US20130327990A1

US20130327990A1 - Configurations and methods for gasification plants

Info

Publication number: US20130327990A1
Application number: US13/990,563
Authority: US
Inventors: John Mak
Original assignee: Fluor Technologies Corp
Current assignee: Fluor Technologies Corp
Priority date: 2010-11-30
Filing date: 2011-11-29
Publication date: 2013-12-12
Also published as: WO2012075000A4; CN103402608A; CA2819498A1; WO2012075000A1; CA2819498C

Abstract

A syngas treatment plant has a decarbonization section and a desulfurization section that use the same solvent to remove various acid gases. Contemplated methods and plants are highly effective in removal of CO2, recycle sulfurous contaminants to extinction. Minimal loss of H2 while maximizing H2S concentration in a Claus plant feed during regeneration of the solvent is achieved by stripping the solvent with both treated syngas and a flash vapor of the desulfurization section.

Description

This application claims priority to our copending U.S. provisional application with the Ser. No. 61/417975, which was filed Nov. 30, 2010.

FIELD OF THE INVENTION

The field of the invention is syngas processing, and especially hydrogen (H2) and carbon dioxide (CO2) production with concurrent removal of carbonyl sulfide (COS) and/or hydrogen sulfide (H2S).

BACKGROUND OF THE INVENTION

With today's increasing natural gas prices, gasification route of low value feedstocks to produce ammonia/urea fertilizer or electric power is becoming an economically attractive option. However, shifted syngas from coal or coke gasification typically contains over 40 mol % CO2, which must be removed to minimize carbon emissions. CO2 removal is typically performed with physical solvents as such solvents can be flash-regenerated and require less energy for their regeneration, particularly where high CO2 partial pressure syngas is treated.
Absorption of acid gases is generally dependent upon the solvent physical properties at the processing temperatures and pressures. For example, methanol can be used as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527. Such volatile solvent typically operates at cryogenic temperatures (e.g., −70° F. or lower), which requires alloy steel equipment. Other known physical solvents are also suitable in the removal of acid gases and include various formulations of ethers of polyglycols, and specifically dimethyl ether of polyglycols and N-substituted morpholine. U.S. Pat. No. 6,102,987 describes a process using N-formylmorpholine and N-acetylmorpholine mixtures as the solvent in a scrubbing operation for the removal of acid gases. U.S. Pat. No 7,811,361 teaches an improved process that uses multiple absorbers, column side-streams, and pumparound circuits and chillers configurations.
Unfortunately, co-absorption of CO2 with currently known physical solvent processes for removal of H2S is generally very high, particularly in treating shifted syngas gases. The high CO2 content in the H2S-rich solvent therefore often produces a dilute H2S feed gas with a low heating value that is not suitable for a conventional sulfur plant. In most cases, acid gas with less than 45 mol % H2S requires special equipment in the sulfur plant (e.g., supplemental fuel gas firing, acid gas preheating, and/or oxygen enrichment), which is frequently energy inefficient and costly. To some extent, the dilute acid gas can be concentrated by an acid gas enrichment unit. However, such enrichment units will also produce an overhead gas that contains the sulfur contaminants that must be incinerated and the release of such incinerated effluent will create an emission problem.
To improve at least some aspects of acid gas removal, a gas treatment plant can have separate sections for H2S and CO2 removal as is described in co-pending U.S. Pat. App. No. 2010/0111784. While such plants provide certain advantages in gas treatment, one or more drawbacks nevertheless remain. For example, and especially where the same solvent is used for both sections, H2 loss may be above desirable levels. Moreover, and depending on the particular source of syngas, H2S concentrations may be below desirable levels. In other configurations and methods, as described in U.S. Pat. No. 7,597,746, sulfurous compounds are removed from a natural gas stream using a solvent in a desulfurization section and are recycled to extinction. However, as such configurations and methods use a single regenerator, relatively high operating costs are encountered. Moreover, such plants are also optimized for hydrocarbon recovery and are thus less suitable for syngas treatment.
Consequently, although many configurations and methods for H2S, COS, and CO2 removal from syngas are known in the art, all or almost all of them suffer from one or more disadvantages. Thus, there is still a need to provide methods and configurations for improved H2S, COS, and CO2 removal, especially for syngas with high CO2 content.

SUMMARY OF THE INVENTION

The present invention is directed to configurations and methods of treating syngas to remove various acid gases, and especially H2S, COS, and CO2, to thus produce a fuel gas for power plants. Most preferably, contemplated methods and plants will achieve over 95 mol % carbon capture while recycling sulfurous contaminants to extinction. In especially preferred methods and plants, the same solvent is used for acid gas removal of H2S and CO2, and the regeneration of the solvent allows for minimal loss in H2 from the syngas.
In one preferred aspect of the inventive subject matter, a method of operating a syngas treatment plant includes a step in which syngas (preferably shifted syngas) and a CO2-loaded lean solvent is fed to an H2S absorber to so produce a CO2-loaded rich solvent (rich solvent) and a desulfurized syngas. CO2 and H2 are then stripped from the CO2-loaded rich solvent in a first stripper using treated syngas as a first stripping gas and a (H2-lean, relative to the first stripper overhead) flash vapor as a second stripping gas to thereby produce a stripped rich solvent and a CO2/H2-rich recycle gas. In another step, the stripped rich solvent is flashed to produce the (H2-lean) flash vapor, and further stripped in a second stripper to regenerate a lean solvent for the CO2 absorber and a concentrated acid gas. In yet another step, the desulfurized syngas is then fed into the CO2 absorber to produce the treated syngas and the CO2-loaded rich solvent.
Most preferably, a portion of the CO2-loaded lean solvent is regenerated in a plurality of flash steps, and refrigeration content from the flash steps is used to satisfy at least part of the refrigeration requirement in the CO2 absorber. So produced flash gas is most preferably recycled to the CO2 absorber. It is still further preferred that the concentrated acid gas is processed in a Claus plant and that the (preferably hydrogenated) Claus plant tail gas is combined with the syngas.
In still further preferred aspects, water is separated from the CO2/H2-rich recycle gas and fed to the second stripper as a reflux stream. Where desirable, COS in the CO2/H2-rich recycle gas may be hydrolyzed in a COS hydrolysis reactor, and/or that the CO2/H2-rich recycle gas is recycled to the H2S absorber.
Therefore, in another preferred aspect of the inventive subject matter, a method of operating a syngas treatment plant having a decarbonization section and a desulfurization section will include a step of regenerating a portion of a CO2-loaded lean solvent in the decarbonization section in a plurality of flash steps and a further step of using refrigeration content from the flash steps for refrigeration of a CO2 absorber while absorbing CO2 from a desulfurized gas in the CO2 absorber to thereby produce a treated syngas and a CO2-loaded lean solvent from a lean solvent. In yet another step, syngas and the CO2-loaded lean solvent from the decarbonization section is fed to an H2S absorber in the desulfurization section to thereby produce a CO2-loaded rich solvent and the desulfurized gas, and in a further step, CO2 and COS are stripped from the CO2-loaded rich solvent in a first stripper using a treated feed gas as a first stripping gas to thereby produce a stripped rich solvent and a CO2/COS-containing overhead product. The CO2/COS-containing overhead product is then fed into a COS hydrolysis reactor to hydrolyze COS and to produce a recycle gas for combination with the syngas. In yet another step, the stripped rich solvent is further stripped in a second stripper to thereby regenerate the lean solvent and to thereby produce a concentrated acid gas.
Most preferably, the syngas is subjected to a shift reaction prior to feeding the syngas to the H2S absorber, and/or the recycle gas is combined with the syngas. Additionally, it is contemplated to feed the concentrated acid gas into a Claus plant and to combine the Claus plant tail gas after hydrogenation with the syngas. Most typically, the concentrated acid gas has an H2S content of at least 35 mol % and the treated syngas has a CO2 content of equal or less than 2 mol %.
Consequently, the inventors also contemplate a syngas treatment plant that includes an H2S absorber that receives a syngas and a CO2-loaded lean solvent and that produces a CO2-loaded rich solvent and a desulfurized syngas. A first stripper is fluidly coupled to the H2S absorber to receive the CO2-loaded rich solvent and uses a treated syngas as a first stripping gas and a flash vapor as a second stripping gas to thereby form a stripped rich solvent and a CO2/H2-rich recycle gas. In such plants, a first flash vessel is fluidly coupled to the first stripper and receives and flashed the stripped rich solvent to produce the flash vapor, and a second stripper is fluidly coupled to the first flash vessel and receives and further strips the stripped rich solvent to so generate a lean solvent and a concentrated acid gas. A CO2 absorber is preferably coupled to the H2S absorber, receives the desulfurized syngas, and forms the treated syngas from the desulfurized syngas using the lean solvent to produce the CO2-loaded rich solvent.
In especially preferred plants, a plurality of flash drums are coupled to the CO2 absorber and regenerate a portion of the CO2-loaded lean solvent in a plurality of flash steps. Most preferably, a heat exchanger is coupled to the CO2 absorber and uses refrigeration content from the portion of the CO2-loaded lean solvent to increase the CO2 absorption capacity in the CO2 absorber. It is also preferred that at least one of the flash drums produces a flash gas that is recycled to the CO2 absorber. As already noted above, it is typically preferred that a shift reactor is coupled to the H2S absorber, provides shifted syngas to the H2S absorber, and/or that a Claus plant and a Claus plant tail gas unit is included to receive the concentrated acid gas to so produce a hydrogenated tail gas that is then combined with the syngas.
While not limiting to the inventive subject matter, it is typically preferred that such plants also include a separator coupled to the first stripper to separate water from the CO2/H2-rich recycle gas, and that a conduit is provided to feed the water to the second stripper as a reflux stream. Additionally, it is contemplated that such plants may include a COS hydrolysis reactor coupled to the first stripper to hydrolyze COS in the CO2/H2-rich recycle gas.
Various objects, features, aspects and advantages of the inventive subject matter will become more apparent from the following detailed description of preferred embodiments, along with the accompanying drawing figures in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic of one exemplary syngas treatment plant according to the inventive subject matter.

FIG. 2 is a schematic of another exemplary syngas treatment plant with COS hydrolysis of the first stripper overhead according to the inventive subject matter.

DETAILED DESCRIPTION

The following discussion provides various exemplary embodiments of the inventive subject matter. Although each embodiment represents a single combination of inventive elements, the inventive subject matter is considered to include all possible combinations of the disclosed elements. Thus if one embodiment comprises elements A, B, and C, and a second embodiment comprises elements B and D, then the inventive subject matter is also considered to include other remaining combinations of A, B, C, or D, even if not explicitly disclosed. As used herein, and unless the context dictates otherwise, the term “coupled to” is intended to include both direct coupling (in which two elements that are coupled to each other contact each other) and indirect coupling (in which at least one additional element is located between the two elements). Therefore, the terms “coupled to” and “coupled with” are used synonymously. As also used herein, the term “about” when in conjunction with a numeral refers to a range of ±10% (inclusive) of that numeral.
The inventor has now discovered that syngas can be treated in a highly effective and conceptually simple manner by removing CO2 and H2S in separate sections using the same type of solvent, and where the solvent is regenerated in a manner that decreases loss of H2 and increases the concentration of H2S in the acid gas stream that is fed to the Claus plant.
More specifically, contemplated methods and plants include a desulfurization section for removal of H2S that is fluidly coupled to a decarbonization section for removal of CO2 to produce from a (typically shifted) syngas a desulfurized and decarbonized syngas. The sulfur contaminants from the desulfurization section are fed to a Claus plant that produces a tail gas that is then recycled to the front end of the plant. Most preferably, the desulfurization section produces an acid gas with over 35 mol % H2S content, while the decarbonization section produces a treated syngas (H2 stream) with less than 2 mol % CO2 while capturing over 95% of the CO2 content of the syngas.
Therefore, contemplated methods and plants comprise a gasification unit that provides syngas to a desulfurization section with an H2S absorber that absorbs H2S and COS from the syngas (preferably using a CO2 loaded solvent), to thus produce a desulfurized syngas. A downstream decarbonization section then receives the desulfurized syngas and removes CO2 from the desulfurized syngas in a CO2 absorber, most preferably using a lean and a semi-lean solvent, to produce a H2 stream (i.e., H2 concentration is equal or greater than 80 mol %, more typically equal or greater than 90 mol %, and most typically equal or greater than 95 mol %) as the treated syngas. The lean solvent is regenerated in the desulfurization section by stripping with heat or steam, and the semi-lean solvent in the decarbonization section is regenerated by flashing without external heating.
In especially preferred aspects, the desulfurization section has at least two strippers, with the first stripper removing most of the CO2 content from the rich solvent using stripping gas(es), thereby concentrating the H2S content in the acid gas stream to the sulfur plant, while the second stripper removes all the acid gases producing a lean solvent (sulfur free) for the CO2 absorber. In particularly preferred plants and methods, the first stripper uses the CO2 depleted H2 stream (treated syngas) from the decarbonization section as well as a flashed vapor that is recycled from a downstream flash drum in the desulfurization section. It should be noted that in such configurations and methods, the H2S concentration in the acid gas from the second stripper is therefore substantially increased while the loss of H2 into the acid gas is significantly reduced. Where desired, the overhead gas (or a portion thereof) from the first stripper is cooled, compressed, and then heated to about 350° F. prior to processing in a COS hydrolysis bed to so convert the COS to H2S. Thus, the so treated overhead gas can be readily recycled to the desulfurization feed section.
Consequently, the inventor contemplates a method of operating a syngas treatment plant that includes a step in which syngas (preferably shifted syngas) and a CO2-loaded lean solvent is fed to an H2S absorber to so produce a CO2-loaded rich solvent and a desulfurized syngas. CO2 and H2 are then stripped from the CO2-loaded rich solvent in a first stripper using treated syngas as a first stripping gas and a (H2-lean, relative to the first stripper overhead) flash vapor as a second stripping gas to thereby produce a stripped rich solvent and a CO2/H2-rich recycle gas. In another step, the stripped rich solvent is flashed to produce the (H2-lean) flash vapor, and further stripped in a second stripper to regenerate a lean solvent for the CO2 absorber and a concentrated acid gas. In yet another step, the desulfurized syngas is then fed into the CO2 absorber to produce the treated syngas and the CO2-loaded rich solvent.
Thus, and in another preferred aspect of the inventive subject matter, a method of operating a syngas treatment plant having a decarbonization section and a desulfurization section will include a step of regenerating a portion of a CO2-loaded lean solvent in the decarbonization section in a plurality of flash steps and a further step of using refrigeration content from the flash steps for refrigeration of a CO2 absorber while absorbing CO2 from a desulfurized gas in the CO2 absorber to thereby produce a treated syngas and a CO2-loaded lean solvent from a lean solvent. In yet another step, syngas and the CO2-loaded lean solvent from the decarbonization section is fed to an H2S absorber in the desulfurization section to thereby produce a CO2-loaded rich solvent and the desulfurized gas, and in a further step, CO2 and COS are stripped from the CO2-loaded rich solvent in a first stripper using a treated feed gas as a first stripping gas to thereby produce a stripped rich solvent and a CO2/COS-containing overhead product. The CO2/COS-containing overhead product is then fed into a COS hydrolysis reactor to hydrolyze COS and to produce a recycle gas for combination with the syngas. In yet another step, the stripped rich solvent is further stripped in a second stripper to thereby regenerate the lean solvent and to thereby produce a concentrated acid gas.
As used herein, the term “lean solvent” refers to a solvent that is suitable for absorption of H2S and CO2. Thus a lean solvent will have a combined CO2 and H2S content of no more than 1000 ppmv, more typically no more than 500 ppmv, even more typically no more than 100 ppmv, and most typically no more than 4 ppmv at the bottom from the regenerator or second stripper conditions, Most typically, lean solvent is produced in a regenerator or second stripper and has undergone one or more stripping steps and one or more flashing steps. As also used herein, the term “semi-lean solvent” refers to a solvent that is suitable for absorption of H2S and CO2, and that has a CO2 loading that is greater than the CO2 loading of the lean solvent. Most typically, a semi-lean solvent is produced by flashing a CO2 loaded solvent to thereby remove at least a portion of the CO2 from the solvent.
As still further used herein, the term “CO2-loaded lean solvent” refers to a lean solvent that is used to absorb H2S and has a CO2 loading, which is defined as mole of CO2 per mole of solvent, of at least 1.0, more typically at least 0.9, even more typically at least 1.2, and most typically at least 1.3 of CO2 at absorption conditions. The extent of the CO2 loading is a function of the operating temperature and pressure and the partial pressure of CO2 in the syngas from the prior H2S removal step. Thus, the term “CO2-loaded rich solvent” as used herein refers to a CO2-loaded lean solvent that has absorbed H2S in a prior absorption step. H2S loading, which is defined as mole of H2S per mole of solvent, is at least 0.1, more typically at least 0.2, even more typically at least 0.3, and most typically at least 0.4 of H2S loading capacity at absorption conditions. The extent of the H2S loading is a function of the operating temperature and pressure and the partial pressure of H2S in the syngas.
The term “desulfurized syngas” as used herein refers to syngas from which at least a major fraction of sulfurous compounds has been removed, and the term “treated syngas” as used herein refers to syngas from which at least a major fraction of sulfurous compounds and CO2 has been removed. As still further used herein, the term “stripped rich solvent” refers to a CO2-loaded rich solvent from which at least a portion of the CO2 (and typically H2 has been removed), and the term “CO2/H2-rich recycle gas” refers to a gas that contains as predominant components CO2 and H2.
One exemplary configuration according to the inventive subject matter is shown in FIG. 1. Here, raw unshifted syngas gas stream 1 is supplied from one or more gasifiers (not shown), typically at about 900 psig and at about 800° F. at a flow rate of about 200 MMscfd with the following typical composition:


	COMPONENT	MOL %

	H2S	1.5
	CO2	4.3
	COS	0.02
	CO	52.6
	H2	41.1
	N2	0.2
	Ar	0.2
	CH4	0.2

The hydrogenated tail gas stream 2 contains a significant amount of COS (typically greater than 200 ppmv) is mixed with the feed gas and processed in the high temperature shift reactor 61. As is well known, the CO shift reactors convert CO into CO2 and H2 via the CO shift reaction: (CO+H2O
CO2+H2) and COS into H2S and CO2 via the hydrolysis reaction: (COS+H2O
H2S+CO2). The high temperature shifted gas 4 is then cooled to about 400° F. in exchanger 62 forming stream 5, which is further processed in the low temperature shift reactor 63, producing a shifted syngas 6 with the following typical composition:


	COMPONENT	MOL %

	H2S	1.3
	CO2	35.4
	COS	<0.01
	CO	<1.0
	H2	61.9
	N2	0.1
	AR	0.1
	CH4	0.2

The shifted syngas is cooled in exchanger 64 to about 100° F. forming stream 7, which is separated in flash drum 65 producing a water condensate stream 8 and a syngas stream 9. The syngas is then mixed with the recycle gas stream 3 from the first stripper 71, and this combined stream is chilled in exchanger 66 to about 60° F. using the cold content of the treated gas stream 11 to form stream 10. Water, stream 12, is removed from the exchanger prior to feeding the H2S absorber 67 in the desulfurization section.
The CO2 loaded lean solvent, stream 13, at about 32° F. and about 900 psig, is supplied from the decarbonization section and fed to the H2S absorber 67 to produce an H2S rich bottom stream 15 and an H2S depleted overhead stream 14. The rich solvent (bottom stream 15) from the H2S absorber at about 60° F. is letdown in pressure to about 500 to 700 psig via JT valve 68 forming stream 16, and heated to about 220° F. in exchanger 69 by the lean solvent 17, forming stream 18 that is fed to the first stripper 71. Stripping gases are supplied from two sources: stream 26 from the letdown of the treated gas from the decarbonization section, and stream 175 from the flashed gas recycled from flash drum 154. It should be appreciated that with the two stripping gases, the CO2 content in the rich solvent can be effectively reduced, concentrating its H2S content while recovering hydrogen content in the stripping vapor. In the so configured first stripper, at least 90% of the CO2 in the rich solvent can be removed overhead and recycled back to the H2S absorber.
The first stripper 71 also produces a CO2 rich overhead gas, stream 19, and a H2S enriched bottom, stream 20. The overhead gas is cooled to about 100° F. in exchanger 79 forming stream 28 which is separated in flash drum 78, producing liquid stream 29 and vapor stream 23. The liquid stream, which predominantly comprises water, is letdown in pressure in valve 76, forming stream 24 which is fed to the rectification section of the second stripper as reflux, while the flashed vapor is compressed by compressor 73 to about 900 psig to form stream 21, which is cooled in exchanger 72 and recycled back to the H2S absorber as stream 3.
The stripper bottom, stream 20, is letdown in pressure in JT valve 77 to about 100 psig to 200 psig forming stream 176, which is separated in separator 153 producing vapor stream 170 and liquid stream 22. The liquid stream is further letdown in pressure to about 50 psig in valve 75, forming stream 26, which is fed to the stripping section of the second stripper 80. The flashed vapor stream 170 is cooled to about 100° F. in exchanger 151, forming stream 180, which is separated in separator 154, producing vapor stream 172 and liquid stream 173. The liquid stream, which predominantly comprises water, is combined with stream 24 after reduction in pressure via JT valve 155 and fed to the rectification in the second stripper as reflux. The vapor stream 172 is compressed by compressor 152 to about 500 to 700 psig at about 300° F., forming stream 175, which is fed to the bottom section of the first stripper 71. It should be appreciated that stream 175 is preferably fed to a lower location than stream 26 in the first stripper to further enhance stripping of the H2 content in stream 20. The recycle stream 175, working in conjunction with the treated gas stream 26 effectively removes most of the CO2 content and recovers the hydrogen content from the rich solvent stream 20.
The second stripper 80 is refluxed with streams 24, 174, and 35, and is fully heated in the bottom reboiler 84 to generate stripping steam and to produce lean solvent 31 at about 300° F., and an overhead vapor stream 30 which is cooled to about 100° F. in exchanger 81 to form stream 32. The overhead vapor 32 is separated in reflux drum 82, producing an acid gas stream 33 and a condensate stream 34. The vapor stream 33 is fed to the sulfur plant, and the condensate 34 is pumped by pump 83, forming stream 35, which is returned to the second stripper as the third reflux.
The lean solvent stream 31 is pumped by pump 85 to form stream 17, cooled in lean/rich exchanger 69 to form stream 36 and chiller 70 to about 32° F. prior to being used as a lean solvent 37 in CO2 absorber 90. The acid gas, stream 33, typically comprising at least 35 mol % of H2S (more typically at least 40 mol %, and most typically over 65 mol %) is fed to the sulfur plant 86. The sulfur plant, which typically includes two stage Claus reactors, produces an effluent stream 55, which is hydrogenated and quenched in the tail gas unit 87 to form stream 56, and is then compressed by compressor 88 forming stream 2 that is recycled back to the COS hydrolysis or CO shift section. It should be appreciated that COS that is produced as a by-product in the Claus reactors must be hydrolyzed in the COS hydrolysis reactors or CO Shift section to H2S because H2S which is generally more soluble than COS and can be easily removed by the physical solvent. CO2 absorber 90 produces treated syngas stream 11, which is split after cooling in exchanger 66 (thereby forming stream 101) into treated syngas product stream 103 and flash gas stream 102.
With respect to the use of the tail gas recycle, it should be noted that contemplated configurations and methods have eliminated the traditional tail gas amine treating unit and tail gas incinerator unit by eliminating emissions from the sulfur plant, which produces significant capital and operating savings. Thus, it should be noted that a sulfur plant is fluidly coupled to the second stripper to accept a H2S enriched overhead gas to produce a sulfur product and a tail gas that is hydrogenated, compressed and recycled to the upstream of COS hydrolysis or CO shifting reactors, consequently eliminating all sulfur plant emissions.
In the decarbonization section, desulfurized gas stream 14 from the H2S absorber at about 40° F., is fed to CO2 absorber 90. The CO2 absorber comprises two sections, with the top section fed by the lean solvent from the second stripper, and the bottom section by the semi-lean solvent from the flash drum 99. The rich solvent 38 from the CO2 absorber, at about 60° F. is split into two portions. About 20 vol % to 40 vol % is used (as stream 40 via pump 91 and cooler 74) in the H2S absorber 67 and the remaining fraction (as stream 39) is letdown in pressure to about 400 psia forming stream 44, using hydraulic turbine 93. The flashed solvent is separated in the high-pressure flash drum 94. To minimize hydrogen and CO2 losses, the flash gas stream 46 is compressed and recycled back to the CO2 absorber as stream 56 using compressor 95.
The flashed liquid stream 45 is further letdown in pressure to about 120 psig, using hydraulic turbine 96. The power extracted by the hydraulic turbines together with the heat of CO2 desorption cools the rich solvent to about 28° F., forming stream 47. This refrigeration is used to cool the CO2 absorber by using a side cooler 91. In turn, the rich solvent 47 is heated to about 55° F. forming stream 48 which is separated in separator 97 at 120 psig, producing a medium pressure CO2 stream 50 that is fed to the interstage of the CO2 compressor 101. Over 70% of the CO2 in the feed gas is produced at the medium pressure of 120 psig. It should be noted that the flash pressures and the number of flash stages can be varied as necessary to match the CO2 compressor design specifications. The flash drum liquid stream 49 is letdown in pressure in JT valve 98 to form stream 51 at about 3 psig in the low pressure flash drum 99. The solvent is partially regenerated and chilled to about 30° F. to 40° F. The low pressure CO2 is fed as stream 53 to the suction stage of the CO2 compressor 101. The semi-lean solvent stream 52 is pumped by pump 100 to 850 psia forming stream 54 that is re-circulated to the CO2 absorber. For a shifted syngas rate of 300 MMscfd with a 95% carbon capture target, about 5,500 GPM semi-lean solvent is required. Compressor 101 produces CO2 product stream 55.
It should therefore be appreciated that a portion of the CO2-rich solvent in the decarbonization section is flashed and self-refrigerated, which is used in cooling the CO2 absorber in an absorber side cooler (via streams 42/43). Viewed from a different perspective, the rich solvent is regenerated using free heat of CO2 absorption hence eliminating external heating. It should also be appreciated that the rich solvent is letdown in pressure using hydraulic turbines that is used to operate the circulation pumps, thereby reducing power consumption.
In especially preferred decarbonization sections, the pressure of the rich solvent is reduced over at least three pressure levels. The first flash pressure produces a H2 and CO2 rich flash vapor that is recovered by recycling back to the CO2 absorber. The second flash pressure produces over 60% of the CO2 content at high pressure (greater than 100 psig) that is fed to the interstage of the CO2 compressor. The third flash gas is produced at atmospheric pressure that is fed to the suction of the CO2 compressor. Additionally, preferred plants will also include one or more expansion devices, hydraulic turbines, and flash vessels coupled to the H2S and CO2 absorbers, which further significantly reduces refrigeration and power consumption.
FIG. 2 shows another exemplary configuration that can be integrated to the above plant and method to further improve the sulfur removal efficiency (with respect to FIGS. 1 and 2, it is noted that like components have like numerals, and that the same considerations for like components of FIG. 1 apply to FIG. 2). Since the relative volatility of COS is almost the same as CO2, the rejection of CO2 overhead in the first stripper 71 also rejects its COS content. In this configuration, the first stripper overhead vapor, stream 19, which contains a concentrated COS content (typically 20 to 100 ppmv or higher and is saturated with steam at about 220° F.) is compressed by compressor 73 to about 900 psig, forming stream 21. To further shift the COS hydrolysis reaction equilibrium to the right side of the equation (COS+H2O
H2S+CO2), high pressure steam, stream 202, is added and the combined stream is further heated in exchanger 203 to about 400° F. to 500° F. to form stream 204. Vapor stream 204, superheated at least 50° F., is processed in a COS hydrolysis reactor 205 which converts most of the COS to H2S. Since the recycle stream is relatively small compared to the main feed gas, the COS hydrolysis reactor can be effectively designed to meet a very low level of COS, typically 4 ppmv, preferably less than 2 ppmv. The COS depleted stream 206 is then cooled in exchanger 207 to about 100° F. forming stream 3 which is recycled back to desulfurization section. It should be appreciated that with this additional COS hydrolysis reactor, almost all COS can be converted to H2S which can then be removed by the physical solvent in the desulfurization section, producing a sulfur free hydrogen for fuel gas and a sulfur free CO2 product for sequestration.
With respect to suitable solvents it should be appreciated that the physical and thermal properties of the solvents must be suitable for selective H2S absorption in configurations and methods contemplated herein. Thus, particularly preferred solvents include those comprising dialkylethers of polyethylene glycols mixtures and formulation that have high acid gas loading capacity and are resistant to acid gas corrosion. Further aspects, advantages, and process configurations and methods are described in our copending International application WO2008/103467 and commonly owned U.S. Pat. Nos. 7,637,987, 7,597,746, and 7,424,808, each of which is incorporated by reference herein.
It should be apparent to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the scope of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced. Where the specification claims refers to at least one of something selected from the group consisting of A, B, C . . . and N, the text should be interpreted as requiring only one element from the group, not A plus N, or B plus N, etc.

Claims

What is claimed is:

1. A method of operating a syngas treatment plant, comprising:

providing a syngas and a CO2-loaded lean solvent from a CO2 absorber to an H2S absorber to so produce in the H2S absorber a CO2-loaded rich solvent and a desulfurized syngas;

stripping CO2 and H2 from the CO2-loaded rich solvent in a first stripper using a treated syngas as a first stripping gas and using a flash vapor as a second stripping gas to thereby produce a stripped rich solvent and a CO2/H2-rich recycle gas;

flashing the stripped rich solvent to thereby produce the flash vapor;

further stripping the stripped rich solvent in a second stripper to thereby regenerate a lean solvent for use in the CO2 absorber and to thereby produce a concentrated acid gas; and

feeding the desulfurized syngas into the CO2 absorber to thereby produce the treated syngas and the CO2-loaded rich solvent.

2. The method of claim 1 further comprising a step regenerating a portion of the CO2-loaded lean solvent in a plurality of flash steps, and using refrigeration content from the flash steps for refrigeration in the CO2 absorber.

3. The method of claim 2 wherein at least one of the plurality of flash steps produces a flash gas, further comprising a step of recycling the flash gas to the CO2 absorber.

4. The method of claim 1 further comprising a step of feeding the concentrated acid gas into a Claus plant and combining a Claus plant tail gas after hydrogenation with the syngas.

5. The method of claim 1 further comprising a step of separating water from the CO2/H2-rich recycle gas and feeding the water to the second stripper as a reflux stream.

6. The method of claim 1 further comprising a step of hydrolyzing COS in the CO2/H2-rich recycle gas using a COS hydrolysis reactor.

7. The method of claim 1 wherein the syngas is a shifted syngas.

8. The method of claim 1 wherein the CO2/H2-rich recycle gas is recycled to the H2S absorber.

9. A method of operating a syngas treatment plant comprising a decarbonization section and a desulfurization section, the method comprising:

regenerating a portion of a CO2-loaded lean solvent in the decarbonization section in a plurality of flash steps and using refrigeration content from the flash steps for refrigeration of a CO2 absorber while absorbing CO2 from a desulfurized gas in the CO2 absorber to thereby produce a treated syngas and a CO2-loaded lean solvent from a lean solvent;

providing a syngas and the CO2-loaded lean solvent from the decarbonization section to an H2S absorber in the desulfurization section to thereby produce a CO2-loaded rich solvent and the desulfurized gas;

stripping CO2 and COS from the CO2-loaded rich solvent in a first stripper using a treated feed gas as a first stripping gas to thereby produce a stripped rich solvent and a CO2/COS-containing overhead product;

feeding the CO2/COS-containing overhead product into a COS hydrolysis reactor to hydrolyze COS and produce a recycle gas for combination with the syngas; and

further stripping the stripped rich solvent in a second stripper to thereby regenerate the lean solvent and to thereby produce a concentrated acid gas.

10. The method of claim 9 further comprising a step of subjecting the syngas to a shift reaction prior to providing the syngas to the H2S absorber.

11. The method of claim 9 further comprising a step of combining the recycle gas with the syngas.

12. The method of claim 9 further comprising a step of feeding the concentrated acid gas into a Claus plant and combining a Claus plant tail gas after hydrogenation with the syngas.

13. The method of claim 9 wherein the concentrated acid gas has an H2S content of at least 35 mol % and wherein the treated syngas has a CO2 content of equal or less than 2 mol %.

14. A syngas treatment plant, comprising:

an H2S absorber that is configured to receive a syngas and a CO2-loaded lean solvent and that is further configured to produce a CO2-loaded rich solvent and a desulfurized syngas;

a first stripper fluidly coupled to the H2S absorber to receive the CO2-loaded rich solvent and configured to allow use of a treated syngas as a first stripping gas and of a flash vapor as a second stripping gas to thereby allow production of a stripped rich solvent and a CO2/H2-rich recycle gas;

a first flash vessel fluidly coupled to the first stripper and configured to receive and flash the stripped rich solvent to thereby allow production of the flash vapor;

a second stripper fluidly coupled to the first flash vessel and configured to receive and further strip the stripped rich solvent to thereby allow generation of a lean solvent and a concentrated acid gas; and

a CO2 absorber fluidly coupled to the H2S absorber and configured to receive the desulfurized syngas, and further configured to allow production of the treated syngas from the desulfurized syngas with use of the lean solvent to thereby allow production of the CO2-loaded rich solvent.

15. The syngas treatment plant of claim 14 further comprising a plurality of flash drums coupled to the CO2 absorber and configured to allow regeneration of a portion of the CO2-loaded lean solvent in a plurality of flash steps, and a heat exchanger coupled to the CO2 absorber and configured to allow use of refrigeration content from the portion of the CO2-loaded lean solvent for refrigeration in the CO2 absorber.

16. The syngas treatment plant of claim 15 wherein at least one of the plurality of flash drums is configured to allow production of a flash gas, and a conduit that fluidly couples the at least one of the plurality of flash drums to the CO2 absorber to so allow for recycling of the flash gas to the CO2 absorber.

17. The syngas treatment plant of claim 14 further comprising a shift reactor fluidly coupled to the H2S absorber and configured to provide shifted syngas to the H2S absorber.

18. The syngas treatment plant of claim 14 further comprising a Claus plant and a Claus plant tail gas unit configured to receive the concentrated acid gas and to produce a treated tail gas, and further comprising a conduit that allow combination of the treated tail gas with the syngas.

19. The syngas treatment plant of claim 14 further comprising separator fluidly coupled to the first stripper and configured to allow separation of water from the CO2/H2-rich recycle gas, and further comprising a conduit that is configured to allow feeding of the water to the second stripper as a reflux stream.

20. The syngas treatment plant of claim 14 further comprising a COS hydrolysis reactor that is fluidly coupled to the first stripper and that is configured to allow for hydrolysis of COS in the CO2/H2-rich recycle gas.