A process is presented to treat a process stream containing a hydrocarbon (oil and/or gas) and hydrogen sulfide with a liquid treatment solution containing a sulfur dye catalyst. The process stream can be within a pipeline, wellbore, subsea pipeline or a wellhead that contains hydrogen sulfide where the liquid treatment solution is injected at a predetermined point to define a scavenger zone such that the sulfur dye catalyst in the liquid treatment solution causes the sulfide from the hydrogen sulfide to react with the catalyst. The hydrocarbon component is separated substantially free of the hydrogen sulfide from a spent treatment solution containing spent sulfur dye catalyst which can then be fed to an oxidation vessel where it is contacted with an oxygen containing gas causing the sulfide to oxidize to thiosulfate and converting the spent sulfur dye catalyst to regenerated sulfur dye catalyst. The thiosulfate can be recovered, and the regenerated sulfur dye catalyst can be recycled as part of the liquid treatment solution.

The present invention relates to methods for improving carbon capture by providing particles within an amine solvent. The particles provide for increased turbulence at the interface between the counter-flowing gas and solvent, which allows for increased amine and carbamate salt diffusion between the liquid film and bulk.

A hydrophilized material has a surface provided with surface roughness that arithmetic mean roughness is 0.3 m to 1.0 m and mean width of roughness profile elements is 0.1 mm or less. A hydrophilized member that contacts a liquid is at least partially made of the hydrophilized material. The hydrophilized member is applicable to a gas-liquid contact apparatus having a gas-liquid contact section, a liquid supply system, and a gas supply system, to constitute the gas-liquid contact section as a packing element. Wettability imparted due to the surface roughness is exhibited continuously.

The embodiments provide an acidic gas absorbent, an acidic gas removal method using the absorbent, and an acidic gas removal apparatus using the absorbent. The absorbent absorbs an acidic gas in a large amount and is hardly diffused. The acidic gas absorbent according to the embodiment comprises an amine compound represented by the following formula (1):

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[In the formula, each R.sup.1 is independently hydrogen, an alkyl group, or a primary or secondary amino-containing aminoalkyl group provided that at least one of R.sup.1s is the aminoalkyl group, each R.sup.2 is independently hydrogen, an alkyl group, hydroxy, amino, hydroxyamino, or a primary or secondary amino-containing aminoalkyl group, the alkyl or aminoalkyl group contained in R.sup.1 or R.sup.2 has a straight-chain or branched-chain skeleton and may be substituted with hydroxy or carbonyl, and p is 2 to 4.]

Sorbent compositions, comprising a solid sorbent, a dispersive agent, and optionally a capture agent for enhanced wet-Flue Gas Desulfurization (wFGD) or wet scrubber unit function in a flue gas pollutant control stream is disclosed. The sorbent composition may include a sorbent with a dispersive agent, designed to enhance the dispersion of the sorbent in an aqueous sorption liquid of a wet scrubber unit, and therefore may be especially useful in EGU or industrial boiler flue gas streams that include one or more wet scrubber units. The sorbent composition may also include a capture agent useful in sequestering mercury and bromine, as well as other contaminants that may include arsenic, selenium and nitrates.

A method and apparatus are provided for recovering an amine solvent from an acid gas stream. The apparatus includes a water wash recovery column, a nozzle for spraying water wash and an amine nucleation agent into the water wash recovery column and an inlet port for introducing acid gas into the water wash recovery column adjacent the lower end thereof. The method includes the steps of treating the acid gas stream in the water wash recovery column with a counter-current flow of water wash in an amine nucleation agent, discharging treated acid gas from an upper end of the water wash recovery column and collecting water wash, amine nucleation agent and entrained amine solvent from the acid gas stream and a sump at a lower end of the water wash recovery column.

An absorbent for selective removal of hydrogen sulfide over carbon dioxide from a fluid stream comprises an aqueous solution of a) a tertiary amine, b) a sterically hindered secondary amine of the general formula (I)

##STR00001##

in which R.sub.1 and R.sub.2 are each independently selected from C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl; R.sub.3, R.sub.4, R.sub.5 and R.sub.6 are each independently selected from hydrogen, C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl, with the proviso that at least one R.sub.4 and/or R.sub.5 radical on the carbon atom bonded directly to the nitrogen atom is C.sub.1-4-alkyl or C.sub.1-4-hydroxyalkyl when R.sub.3 is hydrogen; x and y are integers from 2 to 4 and z is an integer from 1 to 4; where the molar ratio of b) to a) is in the range from 0.05 to 1.0, and c) an acid in an amount, calculated as neutralization equivalent relative to the protonatable nitrogen atoms in a) and b), of 0.05 to 15.0%. One preferred amine of the formula I is 2-(2-tert-butylaminoethoxy)ethanol. The absorbent allows a defined H.sub.2S selectivity to be set at pressures of the kind typical in natural gas processing.

Effluent water is combined with carbon dioxide sourced from a carbon dioxide-containing emission stream to produce a reaction solution. The pH of the reaction solution is controlled to induce precipitation of a carbonate salt from the reaction solution.

The invention relates to a system or method for capturing a molecule of interest contained in an industrial gaseous effluent, enabling the implementation of a regeneration step (120) in at least one regeneration section (30), a condensation step (150) in at least one condensation section (40), and wherein a step (130) of compressing the gas mixture comprising a solvent and the molecule of interest upstream of the condensation section (40) so that the pressure in the at least one condensation section (40) is at least three times higher than the pressure in the at least one regeneration section (30). The method further comprises a heat transfer step (140) between the at least one condensation section (40) and the at least one regeneration section (30).

Various embodiments include a method for isolating water from a moist gas mixture comprising: absorbing water in an absorption medium disposed in an absorption unit; separating the water from the loaded absorption medium in a thermal water isolation plant; and regenerating the absorption medium in the thermal water isolation plant with temperatures of less than 100 C. prevailing in the thermal water isolation plant.