US20120167620A1

US20120167620A1 - Method and system for separating co2 from synthesis gas or flue gas

Info

Publication number: US20120167620A1
Application number: US13/320,298
Authority: US
Inventors: Eva Marfilia Van Dorst; Gerard De Nazelle; Hendrik Jan Van Der Ploeg; Rick Van Der Vaart; Evert Wesker
Original assignee: Individual
Current assignee: Shell USA Inc
Priority date: 2009-05-15
Filing date: 2010-04-12
Publication date: 2012-07-05
Also published as: CA2760602A1; AU2010247399A1; WO2010130781A1; AU2010247399B2; JP2012526962A; EP2429683A1; CN102427868A

Abstract

The present invention provides a method and system for separating CO2 from a gas stream containing CO2. A gas stream having an initial pressure is compressed and subsequently cooled. The compressed and cooled gas stream has an increased pressure and reduced temperature at which the CO2 in the gas stream is at least partially converted to the liquid phase. The liquid phase is separated from the compressed and cooled gas stream, to provide a liquid phase stream and a gas phase stream, wherein the output pressure of the liquid phase stream is higher than the initial pressure of the gas stream.

Description

The present invention relates to a method and system for separating at least CO2 from a synthesis gas stream or a flue gas stream.
Flue gas comprises for instance N2, CO2 and other combustion products.
Synthesis gas streams are gaseous streams mainly comprising carbon monoxide and hydrogen. Synthesis gas streams are for instance produced via partial oxidation or steam reforming of hydrocarbons including natural gas, coal bed methane, distillate oils and residual oil, and by gasification of solid fossil fuels such as coal or coke. Reference is made “The Shell Middle Distillate Synthesis Process, Petroleum Review April 1990 pp. 204-209” by Maarten van der Burgt et al. for a general description on the preparation of synthesis gas.
There are many solid or very heavy (viscous) fossil fuels which may be used as feedstock for generating synthesis gas, including solid fuels such as anthracite, brown coal, bituminous coal, sub-bituminous coal, lignite, petroleum coke, peat and the like, and heavy residues, for instance hydrocarbons extracted from tar sands, residues from refineries such as residual oil fractions boiling above 360° C., directly derived from crude oil, or from oil conversion processes such as thermal cracking, catalytic cracking, hydrocracking etc. All such types of fuels have different proportions of carbon and hydrogen, as well as different substances regarded as contaminants.
Depending on the feedstock used to generate synthesis gas, the synthesis gas may comprise contaminants such as carbon dioxide (CO2), hydrogen sulphide, carbonyl sulphide and carbonyl disulphide while also containing nitrogen, nitrogen-containing components (e.g. HCN and NH3), metals, metal carbonyls (especially nickel carbonyl and iron carbonyl), steam and in some cases mercaptans.
The synthesis gas stream may be treated to remove contaminants and/or to adjust the H2/CO ratio. WO-2008/068305, for instance, describes subjecting part of a synthesis gas stream comprising contaminants to a water gas shift reaction and using a combination of bulk contaminants removal followed by polishing to remove contaminants to a predetermined level.
WO-2008/153379 provides a method for separating CO2 from a flue gas or synthesis gas mixture. The method includes cooling the gas mixture in a heat exchanger, and subsequently expanding the gas mixture adiabatically to cool the gas to a temperature and pressure at which the CO2 in the mixture is at least partially in the liquid phase. Before cooling the mixture, the gas mixture may be pressurized to increase the temperature drop during expansion. The liquid fraction, including CO2, is subsequently separated from the cooled and expanded mixture.
The present invention aims to provide an improved method and system for separating CO2 from a gas stream.
The invention accordingly provides a method for separating CO2 from a synthesis gas stream or a flue gas stream, the method comprising the steps of:

- providing a gas stream at an initial pressure and initial temperature;
- compressing the gas stream;
- cooling the compressed gas stream, wherein the compressed and cooled gas stream has an increased pressure and reduced temperature at which the CO2 in the gas stream is at least partially converted to the liquid phase; and
- separating the liquid phase from the compressed and cooled gas stream, to provide a liquid phase stream and a gas phase stream at an output pressure,

wherein the output pressure of the liquid phase stream is increased relative to the initial pressure of the gas stream.
Cooling by adiabatically expanding the gas seems logical, as the required equipment and operating costs are relatively low. The present invention however teaches to first compress the gas stream, to be able to provide product streams at an increased pressure relative to the input gas stream. As the pressure of the product streams is increased relative to the initial pressure, the product streams can be directly supplied for further processing. The pressure of one product stream may be for instance suitable for injecting CO2 in a subterranean reservoir. Additionally, the method of the present invention removes more CO2 in a single process step than prior art methods, rendering the method more efficient.
In an embodiment, the initial pressure is in the range of 20 to 65 bar, preferably about 35 to 60 bar. The method is thus suitable for directly handling synthesis gas from a plant. The synthesis gas may be of varying or predetermined composition. The H2/CO ratio of the synthesis gas can be determined by including the water gas shift reaction in the method of the invention.
In another embodiment, the output pressure of the liquid phase is above 75 bar, or preferably in the range of 100 to 200 bar. The liquid phase stream can be directly processed, thus obviating the need to pump or otherwise treat the product stream. The liquid phase stream can for instance be directly injected in a subterranean reservoir. Thus, the overall process is relatively efficient. If the output pressure of the liquid phase is not sufficiently high to allow for direct injection in a reservoir, then a pump may be added to the system to increase the pressure of the liquid phase stream sufficiently to allow for direct reservoir injection.
In a preferred embodiment, the output pressure is in the range of 140 to 160 bar. At this pressure, which is determined by the compression of the gas stream, the efficiency of the CO2 removal process is relatively high. The capture rate is for instance above 85%, or in the order of 90%.
In yet another embodiment, the gas stream is a synthesis gas stream, which is subjected to a water shift reaction, to provide a shifted synthesis gas stream having an increased H2 and CO2 content. By increasing the H2 and CO2 content, the efficiency of the process increases. The shifted synthesis gas stream mainly comprises H2 and CO2. Mainly herein indicates for instance more than 40 to 50 mol % H2 and more than 40 mol % CO2. The CO2 can be captured and stored in a reservoir. The H2 rich gaseous stream can be used as fuel for several applications, for instance for fuelling a generator for generating electrical power.
In still another embodiment, the output pressure of the gaseous phase is substantially similar to the output pressure of the liquid phase. The pressurized and H2 rich gaseous phase can for instance be used to fuel an electrical generator.
According to another aspect, the present invention provides a system for separating CO2 from a gas stream containing CO2, the system comprising:

- a compressor for compressing the gas stream having an initial pressure and an initial temperature;
- at least one cooling device for cooling the compressed gas stream, wherein the compressed and cooled gas stream has a pressure and temperature at which the CO2 in the gas stream is at least partially converted to the liquid phase; and
- a separator for separating the compressed and cooled synthesis gas stream in a liquid phase stream and a gas phase stream at an output pressure,

wherein the output pressure of the liquid phase stream is increased relative to the initial pressure of the gas stream.

The invention will now be illustrated in more detail and by way of example with reference to embodiments and the drawings, in which:

FIG. 1 schematically shows an embodiment of a system according to the present invention;

FIG. 2 schematically shows another embodiment of a system according to the present invention;

FIG. 3 schematically shows yet another embodiment of a system according to the present invention;

FIG. 4 schematically shows yet another embodiment of a system according to the present invention;

FIG. 5 schematically shows an alternate design of the system shown in FIG. 4; and

FIG. 6 shows an exemplary phase diagram of a gas stream containing CO2.

A feed gas stream 100 is supplied to the system 102 of the present invention (FIGS. 1-3). The system 102 includes a compressor 104 to compress the gas stream and provide a compressed gas stream 106. Compressor 104 may also further comprise an after cooler to pre-cool the compressed gas stream 106. The system 102 includes one or more, for instance three, heat exchangers 108, 110, 112 for cooling the compressed gas stream. A cooled and compressed gas stream 114 is directed to a separator 116. The separator provides a gaseous stream 118 and a liquid phase stream 120.
The gaseous stream 118 may optionally be directed to the first heat exchanger 108 (FIG. 1) or the second heat exchanger (FIG. 2) for cooling the compressed gas stream.
The liquid phase stream 120 may optionally be directed to the second heat exchanger 110 (FIG. 1) or the first heat exchanger (FIG. 2) for further cooling the compressed gas stream.
In another embodiment, the first heat exchanger 108 may use air, or (sea) water 122 to pre-cool the compressed gas stream 106 (FIG. 3).
In another embodiment (FIG. 4), a multi-stream heat exchanger 109 may be used in place of heat exchangers 108 and 110.
The respective heat exchangers supply a gas phase stream 124 and/or liquid phase stream 126 having an increased temperature relative to streams 118, 120. The pressure drop after the heat exchangers is for instance in the order of 0.5 to 10 bar, typically in the order of 1 to 5 bar.
Separation of CO2, and possibly other contaminants such as H2S, from H2 and CO in a (shifted) synthesis gas stream is achieved by phase change. The composition of the synthesis gas stream may be adjusted using a shift reaction, such that the synthesis gas stream has a predetermined H2/CO ratio. The synthesis gas may then be compressed to a pressure that is required for injection of CO2 in a reservoir. The reservoir is for instance a subterranean reservoir, such as a (partially depleted) gas field and/or a sub-sea reservoir.
Synthesis gas comprises for instance about 25-35 mol % H2, 60-70 mol % CO, some CO2 and contaminants. Part of the CO is converted in a gas mixture comprising 50-60 mol % H2, 35-50 mol % CO2, and for instance some CO and H2S.
The synthesis gas is typically provided at a pressure in the range of 25 to 60 bar, say for instance about 35-40 bar or about 60 bar. This initial pressure is raised to about 100 to 200 bar, or preferably about 140 to 160 bar. The pressure drop after each heat exchanger is relatively small, in the range of about 0.5 to 5 bar.
After compressing the synthesis gas, the CO2 (and optionally the other contaminants) are removed by cooling down the compressed synthesis gas to a temperature at which the CO2 at least partially shifts to the liquid phase.
The cooling may be done in one or more steps, for instance three steps as shown in FIGS. 1 to 3. The product stream may be directed to a first and second heat exchanger respectively (FIGS. 1 and 2), to cool the compressed gas stream. To reach the predetermined target temperature for separating CO2, a third heat exchanger using additional cooling power may be included. The third heat exchanger may use for instance ethane and/or propane as refrigerant. The cooling power required from the third heat exchanger can be diminished with for instance about 40 to 60% by using the latent cold of the product streams to cool the compressed gas.
FIG. 4 shows an alternative embodiment in which a feed gas stream 100 is supplied to compressor 104. However, in the embodiment shown in FIG. 4, a multi-stream heat exchanger 109 is used that performs the function of heat exchangers 108 and 110. The heat exchanger 109 may also use additional propane from an external cooling system as additional refrigerant, to minimise the size of heat exchanger 112.
Alternatively, as shown in FIG. 5, a feed gas stream 100 is also supplied to compressor 104; however, the compressed gas stream 106 is split into at least two separate streams 106A and 106B. In this embodiment, heat exchangers 108 and 110 are arranged in parallel and streams 106A and 106B are fed into heat exchanger 108 and 110, respectively. The cooled and compressed output streams are then recombined and directed to separator 116 via the heat exchanger 112. The separator 116 provides a gaseous stream 118 and a liquid stream 120. Although two streams 106A and 106B are shown in FIG. 5, if desired, the compressed gas stream 106 may be split into more than two streams and fed into the respective number of heat exchangers.
The gaseous stream 118 in FIG. 4 may optionally be directed to the multi-stream exchanger 109 or, in the embodiment of FIG. 5, to first heat exchanger 108 or the second heat exchanger 110 for cooling the compressed gas stream; similarly, the liquid phase stream 120 may optionally be directed to the second heat exchanger 110 or the first heat exchanger 108 for further cooling the compressed gas stream in the case of the embodiment of FIG. 5 or to multi-stream heat exchanger 109 in the case of the embodiment of FIG. 4.
The embodiments shown in FIGS. 4 and 5 allow heat exchanger 112 to be made smaller thus achieving savings in capital costs and energy usage. The embodiment shown in FIG. 4 is preferred.
The system shown in FIGS. 1-5 removes 75% to 80% of the CO2 from the feed gas stream 100. If an even greater level of CO2 removal is desired, a further treatment of gas phase stream 124 may be performed, using for example commercially available CO2 removal processes, such as absorption processes using physical solvent or amine solvents, or adsorption processes using pressure swing or temperature swing regeneration. Such further treatment results in the removal of up to 100% of the CO2 from the feed gas stream. Also, as shown in FIGS. 4 and 5, an expander 125 may be used to provide power recovery and additional cooling of gas phase stream 124, if desired, which may be applied in heat exchanger 109 (FIG. 4) or heat exchanger 110 (FIG. 5) for additional cooling of stream 106.
FIG. 6 shows an exemplary phase diagram of synthesis gas having a certain composition. The x-axis indicates temperature T (in ° C.) and the y-axis indicates pressure P (in bar). The separate phases are indicated with liquid L, vapour V, gas G, solid S, and respective mixtures thereof (GL, VL, GS, VS). Lines 400, 402 indicate boundaries of the respective phase mixtures. Gaseous phase as used herein refers to gas as well as vapour.
As indicated by arrows 406, 408, the gas stream is for example cooled to a temperature within the range of about −30 to −60° C. to obtain a mixture that is partly comprised of gas or vapour, and partly of liquid. In a preferred embodiment, the gas is cooled to about −55° C.
The method and system of the present invention can capture a larger percentage of the CO2 in a single process step. This can be recognized using the following, non-limiting example. A triple point will for instance be at about a pressure of 15 bar, and temperature of −55° C. The partial pressure p_iof component i of the gas relates to the total pressure P, molar percentage y_i, volume percentage x_i, and pressure of the volume percentage P_i ^vas:
p _i =y _i P=x _i P _i ^v (1)
The CO2 capture rate η_CO2at the downstream end can hence be formulated as:
$\begin{matrix} η_{CO 2} = 1 - \frac{y_{CO 2}^{down} (1 - y_{CO 2}^{up})}{y_{CO 2}^{up} (1 - y_{CO 2}^{down})} = 1 - \frac{P_{CO 2}^{v, down} \times (1 - y_{CO 2}^{up})}{y_{CO 2}^{up} P \times (1 - \frac{P_{CO 2}^{v, down}}{P})} & (2) \end{matrix}$
wherein down and up indicate the respective values at the downstream and upstream side of the system respectively.
At an operating pressure P of for instance 150 bar, the CO2 capture may be in the order of 90 mol % (for ideal gas):
$\begin{matrix} 1 - \frac{10 \times (1 - 0.35)}{0.35 \times 150 \times (1 - \frac{10}{150})} = 0.9 & (3) \\ as P_{CO 2}^{v, down} = y_{CO 2}^{down} \times P (with x_{CO 2} \approx 1, and y_{CO 2}^{down} \approx 0.07) . \end{matrix}$
Compressing the gas stream to a pressure in the order of 100 to 200 bar provides preferable results, combining a relatively high CO2 mol % in the liquid phase product stream with relatively limited overall costs.
The feed synthesis gas is for instance supplied, preferably after shifting the gas using a water gas shift reaction. The shifted synthesis gas comprises mainly H2 and CO2, for instance in the order of 40-45 mol % CO2, 50-55 mol % H2. In addition, the shifted synthesis gas includes for instance about 2 mol % CO and/or 1 mol % H2S. The synthesis gas supplied to the process of the present invention has for instance an initial temperature in the range of 45 to 55° C., and/or an initial pressure in the order of 35 to 40 bar.
The gaseous product stream may include for instance 8 to 14 mol % CO2, 2-5 mol % CO, 85-95 mol % H2, and/or <0.5 mol % H2S.
The liquid phase product stream may include about 90 to 98 mol % CO2, <5 mol % H2, and/or <1 mol % CO.
In a practical embodiment, it is proposed to cool the synthesis gas in two or three stages, as indicated in FIGS. 1 to 5. A refrigeration machine, using for instance ethane and/or propane as working fluid, may be included in one or more stages. If the refrigeration machine is for instance used in the last step, the final cooling device may operate at for instance 0.25 MW/kg CO2. Herein, kg CO2 indicates a kilogram of CO2 in the liquid phase stream.
The cold, H2 rich gas phase stream and/or the CO2 rich liquid phase stream may be directed to one of the heat exchangers—for instance to the first and/or second heat exchanger to provide another part of the required duty, for instance about 0.21 MW/kg CO2. The compressed gas stream 106 may be thus cooled in subsequent steps, to for instance 1-10° C. after the first heat exchanger 108, −15 to −25° C. after the second heat exchanger 110, and/or −55 to −30° C. after the third heat exchanger 112.
The separation technology used is not critical to the method of the invention and conveniently a proven gas/liquid separation technology may be used to capture the liquid CO2 droplets. Such technology includes for instance a demister mat or vane pack as used in an interstage cooler of a compressor, a swirl tube or cyclone.
The product streams are supplied at pressures and temperatures that are suitable for further practical use, possibly without further treatment. Overall, the method and device of the present invention provide an efficient and cost effective improvement for removing CO2 from a gas stream. Also, the gaseous product stream, comprising a relatively high mol % H2, for instance about or more than 90 mol % H2, can be readily used in subsequent process steps. These process steps include for instance fuelling a generator for generating electricity. The H2 rich stream may also be directed to a refinery, to introduce the stream in a hydrotreater or hydrocracker, or similar devices for reducing the length of hydrocarbons.
The method and system of the present invention are specifically suited to capture CO2 from a synthesis gas stream or a flue gas stream. The method seems unsuitable for treating natural gas, as a significant fraction of the methane would condense together with the CO2 upon pressurizing and cooling the gas. The synthesis gas or flue gas lack methane but include H2 or N2 respectively. The latter will not condense at the pressures and temperatures involved in the method of the invention. In addition, cooling synthesis gas or flue gas according to the method of the invention turns out to be more efficient than cooling by expansion. On the contrary, natural gas can be more effectively cooled by expansion to relatively low pressures, below 35 bar.
Above, pressure is expressed in the unit bar. Bar herein indicates bar abs.
The above-described embodiments of the invention are intended as non-limiting. Many modifications thereof are conceivable within the scope of the appended claims.

Claims

1. A method for separating CO₂from a synthesis gas stream or flue gas stream, the method comprising the steps of:

providing a gas stream at a initial pressure and initial temperature;

compressing the gas stream;

cooling the compressed gas stream, wherein the compressed and cooled gas stream has an increased pressure and reduced temperature at which the CO₂in the gas stream is at least partially converted to the liquid phase; and

separating the liquid phase from the compressed and cooled gas stream, to provide a liquid phase stream and a gas phase stream at an output pressure,

wherein the output pressure of the liquid phase stream is higher than the initial pressure of the gas stream.

2. The method of claim 1, wherein the initial pressure is in the range of 20 to 65 bar.

3. The method of claim 2, wherein the output pressure of the liquid phase stream is above 75 bar.

4. The method of claim 2, wherein the output pressure of the liquid phase stream is in the range of 100 to 200 bar.

5. The method of claim 4, wherein the output pressure is in the range of about 140 to 160 bar.

6. The method of claim 5, further comprising the steps of:

directing the liquid phase stream and the gas phase stream to one or more heat exchangers for cooling the compressed gas stream.

7. The method of claim 6,

wherein the step of providing the gas stream includes:

providing a synthesis gas stream; and

subjecting the synthesis gas stream to a water shift reaction, to provide a treated synthesis gas stream having an increased H₂and/or CO₂content.

8. The method of claim 7, wherein the output pressure of the gaseous phase is substantially equal to the output pressure of the liquid phase.

9. The method of claim 8, wherein the cooling of the compressed gas stream is at least partially performed in a multi-stream heat exchanger.

10. The method of claim 8, wherein the compressed gas stream is split into at least two streams and the cooling of each of the split compressed gas streams is at least partially performed in separate heat exchangers arranged in parallel.

11. A system for separating CO₂from a gas stream containing CO₂, the system comprising:

a compressor for compressing the gas stream having an initial pressure and an initial temperature;

at least one cooling device for cooling the compressed gas stream, wherein the compressed and cooled gas stream has a pressure and temperature at which the CO₂in the gas stream is at least partially converted to the liquid phase; and

a separator for separating the compressed and cooled synthesis gas stream in a liquid phase stream and a gas phase stream at an output pressure,

12. The system of claim 11, further comprising:

a first heat exchanger, wherein the liquid phase stream is directed to the first heat exchanger for cooling the compressed gas stream.

13. The system of claim 12, further comprising:

a second heat exchanger, wherein the gas phase stream is directed to the second heat exchanger for cooling the compressed gas stream.

14. The system of claim 13, wherein the separator comprises a cyclone, a swirl tube, and/or a demister mat.