Process for the removal of acid gases from gas mixtures containing methane

Claim 2

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more tertiary amines, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more primary or secondary amines, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; and (e) separating water and light hydrocarbons from the sweet gas stream.

Claim 3

The process of claim 1 wherein, in the first or second absorbent mixture, the physical absorbent is selected from N-methyl pyrrolidone, dimethyl formamide, dimethyl ether of polyethylene glycol, and sulfolane.

Claim 4

The process of claim 1 wherein, in the first absorbent mixture, the physical absorbent is sulfolane, and in the second absorbent mixture, the physical absorbent is sulfolane.

Claim 5

The process of claim 3 wherein the chemical absorbent of the first absorbent mixture comprises methyl diethanol amine and the chemical absorbent of the second absorbent mixture comprises di-isopropanol amine.

Claim 6

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more tertiary amines, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more primary or secondary amines, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; (e) separating water and light hydrocarbons from the sweet gas stream; (f) converting H 2 S from step (b) to sulphur and an effluent containing SO 2 in a Claus plant, and catalytically reducing SO 2 in said So 2 -containing effluent to produce an H 2 S-containing stream; (g) contacting the CO 2 stream from step (d) and the H 2 S-containing stream from step (f) in a third absorption zone with an absorbent mixture which is selective for H 2 S under conditions effective to absorb H 2 S and removing the bulk of the H 2 S from said streams.

Claim 7

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more tertiary amines, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent comprising one or more primary or secondary amines, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; (e) separating water and light hydrocarbons from the sweet gas stream; (f) converting H 2 S from step (b) to sulphur and an effluent containing SO 2 in a Claus plant, and catalytically reducing SO 2 in said So 2 -containing effluent to produce an H 2 S-containing stream; (g) contacting the CO 2 stream from step (d) and the H 2 S-containing stream from step (f) in a third absorption zone with an absorbent mixture which is selective for H 2 S under conditions effective to absorb H 2 S and removing the bulk of the H 2 S from said streams.

Claim 8

The process of claim 5 wherein, in the first or second absorbent mixture, the physical absorbent is selected from N-methyl pyrrolidone, dimethyl formamide, dimethyl ether of polyethylene glycol, and sulfolane.

Claim 9

The process of claim 5 wherein, in the first absorbent mixture, the physical absorbent is sulfolane, and in the second absorbent mixture, the physical absorbent is sulfolane.

Claim 10

The process of claim 7 wherein the chemical absorbent of the first absorbent mixture comprises methyl diethanol amine and the chemical absorbent of the second absorbent mixture comprises di-isopropanol amine.

Claim 11

The process of claim 5 wherein absorbent mixture, after absorbing H 2 S in the third absorption zone, is utilized in the first absorption zone as first absorbent mixture.

Claim 12

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from triethanol amine, diethyl ethanol amine, and methyl diethanol amine, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from ethanol amine, diethanol amine, and di-isopropanol amine, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; and (e) separating water and light hydrocarbons from the sweet gas stream.

Claim 13

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from triethanol amine, diethyl ethanol amine, and methyl diethanol amine, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from ethanol amine, diethanol amine, and di-isopropanol amine, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; and (e) separating water and light hydrocarbons from the sweet gas stream.

Claim 14

The process of claim 10 wherein, in the first absorbent mixture, the physical absorbent is sulfolane, and in the second absorbent mixture, the physical absorbent is sulfolane.

Claim 15

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from triethanol amine, diethyl ethanol amine, and methyl diethanol amine, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from ethanol amine, diethanol amine, and di-isopropanol amine, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; (e) separating water and light hydrocarbons from the sweet gas stream; (f) converting H 2 S from step (b) to sulphur and an effluent containing SO 2 in a Claus plant, and catalytically reducing SO 2 in said SO 2 -containing effluent to produce an H 2 S-containing stream; (g) contacting the CO 2 stream from step (d) and the H 2 S-containing stream from step (f) in a third absorption zone with an absorbent mixture which is selective for H 2 S under conditions effective to absorb H 2 S and removing the bulk of the H 2 S from said streams.

Claim 16

A process for the treatment of a gas stream containing methane, light hydrocarbons, H 2 S, and CO 2 comprising (a) contacting said gas stream at superatmospheric pressure in a first absorption zone with a first absorbent mixture which is selective for H 2 S, said first absorbent mixture comprising from 5 percent to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from triethanol amine, diethyl ethanol amine, and methyl diethanol amine, under conditions effective to absorb H 2 S, and absorbing H 2 S and producing a gaseous stream containing methane, light hydrocarbons and CO 2 , and a loaded absorbent solution; (b) passing the loaded absorbent solution to a first regeneration zone, regenerating the loaded absorbent solution and producing H 2 S and first absorbent mixture, and returning regenerated first absorbent mixture to the first absorption zone; (c) contacting the gaseous stream from the first absorption zone in a second absorption zone at superatmospheric pressure with a second absorbent mixture which is selective for CO 2 and H 2 S, said second absorbent mixture comprising from 5 to 35 percent by weight of water, from 15 to 50 percent by weight of physical absorbent, and from 10 to 60 percent by weight of chemical absorbent, said chemical absorbent being selected from ethanol amine, diethanol amine, and di-isopropanol amine, under conditions effective to absorb CO 2 and any H 2 S remaining in the gaseous stream, and absorbing CO 2 and H 2 S remaining in the gaseous stream and obtaining a sweet gas stream containing methane and light hydrocarbons, and a loaded second absorbent solution; (d) passing the loaded second absorbent solution to a second regeneration zone, regenerating the loaded second absorbent solution and producing a CO 2 stream and second absorbent mixture, and returning regenerated second absorbent mixture to the second absorption zone; (e) separating water and light hydrocarbons from the sweet gas stream; (f) converting H 2 S from step (b) to sulphur and an effluent containing SO 2 in a Claus plant, and catalytically reducing SO 2 in said SO 2 -containing effluent to produce an H 2 S-containing stream; (g) contacting the CO 2 stream from step (d) and the H 2 S-containing stream from step (f) in a third absorption zone with an absorbent mixture which is selective for H 2 S under conditions effective to absorb H 2 S and removing the bulk of the H 2 S from said streams.

Claim 17

The process of claim 12 wherein, in the first absorbent mixture, the physical absorbent is sulfolane, and in the second absorbent mixture, the physical absorbent is sulfolane.