GB2464368A

GB2464368A - A solvent regeneration process

Info

Publication number: GB2464368A
Application number: GB0913989A
Authority: GB
Inventors: Cyril Timmins; Keith Raymond Tart
Original assignee: Individual
Current assignee: Individual
Priority date: 2008-10-14
Filing date: 2009-02-11
Publication date: 2010-04-21
Anticipated expiration: 2029-02-11
Also published as: GB0913989D0; GB0907078D0; GB2464368B

Abstract

A process for partly regenerating a first absorption solvent stream containing a given component comprising the steps of:a) contacting a feed gas stream 10 having a concentration of a given component with a lean second absorption solvent stream 36 and producing a rich second solvent stream 30 and a gas stream 12 having a lower concentration of the given component than the feed gas stream,b) heating at least part of the rich second solvent stream, and contacting it with a part of the stripping gas to produce a regenerated second solvent stream (34), andc) regenerating a loaded first absorption solvent stream 38 by contact with a further part of the gas stream 12 having a lower concentration of the given component than the feed gas stream. Advantageously the solvent regeneration process is a high pressure regeneration process that may be used with a main absorber.

Description

High Pressure Physical Absorption Regeneration Process

Technical Field

The present invention relates to a solvent regeneration process for use within a physical absorption process that at least partly removes selected components from a feed gas. In particular, it relates to a process that allows the regeneration of a physical absorption solvent at high pressure using a stripping gas derived from the feed gas itself. The selected component may include carbon dioxide (C02).

Background Art

Gas separation processes often make use of the ability of a liquid solvent to preferentially absorb particular components. Such processes normally use either a physical absorption solvent, a chemical absorption solvent or a mixture of both. Physical absorption processes are often preferred when undertaking gas separation at high pressure. Such processes rely upon differences in solubility in the physical solvent of the gaseous components being separated; these solubilities being dependent upon the temperature of the physical solvent and the partial pressure of individual gaseous components in the feed gas.

A simple physical absorption process comprises an absorption column and a regeneration stage. The physical solvent at high pressure (normally containing a low concentration of the component to be removed) is contacted with a feed gas in the absorption column; thus partly removing the component (X) to be separated. The loaded solvent leaving the gas absorption column contains dissolved component X which is subsequently largely removed in the regeneration stage. This is normally achieved by reducing the pressure of the loaded solvent so that component X is largely flashed off the solvent which, following such regeneration, is then pumped back to the top of the high pressure absorption column. Optionally, after such a flash step the solvent can be stripped by e.g. with air or steam to further lower the concentration of X. If air is used for such stripping of the flashed solvent the product of such stripping which contains component X will be vented, while if steam is used the overheads are cooled to condense the steam and leave low-pressure component X for disposal.

Such a process inevitably yields the separated gas at a relatively low pressure. In some applications it is highly desirable that the separated gas be available without any significant loss of pressure. Notably, when a physical absorption process is used to remove CO2 in a power generation or energy conversion process, the ability to separate CO2 without any loss of pressure facilitates disposal of the captured CO2 (for example by injecting the high pressure CO2 thus separated into a depleted underground gas reservoir).

In a conventional process, which separates CO2 at low pressure, a large and expensive CO2 recompression stage is required. Consequently, for a power generation plant there is generally a Significant power generation efficiency penalty associated with such CO2 capture. However, such capture is highly desirable as it contributes to a reduction in global CO2 emissions.

An object of the present invention is to provide a solvent regeneration process that operates at near or above the pressure of the feed gas to be processed. Another object of the invention is to avoid the generation of low-pressure flash gas and so avoid the possible need of recompression. A further object of the invention is to provide a high pressure solvent regeneration process that can be used with several different absorber configurations; for example to remove CO2 in an energy conversion process.

Summary of Invention

A solvent regeneration process, for use within a physical gas absorption process that partly removes soluble components from a feed gas and where the process allows the regeneration of a first physical absorption solvent at high pressure using a stripping gas derived from the feed gas itself using a further absorption and regeneration step employing either the said first physical absorption solvent or a second physical solvent.

The high pressure regeneration process can be used with a main absorber in energy conversion processes to allow CO2 produced either by combustion, partial oxidation or catalytic means to be separated and exported at pipeline pressure; thus reducing greenhouse gas emissions and avoiding the need for a large CO2 gas compressor In one aspect the invention comprises a process for at least partly regenerating a first absorption solvent (A) stream loaded with a component X; comprising the following steps: (a) contacting a feed gas stream with a lean second absorption solvent (B) stream thereby producing a rich second solvent (B) stream and a stripping gas stream that has a lower concentration of X than said feed gas stream (b) heating at least part of said rich second solvent (B) stream by up to 100°C before or during contacting it with a part of said stripping gas stream to produce a regenerated second solvent (B) stream and (c) regenerating the loaded first solvent (A) stream by contacting this stream with a further part of said stripping gas stream to yield a regenerated first solvent (A) stream.

During step (b) the rich second solvent stream is preferably heated by up to 30°C; and preferably by up to 60°C.

Preferably, the first loaded solvent stream and/or the rich second solvent is regenerated at a pressure in the range 10 to 100 bar. Preferably, the feed gas is contacted with said second solvent at a pressure in the range 10 bar to 100 bar.

Typically, one or more of steps (a), (b), (c) are carried out using contactors that comprise a counter current flow contacting column. In such cases said contacting column may comprise plates or mass transfer packing elements. However, other types of mass transfer contacting device may be used.

Said regenerated first solvent stream may be contacted with a gas stream rich in X to yield a gas stream with a reduced concentration of X and a first solvent stream rich with a dissolved component X from which said first solvent stream loaded with component X is derived. The first solvent stream rich in X may be heated, without depressurization, by a temperature up to 120°C (and preferably up to 80-100°C) to produce the partly regenerated first solvent stream loaded with component X and a gas stream rich in X. In addition, the first solvent stream rich in X may be pumped to a substantially higher pressure before being heated. This substantially higher pressure preferably corresponds to a pressure increase in the range 2 to 50 bar, and preferably in the range 5-25 bar.

Said regenerated first solvent stream may be contacted with a gas rich in X to yield a gas stream with a reduced concentration of X and a first solvent stream rich with a component X to which said first solvent stream loaded with component X corresponds and where the gas stream rich in X is provided by taking at least part of the gas produced by the regeneration steps (b) and/or (c) and partly removing component X by liquefaction.

The component X may comprise C02, H2S, COS, SO2 or a mixture thereof.

Preferably, the first solvent (A) and second solvent (B) are the same solvent. Suitable physical absorption solvents include: for example; (1) dimethyl ether of polyethylene glycol (SelexolT1 process); (2) methanol (RectisolTM process); (3) n-methyl pyrrolidone (PurisolTM process): (4) polyethylene glycol and dialkyl ethers (SepasolvTM MPE process); (5) propylene carbonate (FluorTM Solvent process); and (6) tetrahydrothiophene dioxide (SulfolaneTM process)

Brief Description of Drawings

The invention will now be described by reference to the following simplified process flow diagrams in which: Figure 1 shows the main features of a basic solvent regeneration process according to the present invention; Figure 2 shows a preferred embodiment of the invention where the process uses a single absorption solvent; Figure 3 shows a complete gas separation process that uses the regeneration process of Figure 2; and Figure 4 shows another embodiment of the invention which includes a gas liquefaction stage.

Description of Preferred Embodiments

The basic high pressure solvent regeneration process will be described by reference to Figure 1. The process accepts a loaded high pressure solvent stream (38) from a main gas absorber (not shown) and provides a regenerated first solvent stream (40) for return to the main gas absorber. Stream 38 will typically have been provided by partly regenerating a rich solvent from said main absorber without using pressure reduction; but rather by raising the temperature of said loaded first solvent. Alternatively, said loaded first solvent may come directly from the base of the main absorber.

The loaded solvent 38 from a main absorber will typically be regenerated using stripping gas derived from a feed gas stream (10) that contains an appreciable concentration of the component (X) to be separated. For example, when X is CO2 and the feed gas 10 may comprise a high pressure fuel gas containing between 5-65% CO2. Gas feed 10 is first contacted with a regenerated second solvent stream (36) in a first contactor (50) to produce a much lower CO2 containing stripper gas stream (12). Stream 12 is then normally heated in heater 56 (typically by 50-90°C) and the heated stream 14 then split into two parts; the first part (16) is used to regenerate at lease part of the loaded second solvent (30) leaving the first contactor (50) in a second contactor 54a; and all or some of the remaining part (18) is used to regenerate stream 38 in a third contactor 54b. The gaseous streams 20 and 22 leaving the second and third contactors 54a and 54b are optionally combined to form stream 24 which may then pass either directly or indirectly to a main absorption stage (not shown). In the case where stream 34 passes indirectly to such a main absorption stage there may be intermediate stages comprising for example fuel gas combustion, CO-shift conversion, methane synthesis etc. The loaded second solvent stream (30) leaving first contactor 50 is normally heated (in a heater 52b) before entering second contactor 54a. Thus, the solvent stream 30 is typically heated by 10- 90°C (preferably 10-40°C) before entering (32) the second contactor 54a. The regenerated second solvent 34 leaving column 54a (34) is cooled in cooler 52a before re-entering (36) the first contactor 50. Typically, this cooling of between 10-100°C (preferably 50-90°C) is provided at least in part by combining cooler 52a and heater 52b within a single heat exchanger.

Often it will be possible and desirable to use the same physical absorption solvent in all three contactors. In this case it will often be beneficial to combine contactors 54a and 54b. Figure 2 shows a preferred embodiment of the invention using such combined regeneration contactors. Again, the feed gas 10 is first contacted with a regenerated second solvent stream (36) in a first contactor (50) to produce a much lower CO2 containing stripper gas stream (12) which after heating in heater 56 is used (14) to regenerate both the loaded second solvent (30) leaving the first contactor (50) and also loaded solvent stream (38) from the main absorber (not shown); this regeneration of both streams 32 and 38 taking place in a second contactor 54. Streams 32 and 38 are preferably mixed before entering the second contactor 54. The gaseous stream 24 leaving the second contactor 54 may then pass either directly or indirectly to a main absorption stage (not shown). In the case where stream 24 passes indirectly to such a main absorption stage there may be intermediate stages comprising for example fuel gas combustion, CO-shift conversion, methane synthesis etc. The loaded second solvent (30) stream leaving the first contactor 50 is heated in heater 52b before entering second contactor 54 Thus, the solvent stream 30 is typically heated by 30-90°C before entering second contactor 54. Part of the regenerated solvent (34) leaving the second contactor 54 is chilled in cooler 52a prior to re-entering the first contactor 50. Typically, this cooling is provided at least in part by combining cooler 52b and heater 52a within a single heat exchanger. The remainder of the solvent leaving the second contactor 54 comprises regenerated main solvent stream 40 that is cooled before entering the main absorber (not shown).

An example of a complete gas purification process using the present invention will now be described by reference to Figure 3. In this example CO2 is being removed from a high pressure combustion gas. The composition temperature and pressure of the labeled process streams are shown in Table 1 This example comprises the streams and contactors described earlier in reference to Figure 2, except for the addition of heat exchangers 58, 62, 68; a main absorber 60, a gas-liquid separator (KO Pot) vessel 66, pump 70, expansion valve 72 and their associated streams 26, 42, 44, 46, 48 and 64.

Thus, the gaseous stream 26 (in this case provided by cooling stream 24 in cooler 58 on leaving the second contactor 54) passes to main absorber vessel 60 where CO2 is reduced to a low level by contacting with regenerated main solvent stream 40 thus producing a product gas stream 64 and a main absorber solvent loaded stream 42 which is optionally pumped to a higher pressure by pump 70 and then heated in heater 68 prior to entering KO Pot 66 where high pressure gaseous CO2 (46) suitable for disposal export is separated from the liquid solvent leaving a partly regenerated high pressure solvent stream 48.

Optionally, stream 48 is expanded to a pressure slightly above the operating pressure of the second contactor 54 prior to regeneration therein.

In practice, stream 10 will normally contain sulphur dioxide (SO2). Such SO2 is largely removed in the main absorber (60) and appears in the loaded solvent stream (42) leaving the main absorber; eventually to be released as part of high pressure CO2 export gas stream 46. Such SO2 can be recovered from stream 46 by known means; for example suiphite washing or distillation.

The oxygen content of stream 64 may be used to facilitate its heating; for example, by catalytic combustion using a hydrogen rich gas prior to turbo expansion to produce power. Alternatively, oxygen may be removed from stream 10 by catalytic combustion of an injected fuel. The heat so liberated may be used to heat stream 64 prior to turbo expansion. Reducing the oxygen concentration in stream 10 may be also advantageous in preventing solvent degradation.

Table 2 shows data corresponding to Table 1 for cases where the feed gas 10 comprises a fuel gas derived from the gasification of a carbonaceous feed that has undergone catalytic CO-shift conversion and been largely desulphurised. Stream 10 may contain small amounts of hydrogen sulphide (H2S) in the order of 10 ppmv. Such H2S is largely trapped within the rich solvent stream (42) leaving the main absorber and subsequently leaves as part of a high pressure CO2 export stream 46. This stream will contain a maximum of about 2.5 times the inlet H2S concentration in feed gas 10. Thus, if the inlet H2S gas concentration (stream 10) is 10 ppmv there will be about 25 ppmv H2S in stream 46; product gas stream 64 will contain about 1 ppmv H2S.

Table 3 shows data corresponding to Table 1 where the feed gas 10 comprises a fuel gas that has been derived from the gasification of a carbonaceous feed and methanated using catalytic methane synthesis, respectively.

In this embodiment of the process a recycle stream of CO2 is achieved by recycling the partially regenerated solvent stream 48 exiting KO pot 66, via stream 38 into regenerator vessel 54 where the solvent is largely stripped of CO2 by upwardly flowing gas stream 14 to form part of the C02-rich outlet stream 24. It is then absorbed from said stream together with CO2 derived from feed gas stream 10 in absorber vessel 60 to be returned in streams 42 and 44 to KO pot 66. For a given KO pot pressure the amount of CO2 so recycled is governed by the temperature of said KO pot. Higher temperature operation reduces the recycle rate by reducing the CO2 concentration in stream 48 while lower temperature operation increases said concentration and the recycle rate. This recycle stream of CO2 enables a higher inlet CO2 concentration to be maintained in rich solvent streams 42 and 44 in order to achieve the desired KO pot pressure.

It is also advantageous to cool solvent stream 48; for example against rich solvent stream 30, before reducing its pressure in order to avoid release of gaseous CO2 during pressure reduction; for example using a hydraulic turbine.

The invention may also be used with a process where the gaseous stream 24 leaving the second contactor (54) passes through a CO2 liquefaction stage (I-Ill) prior to entering a main CO2 absorber (60).

Figure 4 shows a combined simplified flow diagram and block flow diagram for such a scheme. The equipment and streams shown in Figure 4 are as described in Figure 2 apart from Units I-Ill and related streams 80, 82, 84, 86, 88, 90 and 92. Unit I is a conventional pre-treatment unit which renders gas stream 80 fit for subsequent cooling to a low temperature and thereby allows subsequent cold recovery from this stream in downstream Unit II using conventional heat exchange art. Downstream Unit III is preferably a cryogenic separation unit equipped with refrigeration means which partly separates CO2 by condensation, to produce a liquid CO2 condensate stream (86) and a CO2-lean gas stream (88).

Thus, gas stream 80 (derived directly or indirectly from stream 24) is passed to Unit I for pre-treatment to render it fit for subsequent cold processing; in particular, water vapour is removed to prevent ice formation. The treated gas 82 is then pre-cooled in unit II and the cooled stream 84 then passed to unit III where part of the CO2 is condensed out as liquid.

Cooling in unit II is achieved in part using cold exit gas from unit III and optionally liquid CO2 from unit III. Additional external refrigeration is also normally provided.

Such cooling must be limited in order to avoid solid CO2 formation which occurs at minus 56°C. In practice, the temperature is preferably higher and in the range minus 10°C to minus 30°C, and so the CO2 content of the exit gas (88) lies in the range 20 to 65 percent by volume. Liquid CO2 (86) separated in unit III is preferably pumped to a suitable pressure (a pressure of 60 bar permits warming up to 20°C) before it is heated partly by heat exchange with treated gas in unit II and partly by exchange with warm higher pressure refrigerant from a refrigerant condenser (not shown) to sub-cool said refrigerant before it is reduced in pressure to enter a refrigerant evaporator (not shown).

This ensures that no vaporization of the liquid CO2 occurs during such heat exchange.

After said heat exchange the liquid CO2 may be pumped to supercritical pressure or higher (above 76 bar and typically 00-150 bar) and passed to an export pipeline Alternatively, the separated liquid CO2 stream may be pumped to supercritical pressure or above prior to said heat exchange. A partly purified gas (88) with a lowered CO2 content of typically 20-40% by volume (C02-lean gas) is passed to unit II for cold recovery and then passed (90) to main absorber 60 where further CO2 is removed by solvent washing.

The resulting low CO2 product gas is stream 92. Thus, all of the CO2 removed in the process leaves as high pressure liquid CO2 stream 86 to be pumped and warmed as above prior to export through a pipeline.

In all of the above embodiments of the invention described by reference to Figures 3 and 4, solvent may be withdrawn from the main absorber 60 at an intermediate point, or points; cooled and then reintroduced it into the absorber column and 60. This advantageously reduces the solvent temperature at the base of column 60 and thus enables an increased concentration of CO2 in the solvent. A lowering of solvent exit to temperature by about 10°C allows a 20% increase in CO2 concentration in the solvent leaving the main absorber column 60.

Thus, the present invention provides a solvent regeneration process that operates at near or above the pressure of the feed gas to be processed. The present invention avoids the generation of low-pressure flash gas and so avoids the possible need of recompression.

The present invention also advantageously provides a high pressure solvent regeneration process that can be used with several different main absorber configurations; for example to remove CO2 more efficiently in an energy conversion process.

TABLE 1

STREAM 10 12 14 24 26 46 64 30 32 34 36 40 42 44 48 GAS FLOW, kmol/h 10000 84.40 84.40 137.78 137.78 15.63 84.40 15.63 %, mo) N2 79.20 93.85 93.85 57.48 57.48 93.85 CO2 17.33 2.05 2.05 40.00 40.00 100.00 2.05. 100.00 02 3.47 4.10 4.10 2.52 2.52 4.10 LIQUID FLOW, ms/h 19.93 19.93 52.53 19.93 32.6 32.6 32.6 32.6 CO2 CONC, kmol/m3 0.845 0.845 0.063 0.063 0.063 1.699 1.22 1.22 PRESSURE, bar 35 35 35 35 35 41 35 35 35 35 35 35 35 41 41 TEMP,C 15 15 85 91 15 120 15 22 44 82 15 15 29 120 120

TABLE 2

STREAM 10 12 14 24 26 46 64 30 32 34 36. 40 42 44 48 GAS FLOW, kmo/h 100.00 61.22 61.22 137.55 137.55 38.78 61.22 38.78 %, mof CO 200 3.27 3.27 1.45 1.45 3.27 CO2 40.00 2.00 2.00 56.38 56.38 100.00 2.00 100 H2 58.00 94.73 94.73 42.17 42.17 94.73 LIQUID FLOW, m3Ih 23.7 23.7 56.3 23.7 32.6 32.6 32.6 32.6 CO2 CONC, kmol/m3 1.699 1.699 0.063 0.063 0.063 2.404 1.214 1.214 PRESSURE, bar 35 35 35 35 35 43 35 35 35 35 35 35 35 43 43 TEMP, C 15 15 85 94 15 122 15 29 58 82 15 15 35 122 122

NJ

TABLE 3

STREAM 10 12 14 24 26 46 64 30 32 34 36 40 42 44 48 GAS FLOW, kmol/h 100.00 35.71 35.71 165.00 165.00 35.71 64.29 %, mol CH4 35.00 98.00 98.00 21.21 21.21 98.00 CO2 65.00 2.00 2.00 78.79 78.79 100.00 2.00 100 LIQUID FLOW, m3Ih 26.37 26.37 71.32 26.37 44.95 44.95 44.95 44.95 CO2 CONC, kmol/m3 2.501 2.501 0.063 0.063 0.063 2.939 1.509 1.509 PRESSURE, bar 35 35 35 35 35 54 35 35 35 35 35 35 35 54 54 TEMP, C 15 15 85 96 15 122 15 35 52 82 15 15 37 122 122

Claims

CLAIMS1. A process for at least partly regenerating a first absorption solvent (A) stream (38) loaded with a component X; comprising the following steps: a) contacting a feed gas stream (10) with a lean second absorption solvent (B) stream (36) thereby producing a rich second solvent (B) stream (30) and a stripping gas stream (12) that has a lower concentration of X than said feed gas stream (10); b) heating at least part of said rich second solvent (B) stream (30) before or during contacting it with a part of said stripping gas stream (12) to produce a regenerated second solvent (B) stream (34,36); and c) regenerating the loaded first solvent (A) stream (38) by contacting this stream with a further part of said stripping gas stream (12) to yield a regenerated first solvent (A) stream (40).
2. A process according to Claim 1 wherein during step (b) the rich second solvent stream (30) is heated by up to 100°C, or by up to 60°C, or by up to 3 0°C.
3. A process according to any preceding claim wherein the first physical absorption solvent (A) and/or the second physical absorption solvent (B) are dimethyl ether of polyethylene glycol (SelexolTM process); or methanol (RectisolTM process); or n-methyl pyrrolidone (PurisolTM process): or polyethylene glycol and dialkyl ethers (SepasolvTM MPE process); or propylene carbonate (FluorTM Solvent process); or tetrahydrothiophene dioxide (SulfolaneTM process).
4. A process according to any preceding claim where the first loaded solvent stream (38) and/or the rich second solvent (30) is regenerated at a pressure in the range lObar to lOObar, or 25bar to lOObar.
5. A process according to any preceding claim wherein the feed gas (10) is contacted with said second solvent at a pressure in the range lObar to 100 bar, or 25bar to 1 O0bar.
6. A process according to any preceding claim where one or more of steps (a), (b), (c) are carried out using contactors that comprise a counter current flow contacting column.
7. A process according to Claim 6 where at least one said contacting column comprises plates or mass transfer packing elements
8. A process according to any preceding claim wherein said regenerated first solvent stream (40) is contacted with a gas stream (26,90) rich in X to yield a gas stream with a reduced concentration of X (64,92) and a first solvent stream (42) rich with a component X fromlto which said first solvent stream (38) loaded with component X is derived/corresponds.
9. A process according to Claim 8 where the first solvent stream rich in X (42) is heated, without depressurization, by a temperature up to 100°C, or by up to 120°C, to produce the partly regenerated first solvent stream (48) loaded with component X and a gas stream (46) rich in X.
10. A process according to Claim 9 where the first solvent stream rich in X (42) is pumped to a substantially higher pressure before being heated.
11. A process according to claim 10 where the substantially higher pressure corresponds to a pressure increase in the range 2 to 50 bar, or in the range 5-25bar.
12.A process according to Claim 8 where the said contacting yields directly said first stream (38) loaded with component X and where the gas stream (90) rich in X is provided by taking at least part of the gas produced (20,22,24) by the regeneration steps (b) and/or (c) and partly removing component X by liquefaction.
13.A process according to any preceding claim where X is C02, H2S, COS, SO2 or a mixture thereof
14. A process according to any preceding claim where the first solvent (A) and second solvent (B) are the same solvent.