The combined acid gas removal and water filtration system (10) removes sour gases, such as hydrogen sulfide (H2S) and carbon dioxide (CO2), from an input gaseous hydrocarbon stream (FG), as well as producing purified water (TW). The acid gas removal system (10) has a contactor (12) for contacting the input gaseous stream (FG) with an absorption liquid solvent (ALS), and a stripper (24) for recycling the absorption liquid solvent (ALS) and removing acidic gases (AG) therefrom. A first heat exchanger (22) heats used absorption liquid solvent (UALS) output from the contactor (12) prior to injection into the stripper (24). A second heat exchanger (26) cools recycled absorption liquid solvent (RALS) using a refrigerant (R) before injection back into the contactor (12). The refrigerant (R) is coupled with an absorber (84), which receives a dilute ethanolic draw solution (DDS) from a forward osmosis filtration system (72), producing purified water (TW).

A method and a system for the removal of carbon dioxide from solvents.

Embodiments of methods and associate system for removing acid gas from a sour gas stream are provided. The method includes (1) passing the sour gas stream in a counter-flow arrangement with an encapsulated phase change material and a lean amine based sorbent liquid configured to absorb the acid gas from the sour gas stream in an absorber; (2) separating the rich amine based sorbent liquid and the encapsulated phase change material; (3) passing the rich amine based sorbent liquid to an amine regenerator wherein the rich amine based sorbent liquid is heated to release the absorbed sour gas and regenerate the lean amine based sorbent liquid; and (4) passing the encapsulated phase change material and the regenerated lean amine based sorbent liquid through a cooler to reduce the temperature of the encapsulated phase change material such that the phase change material in the encapsulated phase change material solidifies.

Embodiments of methods and associate system for removing acid gas from a sour gas stream are provided. The method includes (1) passing the sour gas stream in a counter-flow arrangement with an encapsulated phase change material and a lean amine based sorbent liquid configured to absorb the acid gas from the sour gas stream in an absorber; (2) separating the rich amine based sorbent liquid and the encapsulated phase change material; (3) passing the rich amine based sorbent liquid to an amine regenerator wherein the rich amine based sorbent liquid is heated to release the absorbed sour gas and regenerate the lean amine based sorbent liquid; and (4) passing the encapsulated phase change material and the regenerated lean amine based sorbent liquid through a cooler to reduce the temperature of the encapsulated phase change material such that the phase change material in the encapsulated phase change material solidifies.

A chemical composition for use in degassing of vessels is taught, said chemical composition including 1-10% by weight of an oxyalkylated dodecyl thiol; and 1-20% by weight of an alkyl di-substituted 9-decenamide. A method is further provided for degassing a vessel. The method includes charging said vessel with chemical composition and a carrier medium, wherein said chemical composition comprises 1-10% by weight of an oxyalkylated dodecyl thiol and 1-20% by weight of an alkyl di-substituted 9-decenamide.

A process for treating an H.sub.2S- and CO.sub.2-comprising fluid stream, in which a) the fluid stream is treated in a first absorber at a pressure of 10 to 150 bar with a first substream of a regenerated H.sub.2S-selective absorbent to obtain a treated fluid stream and an H.sub.2S-laden absorbent; b) the H.sub.2S-laden absorbent is heated by indirect heat exchange with regenerated H.sub.2S-selective absorbent; c) the heated H.sub.2S-laden absorbent is decompressed to a pressure of 1.2 to 10 bar in a low-pressure decompression vessel to obtain a first CO.sub.2-rich offgas and a partly regenerated absorbent; d) the partly regenerated absorbent is regenerated in a desorption column to obtain an H.sub.2S-rich offgas and regenerated absorbent; e) the H.sub.2S-rich offgas is fed to a Claus unit and the offgas from the Claus unit is fed to a hydrogenation unit to obtain hydrogenated Claus tail gas; f) the hydrogenated Claus tail gas and the first CO.sub.2-rich offgas are treated in a second absorber at a pressure of 1 to 4 bar with a second substream of the regenerated H.sub.2S-selective absorbent to obtain a second CO.sub.2-rich offgas and a second H.sub.2S-laden absorbent; and g) the second H.sub.2S-laden absorbent is guided into the first absorber. Also described is a plant suitable for performance of the process. The process is notable for a low energy requirement.

An apparatus and process are provided for electricity production and high-efficiency trapping of carbon dioxide, using carbon dioxide within combustion exhaust gas and converging technologies associated with a carbon dioxide absorption tower and a generating device using ions which uses a difference in concentration of salinity between seawater and freshwater. It is expected that enhanced electrical energy production efficiency, an effect of reducing costs for the operation of a carbon dioxide trapping process, and electricity production from carbon dioxide, which is a greenhouse gas, can be simultaneously achieved by increasing the difference in concentration using an absorbent for absorbing carbon dioxide.

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.

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.

Processes for removing a sulfide or a degradation product thereof from in a gas dehydration system are disclosed along with corresponding gas dehydration systems. The processes and systems include contacting a stream comprising the sulfide or a degradation product thereof with an anionic resin to remove at least a portion of the sulfide or a degradation product thereof from the stream. The processes and systems can also be used in the removal of mercury from gas dehydration systems.