independently 0 or 1 and satisfy the relation a+b=1, and R.sup.15 is a hydrogen atom, a C.sub.1-4 alkyl group, a methoxymethyl group, a methoxyethoxymethyl group or a 2-hydroxyethyl group.

Disclosed is an adsorbent containing a metal oxide for adsorption of hydrogen sulfide in biogas, and a biogas purification system using the same.

The acid gas removal system for removing acidic gases from gaseous hydrocarbons (10) removes sour gases, such as hydrogen sulfide (H.sub.2S) and carbon dioxide (CO.sub.2), from an input gaseous stream. The system (10) includes a contactor (12) for contacting the input gaseous stream with an absorption liquid solvent (ALS), and a stripper (24) for recycling the absorption liquid solvent (ALS) and removing acidic gases (AG) therefrom, but with the addition of a pair of plate-plate heat exchangers (22, 26). The first heat exchanger (22) heats the used absorption liquid solvent (UALS) output from the contactor (12) prior to injection into the stripper (24). The used absorption liquid solvent (UALS) is heated via heat exchange with the acidic gases (AG) output from the stripper (24). The second heat exchanger (26) cools the recycled absorption liquid solvent (RALS) before injection back into the contactor (12).

A process for sweetening a syngas stream, the process comprising the steps of: providing a syngas stream to a nonselective amine absorption unit, the sour syngas stream comprising syngas, carbon dioxide, and hydrogen sulfide; separating the syngas stream in the nonselective amine absorption unit to obtain an overhead syngas stream and an acid gas stream; introducing the acid gas stream to a membrane separation unit, the acid gas stream comprising hydrogen sulfide and carbon dioxide; separating the acid gas stream in the membrane separation unit to produce a retentate stream and a permeate stream, wherein the retentate stream comprises hydrogen sulfide, wherein the permeate stream comprises carbon dioxide; introducing the retentate stream to a sulfur recovery unit; processing the retentate stream in the sulfur recovery unit to produce a sulfur stream and a tail gas stream, wherein the sulfur stream comprises liquid sulfur.

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.

Disclosed herein are acid gas absorbents that afford high acid gas (CO2) absorption amount per unit volume and high absorption speed and can prevent the absorbent components from diffusing. The acid gas absorbent contains an amine compound of the formula (1) and a cyclic amine compound of the formula (3) or (3′): ##STR00001##

The embodiments provide an acidic gas absorbent having low diffusibility, an acidic gas removal method, and an acidic gas removal apparatus. The acidic gas absorbent according to the embodiment comprises: an amine compound having a vapor pressure of 0.001 to 10 Pa at 20° C.; a water-soluble polymer compound having a mass-average molecular weight of 900 to 200000 and not containing a functional group having a pKa value greater than 7 except for hydroxy; and water.