KR101312914B1 - Carbon dioxide recovery - Google Patents

Abstract

The methods and systems disclosed herein are for separating carbon dioxide (CO2) from a CO2 containing gas stream comprising water vapor and additional impurities such as nitrogen, oxygen, nitrogen oxides, sulfur oxides and mercury. The CO 2 is captured by passing the CO 2 gas feed stream through a temperature swing adsorption step. The temperature swing adsorption step includes an adsorption step to produce a nearly dry CO 2 depleted stream, and an adsorbent regeneration step of heating the adsorbent bed to produce a nearly water vapor-free carbon dioxide stream. Moisture removal from the CO2 containing gas stream is selectively removed by pressure swing adsorption, temperature swing adsorption, thin film separation or absorption prior to CO2 capture.

Description

Carbon dioxide recovery method {CARBON DIOXIDE RECOVERY}

1. This application claims the benefit of priority “Process For Carbon Dioxide Recovery” of US Provisional Patent Application No. 61 / 123,259, filed April 7, 2008, with US Patent Office.

2. The following patent application is incorporated in its entirety: US Pat. Appl. No. 12 / 419,513, filed April 7, 2009, entitled " Carbon Dioxide Recovery ".

The present invention relates to a method and system for capturing carbon dioxide (CO2) from a combustion source such as flue gas in a power plant and making the carbon dioxide available for use in metal ion sequestration or other applications. .

 Greenhouse gas emissions, such as CO2, can have a potential impact on the climatic environment if left uncontrolled. The conversion of fossil fuels such as coal or natural gas into energy is a major source of greenhouse gas emissions. The emission of greenhouse gases can be reduced by various means, for example, by increasing the efficiency of the combustion process and by utilizing alternative energy sources such as wind and solar, but the reduction of greenhouse gas emissions required to stabilize greenhouse gas levels can be reduced. It cannot be achieved without capturing a significant amount of greenhouse gas at the source of the greenhouse gas emissions during the pre- or post-combustion process. Post-combustion capture of CO2 from a stream, such as flue gas from a power plant or flue gas from a refinery, involves the use of a solvent, typically an amine, which is regenerated by utilizing a portion of the steam produced during the combustion process. do. Pre-combustion capture of CO2 involves the chemical reaction of fuel with air or oxygen and the reaction of steam, producing a carbon dioxide and hydrogen mixture. Carbon dioxide is removed from this stream through the CO2 capture process, and hydrogen is used as fuel for power generation. If oxygen is used for combustion, a flue gas mainly containing carbon dioxide is produced, which can be easily separated for metal ion containment.

 Post-combustion capture of CO2 results in a 9% -11% reduction in absolute efficiency in power generation and an approximate 28-30% decrease in relative efficiency in pulverized coal plants, which is suggested by Ciferno (Ciferno, J., "A Feasibility Study of Carbon Dioxide Capture from an Existing CO₂al-Fired Power Plant," paper presented at the Sixth Annual CO₂nference on Carbon Capture and Sequestration, Pittsburgh, PA, May 2007). NETL's May 2007 report (Carbon Sequestration Technology Roadmap and Program Plan-2007, USDOE National Energy Technology CO2 Purification System (125) aboratory (NETL), May 2007) was developed for CO2 separation and metal ion containment for existing plants. Considering capital and operating costs, he points out that a 60-100% increase in power generation costs is required. Actual power output from the plant is also reduced by more than 30%. Means have been taken to significantly reduce power generation and capital losses associated with such post-combustion CO2 capture. For post-combustion capture, the DOE aims to achieve an increase of less than 35% in power generation costs for 90% CO2 capture.

Most studies involving post-combustion CO2 capture use amine or ammonia based adsorption processes to remove carbon dioxide from flue gases. Such adsorption-based processes have defects that require significant investment costs. The best amine-based adsorbents are such as hindered amines and amine blends and require energy in the range of 750-900 Kcal / kg (1,350-1,620 Btu / lb) of CO2 being captured. Amine-based processes also require the use of special iron equipment and the associated investment costs, due to the corrosion properties of amine and ammonia solutions containing acid gases and oxygen. Such devices require significant investment costs.

Unlike amine-based systems, the heat of CO2 adsorption on various zeolite and carbon-based adsorbents ranges between 140-240 Kcal / kg or 252-432 Btu / lb (Valenzuela, DP and AL Myers, Adsorption Equilibrium Data Handbook, Prentice Hall, Englewood Cliffs, NJ, 1989), which is roughly 1/5 the heat of adsorption of amine base systems. There is an unsatisfactory requirement in the art for substantial adsorption systems that benefit from low heat of adsorption while providing high carbon dioxide yield and high recovery effects.

Temperature swing adsorption systems have been used in a variety of applications such as air drying, natural gas drying, water and CO2 removal prior to cryogenic distillation of air. Such a system typically removes up to 2% of impurities and the regeneration exhaust stream containing impurities is not high purity. Typical temperature change adsorption processes also have an adsorption time of approximately 4-12 hours. This adsorption time requires a very large adsorption bed to provide a CO2 concentration between 10-12% in the flue gas. For example, assuming a 12 wt% working capacity (capacity difference between adsorption and regeneration stages), an adsorption concentration of approximately 660 kgs / m 3 and an adsorption time of 4 hours, the feed side treats 1000 tonnes / day of CO 2. The plant requires approximately 8,000 m 3 of adsorbent (5.300,000 kgs), and the size of building such a system is not practical for capturing carbon dioxide from combustion sources.

The present invention discloses a method and system for providing a solution for efficient CO2 capture using a process based on temperature and pressure swing adsorption cycles.

This Summary is intended to introduce the concepts of the invention in a simplified form and will be described in more detail in the Detailed Description section that follows. This Summary is not intended to identify key or essential inventive concepts of the subject matter of the present invention, nor is it intended to determine the scope of the claimed subject matter.

The methods and systems disclosed herein solve the problems described above for separating carbon dioxide (CO2) from a gas stream comprising water vapor and additional impurities. The method and system of the present invention capture CO2 using a process based on temperature and pressure swing adsorption cycles. The gas is flue gas from coal fired power plants, natural gas fired power plants or refineries.

High purity CO2, ie CO2 containing less than about 10% by volume of impurities, is obtained by passing the CO2 gas stream in a temperature swing adsorption step. The temperature swing adsorption step includes an adsorption step for generating a nearly dry CO 2 depleted stream and an adsorbent regeneration step for heating the adsorbent bed to produce a CO 2 flow that is substantially free of water vapor. During the adsorbent regeneration step, the temperature in the temperature swing adsorption step is raised to approximately 80 ° C to 300 ° C. The duration of the temperature swing adsorption step is in the range of approximately 2 to 60 minutes.

The adsorption action is generally carried out in a gaseous state of temperature 10 ° C. to 80 ° C. and absolute pressure of approximately 1.07 to 40.0 bar. The CO 2 concentration is in the range of approximately 3% to 60% by volume.

Impurities preferably removed from the CO2 containing gas stream are selected from the group comprising, for example, nitrogen, oxygen, hydrocarbons, nitrogen oxides, sulfur oxides, mercury and argon. This adsorption action is carried out in a bed containing adsorbent material, which preferentially adsorbs or reacts with CO2 in the gas stream.

In one embodiment, impurities including, for example, water, hydrocarbons, nitrogen oxides, sulfur oxides and mercury are removed prior to CO 2 adsorption. Moisture removal is carried out using, for example, pressure swing adsorption, temperature swing adsorption, thin film separation and absorption. The duration of the pressure swing adsorption process is in the range of approximately 4 minutes to 60 minutes, and the duration of the temperature swing adsorption process is in the range of approximately 1 hour to 12.0 hours. The water content in the water removal step is lowered to a dew point of -40 ° C or less. Adsorbents, for example activated carbon, carbon molecular filter, zeolites such as 4A, 5A, 13X, NaY and CaX, metallorganic framework compounds, natural zeolites, modified natural and artificial zeolites, modified Activated carbon and pillared clays are used for CO2 adsorption. The stream of CO2 removed from the CO2 adsorption unit is used for regeneration of the water adsorption system.

In another embodiment, a water-containing feed stream is sent directly to the CO 2 adsorption system, from which sodium and potassium carbonates, amines or ions are supported, on which CO 2 is supported on activated carbon or microporous supports. It is removed by chemical reaction with the liquid.

In these two embodiments, the material containing CO 2 is regenerated by direct or indirect heat transfer to produce a high purity CO 2 flow. CO2 removal is also achieved by bed evacuation after heating. The CO 2 produced is further purified through a thin film process, a distillation process, an adsorption process or a getter process to remove impurities such as nitrogen, oxygen, argon, nitrogen oxides, sulfur oxides, and water. Part of the purified CO2 can be used as a rinse in the CO2 separation system.

The method and system of the present invention are effective at removing approximately 80% or more on a volume basis of impurities from the CO2 flow.

The above summary of the present invention can be better understood by reading the following description with reference to the accompanying drawings in conjunction with the following detailed description. For the purpose of illustrating the invention, exemplary configurations of the invention are set forth in the accompanying drawings. However, the present invention is not limited to the specific methods and means described herein.
1 is a schematic diagram of a carbon dioxide (CO2) separation system for recovering high purity CO2 from a feed stream containing CO2.
2A-2D illustrate various exemplary configurations of a CO 2 separation system in which water is selectively removed in a first separation unit followed by capture of CO 2 by chemical reaction or adsorption in the second separation unit.
FIG. 3 illustrates various exemplary configurations of a water adsorption system in which water and additional impurities, such as hydrocarbons, sulfur oxides or nitrogen oxides and mercury, etc., are removed by the combined action of pressure and temperature swing adsorption. .
4 shows various exemplary configurations of a CO 2 separation system, in which CO 2 is removed from the feed stream by adsorption or chemical reaction and is directly and indirectly by steam, hot water or dry flow recovered from the CO 2 separation system. Recovered by heating.

1 is an overall configuration diagram of a carbon dioxide (CO2) separation system 80 for recovering high purity CO2 from a feed stream containing CO2. Such CO2 is produced in one process (5), which is a combustion process or another process that generates CO2. If process 5 is a combustion process, an oxygen rich stream 10 is optionally used during the combustion to improve combustion efficiency and to increase the concentration of CO2 resulting from combustion. By utilizing the thermal regeneration in the process (5), steam can be generated as the stream (15). A portion of the stream 15 is separated as stream 20 and utilized in the CO 2 separation system 80 described later. The remainder of the stream 15 is obtained as stream 25 and may be used for other purposes, for example for power generation, or for syngas production in unit 30. Flow 35, low pressure flow or hot water in unit 30 may be used in CO 2 separation system 80, or may be sent to unit 5 to produce steam. A portion of the power generated at unit 30 may be sent to CO2 separation system 80 via line 45. The remaining power may be supplied via line 50 to end users, ie industrial and residential consumers. A CO2 containing stream, such as flue gas, exits process (5) as stream (55).

After removing the particulates, the stream 55 is optionally sent to a feed control unit 60 to remove impurities such as nitrogen oxides, sulfur oxides and mercury. The pressure of the flow 55, including residual sulfur and nitrogen oxides, mercury, nitrogen, oxygen, argon, etc. as the main impurities, may be raised by the fan or blower 65 after the unit 60, if necessary. . If the CO2 containing stream is from a chemical plant or refinery, or from a pre-combustion process, the CO2 containing stream may include additional impurities such as hydrogen, hydrocarbons and carbon monoxide. In coal or natural gas power plants, the pressure of the flue gas can typically be raised from approximately 1.07 bar to 1.34 bar absolute pressure. The CO2 flow produced in a chemical or industrial process may or may not be higher than its absolute pressure of 1.07-1.34 bar. In a gasification process in which fuel is gasified with air or oxygen, the pressure of the stream containing CO 2 may be several times the atmospheric pressure, and may not be as high as that. In the oxygen combustion process, flue gas can be reused in the combustion system to increase the concentration of CO2. After the removal of nitrogen oxides, sulfur oxides and mercury, and the compressed state, the CO 2 -containing stream is cooled to a temperature range typically between ambient temperature and 60 ° C. before CO 2 capture. The flue gas cooling unit is not shown in FIG. 1. Many power plants have systems for removing particulates, nitrogen oxides and sulfur oxides. Such a system may include a selective reduction catalyst (SCR) for nitrogen oxides, an electrostatic precipitator for particulates and a wet dust collector for sulfur oxides. Removal of particulates, nitrogen oxides and sulfur oxides may be unnecessary if the flow 55 comes from a partial oxidation or reforming process.

The CO2 containing stream exits unit 65 as stream 70 and enters the CO2 separation system 80. The CO2 separation system 80 includes at least one bed, which has a material that removes CO2 from the feed stream by adsorption or chemical reaction. The pressure of the bed is an absolute pressure of approximately 1.07 to 40.0 bar.

Depending on the material used to capture CO 2, the CO 2 separation system 80 includes additional units to remove other components in the feed stream, such as moisture, residual sulfur oxides, nitrogen oxides and mercury. can do. If materials such as activated carbon or potassium carbonate, the amine or ionic liquid on the microporous support is used for CO2 removal and the moisture in the feed stream 70 does not need to be removed, and CO2 exiting the CO2 separation system 80. The depleted stream 85 contains most of the moisture contained in the stream 70. In such a case, the flow 85 may exit. However, if a material such as zeolite is used to capture CO 2 by adsorption, the moisture from feed stream 70 must be removed prior to CO 2 adsorption and the CO 2 removed stream 85 will be relatively dry. In such a case, stream 95, which is part or all of stream 85, may be used to regenerate the water adsorption system 79.

CO2 captured in the CO2 separation system 80 is recovered by desorbing the CO2. The energy required for CO2 desorption may be provided by flow 20, flow 35, or by electricity represented by flow 45. Other external heat and electricity sources may be used for material recovery in the CO2 separation system 80. The adsorbents or reactants can be in direct contact with the flow or condensate if the material can withstand it. The material in the CO 2 separation system 80 may be regenerated by a stream 85 in which the dried CO 2 is removed, which is heated by steam, hot water or electricity. If the adsorbent material is not water tolerant, the adsorbent bed must be indirectly heated by steam or hot water. Typically, the regeneration of the moisture adsorbent material and the CO 2 adsorption material in the CO 2 separation system 80 is performed in parallel to ensure that the CO 2 exiting the CO 2 separation system 80 is reliably dried. In addition to heating, a vacuum pump may be used to remove CO2 from the CO2 separation system 80. The flow used for regeneration is shown as flow 90 in FIG. 1. More than 80% of the impurities are typically removed in the CO2 separation.

The desorbed CO 2 exits the CO 2 separation system 80 through line 105 and is sent to the CO 2 purification system 125. An optional vacuum pump 110 is used to facilitate the recovery of CO2 from the CO2 separation system 80. A portion of the CO2 product enters vacuum pump 110 as stream 100, merges with stream 105, and exits vacuum pump 110. The flow exiting the flow 105 and the vacuum pump 110 merges with each other to form a CO 2 production flow and enters the CO 2 purification system 125 as a flow 120. The purity of the CO2 production stream 120 produced during the regeneration process depends on the feed CO2 concentration, but is typically higher than 90%. This stream 120 is optionally compressed and maintained at an absolute pressure of 1.1 bar to 200 bar before purification. The CO2 purification system 125 may consist of, for example, a distillation system, a thin film system, a pressure or temperature swing adsorption system or a getter system to remove even small amounts of impurities such as nitrogen, oxygen, nitrogen oxides and sulfur oxides from CO2. Let's do it. And, if the CO2 flow exiting the CO2 separation system 80 is wet, moisture is also removed. The purified CO2 exits from the CO2 purification system 125 as stream 130. Flow 135 is a small portion of flow 120 and can be used to remove inert portion in CO2 separation system 80 using flow 115 or flow 130. This stream 135 enters the CO2 separation system 80 as stream 145. The purified CO2 product exits the CO2 purification system 125 as stream 140 and can be used in food or beverage applications, industrial applications, high quality oil and gas recovery processes, and metal ion containment. The CO2 product stream 140 may be compressed, liquefied, or both, before being used in some such applications.

2A-2D illustrate various exemplary configurations of a CO 2 separation system 80 in which moisture is selectively removed in a first separation unit followed by capture of CO 2 by chemical reaction or adsorption in a second separation unit. This is done.

In FIG. 2A, wet CO 2 flow 70 passes through the bed material, where in the presence of moisture, CO 2 is adsorbed or reacted. The adsorption or chemical reaction system comprises at least two beds, at least one of which removes CO 2 from the feed stream, at least one of which realizes regeneration at any time. As described later in connection with FIG. 4, additional beds may be used for other steps, such as cooling, pressurization, rinse and evacuation. The cleaning step can be accomplished using a relatively pure CO 2 flow 145. As shown in FIG. 1, the CO2 production stream exits the CO2 separation system 80 as a flow 105 and additional optional flow 100.

In FIG. 2B, wet CO2 flow 70 passes through the thin film dryer 71 where moisture is removed from the feed stream. The dried feed stream 72 is sent to an adsorption or reaction bed 81 where CO 2 is removed from the feed stream and a dried, CO 2 removed stream 85 exits the CO 2 separation system 80. While CO2 is adsorbed, at least one other bed 81 is regenerated using stream 90. As in the case of Figure 2A, additional beds may be used in other stages, such as cooling, pressurization, cleaning and evacuation. A portion or all of the flow 85 is taken as the flow 95 and used to drain the penetrating moisture in the thin film dryer 71. The flow, including moisture, exits the thin film dryer 71 as a flow 73. An optional vacuum pump 74 may be used to increase the driving force across the membrane and to facilitate moisture removal, wherein the water-containing flow exits the vacuum pump 74 as a flow 75.

In FIG. 2C, wet CO2 flow 70 passes through absorption system 76 where water is removed from the feed stream by an absorbent such as ethylene glycol. Beds used for water removal typically include a dumped or structural packing for mass transfer between the feed stream and the absorbent, and the flows typically flow in countercurrent directions. The dried feed stream 72 exiting the absorption system 76 is sent to a CO2 adsorption bed 81 where CO2 is removed from the feed stream, and the dried CO2 removal stream 85 passes the CO2 separation system 80. Exit While CO2 is absorbed, at least one other bed 81 is regenerated using flow 90. Additional beds may be used for other steps such as cooling, pressurization, cleaning and evacuation. A solvent 85, which is part or all of the CO2 removal stream, is obtained as stream 95, heated in a heat exchanger or heater 96, passed through absorption system 76 as stream 97, and contains moisture. Regenerate flow 77. The moisture-containing solvent may be regenerated through countercurrent heat exchange in a heat exchanger (not shown) to which steam is supplied. The regenerated solvent stream 78 is directed to an absorption system 76 for water removal. This flow 95 can be heated by a heat exchanger provided with steam or condensate, and the flow 95 can be directly heated using electrical energy. The moisture-containing stream exits absorption system 76 as stream 75.

In FIG. 2D, the wet CO2 flow 70 is passed to a water adsorption system 79 where water from the feed stream is removed by an adsorbent such as activated alumina, silica gel or molecular filters. The dried feed stream 72 exiting the moisture adsorption system 79 is sent to a CO2 adsorption bed 81 where CO2 is removed from the feed stream and the dried CO2 removal stream 85 is a CO2 separation system (80). Exit) While CO2 is removed in one or more CO2 adsorption beds 81, at least one other CO2 adsorption bed 81 is regenerated using flow 90. Additional beds may be used for other steps where the beds are cooled, pressurized, cleaned, and introduced. Some or all of the flow 85 is obtained as the flow 95, optionally heated in a heat exchanger or heater 96, and used to regenerate moisture adsorption beds in the moisture adsorption system 79. If the stream 95 is heated prior to the regeneration of the moisture adsorption bed, this stream 95 may be heated by a heat exchanger provided with steam or hot water. Flow 95 may be directly heated using electrical energy. The moisture-containing stream exits the moisture adsorption system 79 as stream 73. An optional vacuum pump 74 may be used to provide additional driving force for water removal, and the moisture-containing flow then exits the vacuum pump 74 as a flow 75.

The water adsorption system 79 typically includes a plurality of water adsorption beds to remove levels and other impurities, such as heavy hydrocarbons that may interfere with the adsorption of CO2 in the CO2 adsorption bed 81. Let's do it. The moisture adsorption beds in the moisture adsorption system 79 may be designed to remove some ring oxides, nitrogen oxides, mercury impurities, and the like in the feed stream. For moisture removal, the moisture adsorption beds in the moisture adsorption system 79 are typically operated in a pressure swing, temperature swing or vacuum swing mode. For pressure or vacuum swing adsorption, the heat of moisture adsorption is maintained during the adsorption, and at lower pressures the stream 95 desorbs the moisture. Water may be removed by pressure swing adsorption alone, but the use of temperature swing adsorption may be necessary to desorb other impurities such as heavy hydrocarbons, sulfur oxides, nitrogen oxides and mercury. This operation can be done as a cycle comprising three or more beds, which will be described later.

FIG. 3 shows an exemplary configuration of a water adsorption system 79, wherein water and additional impurities, such as hydrocarbons, sulfur oxides or nitrogen oxides and mercury, are employed in the combined action of pressure and temperature swing adsorption. Is removed. A three bed pressure and temperature swing adsorption system is used for the removal of moisture and other impurities and is shown in FIG. 3. However, water and trace impurity removal processes are not limited to these three bed systems. If removal of impurities such as sulfur oxides and hydrocarbons is not required, two beds operating in pressure swing adsorption (PSA), vacuum swing adsorption (VSA) or temperature swing adsorption (TSA) modes can be used. Also when the system is operating in PSA and TSA, or VSA and TSA modes, two or more beds may be used for PSA or VSA operation, and one or more beds may be used for TSA operation. The number of water adsorption beds in the water adsorption system 79 is not essential to the operation of such a process. In the system shown in FIG. 3, the wet feed stream enters the water adsorption system 79 as a flow 70 through valves 200, 210 and 220, respectively. These valves 200, 210 and 220 control the feed gas flow into the vessels 230, 235 and 240, respectively. The vessels 230, 235 and 240 each have a first adsorbent layer 230a, 235a and 240a, respectively, and are molecules such as activated alumina, silica gel or 3A, 4A, 5A and 13X zeolites. It is used to remove moisture including adsorbents such as filters. Located above layers 230a, 235a and 240a in vessels 230, 235 and 240 are optional layers 230b, 235b and 240b, respectively, with hydrocarbons , Adsorbents selective to nitrogen and sulfur oxides and mercury. Adsorbents such as activated carbon, zeolites such as 13X, and saturated alumina can be used to adsorb these impurities. Modified activated carbons and silicates can be used to remove mercury impurities. Adsorbents in vessels 230, 235 and 240 are selected to minimize the adsorption of CO 2 to maximize the recovery of CO 2 in the CO 2 adsorption bed 81. Preferred adsorbents for water removal are 3A and 4A zeolites, activated alumina, silica gel and mixtures of activated alumina and zeolites 3A and 4A.

The outlet ends of the vessels 230, 235, and 240 are connected to an outlet piping having valves 245, 260, and 275, respectively. Depending on the bed undergoing adsorption, the dried CO2 containing stream exits the water adsorption system 79 as stream 72 through one of these valves 245 and is sent to the CO2 separation system 80. A purge stream 95 from the CO2 separation system 80 is used to regenerate the moisture adsorption beds. For the PSA or VSA mode of regeneration, purge gas 95 enters through valve 290 and any one of these valves 250, 265 and 280, and the corresponding valves 205, 215 and ( 225 exits the water adsorption system 79 as a flow 73. If an optional vacuum pump 74 is used, the purge gas 95 exits the water adsorption system 79 as a flow 75. For the TSA mode of regeneration, purge gas 95 is heated in heater or heat exchanger 96 and vessel 230, 235 through any one of open valves 255, 270 and 285. ) And 240, and exit the water adsorption system 79 through corresponding valves 205, 215, and 225. If vacuum pump 74 is not used, purge gas 95 exits water adsorption system 79 as stream 73. If vacuum pump 74 is used, purge gas 95 exits water adsorption system 79 as flow 75. In normal operation, one of the containers is regenerated through PSA or VSA, and the other is regenerated by TSA.

Various layers may be contained as shown in single containers, and if necessary, each layer may be contained in separate containers. The duration of each termination cycle of the PSA stage is at most several minutes (mins), typically 4-60 minutes, and the duration of thermal regeneration is generally approximately 1-12 hours; Thus, during any single step of this process, the two vessels in PSA or VSA mode will go through many PSA or VSA cycles, while the third vessel will go through one thermal regeneration step. For illustrative purposes, it is assumed that the PSA or VSA process is run during the adsorption step with pressurization above atmospheric pressure and with reduced pressure at atmospheric pressure or below during the bed regeneration step. The pressure in the vessel undergoing thermal regeneration is maintained at or near atmospheric pressure.

The process described below comprises three steps; The first step involves vessels 230 and 235 initially operating PSA or VSA cycles alternately, and the adsorbent in vessel 240 undergoes thermal regeneration; The second step involves vessels 235 and 240 alternately operating PSA or VSA cycles, and the adsorbent in vessel 230 undergoes thermal regeneration; In a third step, vessels 230 and 240 initially operate PSA or VSA cycles alternately, and the adsorbent in vessel 235 undergoes thermal regeneration.

At the time point 1 of the first step of the process, one of the vessels 230 or 235, for example, the vessel 230 is in adsorption mode and the other vessel is in regeneration mode. When vessel 230 starts in adsorption mode, wet feed stream 70 enters bed through open valve 200 and exits bed through open valve 245. Prior to initiation of adsorption, vessel 230 is pressurized to adsorption pressure through valve 200. As feed stream 70 passes through vessel 230, almost all water vapor, hydrocarbons, sulfur oxides and mercury and some nitrogen oxides are removed. The dew point of the gas stream leaving the water adsorption system 79 is typically -40 ° C, more preferably -60 ° C. For regeneration of bed 235, a portion of purge gas 95 enters through open valves 290 and 265, withdraws water from adsorbent bed 235 and exits through valve 215. Although not required, the purge gas may be heated before being used in a PSA or VSA process. The remainder of the purge gas entering the moisture adsorption system 79 is heated in the heater or heat exchanger 96 and flows through the layers 240a and 240b of the vessel 240. When heated purge gas flows through layers 240a and 240b in vessel 240, the purge gas desorbs residual moisture, hydrocarbons, nitrogen, sulfur oxides, and mercury from other layers. Gradually accumulated in vessel 240 during previous PSA and VSA steps performed in the vessel. The regeneration gas exits the container 240 through open valves 225 with desorbed impurities. After any time, typically 4 to 60 minutes, based on the moisture concentration in the stream 72 and the retention heat distribution in the bed, the vessel 230 begins regeneration and the vessel 235 removes moisture and other impurities. Initiate. Vessels 230 and 235 operate continuously for a period of time or days, typically 8 to 96 hours, under PSA and VSA operation, and vessel 240 is thermally regenerated during some of this time. . Temperatures for thermal regeneration typically range between 100 ° C. and 300 ° C. but may be higher or lower depending on the material. Impurities such as nitrogen oxides and sulfur oxides removed during thermal regeneration can be sent to existing nitrogen and sulfur removal systems for further removal of such impurities.

As the PSA and VSA cycles proceed in vessels 230 and 235, various impurities, such as sulfur oxides and mercury, are adsorbed more strongly than the water vapor accumulated in these vessels, which purge the pressure swing or vacuum swing adsorption. This is because it is not removed during the step. When the growth of these components in one or more layers reaches a point that adversely affects the efficiency of the gas stagnation process, the first step of the process ends and the second step begins.

During the second stage of the process, vessels 235 and 240 are alternately subjected to PSA and VSA operation and the adsorbents in vessel 230 perform thermal regeneration. At the time point 1 of this stage of the process, one of the vessels 235 or 240, for example, the vessel 235 is in adsorption mode and the other vessel is in regeneration mode. When vessel 235 starts in adsorption mode, wet feed stream 70 enters bed through open valve 210, exits bed through open valve 260, and is purified during the process. Prior to the start of adsorption, the vessel 235 is pressurized to the adsorption pressure through the valve 210. For regeneration of bed 240, a portion of purge gas 95 enters through open valves 290 and 280, withdraws water from adsorbent bed 240 and exits through open valve 225. . The remainder of the purge gas entering the moisture adsorption system 79 is heated in a heater or heat exchanger 96 and flows through the layers 230a and 230b of the vessel 230 to provide residual moisture, hydrocarbons, Desorbs nitrogen, sulfur oxides, and mercury from other layers, which are accumulated gradually in the vessel 230 during the previous PSA and VSA steps performed in this vessel 230. The regeneration gas exits the container 230 through open valves 205 with desorbed impurities. After any time based on the moisture concentration in flow 72 and the retention heat distribution in the vessel, vessel 235 begins regeneration and vessel 240 initiates the removal of moisture and other impurities. Vessels 235 and 240 alternately operate continuously for a period of hours or days under PSA or VSA operation, and vessel 230 is thermally regenerated during some of this time.

As the PSA and VSA cycles proceed in vessels 235 and 240, various impurities are adsorbed more strongly than the water vapor accumulated in these vessels 235 and 240. When the growth of these components in one or more layers reaches a point that adversely affects the efficiency of the gas stagnation process, the second step of the process ends and the third step begins.

During the third step of the process, vessels 230 and 240 are subjected to PSA or VSA operation and the adsorbents in vessel 235 perform thermal regeneration. The operation of the third stage is similar to that of the first and second stages. After all three steps have ended, the process starts again as step 1 and all three steps are repeated in a cyclic manner.

Like the PSA and VSA beds, the CO2 adsorption or reaction beds (beds A to E in FIG. 4) also undergo a circulating process to achieve continuous operation, maximizing CO2 recovery. Such beds include one or more materials that have a greater selectivity for CO2 than other components of the flue gas, such as oxygen, nitrogen and argon. Some materials that can be used to capture CO2 from flue gases include, for example, activated carbon, carbon molecular filters, zeolites such as 4A, 5A, 13X, NaY, and CaX, metallorganic framework compounds. Natural zeolites, modified natural and artificial zeolites, modified activated carbons, pillared clays and ionic liquids supported on reactive solvents such as sodium, potassium carbonate, amines or microporous supports. Include.

The various beds in the CO 2 capture shown in FIG. 4 typically undergo steps such as adsorption, equalization, cleaning with CO 2 products, heating, heating by evacuation, cooling and repressurization. Depending on the material and process conditions, different combinations of the above steps may be used to maximize CO 2 recovery. And during some cycles, some steps may be omitted, eg bed cooling. During operation of the CO2 adsorption bed 81, all sulfur oxide impurities in the feed stream directed to the CO2 capture are removed because most adsorbents have a higher affinity for sulfur oxides than CO2. Since most adsorbents have a higher affinity for CO2 than nitrogen oxides, most of the nitrogen oxide impurities in the feed stream directed to these captures pass into the CO2 depleted stream 85 exiting the CO2 separation system 80. . For the removal of CO2 by chemical reactions, for example by supported carbonates or amines, some nitrogen oxides and sulfur oxides can be removed by chemical reactions.

4 shows various exemplary configurations of a CO 2 separation system 80, where CO 2 is removed from the feed stream by adsorption or chemical reaction, and is recovered from steam, hot water or CO 2 separation system 80. Recovered by direct and indirect heating by dry flow. The five bed CO2 capture process is shown overall in FIG. 4. The CO2 supply step and the CO2 production step are performed continuously in this cycle. Although the CO2 capture is shown using five bed processes. The CO 2 capture process is not limited to five beds. This process can use less than five beds or more, and at least two beds are needed to carry out CO2 capture and production at the same time. As shown in FIG. 4, at any time, while one bed removes CO 2 from the feed stream through adsorption or reaction, the other bed performs an equalization and pressurization step, and the third bed undergoes CO 2 during heating. The fourth bed produces CO2 during the heating and evacuation step, and the fifth bed performs CO2 cleaning and equalization steps. Other similar cycles can be used by omitting steps such as CO2 cleaning and adding steps such as bed cooling after the heating step. The equalization process can be performed from the bottom, from the top or from both the top and the bottom. Pressurized processes can also be made from the bottom using a feed stream or from the top using a CO2 removal stream.

 Each individual step of the CO2 capture process takes place over approximately 2-60 minutes to maximize the productivity of the process. A typical cycle using the five bed configuration shown in FIG. 4 is shown in Table 1.

The feed flow to the adsorbers A to E typically maintains a pressure between a temperature of approximately 10 to 80 ° C. and an absolute pressure of approximately 1.07 bar to 40 bar and preferably a temperature of approximately 20 to 60 ° C. For CO2 capture from flue gas from a power plant or refinery, the pressure will be an absolute pressure of approximately 1.07-1.34 bar. The regeneration temperature is in the range of approximately 80 ° C to 300 ° C, more typically in the range of 80 ° C to 150 ° C. The CO2 concentration in the feed gas is approximately 3% for natural gas thermal power plants, approximately 12% for coal-fired power plants, and up to 60% for various chemical processes. Prior to the initial initiation of the CO 2 separation, the beds in the adsorbers A to E can be heated to a temperature above 300 ° C. to remove any residual moisture contained therein. A high temperature regeneration process may be performed to remove impurities generated during normal operation.

The operation of the various valves is shown using steps 1 and 2 of Table 1. In two steps 1 and 2 for bed A, feed gas 72 enters the bed through an open valve 302, in which CO2 is trapped, and the CO2 removal flow flows through open valve 312. Exit 85 as (85). During step 1, beds B and E undergo pressure equalization through open valves 340 and 430. During step 2, bed B is pressurized using bed A through open valves 320 and 350. During two steps 1 and 2, Bed C is regenerated by heating under vacuum and valve 366 is open. The high purity CO2 product exits as stream 100 and enters vacuum pump 110. During two stages 1 and 2, Bed D is regenerated by heating, valves 398 and 408 are open, and the CO2 product exits as stream 105. During step 2, bed E is cleaned as CO2 product stream 145, which enters the bed through open valve 424 and exits through open valve 434. The operation of the various valves during steps 3 to 10 is similar to the operation during steps 1 and 2. Once all steps have been completed, the cycle is repeated continuously starting at step 1.

Typical Cycle Sequences for CO₂ Capture Processes  step    Bed A   Bed B   Bed C    Bed D    Bed E time
minute   One absorption/
reaction  Equalize with Bed E  Heating with introduction  heating  Equalize with Bed B   2.0   2 absorption/
reaction  Pressure  Heating with introduction  heating  CO₂ cleaning   2.0   3  Equalize with Bed C absorption/
reaction  Equalize with Bed A  Heating with introduction  heating   2.0   4  CO₂ cleaning absorption/
reaction  Pressure  Heating with introduction  heating   2.0   5  heating  Equalize with Bed D absorption/
reaction  Equalize with Bed B  Heating with introduction   2.0   6  heating  CO₂ cleaning absorption/
reaction  Pressure  Heating with introduction   2.0   7  Heating with introduction  heating  Equalize with Bed E absorption/
reaction  Equalize with Bed C   2.0   8  Heating with introduction  heating  CO₂ cleaning absorption/
reaction  Pressure   2.0   9  Equalize with Bed D  Heating with introduction  heating  Equalize with Bed A absorption/
reaction   2.0   10  Pressure  Heating with introduction  heating  CO₂ cleaning absorption/
reaction   2.0

 20.0 minutes total

As shown in Table 1, the various steps of the CO2 capture and regeneration process are significantly faster than typical temperature swing adsorption processes where these steps take approximately several hours. For water-resistant adsorbents and reactants, rapid heating can be achieved by directly heating the beds with steam, after which a purge process must be performed to remove the steam, and then the beds must be cooled. For adsorbents and reactants that are not water resistant, such as zeolites, direct heating through steam is not a solution, and heating through dry gas will be too late. In such cases, the beds may be heated indirectly. One such configuration is a shell and tube configuration wherein the adsorbent and reactants are contained in a small diameter tube and the heating medium flows on the cell side during the regeneration portion of the cycle. Regeneration temperatures of approximately 80 ° C.-300 ° C. can be obtained using steam or hot water as the heating medium. Heated liquid or gas streams utilizing electricity produced at the power plant can be used for regeneration. One alternative configuration is to include the adsorbent material on the cell side with the heating or cooling liquid on the tube side. Another configuration that allows indirect heating is a plate and frame structure wherein the adsorbent is disposed in staggered sideways and the heated fluid flows in staggered sideways. Steam or heated fluid can be used as the heating medium. For the cell and tube configurations and the plate and frame configurations, cold fluid can be used in the CO2 removal step to remove heat of adsorption or chemical reaction. Cold liquid can also be used for the bed cooling step. For retrofit applications, it may be easier to use hot water or low pressure steam as the regeneration medium, because it is easy to minimize and improve confusion in the steam cycle of the power plant. In addition to the vertical bed, both horizontal and radial beds are usable to carry out the cycle. And, if desired, each of the cell and tube configurations or the plate and frame configurations can be used for heat exchange with horizontal or radial beds.

The CO2 produced during the heating and evacuation process of the cycle typically has a purity of at least 90%. This stream is compressed and sent to the CO 2 purification plant as described above. If a thin film is used for the CO 2 purification, a small amount of CO 2 flow penetrates the thin film to produce a higher purity CO 2 flow and is used as a cleaning flow in the CO 2 separation system 80. The remainder of the stream can be further compressed and used for enhanced oil recovery, industrial applications, or CO2 metal ion containment. If the getter process is used for CO2 purification, impurities such as oxygen and sulfur oxides are removed by reaction with the getter, and the purified CO2 flow is more compact and can be used for a variety of applications. If a distillation process is used for CO2 purification, CO2 is obtained as bottom product and non-condensates are removed in the top layer of the distillation column. Part of the CO2 produced by the distillation process can be used for the purge of the CO2 trap; The remainder is used in various applications such as pressurized pumping at higher pressures for enhanced oil recovery or metal ion containment. The non-condensed stream can be further purified through a thin film or adsorption process to recover additional CO2 content.

Test Example 1:

A commercially available 5A zeolite of 8 × 12 mesh size (approximately 1.5 mm) was purchased from Aldrich Corporation and loaded into two 18 mm diameter adsorbent beds. The total weight of the adsorbent was approximately 500 gms. A feed stream containing approximately 12.5% CO2 and the remainder nitrogen was prepared to simulate the flue gas from the coal-fired power plant, passing through these beds at a flow rate of 11 standard liters per minute and a pressure of 1.34 bar absolute. It became. Standard conditions are 21.1 ° C. and 1 bar absolute. The adsorption bed was cooled by a jacket containing a water / glycol mixture at 30 ° C. The regeneration bed was heated by a jacket containing a water / glycol mixture at 100 ° C. The CO2 removed stream and the concentration in the CO2 product were analyzed using an infrared CO2 analyzer. The cycles of this process are shown in Table II. After heating, the beds were introduced at an absolute pressure of approximately 0.25 bar in the introduction step. For these process conditions, 99.8% average CO2 purity and 85.8% average CO2 recovery were obtained.

 step#          Bed A           Bed B  Step time     minute    One     absorption     Parallel heating     8.0    2     Equalization     Equalization     1.0    3     washing     revolution     1.0    4     heating     revolution     7.0    5     heating     Pressure     1.0    6     Parallel heating     absorption     8.0    7     Equalization     Equalization     1.0    8     Idle     washing     1.0    9     revolution     heating     7.0    10     Pressure     heating     1.0

Test Example 2:

The process of Test Example 1 was run at different adsorption temperatures. Other process conditions, namely feed pressure, feed CO2 concentration, and adsorbent material were the same as in Test Example 1. Again, the concentrations in the CO2 removed stream and the CO2 product stream were analyzed using an infrared CO2 analyzer. The process cycles in Table II were used. For a feed temperature of 20 ° C., an average CO 2 purity of 99.0% and an average CO 2 recovery of 88% were obtained. For a feed temperature of 40 ° C., an average CO 2 purity of 99.2% and an average CO 2 recovery of 84% were obtained.

Test Example 3:

The process of Test Example 1 was carried out by purchasing a commercially available 13X zeolite of 8 X 12 mesh size (approximately 1.5 mm) from Aldrich Corporation. The feed pressure and feed CO 2 concentration were the same as in Test Example 1, the process cycle of Table II was used. Again, the concentrations in the CO2 removed stream and the CO2 product stream were analyzed using an infrared CO2 analyzer. For a feed temperature of 20 ° C., an average CO 2 purity of 98.5% and an average CO 2 recovery of 87% were obtained. For a feed temperature of 30 ° C., an average CO 2 purity of 98.5% and an average CO 2 recovery of 78% were obtained.

Test Example 4:

As in Test Example 1, a bed comprising 5A (approximately 500 grams total weight) contained approximately 3.4% of CO 2 and the remainder was used with a feed stream that simulated flue gas from a natural gas thermal power plant. The feed flow was passed through these beds at a total flow rate of 17 standard liters / minute. The adsorption bed was cooled by a jacket containing a water / glycol mixture at 20 ° C. The process cycles in Table II were used. The regenerated bed was heated by a jacket containing a water / glycol mixture at 100 ° C. The CO2 removed stream and the concentration in the CO2 product were analyzed using an infrared CO2 analyzer. For these process conditions, an average CO2 purity of 91% and an average CO2 recovery of 86% were obtained. The results of these tests indicate that the process of the present invention can provide excellent purity and recovery for flows containing very low levels of carbon dioxide such as those emitted from natural gas fired power plants.

Comparative Example 1:

The 5A zeolite of Test Example 1 was used to obtain results for the vacuum swing adsorption process without any thermal regeneration. The feed flow included an absolute pressure of 1.34 bar and 12.8% CO2 at 30 ° C. The beds were introduced at a pressure of 0.25 bar absolute in the regeneration phase. Both adsorption and regeneration steps were performed at 30 ° C. The process cycle included adsorption, equalization, washing with pure CO2, introduction, equalization and pressurization steps.

5.5 average CO2 purity and 81.6% average CO2 recovery for a feed rate of 5.5 standard liters / minute, adsorption time of 4 minutes, equalization time of 0.5 minutes, cleaning time of 1.0 minutes, introduction time of 4.0 minutes and pressurization time of 0.5 minutes 25.4% were obtained. 2.2 Deceleration of feed flow rate to standard liters / minute lowered average purity to 53% and average recovery to 26%. 59.4% average purity for 5.5 standard liters / minute feed flow rate and faster cycles (2 minutes adsorption time, 0.25 minutes equalization time, 0.5 minutes cleaning time, 2.0 minutes introduction time and 0.25 minutes pressurization time) And an average recovery of 43.9% were obtained.

Comparing the results of this Comparative Example with Test Example 1 shows that the two effects of CO 2 recovery and CO 2 purity are significantly lower without thermal regeneration of the beds.

Test Example 5:

F-200 activated alumina commercially available from Alcoa was loaded into the bed of Test Example 1. The total weight of the adsorbent was approximately 300 grams. The feed stream was saturated with water at 25 ° C., containing approximately 12.5% of CO 2, and the remainder being nitrogen passed through these beds at a total flow rate of 10 standard liters / minute and an absolute pressure of 1.34 bar. The cycle included a 5 minute adsorption time, a 4.5 minute purge time and a 0.25 minute pressurization and decompression time, respectively, and was designed to maintain most of the heat of adsorption of water in the bed. The dried product exiting the adsorptive bed was used for purge operation after lowering its pressure to approximately atmospheric pressure. The dew point of the product flow leaving the bed was continuously detected and the moisture concentration of the product remained below 1 / 1,000,000 parts per million (ppm) over a five day cycle.

This example shows that under certain conditions, the feed stream to the CO 2 separation can be dried to very low moisture levels to improve CO 2 recovery in the CO 2 separation. In a process where water is removed prior to CO2 adsorption, the purge gas will be a stream of CO2 removed from the CO2 adsorption section.

The results of these test examples suggest that the process presented in the present invention can be used to recover CO2 with high purity and recovery from various process streams.

Estimated energy consumption in the process of the present invention indicates that the energy required for CO 2 capture in this process is approximately half of the energy required for the amine-based CO 2 capture process.

The methods and systems presented here for capturing CO2 provide a number of advantages. The process is applicable to both retrofit applications and new installations. The retrofitting required by the plant for retrofitting is significantly smaller than required for amine-based CO2 capture. The process of the present invention is applicable to both coal and natural gas fired power plants. The process is also applicable to other streams such as refineries and chemical process streams containing carbon dioxide. Unlike the adsorption process in which nitrogen oxides and sulfur oxides (NOx and SOx) in the feed stream can irreversibly react to the solvent and require removal below approximately 10 ppm level, the NOx and SOx in the feed stream are adsorbents. Does not adversely affect Oxygen in the feed stream has no effect on the adsorbent, unlike adsorption based processes that degrade the quality of the amine solvent. The process provides a dry CO2 product which eliminates the drying step prior to CO2 compression and liquefaction and reduces the associated energy and capital costs.

Although the systems and methods of the present invention described above have been described with reference to specific examples, the scope of the present invention is not limited thereto. For example, the feed gas containing CO 2 may be from other processes, for example a natural gas fired power plant or a coal gasification power plant.

The examples described above are merely provided to illustrate the present invention and should not be construed as limiting the method and system of the present invention. Although the present invention has been described with reference to various embodiments, it is to be understood that the terminology used herein is for the purpose of description and illustration, and is not intended to be limiting. Also, while the invention has been described herein with reference to specific means, materials and embodiments, the invention is not intended to be limited to the specific embodiments set forth herein; The present invention includes all functionally equivalent structures, methods and uses, for example, those included within the scope of the appended claims. Those skilled in the art having learned the present disclosure will appreciate that various changes and modifications can be made to the embodiments described above without departing from the inventive concept of the invention.

5 ...... process
10,15,20,25,55,70,85,90,95,105,115,120,130,140,145 ..... flow
30,60 ..... Unit 45,50,105 ..... Line
65 ..... Blower 71 ..... Thin Film Dryer
74 ..... vacuum pump 76 ..... absorption system
79 ..... Moisture Adsorption System
80 ..... CO2 Separation System
81 ..... Bed 96 ..... Heat Exchanger or Heater
110 ... vacuum pump 125 ... CO2 purification system
200,210,220,245,250,260,265,275,280,290,320,340,350,430 ..... Valve
230,235,240 ..... Courage
230a, 230b, 235a, 235b, 240a, 240b .... Floor

Claims (23)

The gas stream is run in a first moisture removal step, wherein all moisture from the gas in the gas stream is removed using any process selected from the group comprising pressure swing adsorption, temperature swing adsorption, thin film separation and absorption; And
The moisture-free gas is run in a second temperature swing adsorption step, where the second temperature swing adsorption step is performed in a bed containing an adsorbent, and the second temperature swing adsorption step is dried and carbon dioxide is removed. An adsorption step for producing a stream, the adsorbent regeneration step comprising heating the adsorbent bed to produce a water-depleted carbon dioxide stream; And bed introduction process for recovering additional carbon dioxide amount after bed heating,
Separating carbon dioxide from a gas stream comprising water and additional impurities, including performing the steps one or more times. The pressure of the gas stream is within the absolute pressure range of 1.07 to 40 bar, the carbon dioxide concentration is in the range of 3% to 60% by volume, and the gas temperature is 10 ℃ to 80 ℃ Method within a range. According to claim 1, wherein the duration of the pressure swing adsorption process in the first water removal step is within the range of 4 minutes to 60 minutes, the duration of the temperature swing adsorption process in the first water removal step is 1 hour to 12.0 time range. The method of claim 1, wherein the temperature in the second temperature swing adsorption step during the adsorbent regeneration step is raised to 80 ° C to 300 ° C. The method of claim 1 wherein the duration of the second temperature swing adsorption step is in the range of 2 minutes to 60 minutes. The method of claim 1, wherein the gas is flue gas generated from any one of a coal fired power plant, a natural gas fired power plant, and a refinery. The method of claim 1 wherein the adsorbent used in the first water removal step is selected from the group comprising a molecular filter comprising activated alumina, silica gel, 3A, 4A, 5A and 13X zeolite. delete The method of claim 1 wherein the adsorbent used in the second temperature swing adsorption step is activated carbon, carbon molecular filter, 4A, 5A, 13X, NaY and CaX zeolites, metallorganic framework compounds, natural zeolites , Modified natural and artificial zeolites, modified activated carbons, pillared clays. The method of claim 1, wherein the purity of the moisture-depleted carbon dioxide stream produced in the second temperature swing adsorption step is 90% or more. The dry, carbon dioxide removed stream obtained from the second temperature swing adsorption step is used to regenerate either one of the adsorbents or the adsorbents in the first water removal step, and thin film drying. Characterized in that it is used to provide the driving force for the step. The method of claim 1 wherein the adsorbent regeneration comprises heating the adsorbent bed directly as a gas stream or indirectly using steam or hot fluid in a heat exchanger structure. delete The method of claim 1, wherein the second temperature swing adsorption step further comprises bed equalization, bed pressurization, bed depressurization, and bed cooling. The method of claim 1 wherein the impurities in the feed stream directed to the second temperature swing adsorption step comprise hydrocarbon, oxygen, nitrogen, argon and nitrogen oxides. The method of claim 1 wherein the additional impurities selected from the group comprising hydrocarbons, nitrogen oxides, sulfur oxides and mercury are removed from the gas stream in the first water removal step. The method of claim 1 wherein the adsorbents used to remove hydrocarbons, nitrogen oxides, sulfur oxides and mercury are selected from activated carbon, 13X zeolite, saturated alumina, modified activated carbon and silicate. The method of claim 1, wherein the water and additional impurities removal process comprises a first adsorption section, a second adsorption section, and a third adsorption section arranged side by side, wherein each of the first adsorption section, the second adsorption section, and the first adsorption section is arranged. The three adsorption sections comprise a first region containing a water removal adsorbent and a second region containing one or more adsorbents for the removal of impurities selected from hydrocarbons, nitrogen oxides, sulfur oxides and mercury, Run it one or more times:
The gas is subjected to a cycle of pressure swing adsorption process, so that the adsorption step and the adsorbent regeneration steps are alternately performed in the first adsorption part and the second adsorption part, thereby removing all moisture from the gas. Desorb water and other impurities from the adsorbent in the first and second regions of the third adsorbent by heating adsorbents;
The gas is subjected to a pressure swing adsorption process forming a cycle so that the adsorption step and the adsorbent regeneration steps are alternately performed in the first adsorption part and the third adsorption part, thereby removing all moisture from the gas. Desorb water and other impurities from the adsorbent in the first and second regions of the second adsorption section by heating adsorbents; And
The gas is subjected to a cycle of the pressure swing adsorption process forming a cycle so that the adsorption step and the adsorbent regeneration steps are alternately performed in the second adsorption part and the third adsorption part, thereby removing all moisture from the gas. Heating the adsorbents to desorb water and other impurities from the adsorbent in the first and second regions of the first adsorption section. 19. The method of claim 18, wherein said adsorbent heating step is performed at a temperature in the range of < RTI ID = 0.0 > 80 C-300 C. < / RTI > The gas stream comprising the moisture and additional impurities is sent directly to a second temperature swing adsorption step without first removing the water and additional impurities, wherein the second temperature swing adsorption step is discretized. Adsorption step for producing a carbon-free stream and adsorbent regeneration step of heating the adsorbent bed to produce a pure carbon dioxide stream. 21. The method of claim 20, wherein the adsorbent for the second temperature swing adsorption step is selected from activated carbon or carbonate, amine or ionic liquid of microporous support. The impurity of claim 1, wherein the carbon dioxide stream is further purified by any one of a thin film process, a distillation process, an adsorption process, and a getter process to contain nitrogen, oxygen, argon, nitrogen oxides, sulfur oxides, and moisture. Removing them. 23. The method of claim 22, wherein the purified carbon dioxide is used to provide a high purity cleaning flow of the carbon dioxide separation system.

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