Apparatus and method for storing carbon dioxide

Abstract

The CO2 capture and storage system includes an absorber tower near a CO2 source. The CO2 absorber tower has a CO2 gas inlet, a gas outlet, an absorbent inlet, and an absorbent outlet. The CO2 stripping tower is near a well penetrating a geological structure. The stripping tower has an absorbent inlet, a gas outlet, an absorbent outlet, and a heating fluid inlet. A CO2 condensing unit is disposed proximate to the stripping tower and operably connected to a gas outlet on the stripping tower. The condensing unit has a compressor and / or a chiller where CO2 gas from the condensing unit is converted to a liquid. The outlet of the condensing unit is in fluid communication with the well. A pipeline is interposed between the absorber tower and the stripping tower, and the CO2 source and the well are remote from each other.

Description

[Background technology]

[0001] This disclosure relates to carbon capture and storage (CCS). More particularly, this disclosure relates to a system in which carbon dioxide is removed from flue gases by an absorbent and the carbon dioxide is liquefied and disposed of in a geological formation.

[0002] For example, in Norway, the national government is providing financial support for the realization of a full CCS project, including carbon dioxide (CO2) capture, transport and storage. The project, named "Langskip" or "Longship", consists of three parts that together make up the state-funded Project Longship.

[0003] Once captured, the CO2 is pressurized and stored as a liquid in tanks. The CO2 must be under pressure and within a certain temperature range to be transportable in liquid form. The liquid CO2 is then loaded onto special tank vessels, which transport it to an emplacement location. At the emplacement location, the CO2 may be pumped into underground geological formations by pumping equipment located near the emplacement site. Summary of the Invention [Problem to be solved by the invention]

[0004] There is a need for an improved system that reduces the transfer of liquid CO2 between systems. [Means for solving the problem]

[0005] The present disclosure relates to a CO2 capture and storage device for transporting CO2 into a geological formation and a method for delivering extracted CO2 into a well. Example embodiments are described in more detail below.

[0006] The stripping tower is an integral part of the CO2 storage apparatus according to the present disclosure, and the CO2 is handled in the pipe system using a separate transport tank. Possible advantages of the apparatus and method according to the present disclosure may include one or more of the following: It is easier to handle liquid CO2 in a consistent, closed system with tank containers or tank vehicles than to move liquid CO2 from one system to another. Logistics are more predictable because handling liquid CO2 is not dependent on local weather conditions. The use of CO2 storage equipment is more efficient, as waiting time for the next CO2 supply is minimized. The need for large temporary storage (buffer) tanks adjacent to the CO2 injection equipment is eliminated.

[0007] When injecting CO2 into a geological formation, operating the CO2 injection equipment in an intermittent mode causes fluctuations in the pressure in the geological formation, which may increase the amount of CO2 that can be deposited.

[0008] For example, when operating in a depleted HPHT (high pressure, high temperature) well, or another depleted high temperature well, the geological formations may provide the thermal energy necessary for the stripping tower to release the CO2 absorbed by the absorbent. By circulating heated fluid in this high temperature well, the heated fluid can pass through a heat exchanger to heat water that passes to the desorber component.

[0009] A CO2 capture and storage system according to one aspect of the present disclosure includes an absorber tower located near a CO2 source. The CO2 absorber tower has a CO2 gas inlet, a gas outlet, an absorbent inlet, and an absorbent outlet. A CO2 stripping tower is located near a well penetrating the geological formation. The stripping tower includes: The absorber has an absorbent inlet, a gas outlet, an absorbent outlet, and a heating fluid inlet. The CO2 condensing unit is disposed proximate to the stripping tower and operably connected to the gas outlet on the stripping tower. The condensing unit has a compressor and / or a cooler, and CO2 gas from the condensing unit is converted to a liquid. The outlet of the condensing unit is in fluid communication with a well. A pipeline is interposed between the absorber and the stripping tower, and the CO2 source and the well are remote from each other.

[0010] Some embodiments further include a CO2 storage tank proximate to the well and in fluid communication with the outlet of the CO2 condensation unit and the well, wherein the CO2 stored in the CO2 storage tank is released into the well at a selected time.

[0011] In some embodiments, the CO2 storage tank includes a liquid level sensor positioned to measure a level of liquid CO2 within the CO2 storage tank. The system further includes an injection pump interposed between the CO2 storage tank and the well, the injection pump operable to move the liquid CO2 from the CO2 storage tank to the well when the liquid level sensor reaches a first predetermined threshold.

[0012] In some embodiments, the infusion pump is switched off when a second predetermined threshold is reached that is lower than the first predetermined threshold.

[0013] Some embodiments further include a dehydration tower interposed between the gas outlet of the stripping tower and the inlet to the CO condensation unit. The dehydration tower contains a dehydration liquid through which the CO gas and water pass to extract the water from the CO gas and water.

[0014] In some embodiments, the dehydrating liquid comprises glycol.

[0015] In some embodiments, the CO2 absorber includes a liquid absorbent therein, and gas entering the CO2 gas inlet travels upward as bubbles through the CO2 absorber, extracting CO2 from the entering gas.

[0016] In some embodiments, the liquid absorbent comprises an amine.

[0017] In some embodiments, the liquid-absorbing agent comprises carbonic anhydrase.

[0018] Some embodiments further include a heating fluid pump and a heat exchanger, the heating fluid pump configured to circulate a fluid through the subterranean well to extract heat from the fluid, and the heat exchanger configured to transfer heat to a fluid entering a heating fluid inlet of the stripping tower, the transferred heat being applied to the CO2-laden absorbent traveling through the stripping tower to result in the release of absorbed CO2.

[0019] In some embodiments, the underground well is the same well as the well adjacent to the stripping tower.

[0020] Some embodiments further include a control unit in signal communication with a liquid level sensor positioned to measure the level of liquid CO in the CO storage tank. The system further includes an injection pump interposed between the CO storage tank and the well and in control communication with the control unit, the control unit being positioned to activate the injection pump to move liquid CO from the CO storage tank to the well when the liquid level sensor reaches a first predetermined threshold.

[0021] In some embodiments, the control unit is arranged to stop the infusion pump when the level reaches a second predetermined threshold that is lower than the first predetermined threshold.

[0022] Some embodiments further include an agitator disposed in each of the absorption and stripping columns, each agitator positioned to force liquid within the respective column such that the liquid moves downwardly as a result of rotation of the respective agitator.

[0023] In some embodiments, the source of CO2-containing gas includes a combustion system, the combustion system emitting CO2-baring flue gas.

[0024] According to another aspect of the present disclosure, a method for extracting and storing CO2 from a source of CO2-containing gas includes transferring CO2-containing gas from the source to a CO2 absorbent in a first container located proximate to the source to produce a CO2-rich absorbent. The CO2-rich absorbent is transferred to a second container remote from the first container and proximate to an underground disposal well. The CO2-rich absorbent in the second container is heated to release CO2 therefrom. The CO2-depleted absorbent is then returned to the first container. The released CO2 is condensed to a liquid and stored until the stored liquid CO2 increases to a first predetermined threshold. The stored CO2 is injected into a disposal well when its level exceeds the first predetermined threshold.

[0025] Some embodiments further include dehydrating the liberated CO2 before condensation.

[0026] In some embodiments, the dehydration involves transferring the liberated CO2 through liquid glycol.

[0027] In some embodiments, the absorbent comprises an amine.

[0028] In some embodiments, the absorbent comprises carbonic anhydrase.

[0029] In some embodiments, the heating comprises pumping steam or heated water into the second vessel.

[0030] In some embodiments, heated water or steam is produced by circulating a fluid through an underground well and transferring heat from the circulating liquid to a fluid traveling into a second vessel.

[0031] In some embodiments, the well through which the fluid is circulated is the same well into which the stored CO2 is injected.

[0032] In some embodiments, the CO2-bearing as source includes a combustion plant.

[0033] Other aspects and potential advantages of the systems and methods according to the present disclosure will become apparent from the following description and claims. [Brief explanation of the drawings]

[0034] [Figure 1] 1 shows a schematic diagram of a carbon capture plant according to an embodiment of the present invention; [Figure 2] 1 shows a schematic diagram of an embodiment of a CO2 storage device according to the present invention; [Figure 3] Referring to Figure 2, we show how a CO2 storage device can be applied to dispose of CO2 in geological formations via offshore wells; [Figure 4] Showing pipelines shown in cross section; [Figure 5] CO2 pressure-temperature phase diagram shown; [Figure 6] Referring to Figure 2, we show how the CO2 storage device shown can be applied to dispose of CO2 in geological formations via onshore wells; [Figure 7] 3 illustrates the control of operating parameters in one embodiment of the CO2 storage device shown in FIG. 2. [Figure 8] Another example of the embodiment is shown. DETAILED DESCRIPTION OF THE INVENTION

[0035] FIG. 1 schematically illustrates an example embodiment of a carbon dioxide (CO2) capture system 1 according to the present disclosure. CO2 capture system 1 includes an absorber tower 10 having a flue gas inlet 11 for receiving CO2-rich flue gas (described in more detail with reference to FIGS. 5 and 6). Absorber tower 10 may be a sealed, pressure-resistant vessel. Absorber tower 10 includes an absorbent, e.g., a liquid absorbent 10A, capable of absorbing CO2 from the CO2-rich flue gas as it bubbles upward from flue gas inlet 11 through absorbent 10A within absorber tower 10. Absorbent 10A circulates continuously through carbon capture system 1, entering absorber tower 10 as a lean CO2 absorbent through absorbent inlet 14 near the top of absorber tower 10 and absorbing CO2 from the CO2-rich flue gas moving upward therethrough to produce a CO2-rich absorbent. The CO2-rich absorbent exits absorber tower 10 through absorbent outlet 13 located near the bottom of absorber tower 10.

[0036] To ensure circulation of the absorbent 10A within the absorber tower 10, pumps (not shown in FIG. 1 ) may be provided in or along pipes 14A, 13A connected to the absorbent inlet 14 and absorbent outlet 13, respectively. CO2-rich flue gas passes through the absorbent 10A from the gas inlet 11 toward the flue gas outlet 12. As the CO2-rich flue gas bubbles upward through the absorbent 10A within the absorber tower 10, a substantial portion of the CO2 in the CO2-rich flue gas is absorbed by the absorbent 10A; therefore, the flue gas exiting the absorber tower 10 through the flue gas outlet 12 contains a significantly lower concentration of CO2 compared to the CO2-rich flue gas entering the absorber tower 10; such a gas may be referred to as a CO2-lean gas.

[0037] The CO2 capture system 1 further includes a desorber component 20 having a stripping tower 25 in which the CO2-rich absorbent is stripped to remove CO2 therefrom. The stripping tower 25 may be a sealed, pressure-resistant vessel. The CO2-rich absorbent enters the stripping tower 25 via an absorbent inlet 21 near the top of the stripping tower 25, travels downwardly through the stripping tower 25, and then exits the stripping tower 25 via an absorbent outlet 22 near the bottom of the stripping tower 25. Thermal energy is applied to the absorbent in the stripping tower 25 to force the CO2-rich absorbent to release absorbed CO2 before exiting the stripping tower 25, sometimes referred to as CO2-stripped or CO2-lean absorbent. The released CO2 exits the stripping tower 25 via a CO2 gas outlet 23. As explained above, the absorbent 10A may be a liquid that is capable of absorbing CO2 and subsequently liberating the CO2 by supplying energy (eg, thermal energy) to the CO2-rich absorbent.

[0038] In one embodiment, the thermal energy applied to the absorbent in stripping tower 25 may be provided by steam supplied to stripping tower 25 through heating fluid inlet 24, where the steam bubbles upwardly through stripping tower 25 and heats the absorbent. As further described below, the thermal energy applied to stripping tower 25 may be provided by circulating a liquid through an underground hot well.

[0039] In some embodiments, agitators 26, 27 are provided in absorber 10 and stripping column 25, respectively. Agitators 26, 27 may be provided to assist the downward flow of absorbent through each tower 10, 25. Such agitators 26, 27 may be rotated by a motor, such as an electric motor.

[0040] In some CO2 capture systems known prior to the present disclosure, the absorber tower 10 and the desorber component 20 (including the stripping tower 25) are located near each other to minimize the volume of absorbent required within the CO2 capture system. According to the present disclosure, the absorber tower 10 and the desorber component (including the stripping tower 25) may be separated from each other by a significant distance and connected to each other via a pipeline 15. The particular distance between the absorber tower 10 and the desorber component 20 is not limited within the scope of the present disclosure; it is within the scope of the present disclosure that the absorber tower 10 may be located in or at the source of CO2-rich flue gas and the desorber component 20 may be located adjacent to or at the surface location of one or more underground wells through which extracted CO2 is injected into the subsurface geological formation.

[0041] The pipeline 15, as may be observed in cross section in FIG. 4, may include a first conduit 16 that guides the CO2-rich absorbent from the absorber tower (10 in FIG. 1) toward the stripping tower (25 in FIG. 1) and a second conduit (17 in FIG. 1) that returns the CO2-lean absorbent to the absorber tower (10 in FIG. 1). The stripping tower (25 in FIG. 1) may be located close to the surface of the well (FIGS. 2, 3, 6), so that a large storage tank (buffer sunk) need not be located close to the well and the CO2 need not be transported from the capture system (1 in FIG. 1) to the well using a tank carrier. The pipeline 15 may include a power cable 18 disposed along the pipeline 15 to provide power to pumps, heaters, and coolers provided for conditioning the CO2. The pipeline 15 may include data cables 19 for monitoring data collected from sensors (not shown) located in or adjacent to pumps, heaters, and coolers along the pipeline 15 and transmitting the collected data to a control unit (100 in FIG. 7). The control unit (100 in FIG. 7) may then operate the pumps, heaters, and coolers (not shown in FIG. 1) along the pipeline 15 according to the received data. The control unit (100 in FIG. 7) ensures that the absorbent maintains suitable rheological properties for circulating between the absorber tower 10 and the stripping tower 25.

[0042] In some embodiments, the power cable 18 may be connected to a distribution panel (not shown) adjacent to the stripping tower 25, and the data cable 19 may be connected to a control unit (100 in FIG. 7), as further described below with reference to FIG. 7.

[0043] In some embodiments, the absorbent 10A may include one or more amines. Amines are well known for use in gas treatment, such as amine scrubbing, gas sweetening, and acid gas removal. The absorption process, in some embodiments, uses aqueous solutions of various alkylamines (commonly referred to as amines) to remove CO from exhaust gases. Many different amines may be used in gas treatment, including diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), diisopropanolamine (DIPA), aminoethoxyethanol, or combinations thereof. In one embodiment, the absorbent is monoethanolamine (MEA).

[0044] In some embodiments, the absorbent 10A may include carbonic anhydrase (CA). Carbonic anhydrase is based on a zinc-containing metalloenzyme widely found in animals, plants, and microorganisms and can catalyze the conversion of CO2 and water to bicarbonate. Carbonic anhydrase is widely present in metabolically diverse species of bacteria, for example, indicating that such metalloenzymes play a significant role in CO2 concentration. The absorbent may be a catalyst containing carbonic anhydrase activity and a catalytic domain. The term "carbonic anhydrase-active enzymes" may be understood as enzyme solutions containing carbonic anhydrase activity, as well as polynucleotides encoding the polypeptides and catalytic domains. Compared to amine-based absorbents, enzyme solutions with carbonic anhydrase activity generally require significantly less chemical to be effective in CO capture and significantly lower temperatures to re-liberate CO.

[0045] The difference between carbonic anhydrase and amine systems is that CA enzyme solutions use non-toxic, non-corrosive solvents that are effective at lower stripping temperatures than those required for amine stripping. Lower stripping temperatures allow for the use of less valuable heat (e.g., waste heat) and hot water instead of steam, which reduces energy costs. Enzyme solutions providing carbonic anhydrase can be economically beneficial for use in CO2 capture systems because, among other reasons, a given volume of CA enzyme solution can absorb more CO2 than a similar volume of amine.

[0046] Figure 5 shows a CO2 pressure-temperature phase diagram. The liquid state of CO2 (CO2) cannot exist below atmospheric pressure, as may be observed at the triple point shown in Figure 5. Liquid CO2 can only exist at pressures above 520 kPa (5.1 atm) and temperatures below 31.1°C (the critical point temperature in Figure 5) and above -56.6°C (the triple point temperature). The solid form of low-temperature CO2 is known as "dry ice." Solid CO2 sublimes at 194.65 K (-78.5°C) at atmospheric pressure, i.e., it changes directly from a solid to a gas without an intermediate liquid stage.

[0047] At the critical point (critical state), the boundary between the liquid and gaseous states disappears. Beyond the critical point, CO2 becomes a supercritical fluid, there is no difference in density, surface tension disappears, and the specific latent heat of vaporization is zero. For CO2, the critical point occurs at a pressure of 7.4 MPa and a temperature of 304.1 K. The density pc of CO2 at the critical point is 469 kg / m 3 is.

[0048] According to the present disclosure, CO2 is collected from the desorber component (20 in FIG. 1), liquefied, and temporarily stored in a storage tank (described below) for eventual pumping (injection) of the liquid CO2 into a well drilled through an underground geological formation for storage in a suitable geological formation.

[0049] 2 illustrates CO2 storage or sequestration within a geological structure 50. The geological structure 50 may either absorb the injected CO2 (e.g., by dissolution into fluids present in the pore space in the structure 50) or may supplement the injected CO2 by migration of a volume enclosed by an impermeable structure located above the geological structure 50, or both. The desorber component 20 may be substantially as described with reference to FIG. 1, including a stripping tower 25 having its absorbent inlet 21 for a CO2-rich absorbent and an absorbent outlet 22 for a CO2-lean absorbent. The stripping tower 25 releases CO2 stripped from the absorbent through a CO2 gas outlet 23. The CO2 exiting the desorber component 20 may then be transferred to a CO2 condensation component 30.

[0050] In some embodiments, thermal energy (heat), such as, but not limited to, steam, superheated steam (steam heated above its saturation temperature), or hot water, may be added to stripping tower 25 via pumping to force the absorbent to release the absorbed CO. In such cases, the release from CO gas outlet 23 may include CO combined with water, which may form a highly corrosive mixture under high pressure and temperature. Such a mixture may also have the ability to corrode stainless steel tubing and other components downstream of the CO capture system. Therefore, the CO and water vapor exiting stripping tower 25 may be transferred from stripping tower 25 to dehydration tower 31 within CO condensation component 30, where the water-laden CO gas is dehydrated, e.g., by a dry dehydration column 32. The CO2 gas is dried by contacting it with dry glycol, which absorbs water from the mixed gas. The CO2 gas exits the dehydration tower 31 as dry CO2 gas. The dry CO2 gas may travel from the dehydration tower 31 through a cooler 32 and a compressor 33, which form part of the condensing component 30, where the dry CO2 gas is pressurized and cooled to condense the CO2 into a liquid. A pump 34 in the condensing component 30 may be used to pump the liquefied CO2 into a CO2 injection component 60, which may include temporary storage, for example, in a CO2 storage tank 35. The CO2 storage tank 35 may include a level sensor 35A positioned to measure the liquid level in the CO2 storage tank 35, and the liquid level measurement may be used as described below with reference to FIG. 7.

[0051] The CO2 injection component 60 may be used to move the liquid CO2 into the geological structure 50. The CO2 injection component 60 may include a CO2 storage tank 35 and one or more injection pumps 36 for moving the liquefied CO2 from the CO2 storage tank 35 towards the geological structure 50. The injection pumps 36 may be used to transport the liquefied CO2 from the CO2 storage tank 35 through a pipe 37 into a well head 40. The well head 40 provides a structural and pressure-containing interface for a well 41 drilled through the geological structure 50.

[0052] The embodiment shown in Figure 2 may be based on an offshore (ocean) well 41 extending below the seabed 39 toward a geological structure 50. The well 41 may have been drilled by offshore oil drilling equipment of a type known in the art and may be enclosed with a steel casing. Just above the seabed 39, the steel casing has a flange 42 to which a valve assembly (so-called Christmas tree) 43 is attached. A well head 40, which may include the Christmas tree 43, may be welded onto the casing. The casing may be cemented in place during drilling operations to form the integral structure of the well 41.

[0053] When well 41 is drilled, it is completed with an interface with geological formation 50 and the provision of a tubular conduit for well fluid. Surface pressure control is provided by Christmas tree 43, which is installed on top of flange 42 and has shut-off valves, e.g., 43A, 43B, and choke devices (not shown separately) that control the flow of well fluid.

[0054] Offshore, when the well head 40 is located on a production platform or drilling rig above the sea surface 38, the well head 40 is called a surface well head, and when the well head 40 is located below the sea surface 38, the well head 40 is called a subsea well head or a mudline well head.

[0055] Christmas tree 43 is an assembly of valves, e.g., 43A, 43B, casing spools, and fittings used to regulate flow through various pipes in oil wells, gas wells, water injection wells, water disposal wells, gas injection wells, condensate wells, and other types of wells that penetrate a particular geological formation.

[0056] During gas or oil production, the primary function of Christmas tree 43 is to control the flow of oil or gas from well 41. However, Christmas tree 43 may also be used to control the injection of fluids, such as gas or water, into well 41. Injecting gas, water, and / or other fluids into a well is a known procedure for increasing the rate of oil production from nearby wells. In the present disclosure, liquid CO2 is pumped through pipe 37 via Christmas tree 43 in well head 40, where it enters well 41 and continues down well 41 toward geological structure 50.

[0057] In some embodiments, pipe 37 is a high-pressure CO pipeline for transporting CO compressed to sufficient pressure to ensure its single-phase flow. Operating pressures may range from 7.4 to 52 MPa or higher. Drilling service companies may provide pumps, such as drilling mud pumps, capable of pumping fluids at such pressure ranges, among others. Above 7.4 MPa, CO exists as a single dense phase over a wide temperature range consistent with that of the environment, so CO may remain stable either in the liquid phase or as a supercritical fluid.

[0058] In some embodiments, the CO2 is compressed to the desired pressure using a gas compressor or liquefied at low pressure by using a refrigeration system and then pumped to the desired pressure. In such embodiments, either chiller 32 or compressor 33 may be omitted.

[0059] In some embodiments, the CO2 storage device includes a heat transfer fluid pump 45, such as a drilling mud pump, which is a reciprocating piston / plunger pump designed to circulate fluid under high pressure in and out of the well 41. For example, when operating in a depleted HPHT (high pressure, high temperature) well, or another depleted high temperature well, the heat transfer pump 45 circulates heated fluid within the well 41, which in turn passes through a heat exchanger 46 to heat water, steam, or another heat transfer fluid passed to the desorber component 20 via the heated fluid inlet 24.

[0060] HPHT wells are defined as wells with undisturbed bottom temperatures greater than approximately 150°C and require a pressure control device called a BOP (blowout preventer) rated at greater than 10,000 psi (approximately 70 MPa).

[0061] In some embodiments, pump 45 may circulate the heated fluid in a different well than well 41 shown in FIG. 2 , e.g., an adjacent or nearby well, to avoid mixing of the circulating fluid with the CO2 being injected into geological formation 50. In some embodiments, pump 34 fills CO2 storage tank 35, and when a predetermined tank level is reached, injection pump 36 begins to discharge CO2 contained in CO2 storage tank 35, moving the CO2 toward well head 41, thereby operating intermittently. In one embodiment, CO2 is pumped as liquid CO2 by injection pump 36 through pipe 37. In some embodiments, carbon sequestration may include injecting CO2 as a supercritical fluid into underground geological formation 50. In some embodiments, the heat transfer fluid may be circulated in the same well as the well used to inject CO2 into the geological formation; in such embodiments, the heat transfer fluid may be circulated in the annular space between casing 41A and nested tubing (not shown) within casing 41A. Such an arrangement would isolate the heat transfer fluid from the CO being injected into the well 41. In such an embodiment, the heat transfer fluid source conduit 45B and the heat transfer fluid return conduit 45A may be connected to an annulus (not shown).

[0062] The example embodiments described above contemplate using otherwise configured wells for the production of fluids from one or more subsurface geological formations or for the injection of fluids for the purpose of enhancing fluid recovery from the subsurface formations. The foregoing is not intended to limit the scope of the present disclosure; in some embodiments, one or more wells may be constructed specifically for the injection of CO2 into the subsurface geological formation 50.

[0063] Figure 3 shows how the CO2 storage device described with reference to Figure 2 may be used to inject CO2 into a geological formation through a subterranean well 41, such as an offshore well. The combustion system supplies CO2-rich flue gas to absorber 10 through inlet 11. A substantial portion of the CO2 in the flue gas is absorbed by the absorbent in absorber 10. The CO2-lean flue gas exiting absorber 10 is returned to plant 54.

[0064] The absorbent in absorber 10 is circulated between absorber 10 and stripping tower (25 in FIG. 2) by pipeline 15 and one or more pumps 53 disposed along pipeline 15 to ensure that the absorbent flows between absorber 10 and stripping tower (25 in FIG. 2). In some embodiments, absorber 10 may be located in close proximity to plant 54 to minimize the length of the conduit (not shown) connecting flue gas inlet 11 to plant 54. As shown in FIG. 3, desorption component 20 may be located in close proximity to well 41.

[0065] 3, the desorber component 20, the CO2 condenser component (30 in FIG. 2), and the injection component 60 may be located on an offshore structure including a platform 51 that rests on a number of legs 52. Pipes 37 extend from the CO2 injection component 60 through the platform 51 and water down to and into the well 41. In this manner, CO2 may be pumped from a CO2 storage tank (33 in FIG. 2) into the underground geological formation 50.

[0066] Although example embodiments disclosed herein are described with reference to offshore wells, it should be expressly understood that it is also within the scope of the present invention to store CO2 in geological formations using wells located on land, rather than below the bottom of a body of water. Such types of wells are described below with reference to Figure 6.

[0067] Figure 6 shows how the CO2 storage device shown with reference to Figure 2 is applied to dispose of CO2 in a geological formation via an onshore well 41. A combustion system, which may be located in a CO2-producing power or manufacturing plant 54, supplies CO2-rich flue gas to an absorber 10 through an inlet 11. A substantial portion of the CO2 in the flue gas is absorbed by an absorbent in the absorber 10. The CO2-lean flue gas may be returned to the plant 54.

[0068] The absorbent in absorber tower 25 is circulated between absorber tower 10 and stripping tower 25 by pipeline 15 and one or more pumps 53 to ensure that the absorbent is flowing. CO2 is extracted from the absorbent in stripping tower 25 of desorber component 20. In the example embodiment shown in Figure 3, desorber component 20, CO2 condenser component 30, and injection component 60 are located on or near ground surface 55. Pipe 37 extends from CO2 injection component 60 through valve assembly (Christmas tree) 43 into well 41. CO2 may thereby be pumped from the CO2 storage tank (33 in Figure 2) into subsea geological formation 50.

[0069] 7 illustrates the control of certain operating parameters in one embodiment of the CO2 storage device shown in FIG. 2. The CO2 storage device in this example embodiment includes a control unit 100. The control unit 100 may be, for example, but not limited to, a microcomputer, a microprocessor, a programmable logic controller, a field programmable gate array, an application specific integrated circuit, or any corresponding analog or digital control device. The control unit 100 may be in signal communication with one or more sensors (not separately shown) positioned to monitor parameters within the desorber component 20, such as the absorbent flow rate through the stripping column (25 in FIG. 2), the CO2 content in the inlet (21 in FIG. 2) and outlet (22 in FIG. 2), the amount of thermal energy applied as steam or hot water through the heating fluid inlet (24 in FIG. 2), and the amount of CO2 exiting through the outlet (23 in FIG. 2). There is a match.

[0070] The control unit 100 may include a data bus 102 for communicating sensor signals from various elements of the CO2 storage system, including the desorber component 20, the CO2 condenser component 30, the CO2 injection component 60, and the well head 40. Each of the various elements of the CO2 storage system may include a data hub, which is a central intermediary between the sensors within that portion of the CO2 storage system and the data bus 102. The data hub 104 may include data processing equipment for reading sensor data and sending the read sensor data in data packets conforming to the specifications of the data bus 102. The data hub 104 may include data processing equipment for translating control signals generated by the control unit 100 into commands for controllable elements, such as valves, pumps, and motors, within the desorber component 20, the CO2 condenser component 30, the CO2 injection component 60, or the well head 40.

[0071] To optimize the CO2 extraction and storage process, the control unit 100 may, for example, adjust the heat energy applied to the heating fluid inlet (24, FIG. 2), and the flow through the towers (10 and 25, FIG. 2) may be controlled by an electric agitator (27, FIG. 2). The control unit 100 monitors various parameters within the CO2 condenser components (30, FIG. 2), such as the humidity of the water vapor entering and exiting the dehydration tower (31, FIG. 2), and the temperature and pressure of the gas or liquid flowing toward the CO2 storage tank (33, FIG. 2). To operate within predetermined process parameters, the dehydration tower (31, FIG. 2), chiller (32, FIG. 2), compressor (32, FIG. 2), and pump (34, FIG. 2) are controlled accordingly.

[0072] As long as the stripping tower (25, FIG. 2) is in operation, the pump (34, FIG. 2) continuously pumps the liquefied CO2 to move it to the CO2 storage tank (35, FIG. 2). The control unit 100 is configured to monitor the CO2 injection component 60, including the amount of CO2 present in the CO2 storage tank (35, FIG. 2), as well as the pressure and temperature of the CO2. Additionally, the control unit 100 is configured to monitor the amount of liquid CO2 passing through the pump (36, FIG. 2), as well as its pressure and temperature.

[0073] In some embodiments, the control unit 100 interrogates the liquid level sensor (35A in FIG. 2), and if the amount of liquid CO2 in the CO2 storage tank 35 exceeds a first threshold, e.g., 85% full, the control unit 100 starts the infusion pump 36. The infusion pump (36 in FIG. 2) runs until the control unit 100 detects when the liquid CO2 in the CO2 storage tank (35 in FIG. 2) falls below a second threshold, e.g., 15% full, and then switches off the infusion pump (36 in FIG. 2).

[0074] The control unit 100 monitors the pressure in the pipe (37, FIG. 2), the well (41, FIG. 2), and in some embodiments, the pressure in the well at its interface with the geological structure (50, FIG. 2). The control unit 100 may intermittently operate the injection pump (36, FIG. 2) depending on the amount of liquid CO2 present in the CO2 storage tank (35, FIG. 2). By intermittently operating the injection pump (36, FIG. 2), the pressure in the pipe (37, FIG. 2), the well (41, FIG. 2), and the geological structure (50, FIG. 2) fluctuates, which can improve the ability of the geological structure 50 to absorb CO2.

[0075] CO2 capture and storage systems and methods according to the present disclosure may offer one or more possible benefits over CO2 capture and storage known in the art prior to the present disclosure. Systems and methods according to the present disclosure may reduce costs and increase safety by eliminating the need to move liquefied CO2 over long distances using tanker ships or vehicles. Costs may be reduced and efficiencies increased by using heat from one or more underground wells to release CO2 from the absorbent rather than by using a separate heat source. The CO2 absorbent may be located in proximity to the CO2 gas source, while the CO2 stripping unit may be located near the disposal well, thereby eliminating the need for a large-capacity buffer reservoir near the disposal well. The systems and methods according to the present disclosure may be completely closed to the atmosphere, thereby eliminating the need to transfer CO2 between tanks, vessels, or other system components and risk atmospheric exposure when connections between those devices are made and broken.

[0076] In light of the principles and example embodiments described and illustrated herein, it will be recognized that example embodiments can be modified in arrangement and detail without departing from such principles. While the foregoing discussion has focused on particular embodiments, other configurations are contemplated. In particular, even if expressions such as "embodiment" are used herein, these phrases are meant to generally refer to possible embodiments and are not intended to limit the disclosure to specific embodiment configurations. As used herein, these terms may refer to the same or different embodiments that can be combined into other embodiments. In principle, unless otherwise indicated, any embodiment referenced herein can be freely combined with any one or more of the other embodiments referenced herein, and any number of features of different embodiments can be combined with each other. While only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of the present disclosure, as defined by the following claims.

Claims

1. 1. A carbon dioxide (CO2) capture and storage system comprising: a CO2 absorber tower positioned proximate to a source of CO2-containing gas from which CO2 is to be removed, the CO2 absorber tower including a CO2 gas inlet, a gas outlet, an absorbent inlet, and an absorbent outlet; a CO2 stripping tower positioned proximate to a well penetrating a subterranean geological formation, the CO2 stripping tower including an absorbent inlet, a gas outlet, an absorbent outlet, and a heating fluid inlet; a CO2 condensing unit disposed proximate to the stripping tower and operably connected to a gas outlet on the stripping tower, the CO2 condensing unit including at least one of a compressor and a cooler, wherein CO2 gas exiting the CO2 condensing unit is converted to a liquid phase, an outlet of the CO2 condensing unit in fluid communication with the well; A pipeline interposed between the CO2 absorption tower and the stripping tower, wherein the CO2 source and the well are separated from each other; A carbon dioxide (CO2) capture and storage system comprising:

2. 10. The system of claim 1, further comprising a CO2 storage tank proximate to the well and in fluid communication with the outlet of the CO2 condensing unit and the well, wherein the CO2 stored in the CO2 storage tank is released into the well at a selected time.

3. 3. The system of claim 2, wherein the CO2 storage tank includes a liquid level sensor positioned to measure the level of liquid CO2 in the CO2 storage tank, and the system further includes an injection pump interposed between the CO2 storage tank and the well, wherein the injection pump is operable to move the liquid CO2 from the CO2 storage tank to the well when the liquid level sensor reaches a first predetermined threshold.

4. 4. The system of claim 3, wherein the infusion pump is switched off when the infusion pump reaches a second predetermined threshold that is lower than the first predetermined threshold.

5. 10. The system of claim 1, further comprising a dehydration tower interposed between the gas outlet of the stripping tower and the inlet to the CO2 condensation unit, the dehydration tower containing a dehydration liquid through which the CO2 gas and water pass to extract the water from the CO2 gas and water.

6. The system of claim 5 , wherein the dehydration liquid comprises glycol.

7. 10. The system of claim 1, wherein the CO2 absorber tower includes a liquid absorbent therein, and gas entering the CO2 gas inlet travels upward as bubbles through the CO2 absorber tower to extract CO2 from the entering gas.

8. The system of claim 7 , wherein the liquid absorbent comprises an amine.

9. The system of claim 7 , wherein the liquid absorbent comprises carbonic anhydrase.

10. 10. The system of claim 1, further comprising a heating fluid pump and a heat exchanger, wherein the heating fluid pump is arranged to circulate a fluid through the underground well to extract heat from the fluid, and the heat exchanger is arranged to transfer heat to a fluid entering the heating fluid inlet of the stripping tower, the transferred heat being applied to a CO2-laden absorbent traveling through the stripping tower to result in the release of absorbed CO2.

11. 11. The system of claim 10, wherein the underground well is the same well as the well adjacent to the stripping tower.

12. 10. The system of claim 1, further comprising a control unit in signal communication with a liquid level sensor arranged to measure the level of liquid CO2 in the CO2 storage tank, the system further comprising an injection pump interposed between the CO2 storage tank and the well and in control communication with the control unit, the control unit arranged to operate the injection pump to move liquid CO2 from the CO2 storage tank to the well when the liquid level sensor reaches a first predetermined threshold.

13. 13. The system of claim 12, wherein the control unit is arranged to stop the infusion pump when the level reaches a second predetermined threshold that is lower than the first predetermined threshold.

14. 10. The system of claim 1, further comprising an agitator disposed in each of the absorption tower and the stripping tower, each agitator positioned to force liquid within the respective tower such that the liquid moves downwardly as a result of rotation of the respective agitator.

15. 10. The system of claim 1, wherein the source of CO2-containing gas comprises a combustion system, the combustion system emitting CO2-baring flue gas.

16. 1. A method for extracting and storing carbon dioxide (CO2) from a source of CO2-containing gas, comprising: transferring a CO2-containing gas from a source to a CO2 absorbent in a first vessel to produce a CO2-rich absorbent, the first vessel being disposed proximate to the source; transferring the CO2-rich sorbent to a second container spaced from the first container and proximate to the underground disposal well; heating the CO2-rich absorbent in the second vessel to liberate CO2 from the CO2-rich absorbent and returning the CO2-depleted absorbent to the first vessel; condensing the released CO2 into a liquid and storing the liquid CO2 until the level of the liquid CO2 increases to a first predetermined threshold; injecting the stored CO2 into a disposal well when the level exceeds a first predetermined threshold; A method comprising:

17. 17. The method of claim 16, further comprising dehydrating the liberated CO2 before condensing.

18. 17. The method of claim 16, wherein the dehydration comprises transferring the liberated CO2 through liquid glycol.

19. 17. The method of claim 16, wherein the absorbent comprises an amine.

20. 17. The method of claim 16, wherein the absorbent comprises carbonic anhydrase.

21. 17. The method of claim 16, wherein heating comprises pumping steam or heated water into the second vessel.

22. 22. The method of claim 21, wherein the heated water or steam is produced by circulating a fluid through an underground well and transferring heat from the circulating liquid to a fluid traveling into the second vessel.

23. 23. The method of claim 22, wherein the well through which the fluid is circulated is the same well into which the stored CO2 is injected.

24. 17. The method of claim 16, wherein the source of CO2 comprises a combustion plant.

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