Biphasic solvent co2 ejector capture system and method

Abstract

The embodiments of this disclosure describe a process and apparatus for capturing carbon dioxide (CO2) from a gas stream through use of a biphasic solvent in an ejector system to eliminate the need for conventional components such as blowers, packed bed absorber towers or trayed absorber towers. The ejectors serve a dual purpose, providing both pressurization and efficient mixing for the capture of CO2 from flue gas. The utilization of a biphasic solvent ensures that only the CO2-rich solvent phase is directed to the regenerator tower, thereby optimizing the energy required for the subsequent separation of solvent and CO2.

Description

BIPHASIC SOLVENT CO2 EJECTOR CAPTURE SYSTEM AND METHOD TECHNICAL FIELD

[0001] A biphasic solvent-based carbon dioxide (CO2) capture system and method are disclosed, wherein ejectors are employed to eliminate the need for conventional components such as blowers, packed bed absorber towers, or trayed absorber towers. The ejectors serve a dual purpose, providing both pressurization and efficient mixing for the capture of CO2 from flue gas. The utilization of a biphasic solvent ensures that only the CO2-rich solvent phase is directed to the regenerator tower, thereby optimizing the energy required for the subsequent separation of solvent and CO2. BACKGROUND

[0002] It is known that the world and its economies derive many benefits from the burning of fossil fuels given they currently supply over 85 percent of the world’s energy needs. Existing transportation and energy infrastructure is convenient and affordable but burning petroleum-based fuels emit greenhouse gases (GHG).

[0003] Prentice in “Climate change 2001: the scientific basis: contribution of Working Group I to the Third Assessment Report of the Intergovernmental Panel on Climate Change” published in 2001, notes that the carbon dioxide concentration was 280 ppm + / - 10 ppm for several thousand years. It has risen considerably since then reaching 367 ppm in 1999. The rate of increase over the past century is unprecedented at least during the past 20,000 years. Modelling by Peters G., et al January 2013 “The Challenge to Keep Global Warming below 2C” shows that even if all GHG emissions decreased to zero, without sequestering carbon from the atmosphere, some degree of warming would still take place.

[0004] During the combustion of fuels such as oil, natural gas, biochar, or coal for energy production, a hot process gas, commonly referred to as flue gas, is generated. This flue gas contains, among other constituents, carbon dioxide (CO2). The detrimental environmental impact of releasing CO2 into the atmosphere is welldocumented, leading to the development of various processes designed to capture and remove carbon dioxide from the flue gas produced by the combustion of these fuels.

[0005] Known CO2 capture processes for flue gas commonly utilize a regenerable solvent, typically an aqueous amine solution, to capture the CO2 from the gas stream. In these systems the flue gas is passed through an absorber tower usually filled with a packed bed or trays to encourage counter-flow contact with the amine solvent such that the CO2 can be absorbed. Due to the pressure drop of the absorber tower packed bed or trays a blower is required to pressurize the flue gas. At near atmospheric pressures the size of the blowers and absorber tower are generally large given the large volumetric flow rates resulting in large sizes and pressure drops. Due to the large flue gas volumetric flow rates CO2 absorber towers typically have required diameters over 2m and heights over 10m tall making them difficult to tray or pack to promote good absorption by the solvent. It would be of benefit then to have a CO2 capture system that eliminates the need for large absorber towers and the related blowers. SUMMARY

[0006] Embodiments of the present invention provide a system and method for capturing carbon dioxide (CO2) from a process gas stream. More particularly the proposed invention is to process a post-combustion flue gas at near atmospheric pressure. The proposed invention eliminates the need for a blower and a packed bed or trayed absorber tower in favor of use of a biphasic solvent and an ejector system.

[0007] Some embodiments of the present disclosure relate to a system for the capture of CO2 where a heat exchanger is used to reduce the temperature of the flue gas to around 120℃ while recovering this energy for biphasic solvent regeneration. The flue gas is then repressurized in an ejector with water as the motive fluid while cooling the flue gas to less than 100℃. Water is recovered from the flue gas in a separator which the water recycled as a motive fluid. A second ejector is then used with a CO2 lean biphasic solvent solution as the motive fluid pressurizing the flue gas while concurrently capturing CO2. The biphasic solvent is recovered from the flue gas in aseparator. The flue gas is then fed to a conventional water wash or acid wash tower to eliminate solvent emission prior to release to the atmosphere. The recovered biphasic solvent is allowed to separate by gravity between a denser CO2 rich phase and a lighter CO2 lean phase. The CO2 lean phase from the gravity separator is recycled as a motive fluid for the second ejector. The CO2 rich phase is pumped through a cross-exchanger and fed into a regenerator tower with reboiler and condenser for distillation of CO2 from the biphasic solvent. Recovered lean biphasic solvent is recycled as a motive fluid for the second ejector.

[0008] Biphasic solvents are receiving increased attention in post-combustion CO2 capture systems as they reduce the regeneration energy requirements compared to conventional, single-phase solvents. With a biphasic CO2 capture solvent, liquid–liquid or liquid–solid phase separation forms after the solution absorbs CO2 resulting in a CO2 rich phase and a CO2 lean phase. In theory only the CO2 rich phase needs to be sent to the regenerator potentially reducing the regenerator reboiler energy duty. Biphasic solvents however suffer from higher viscosity and phase splitting which reduces their absorption effectiveness in a packed bed or trayed tower. For instance 2.5M piperazine and 2.5M sulfolane has a large CO2 loading of 0.85mol CO2 / mol amine however has undesirable absorption performance in a packed bed column due to high viscosity and rapid phase splitting.

[0009] An ejector is a mechanical device that uses a high-velocity fluid (often a liquid or gas) to entrain and move another fluid. It operates on the principle of jet propulsion, where a high-pressure, high-speed fluid (the motive fluid) is directed through a nozzle, creating a low-pressure zone that draws in and mixes with a secondary fluid (the suction fluid). This results in the transfer or mixing of the fluids without the need for moving parts.

[0010] Ejectors can be utilized for flue gas pressurization and CO2 capture mixing using conventional single phase solvents however at a required motive gas-toliquid ratio lower than 60:1 by volume resulting in high liquid flow rates far in excess of the higher than 500:1 gas-to-liquid ratio required for CO2 capture in a conventional packed or trayed tower. This high motive flow rate would significantly increase theregenerator reboiler duty such that any process would be subeconomic. The use of a biphasic solvent to concentrate the rich solvent for regeneration enables the use of ejectors given that the CO2 lean solvent which is only used for pressurization does not need to be regenerated and can be recycled by pump back to the ejector.

[0011] Ejectors with the lean solvent being pumped at high pressures and rapidly mixed with the low pressure flue gas are not as sensitive to high viscosity or solvent mixture separation thus enabling the effective use of biphasic solvents that would show poor performance in a trayed or packed tower.

[0012] Some embodiments of the present disclosure relate to utilizing a separate vessel for the flue-gas biphasic solvent separation with the biphasic solvent pumped to a conventional atmospheric tank for biphasic solvent gravity separation of dense and lean phases. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] These and other features of the present disclosure will become more apparent in the following detailed description in which reference is made to the appended drawings.

[0014] FIG. 1 is a schematic that represents a system and apparatus for the capture of carbon dioxide (CO2) from a gas stream wherein a biphasic solvent and ejectors are employed to eliminate the need for conventional components such as blowers, packed bed absorber towers, or trayed absorber towers. DETAILED DESCRIPTION

[0015] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs.

[0016] As used herein, the term “about” refers to an approximately + / -10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

[0017] As used herein, the term “conduit” refers to a pipe, fluid transmission line or other mechanism for providing fluid communication between at least two features of the present disclosure. In the figures of the present disclosure, conduits are typically represented by an arrowed line that connects one or more components, features or units within a depicted system. In some implementations of the present disclosure, use of the singular “conduit” can include multiple “conduits”. The term “conducting” may be used interchangeably with the terms “feeding” or “flowing” and these terms refer to the movement of a fluid, with or without entrained solids, through a conduit or otherwise between different components or units of a system, which is understood to also contemplate moving feed stocks, intermediate and final products between different steps of a process.

[0018] As used herein, the term “downstream” refers to a position or a component within a system, apparatus, or a step within a process that follows a prior position, component or step.

[0019] As used herein, the term “upstream” refers to a position or component within a system, apparatus, unit or a step within a process that precedes a subsequent position, component or step.

[0020] As used herein, the term “tower” or “column” can be used interchangeably as a vessel used to promote absorption or de-absorption of CO2 from a solvent and separation of components. If the tower contains trays to the vessel is called a tray tower or tray tower. If the tower contains packing the vessel is called a packed tower or packed column.

[0021] The embodiments of the present disclosure will now be described by reference to FIG. 1 with a representation according to the present disclosure.

[0022] FIG. 1 shows one a system 1 that can capture CO2 from a hot process gas stream.

[0023] A combustion source 2, such as a gas turbine, reciprocating engine or boiler, generates a flue gas 3. Flue gas 3 is cooled by means of a heat exchanger 4 toless than 120℃ such that water condensation and corrosion is limited in the exchanger. In some iterations the heat is exchanged with a steam or thermal oil stream 5 to be used for solvent regeneration.

[0024] Cooled flue gas 6 is further cooled through mixing with a recycled high pressure water stream at a pressure of greater than 3000kPag 7 in an upstream ejector 8. This pressures the ejector outlet mixture 9 to greater than 20kPag. The mixture 9 is fed into a gas-liquid separator 10 where water 11 is separated from the flue gas 12. Water 11 is pressurized by pump 13 to a pressure greater than 3000kPag in conduit 14 and is cooled by a heat exchanger 15 to a temperature below 40℃ prior to being recycled to ejector 8 by conduit 7. The motive water flow rate in conduit 7 is such that the pressure of the flue gas 12 is greater than 1kPag and a temperature below 80℃. Excess water is removed by bleed conduit 16.

[0025] The dewatered flue gas 12 is fed into the primary ejector 17 where it is mixed with a CO2 lean biphasic aqueous solution 18. This pressurizes the ejector outlet mixture 19 to while providing rapid solvent-CO2 contact and mixing. The flow rate of the biphasic aqueous solution 18 into the primary ejector 17 is high at a Gas-to-Liquid ratio of 100:1 or less such that the ejector outlet mixture 19 has a pressure greater than 10kPag and that a substantial portion of the CO2 has been absorbed from the mixture into the liquid solvent. The mixture 19 is fed into a gas-liquid separator 20 where liquid biphasic solvent 22 is separated from the flue gas vapors 21.

[0026] The liquid biphasic solvent 22 is fed by pump 23 into a liquid-liquid phase gravity separator 24 where the CO2 lean solvent phase 25 is separated from the CO2 rich solvent phase 26. The lean solvent phase 25 is fed to a pump 27 where it is pressurized to over 3000kPag and recycled by conduit 28 and cooled by heat exchanger 29 to a temperature below 40℃ prior to the CO2 lean biphasic aqueous solution 18 being recycled back into the primary ejector 17.

[0027] In some iterations the gas-liquid separator 20 can also act as a liquidliquid phase separator 24 eliminating the need for two separators.

[0028] In some iterations the biphasic solvent 18 is 2.5M piperazine and 2.5M sulfolane with a large CO2 absorption capability with loading as high as 0.85 mol CO2 / mol amine and good rich-lean phase separation.

[0029] The CO2 rich solvent phase 26 is fed to a pump 30 where it is pressurized in conduit 31. The CO2 rich solvent is heated by cross-exchanger 32 prior to being fed by conduit 33 into a regenerator column 34. The regenerator column 34 is heated by reboiler 35 to over 80℃ such that the CO2 will disassociate from the biphasic solvent resulting in a regenerated CO2 lean solvent stream 36. The regenerated CO2 lean solvent stream 36 is fed to cross exchanger 32 to recover energy and fed by conduit 37 to pump 27 where it is pressurized to over 3000kPag in conduit 28, cooled by heat exchanger 29 and recycled back by conduit 18 into the primary ejector 17.

[0030] CO2 off the top of the regenerator column 38 is cooled by heat exchanger 39 and fed into a gas-liquid separator 40 with any condensate 41 recycled back to the regenerator 34. The captured CO2 42 can be pressurized by compressor or liquefied by refrigeration loop for downstream sequestration. In some iterations the regenerator 38 is run at over 3barg to reduce the column size and compression requirements.

[0031] In some iterations a steam or thermal oil loop from heat exchanger 4 provides energy to the reboiler 35 by means of thermal fluid conduit 43, 44 and 45 recycled by pump 46 and conduit 5. Additional heat to the thermal fluid loop can be provided by exchanger or heater 47. For thermal oil to be used the flue gas must be precooled to less than 400℃ by means of water injection 48.

[0032] In some iterations amine emissions in the flue gas 21 are reduced by a conventional water wash, acid wash or a cold dry bed amine emission reduction unit 49. When a cold dry bed is used for amine emission reduction it is of benefit to purposely impose pressure drop while cooling the flue gas off the top with a heat exchanger 51 prior to releasing the flue gas to the environment by conduit 52.

[0033] Cooling for exchangers 15, 29 and 51 can be provided by a glycol solution loop pressurized by pump 53 fed by conduit 54 to an air cooler to reduce thetemperature below 40℃. The glycol solution is fed to the exchangers by conduit 45 and recycled by conduit 57.

[0034] Multiple banks could be utilized such that large plants can utilize multiple ejectors banks feeding a single pressurized regenerator tower and a reduced number of skim tanks.

[0035] EXAMPLE 1

[0036] A gas turbine combusting natural gas to generate 6MW of power releases 19.2 tonnes per hour of flue gas of which 3.1 tonnes per hour is carbon dioxide. The exhaust is cooled from 578℃ to 120℃ in a heat exchanger designed as a cylindrical boiler with a casing surrounding a convective section. The heat is transferred to 10barg steam.

[0037] The flue gas is mixed with 19.4 tonnes per hour of water at 5000kPag in the upstream ejector cooling the stream to 51℃ while providing a mixture pressure of 30kPag. Due to ejector size limitations two ejectors in parallel are utilized. The mixture is fed into a free-water-knock-out vessel where 19.8 tonnes per hour of liquid water is separated from the flue gas stream. 19.4 tonnes per hour of the water is recycled to the upstream ejector by pump while 0.4 tonnes per hour of water is bled from the system.

[0038] The 18.7 tonnes per hour of remaining flue gas with around 3.1 tonnes per hour of CO2 is fed into the primary ejector where it is mixed with biphasic 2.5M piperazine and 2.5M sulfolane solvent at a rate of 60:1 gas-to-liquid by ratio resulting in a flow rate of around 264 tonnes per hour and a pressure with an inlet pressure of 5000kPag resulting in a mixture pressure of 65kPag. Due to ejector size limitations two ejectors in parallel are utilized. For 90% carbon capture approximately 25.9 tonnes per hour of the biphasic solvent will absorb the CO2 and form a CO2 rich phase capturing 2.8tpd of the carbon dioxide from the flue gas. The primary ejector output is fed into a 1.5m diameter by 6 meter horizontal vessel to separate the vapors from the gas. The flue gas is depressurized and fed into a conventional acid wash scrubber to eliminate any solvent emissions prior to atmospheric release.

[0039] The 264 tonnes per hour of both CO2 rich and lean biphasic solvent is fed into a 47m3 skim tank providing ten minutes retention time for phase separation. 238tpd of CO2 lean solvent is pumped back to the primary ejector. The 25.9 tonnes of CO2 rich solvent with 2.8tpd of CO2 is pumped to the regenerator where it is heated by cross-exchanger prior to being fed into the regenerator tower. The regenerator reboiler is operated at 120℃ to 150℃ and 3barg. The regenerator duty is approximately 2730kW of heat of which 2645kW is provided by generated steam from the flue gas cooler. The remaining 85kW of heat is provided by a small steam generator. The regenerated 25.9 tonnes of now CO2 lean solvent is recycled to the primary ejector by pump.

[0040] In the process approximately 528kW of electrical power was utilized with most of the demand being the motive fluid pumps derating the power plant to 5.4MW of power generation.

[0041] The 2.8tpd of CO2 from the regenerator condenser separator is compressed to 80barg for supercritical CO2 sequestration in a downhole well.

[0042] EXAMPLE 2

[0043] In the case of a 60MW power plant six ejector banks of the system from Example 1 can be deployed but with only a single regenerator tower utilized. As the regenerator tower is at pressure and given the flow rate of rich CO2 solvent limiting the size it would not make economic sense to have multiple regenerator towers. The number of liquid-liquid separation tanks and related pumps is also reduced from six to three that standard 2000BBL skim tanks can be utilized.

[0044] EXAMPLE 3

[0045] In the case of Example 1 where the unit is deployed in a remote environment the operator may wish to avoid a steam system for the regenerator. In this case the flue gas off the reciprocating engine is first cooled to 400℃ through sprayed injection of 1.3 tonnes per hour of water prior to the initial flue gas cooler. The flue gas cooler then exchanges heat not with steam but with a thermal oil stream. The 1.3 tonnesper hour of water will be recovered in the initial liquid-gas separator and can be recycled back to the sprayer. This will reduce the recovered energy to 1978kW and increase the system heat deficit to 751kW. This is provided by a thermal oil heater increasing the power plant gas requirement by approximately 5%.

Claims

Claims 1. A method for removing carbon dioxide (CO2) from a flue gas stream comprising: a. Mixing a pressurized, CO2-lean biphasic solvent with flue gas in an ejector device to facilitate both pressurization and rapid mixing; b. Separating the flue gas from the biphasic solvent via gas-liquid gravity separation; c. Separating the CO2-rich biphasic solvent from the CO2-lean biphasic solvent via liquid-liquid gravity separation; d. Recycling the CO2-lean biphasic solvent back to the ejector by means of a pump at a pressure greater than 20barg; e. Pumping the CO2-rich biphasic solvent to a regenerator tower, where heat is applied to separate the CO2 from the biphasic solvent, and recycling the CO2-lean regenerated biphasic solvent back to the ejector via pump at a pressure greater than 20barg.

2. The method of Claim 1 further comprising using an upstream ejector powered by water as a motive fluid to cool the flue gas below 100°C while simultaneously pressurizing it. The recovered water is separated from the flue gas by gas-liquid separator and pumped back into the upstream ejector with excess water discharged via a bleed stream. The cooled flue gas is then directed to the downstream ejector of Claim 1 for CO2 capture.

3. The method of Claim 2, wherein a heat exchanger is used prior to the upstream ejector to cool the flue gas to below 150°C while recovering energy for use in regenerating the biphasic solvent.

4. The method of Claim 3 wherein the heat exchanger cools the flue gas by transferring heat to generate steam 5. The method of Claim 3 wherein the heat exchanger cools the flue gas by transferring heat to thermal oil.

6. The method of Claim 5 wherein water is sprayed into the flue gas to reduce the mixture temperature to below 420°C with water recovered and recycled to the sprayer in the downstream flue-gas water separator.

7. The method of Claim 1, wherein the CO2-lean flue gas is treated with a conventional water wash to reduce biphasic solvent emissions.

8. The method of Claim 1, wherein the CO2-lean flue gas is treated with a conventional acid wash to reduce biphasic solvent emissions.

9. The method of Claim 1, wherein the CO2-lean flue gas is treated by condensing vapor-phase biphasic solvent using a cooled packed bed to reduce biphasic solvent emissions.

10. The method of Claim 1, wherein the regenerator column is operated at a pressure greater than 3 barg to minimize downstream CO2 compression.

11. The method of Claim 1 where the biphasic solvent is 2.5M piperazine and 2.5M sulfolane