NO20191345A1 - System and method for capturing carbon dioxide (co2) from a flue gas - Google Patents
System and method for capturing carbon dioxide (co2) from a flue gas Download PDFInfo
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- NO20191345A1 NO20191345A1 NO20191345A NO20191345A NO20191345A1 NO 20191345 A1 NO20191345 A1 NO 20191345A1 NO 20191345 A NO20191345 A NO 20191345A NO 20191345 A NO20191345 A NO 20191345A NO 20191345 A1 NO20191345 A1 NO 20191345A1
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- Prior art keywords
- flue gas
- fluid
- phase liquid
- capturing
- pump
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- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 title claims description 211
- 239000001569 carbon dioxide Substances 0.000 title claims description 105
- 229910002092 carbon dioxide Inorganic materials 0.000 title claims description 105
- 239000003546 flue gas Substances 0.000 title claims description 70
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 title claims description 67
- 238000000034 method Methods 0.000 title claims description 25
- 239000012530 fluid Substances 0.000 claims description 70
- 239000007788 liquid Substances 0.000 claims description 55
- 238000004821 distillation Methods 0.000 claims description 31
- 239000002904 solvent Substances 0.000 claims description 30
- 238000010521 absorption reaction Methods 0.000 claims description 29
- 238000002156 mixing Methods 0.000 claims description 20
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 14
- 238000002347 injection Methods 0.000 claims description 12
- 239000007924 injection Substances 0.000 claims description 12
- 238000011084 recovery Methods 0.000 claims description 12
- 239000007789 gas Substances 0.000 claims description 10
- 238000010438 heat treatment Methods 0.000 claims description 3
- 239000000203 mixture Substances 0.000 claims description 3
- 239000003921 oil Substances 0.000 description 30
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 238000002485 combustion reaction Methods 0.000 description 4
- 238000005516 engineering process Methods 0.000 description 4
- 230000008901 benefit Effects 0.000 description 3
- 238000001816 cooling Methods 0.000 description 3
- 239000013535 sea water Substances 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- 238000010792 warming Methods 0.000 description 3
- 239000006096 absorbing agent Substances 0.000 description 2
- 239000002803 fossil fuel Substances 0.000 description 2
- 239000005431 greenhouse gas Substances 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- BWHMMNNQKKPAPP-UHFFFAOYSA-L potassium carbonate Chemical compound [K+].[K+].[O-]C([O-])=O BWHMMNNQKKPAPP-UHFFFAOYSA-L 0.000 description 2
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonium chloride Substances [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 1
- VHUUQVKOLVNVRT-UHFFFAOYSA-N Ammonium hydroxide Chemical compound [NH4+].[OH-] VHUUQVKOLVNVRT-UHFFFAOYSA-N 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 235000011114 ammonium hydroxide Nutrition 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 238000004177 carbon cycle Methods 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 239000002826 coolant Substances 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 238000005262 decarbonization Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000010586 diagram Methods 0.000 description 1
- 230000005611 electricity Effects 0.000 description 1
- -1 for example Substances 0.000 description 1
- 239000000446 fuel Substances 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 239000002608 ionic liquid Substances 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 239000012528 membrane Substances 0.000 description 1
- 239000002808 molecular sieve Substances 0.000 description 1
- 230000020477 pH reduction Effects 0.000 description 1
- 229910000027 potassium carbonate Inorganic materials 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- 230000000630 rising effect Effects 0.000 description 1
- 238000000926 separation method Methods 0.000 description 1
- URGAHOPLAPQHLN-UHFFFAOYSA-N sodium aluminosilicate Chemical compound [Na+].[Al+3].[O-][Si]([O-])=O.[O-][Si]([O-])=O URGAHOPLAPQHLN-UHFFFAOYSA-N 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
Classifications
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1475—Removing carbon dioxide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/38—Removing components of undefined structure
- B01D53/40—Acidic components
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
- Y02A50/00—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE in human health protection, e.g. against extreme weather
- Y02A50/20—Air quality improvement or preservation, e.g. vehicle emission control or emission reduction by using catalytic converters
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
Description
SYSTEM AND METHOD FOR CAPTURING CARBON DIOXIDE (CO2) FROM A
FLUE GAS
TECHNICAL FIELD OF THE INVENTION
The invention disclosed herein generally relates to a system and method for capturing carbon dioxide (CO2) from a flue gas. More particularly, the present invention relates to a system and method for capturing carbon dioxide (CO2) from a variety of sources or gases, for example, a flue gas, and the captured CO2 is introduced into a fluid to produce a single-phase liquid. The single-phase liquid is injected into one or more wells for extracting oil from an oil field using an enhanced oil recovery (EOR) system.
BACKGROUND
Global warming is caused by the emission of greenhouse gases. Carbon dioxide is one of the most significant long-lived greenhouse gases in Earth's atmosphere. Since the Industrial Revolution, however, energy-driven consumption of fossil fuels has led to a rapid increase in the CO2 emissions, disrupting the global carbon cycle and leading to a planetary warming impact. CO2 has long been a by-product of many industrial processes. A large amount of CO2 is released into the atmosphere, thereby rapidly increasing its concentration in the atmosphere and leading to global warming and ocean acidification.
In response to the rising concern regarding CO2 emissions, a number of CO2 capture techniques, devices and systems have been proposed to reduce CO2 emissions by removal of CO2 from flue gases using a variety of approaches such as, but not limited to, oxy-fuel combustion, pre-combustion decarbonization, post- combustion processing, chemical looping combustion, chemically active absorption processes, physical absorption processes, adsorption by molecular sieves, membrane separation, and cryogenic techniques. In addition, some of the CO2 capture techniques and systems use chemical solutions such as, but not limited to, an ammonia solution, potassium carbonate, and ionic liquids as solvents amines. However, the cost of capturing CO2 using current technologies is very high.
Carbon capture and storage (CCS) is one of the available conventional technologies that can capture maximum CO2 emissions that are produced from the use of fossil fuels in electricity generation and industrial processes, thereby preventing CO2 from entering the atmosphere. The process of CCS includes three steps such as, capturing CO2, transporting, and securely storing the CO2 in a reservoir or a container. The CCS can also significantly reduce CO2 emissions from industry such as power plants, cement, steel and chemical industries, and oil and gas industries. However, one important challenge for the large deployment of this CCS technology is infrastructure. In addition, the CCS technology requires several compressor stages, coolers, and additional equipment, which may increase the installation costs.
In the light of above-mentioned problems, it is desirable to provide a system and method for efficiently capturing CO2 from flue gases and intrude the captured CO2 into a fluid to produce a single-phase liquid. The single-phase liquid is stored in a reservoir and used for extracting oil from an oil field using an enhanced oil recovery (EOR) system. Further, it is desirable to provide an inexpensive system and method for effectively capturing CO2 from flue gases using less equipment with less power consumption.
SUMMARY OF THE INVENTION
This summary is provided to introduce a selection of concepts in a simplified form that are further disclosed in the detailed description of the invention. This summary is not intended to identify key or essential inventive concepts of the claimed subject matter, nor is it intended for determining the scope of the claimed subject matter.
The present invention discloses a system and method for capturing carbon dioxide (CO2) from a flue gas. More particularly, the present invention relates to a system and method for capturing carbon dioxide (CO2) from a variety of sources or gases, for example, a flue gas, and intruding the captured CO2 into a fluid to produce a single-phase liquid. The single-phase liquid is injected into one or more wells for extracting oil from an oil field using an enhanced oil recovery (EOR) system.
In one embodiment, the system is configured to capture the CO2 from a variety of sources or gases, for example, a flue gas, and the captured CO2 is introduced into a fluid to produce a single-phase liquid. In one embodiment, the single-phase liquid is injected into one or more wells for extracting oil from an oil field using an enhanced oil recovery (EOR) system. In one embodiment, the system comprises a capturing unit, a CO2-fluid mixing unit, and an injection unit. The capturing unit is efficiently configured to capture CO2 from the flue gas.
In one embodiment, the capturing unit comprises a flue gas conduit, configured to receive the flue gas via a flue gas inlet. In one embodiment, a first heat exchanger is securely disposed in the flue gas conduit for extracting heat from the flue gas. The first heat exchanger is fluidly connected to a heater, which is securely positioned in the distillation column via the streamlines. In one embodiment, warmed stream/fluid could be circulated to the heater via the streamlines. In one embodiment, the capturing unit of the system further comprises an inlet for receiving a fluid from a fluid source. In one embodiment, a cooler is securely disposed in the flue gas conduit for cooling the flue gas that is received from the flue gas inlet. In one embodiment, the fluid could be, but not limited to, seawater or water. In one embodiment, the capturing unit further comprises, but not limited to, a compressor, an absorption column/absorber, and a distillation column/desorber. The compressor is securely disposed downstream of the flue gas conduit and configured to receive the flue gas via a streamline and compress the flue gas for increasing the pressure. In one embodiment, the absorption column is securely disposed downstream of the compressor. In one embodiment, the absorption column includes a lean solvent and a rich solvent for extracting/capturing the CO2 from the flue gas within the absorption column.
In one embodiment, the distillation column is securely disposed downstream of the absorption column. The distillation column includes a heater, configured to heat the rich solvent, thereby effectively desorbing the CO2 within the distillation column by continuously circulating the lean solvent via a second heat exchanger using at least one pump. The distillation column is fluidly connected to the absorption column via the second heat exchanger and the streamline for continuously circulating the lean solvent using the pump. The rich solvent stream from the absorption column is driven by the pressure from the absorption column into the distillation column and the lean solvent is pumped back into the absorption column using the pump. In one embodiment, the nitrogen and other trace gases, which are not dissolved in the solvent, are released into the atmosphere via an outlet of the absorption column.
In one embodiment, the CO2-fluid mixing unit of the system is fluidly connected to the capturing unit via the streamlines. In one embodiment, the CO2-fluid mixing unit comprises, but not limited to, a mixer. The mixer is securely disposed downstream of the distillation column. The mixer is fluidly connected to the inlet for receiving the fluid via the pump and the streamlines. In one embodiment, the mixer is configured to receive the captured CO2 from the capturing unit via the distillation column and the streamline and the fluid received from the capturing unit via the streamlines using at least one pump for intruding the CO2 into the fluid to produce a single-phase liquid. The mixer is configured to mix the captured CO2 with the fluid, thereby efficiently producing the single-phase liquid. The single-phase liquid could be carbonated water. The pump increases the pressure of the fluid. In one embodiment, the single-phase liquid could be securely stored in one or more reservoirs or containers.
In one embodiment, the CO2-fluid mixing unit further comprises a scrubber. The scrubber is securely disposed downstream of the mixer for receiving the single-phase liquid from the mixer. In one embodiment, excess gases and/or CO2 are vented out via the streamline via an outlet in the scrubber. In one embodiment, the fluid from the capturing unit is directly distributed to the injection unit via the streamline to ensure enough flow and flowrate.
In one embodiment, the CO2-fluid mixing unit is further configured to receive additional CO2 via a CO2 inlet from a CO2 source and the additional CO2 could be distributed to the mixer. In one embodiment, the additional CO2 could be distributed to the mixer along with the captured CO2 from the capturing unit via the distillation column. In some embodiments, the additional CO2 could be directly distributed to the mixer without the captured CO2 from the capturing unit via the distillation column.
In one embodiment, the injection unit of the system is fluidly connected to the CO2-fluid mixing unit for receiving the single-phase liquid from the CO2-fluid mixing unit via the scrubber. The injection unit is configured to inject the single-phase liquid received from the scrubber into one or more wells by pressurizing the single-phase liquid using at least one pump, thereby extracting oil from an oil field using the enhanced oil recovery (EOR) system. In one embodiment, the single-phase liquid could be carbonated water. In one embodiment, the single-phase liquid could be securely stored in one or more reservoirs or containers.
In one embodiment, a method for capturing the CO2 from the flue gas and intruding the captured CO2 into the fluid is disclosed. In one embodiment, the fluid is water and it is used for cooling the flue gas. At one step, the flue gas received from the flue gas conduit is compressed by the compressor of the system for increasing the pressure. At another step, the CO2 is extracted from the flue gas within the absorption column using a lean solvent and a rich solvent. At another step, the CO2 is captured from the flue gas by heating the rich solvent using a heater within the distillation column. At another step, the mixer could mix/intrude the captured CO2 into the fluid received from the capturing unit via the pump and the streamline to produce a single-phase liquid. Further, at another step, the singlephase liquid is injected into one or more wells by pressurizing the single-phase liquid using at least one pump, thereby extracting oil from an oil field using an enhanced oil recovery (EOR) system. In one embodiment, the single-phase liquid could be carbonated water. In one embodiment, the single-phase liquid could be securely stored in one or more reservoirs or containers.
Other objects, features and advantages of the present invention will become apparent from the following detailed description. It should be understood, however, that the detailed description and the specific examples, while indicating specific embodiments of the invention, are given by way of illustration only, since various changes and modifications within the spirit and scope of the invention will become apparent to those skilled in the art from this detailed description.
BRIEF DESCRIPTION OF THE DRAWINGS
The foregoing summary, as well as the following detailed description of the invention, is better understood when read in conjunction with the appended drawings. For illustrating the invention, exemplary constructions of the invention are shown in the drawings. However, the invention is not limited to the specific methods and structures disclosed herein. The description of a method step or a structure referenced by a numeral in a drawing is applicable to the description of that method step or structure shown by that same numeral in any subsequent drawing herein.
FIG.1 exemplarily illustrates a block diagram of a system for capturing carbon dioxide (CO2) from a flue gas and intruding captured CO2 into a fluid to produce a singlephase liquid in an embodiment of the present invention.
FIG.2 exemplarily illustrates a flowchart of a method for capturing the CO2 from a flue gas and intruding the captured CO2 into a fluid to produce a single-phase liquid in one embodiment of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
Referring to FIG.1, a system 100 for capturing carbon dioxide (CO2) from a flue gas and intruding captured CO2 into a fluid to produce a single-phase liquid is disclosed. In one embodiment, the system 100 is configured to capture the CO2 from a variety of sources or gases, for example, a flue gas, and the captured CO2 is introduced into a fluid to produce a single-phase liquid. In one embodiment, the single-phase liquid is injected into one or more wells 140 for extracting crude oil from an oil field using an enhanced oil recovery (EOR) system. In one embodiment, the system 100 comprises a capturing unit 102, a CO2-fluid mixing unit 128, and an injection unit 136. The capturing unit 102 is efficiently configured to capture CO2 from the flue gas.
In one embodiment, the capturing unit 102 comprises a flue gas conduit 106, configured to receive the flue gas via a flue gas inlet 104. In one embodiment, a first heat exchanger 108 is securely disposed in the flue gas conduit 106 for extracting heat from the flue gas. The first heat exchanger 108 is fluidly connected to a heater 124, which is securely positioned in the distillation column 122 via the streamlines (121 and 123). In one embodiment, warmed stream/fluid could be circulated to the heater via the streamlines (121 and 123). In one embodiment, the capturing unit 102 of the system 100 further comprises an inlet 112 for receiving a fluid from a fluid source 103. In one embodiment, the fluid could be, but not limited to, seawater or water. In one embodiment, a cooler 110 is securely disposed in the flue gas conduit 106 for cooling the flue gas streamline. In one embodiment, the capturing unit 102 further comprises, but not limited to, a compressor 114, an absorption column/absorber 116, and a distillation column/desorber 122. The compressor 114 is securely disposed downstream of the flue gas conduit 106 and configured to receive the flue gas via a streamline 115 and compress the flue gas for increasing the pressure. In one embodiment, the absorption column 116 is securely disposed downstream of the compressor 114. In one embodiment, the absorption column 116 includes a lean solvent and a rich solvent for extracting/capturing the CO2 from the flue gas within the absorption column 116.
In one embodiment, the distillation column 122 is securely disposed downstream of the absorption column 116. The distillation column 122 includes a heater 124, configured to heat the rich solvent, thereby effectively desorbing the CO2 within the distillation column 122 by continuously circulating the lean solvent via a second heat exchanger 120 using at least one pump 126. The distillation column 122 is fluidly connected to the absorption column 116 via the second heat exchanger 120 and the streamline 118 for continuously circulating the lean solvent using the pump 126. The rich solvent stream 154 from the absorption column 116 is driven by the pressure from the absorption column 116 into the distillation column 122 and the lean solvent is pumped back into the absorption column 116 using the pump 126. In one embodiment, the nitrogen and other trace gases, which are not dissolved in the solvent, are released into the atmosphere via an outlet 144 of the absorption column 116.
In one embodiment, the CO2-fluid mixing unit 128 of the system 100 is fluidly connected to the capturing unit 102 via the streamlines (113 and 129). In one embodiment, the CO2-fluid mixing unit 128 further comprises, but not limited to, a mixer 132. The mixer 132 is securely disposed downstream of the distillation column 122. The mixer 132 is fluidly connected to the inlet 112 for receiving the fluid via the pump 134 and the streamlines (113 and 152). In one embodiment, the fluid in the streamlines (113 and 152) is mixed and circulated using the pump 134. In one embodiment, the mixer 132 is configured to receive the captured CO2 from the capturing unit 102 via the distillation column 122 and the streamline 129 and the fluid received from the capturing unit 102 via the streamlines (113 and 152) using at least one pump 134 for intruding the CO2 into the fluid to produce a single-phase liquid. The mixer 132 is configured to mix/intrude the captured CO2 with the fluid, thereby efficiently producing the single-phase liquid. The single-phase liquid could be carbonated water. In one embodiment, the single-phase liquid could be securely stored in one or more reservoirs or containers. The CO2 could be dissolved and compressed nearly isothermal since the water has more than 90% of the mass and acts as a cooling medium. The pump 134 increases the pressure of the fluid. In one embodiment, the mixer 132 could act as a two-phase pump.
In one embodiment, the CO2-fluid mixing unit 128 further comprises a scrubber 133. The scrubber 133 is securely disposed downstream of the mixer 132 for receiving the single-phase liquid from the mixer 132. In one embodiment, the fluid from the capturing unit 102 is directly distributed to the scrubber 133 via the streamlines (113, 150 and 146) using the pump 134. In one embodiment, excess gases and/or CO2 are vented out via the streamline 156 and an outlet 142 in the scrubber 133. In one embodiment, the fluid from the streamlines (148 and 158) is directly mixed to ensure enough flow to the injection unit 136 and ensure enough fluid to mix with the CO2. In one embodiment, the fluid from the capturing unit 102 is directly distributed to the injection unit 136 via the streamline 148 to ensure enough flow and flowrate.
In one embodiment, the CO2-fluid mixing unit 128 is further configured to receive additional CO2 via a CO2 inlet 130 from a CO2 source and the additional CO2 could be distributed to the mixer 132. In one embodiment, the additional CO2 could be distributed to the mixer 132 along with the captured CO2 from the capturing unit 102 via the distillation column 122. In some embodiments, the additional CO2 could be directly distributed to the mixer 132 without the captured CO2 from the capturing unit 102 via the distillation column 122.
In one embodiment, the injection unit 136 of the system 100 is fluidly connected to the CO2-fluid mixing unit 128 for receiving the single-phase liquid from the CO2-fluid mixing unit 128 via the scrubber 133. The injection unit 136 is configured to inject the single-phase liquid received from the scrubber 133 into one or more wells 140 by pressurizing the single-phase liquid using at least one pump 138, thereby extracting oil from an oil field using an enhanced oil recovery (EOR) system.
Referring to FIG. 2, a flowchart of a method 200 for capturing the CO2 from the flue gas and intruding the captured CO2 into the fluid is disclosed. At step 202, the flue gas received via the flue gas conduit 106 is compressed by the compressor 114 of the system 100 for increasing the pressure. At step 204, the CO2 is extracted from the flue gas within the absorption column 116 using a lean solvent and a rich solvent. At step 206, the CO2 is captured from the flue gas by heating the rich solvent using a heater within the distillation column 122. At step 208, the mixer 132 could mix/intrude the captured CO2 into the fluid received from the capturing unit 102 via the pump 134 and the streamline 113 to produce a single-phase liquid. Further, at step 210, the single-phase liquid is injected into one or more wells 140 by pressurizing the single-phase liquid using at least one pump 138, thereby extracting oil from an oil field using an enhanced oil recovery (EOR) system. In one embodiment, the single-phase liquid could be a carbonated water. In one embodiment, the single-phase liquid could be securely stored in one or more reservoirs or containers.
The advantages of the present invention include: the system 100 could be used for efficiently capture the CO2 from the flue gas and intrude the captured CO2 into the fluid, for example, seawater to produce a single-phase liquid such as carbonated water. The apparatus 100 is inexpensive, easy to operate, and simple in design. The system 100 and method 200 are high in work efficiency, and suitable for extracting oil from an oil field using an enhanced oil recovery (EOR) system.
The foregoing examples have been provided merely for the purpose of explanation and are in no way to be construed as limiting of the present concept disclosed herein. While the concept has been described with reference to various embodiments, it is understood that the words, which have been used herein, are words of description and illustration, rather than words of limitation. Further, although the concept has been described herein with reference to particular means, materials, and embodiments, the concept is not intended to be limited to the particulars disclosed herein; rather, the concept extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims. Those skilled in the art, having the benefit of the teachings of this specification, may affect numerous modifications thereto and changes may be made without departing from the scope and spirit of the concept in its aspects.
Claims (10)
1. A system (100) for capturing carbon dioxide (CO2) from a flue gas and intruding captured CO2 into a fluid to produce a single-phase liquid, characterized by:
a capturing unit (102) configured to capture CO2 from the flue gas, wherein the capturing unit (102), comprising:
a flue gas conduit (106) configured to receive the flue gas via a flue gas inlet (104);
a first heat exchanger (108) securely disposed in the flue gas conduit (106), wherein the first heat exchanger (108) is configured to extract heat from the flue gas;
an inlet (112) configured to receive the fluid from a fluid source (103), wherein the fluid is water;
a compressor (114) securely disposed downstream of the flue gas conduit (106), wherein the compressor (114) is configured to receive the flue gas via a streamline (115) and compress the flue gas for increasing the pressure of the flue gas;
an absorption column (116) securely disposed downstream of the compressor (114), wherein the absorption column (116) includes a lean solvent and a rich solvent for capturing the CO2 from the flue gas within the absorption column (116), and
a distillation column (122) securely disposed downstream of the absorption column (116), wherein the distillation column (122) includes a heater (124), configured to heat the rich solvent, thereby effectively desorbing the CO2 within the distillation column (122) by continuously circulating the lean solvent and the rich solvent via a second heat exchanger (120) using at least one pump (126), and
a CO2-fluid mixing unit (128) configured to receive the captured CO2 from the capturing unit (102) from the distillation column (122) via a streamline 129 and the fluid received from the capturing unit (102) and the streamlines (113 and 152) via at least one pump (134) for intruding the CO2 into the fluid, comprising:
a mixer (132) securely disposed downstream of the distillation column (122), wherein the mixer (132) is configured to receive and mix the captured CO2 with the fluid, thereby efficiently producing the single-phase liquid and securely stored in one or more reservoirs/containers, wherein the single-phase liquid is carbonated water.
2. The system (100) of claim 1, wherein the CO2-fluid mixing unit (128) further comprises a scrubber (133), securely disposed downstream of the mixer (132) for receiving the single-phase liquid from the mixer (132), wherein the scrubber (133) is configured to remove any excess gases from the near single-phase liquid and to assure single phase fluid to the pump (138).
3. The system (100) of claim 1, further comprises an injection unit (136) is fluidly connected to the CO2-fluid mixing unit (128) for receiving the single-phase liquid from the CO2-fluid mixing unit (128) via the scrubber (133).
4. The system (100) of claim 1, wherein the injection unit (136) is configured to inject the single-phase liquid into one or more wells (140) by pressurizing the single-phase liquid using at least one pump (138), thereby extracting oil from an oil field using an enhanced oil recovery (EOR) system.
5. The system (100) of claim 1, further comprises a cooler (110), securely disposed within the capturing unit (102), wherein the cooler (110) is configured to cool the flue gas.
6. The system (100) of claim 1, wherein the mixer (132) is fluidly connected to the inlet (112) for receiving the fluid from the streamlines (113 and 152) via the pump (134).
7. The system (100) of claim 1, wherein the CO2-fluid mixing unit (128) is further configured to receive additional CO2 via a CO2 inlet (130) from a CO2 source, wherein the additional CO2 is distributed to the mixer (132).
8. The system (100) of claim 1, wherein the distillation column (122) is fluidly connected to the absorption column (116) via the second heat exchanger (120) and the streamline (118) for continuously circulating the lean solvent using a pump (126).
9. A method (200) for capturing carbon dioxide (CO2) from a flue gas and intruding the captured CO2 into a fluid to produce a single-phase liquid using a system (100), wherein the system comprising a capturing unit (102), a CO2-fluid mixing unit (128), and an injection unit (136), wherein the flue gas is cooled using a cooler (110), the method (200) comprising the steps of:
compressing the flue gas received from a flue gas conduit (106) using a compressor (114) for increasing the pressure of the flue gas;
capturing the CO2 from the flue gas by heating a rich solvent using a heater (124) within a distillation column (122), and
intruding the captured CO2 into the fluid received from the capturing unit (102) via the pump (134) and the streamlines (113 and 152) for producing the single-phase liquid using a mixer (132), wherein the fluid is water.
10. The method (200) of claim 9, further comprises the step of: injecting the single-phase liquid into one or more wells (140) by pressurizing the single-phase liquid using at least one pump (138), thereby extracting oil from an oil field using an enhanced oil recovery (EOR) system, wherein the single-phase liquid is carbonated water.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| NO20191345A NO20191345A1 (en) | 2019-11-13 | 2019-11-13 | System and method for capturing carbon dioxide (co2) from a flue gas |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| NO20191345A NO20191345A1 (en) | 2019-11-13 | 2019-11-13 | System and method for capturing carbon dioxide (co2) from a flue gas |
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| Publication Number | Publication Date |
|---|---|
| NO20191345A1 true NO20191345A1 (en) | 2021-05-14 |
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| Application Number | Title | Priority Date | Filing Date |
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| NO20191345A NO20191345A1 (en) | 2019-11-13 | 2019-11-13 | System and method for capturing carbon dioxide (co2) from a flue gas |
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| NO (1) | NO20191345A1 (en) |
Citations (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3065790A (en) * | 1957-11-22 | 1962-11-27 | Pure Oil Co | Oil recovery process |
| WO2000048709A1 (en) * | 1999-02-19 | 2000-08-24 | Norsk Hydro Asa | A method for removing and recovering co2 from exhaust gas |
| WO2008058298A1 (en) * | 2006-11-07 | 2008-05-15 | Geoffrey Jackson | Method and apparatus for the delivery of under-saturated sour water into a geological formation |
| EP3488915A1 (en) * | 2013-12-19 | 2019-05-29 | C-Capture Ltd. | System for the capture and release of acid gases |
-
2019
- 2019-11-13 NO NO20191345A patent/NO20191345A1/en not_active Application Discontinuation
Patent Citations (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3065790A (en) * | 1957-11-22 | 1962-11-27 | Pure Oil Co | Oil recovery process |
| WO2000048709A1 (en) * | 1999-02-19 | 2000-08-24 | Norsk Hydro Asa | A method for removing and recovering co2 from exhaust gas |
| WO2008058298A1 (en) * | 2006-11-07 | 2008-05-15 | Geoffrey Jackson | Method and apparatus for the delivery of under-saturated sour water into a geological formation |
| EP3488915A1 (en) * | 2013-12-19 | 2019-05-29 | C-Capture Ltd. | System for the capture and release of acid gases |
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