A method and system for solidifying and storing carbon dioxide on the seabed

Abstract

A method and system for solidifying and sealing carbon dioxide on the seabed. The method comprises: determining a storage target area on the seabed according to the emission point of carbon dioxide (CO2); designing an injection well according to the geological environment of the storage target area, the injection well extending into the interior of the storage target area and / or below the storage target area; injecting CO2 and additives into the storage target area through the injection well, the additives comprising a kinetic promoter, a thermodynamic promoter, a kinetic inhibitor and a thermodynamic inhibitor of CO2 hydrate; and CO2 forming CO2 hydrate in the storage target area to seal the CO2 in the storage target area. The method for solidifying and sealing CO2 on the seabed provided in the present application can achieve safe, stable, efficient, environmentally friendly and large-scale geological storage of CO2 by solidifying and sealing CO2 in the storage target area by forming hydrate into CO2.

Description

Technical Field

[0001] The present application belongs to the technical field of carbon dioxide storage, and specifically relates to a method and system for subsea solidification and storage of carbon dioxide. Background Art

[0002] The geological storage method of carbon dioxide (CO2) usually involves injecting CO2 into geological bodies such as depleted oil and gas reservoirs or saline aquifers. The main storage mechanisms of conventional storage methods include dissolution storage, mineralization storage, structural storage, and residual storage. Although the above methods are relatively mature, they have strict requirements on geological bodies, and once the cap rock is destroyed, the buoyant gaseous or supercritical CO2 can easily escape back into the atmosphere through cracks or faults. In addition, some economically developed, densely populated, high-carbon emission areas are not suitable for the application of the above storage methods. Therefore, there is an urgent need to explore a new type of geological storage method that is efficient, safe, and more universal. Summary of the invention

[0003] In view of this, in order to solve at least one of the above technical problems, it is necessary to propose a new method and system for subsea solidification and storage of carbon dioxide.

[0004] The present application embodiment provides a method for subsea solidification and storage of carbon dioxide, the method comprising:

[0005] Identify storage targets on the seafloor based on carbon dioxide (CO2) emission points;

[0006] Designing an injection well according to the geological environment of the sealing target area, wherein the injection well extends into the interior of the sealing target area and / or below the sealing target area;

[0007] Injecting CO2 and additives into the storage target area through the injection well, wherein the additives include a kinetic promoter, a thermodynamic promoter, a kinetic inhibitor and a thermodynamic inhibitor of CO2 hydrate; and

[0008] CO2 forms CO2 hydrate in the storage target area to store CO2 in the storage target area.

[0009] In some embodiments, the kinetic promoter includes at least one of methionine, tryptophan, leucine, isoleucine, phenylalanine, sodium dodecyl sulfate, and sodium lignin sulfonate.

[0010] In some embodiments, the thermodynamic promoter includes at least one of tetrahydrofuran, 1,3 dioxolane, and cyclopentane.

[0011] In some embodiments, the kinetic inhibitor comprises at least one of an ionic liquid and a hydrophilic amino acid.

[0012] In some embodiments, the thermodynamic inhibitor comprises an alcohol compound.

[0013] In some embodiments, the conversion rate of CO2 hydrate is greater than or equal to 45%.

[0014] In some embodiments, the storage target area includes a sedimentary layer, the sedimentary layer includes a near-well end close to the injection well and a far-well end away from the injection well, and the step of injecting CO2 and additives into the storage target area through the injection well includes:

[0015] CO2 enters the near well end from the injection well, and seeps and diffuses through the near well end into the far well end, and the seepage and diffusion rate of CO2 at the near well end is greater than the seepage and diffusion rate at the far well end;

[0016] The step of forming CO2 hydrate in the storage target area includes:

[0017] CO2 forms the CO2 hydrate at the remote wellhead.

[0018] In some embodiments, in the step of injecting CO2 and additives into the storage target area through the injection well, the injection pressure of CO2 is 15MPa to 20MPa.

[0019] In some embodiments, the injection matching principle of the additive is to inhibit the formation of CO2 hydrate at the near well end and promote the formation of CO2 hydrate at the far well end.

[0020] In some embodiments, the seabed within a range of 1200m to 1800m from the sea surface is used as the storage target area; the temperature of the storage target area is 275K to 285K; the pressure of the storage target area is 12MPa to 20MPa; the porosity of the storage target area is 0.3 to 0.5; the permeability of the storage target area is 1mD to 2000mD; and the permeability anisotropy of the storage target area is 1 to 10.

[0021] In some embodiments, before the step of injecting CO2 and additives into the storage target area through the injection well, the method further comprises:

[0022] The CO2 is transported to the injection well by at least one of road transportation, pipeline transportation and ship transportation.

[0023] In some embodiments, the method further comprises:

[0024] The monitoring system is used to monitor before, during and after CO2 injection.

[0025] In some embodiments, the monitoring system includes a monitoring well. For muddy silt sand formations, the monitoring well is located 10m to 15m away from the injection well. For sandy formations, the monitoring well is located 20m to 50m away from the injection well.

[0026] The present application also provides a system for seabed solidification and sealing of carbon dioxide, which is used to execute the above-mentioned method for seabed solidification and sealing of carbon dioxide, and comprises: a CO2 collection system, a CO2 transportation system, an injection system and a storage target area, wherein the CO2 collection system is used to collect CO2 emitted from a CO2 emission point, the CO2 transportation system is used to transport the CO2 collected by the CO2 collection system to the injection system, and the injection system is used to inject CO2 and additives into the storage target area so that the CO2 forms CO2 hydrates in the storage target area and is sealed.

[0027] Compared with the prior art, the method and system for the solidification and storage of carbon dioxide on the seafloor provided in the embodiment of the present application utilizes the storage target area (i.e., the vast hydrate stability area on the seafloor) to store CO2 on a large scale in the form of hydrates, which can achieve safe, stable, efficient, and environmentally friendly geological storage of CO2. This method reduces energy consumption and saves costs by selecting the storage target area; by optimizing the design of injection wells and using additives, a large degree of rapid injection, seepage, and diffusion of CO2 in the storage target area and a high CO2 hydrate conversion rate are achieved; the formation of CO2 hydrates is highly stable and safe, and the generated CO2 hydrates can not only serve as a low-permeability caprock to limit the further migration of CO2, but also self-seal the original fractures in the formation to prevent CO2 from escaping. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] Figure 1 A process flow chart of a method for subsea solidification and storage of carbon dioxide provided in one embodiment of the present application.

[0029] Figure 2 Schematic diagram of temperature and pressure conditions of a target area for storing carbon dioxide hydrate in one embodiment of the present application.

[0030] Figure 3 A schematic structural diagram of a system for subsea solidification and storage of carbon dioxide provided in one embodiment of the present application.

[0031] Figure 4 This is a schematic diagram of the sealing process of the method for seabed solidification and sealing of carbon dioxide in Example 1 of the present application.

[0032] Main component symbols

[0033] System for solidification and storage of carbon dioxide on the sea floor100

[0034] CO2 Collection System 10

[0035] CO2 Transport System 20

[0036] Coastal temporary storage area 30

[0037] Injection system 40

[0038] Sealed target area 50

[0039] Monitoring system 60

[0040] CO2 collection device 11

[0041] Compression device 12

[0042] Coastal Storage Tank 31

[0043] Coastal Supply Station 32

[0044] Injection platform 41

[0045] Injection well 42

[0046] Monitoring device 61

[0047] Monitoring well 62

[0048] The following specific implementation methods will further illustrate the present application in conjunction with the above-mentioned drawings. DETAILED DESCRIPTION

[0049] The following will be combined with the drawings in the embodiments of the present application to clearly and completely describe the technical solutions in the embodiments of the present application. Obviously, the described embodiments are only part of the embodiments of the present application, not all of the embodiments. Based on the embodiments of the present application, all other embodiments obtained by those skilled in the art without creative work are within the scope of protection of the present application.

[0050] See also Figure 1 , the embodiment of the present application provides a method for solidifying and storing carbon dioxide on the seafloor. The method specifically comprises the following steps:

[0051] Step S1, determining the storage target area on the seabed.

[0052] The specific steps may include:

[0053] Step S11, selecting a potential storage target area according to relevant parameters of the carbon dioxide (CO2) emission point.

[0054] Among them, CO2 emission points are CO2 point sources, which refer to places where a large amount of CO2 is produced in a specific location or process. These CO2 point sources are one of the main sources of increased CO2 concentration in the atmosphere, including exhaust emissions from industrial processes such as coal-fired power plants, steel production and cement production.

[0055] The process of determining potential storage targets based on CO2 point sources is as follows: First, comprehensively measure the CO2 concentration, emission rate and emission time of different types of CO2 emission points. Second, select the storage target area close to the CO2 point source as the potential storage target area. Considering that the geographical distance between the CO2 emission point and the storage target area will affect the cost and technical requirements of CO2 transportation, selecting the storage target area close to the CO2 point source can reduce the energy consumption and cost during the transportation process.

[0056] The above source-sink matching method is used to conduct preliminary screening and identification of storage target areas to obtain potential storage target areas.

[0057] Step S12: Conduct stability assessment and reserve assessment on potential storage target areas to determine the final storage target areas.

[0058] Specifically: First, based on the evaluation of factors such as temperature and pressure in the storage target area, the thermodynamic stability conditions for hydrate storage are predicted.

[0059] Secondly, a detailed geological assessment is conducted, including the assessment of geological characteristics such as porosity, permeability, and heterogeneity to ensure the stability of the geological layer, which can accommodate the specified amount of CO2 and maintain the stability of the storage. The storage target area should have good mechanical stability to prevent formation instability during CO2 injection, and should have appropriate porosity and permeability to ensure smooth CO2 injection.

[0060] Finally, based on geological conditions, reservoir thickness, storage temperature and pressure conditions, the storage capacity is evaluated and matched with the CO2 point source emissions, and the storage target area where CO2 hydrates can be stably stored is finally determined. Specifically, the estimated storage capacity of the storage target area Should be greater than the CO2 emissions from the corresponding CO2 point source Using the above process to determine the storage target area of ​​CO2 hydrate can reduce transportation energy consumption, save costs, and increase the storage capacity of CO2 and the storage stability of CO2 hydrate.

[0061] In some embodiments, the depth of the storage target area from the sea level can be 1200m to 1800m, that is, the storage of CO2 within the range of 1200m to 1800m from the sea level can improve the stability of CO2 hydrates, and can further be 1300m to 1600m, and can be 1300m, 1400m, 1500m, and 1600m by way of example. The thickness of the reservoir can be designed according to the actual reserve requirements. Within the depth range of the above storage target area, the reservoir thickness can be 50m to 300m, and can further be 100m to 300m, and can further be 200m to 300m, and can be 50m, 100m, 150m, and 300m by way of example.

[0062] In some embodiments, the temperature range of the determined seabed storage target area can be 275K to 285K, and further can be 277.6K to 284K; the pressure range of the storage target area can be 12.0MPa to 20MPa, and further can be 15MPa to 18.2MPa. The storage target area at the above temperature and pressure can improve the stability of CO2 hydrate.

[0063] like Figure 2 As shown in the figure, the temperature and pressure conditions of the storage target area need to meet the phase equilibrium conditions of CO2 hydrate, that is, there is an intersection area between the seabed sediment temperature and pressure variation curve with depth and the CO2 hydrate phase equilibrium stability zone to meet the thermodynamic stability conditions of CO2 hydrate.

[0064] In some embodiments, the porosity of the storage target area may be 0.3-0.5, the permeability may be 1mD-2000mD, the permeability anisotropy may be 1-10, and the storage target area may have heterogeneity. Formation properties such as porosity, permeability, permeability anisotropy and heterogeneity of the storage target area are important factors affecting the storage potential. They should be able to accommodate a specified amount of CO2 and have appropriate porosity and permeability to ensure smooth CO2 injection. This embodiment limits the porosity, permeability and permeability anisotropy to the above ranges, which can effectively improve the CO2 storage efficiency.

[0065] Step S2, designing injection wells according to the geological environment of the storage target area, wherein the injection wells extend into the interior of the storage target area and / or below the storage target area. Specifically, by conducting a systematic geological exploration and assessment of the storage target area, the injection wells are designed and arranged based on geological data, and an optimized well layout plan is determined to maximize the total amount of CO2 stored.

[0066] In some embodiments, there can be one or more injection wells. If there are multiple injection wells, the optimal spacing between two adjacent injection wells should also be considered to balance injection efficiency and resource protection. In some embodiments, when there are multiple injection wells, the spacing between two adjacent injection wells can be 30m to 50m.

[0067] In some embodiments, the wellbore diameter of the injection well can be 0.1m to 0.2m, and the injection section length can be 20m to 100m. By optimizing the wellbore diameter and injection section length of the injection well to adapt to the geological conditions of different storage target areas, the CO2 injection and storage efficiency can be improved at the same time. This step can help achieve rapid injection, seepage and diffusion of CO2, and achieve the purpose of comprehensive and efficient generation of CO2 hydrates in the storage target area.

[0068] In some embodiments, before forming the injection well, an injection platform (i.e., drilling platform) needs to be set up on the sea surface corresponding to the sealed target area. The injection platform can include various forms, including fixed drilling platforms, jack-up drilling platforms, semi-submersible drilling platforms, and drilling ships.

[0069] In some embodiments, the injection well may be a vertical well, a horizontal well, a multi-branch well, or a well pattern system.

[0070] In some embodiments, the injection position of the injection well can be located inside the storage target area, or set below the storage target area, or can be set inside and below the storage target area at the same time. That is, the injection position of the injection well can be set inside the CO2 hydrate formation stable zone, or can be set below the CO2 hydrate formation stable zone, or injection wells can be set inside and below the CO2 hydrate formation stable zone. The CO2 hydrate generated in the stable zone fully seeps and diffuses in the stable zone of the storage target area to achieve large-scale storage of CO2; CO2 hydrates outside the formation stable zone eventually migrate to the CO2 hydrate formation stable zone through seepage and diffusion, and at the same time, the rapid generation of CO2 hydrates after injection can be avoided to affect subsequent injection. Injection outside the hydrate formation stable zone can also effectively reduce the risk of CO2 leakage due to its distance from the seabed mud line.

[0071] Step S3, injecting CO2 and additives into the storage target area through the injection well, wherein the additives include a kinetic promoter, a thermodynamic promoter, a kinetic inhibitor and a thermodynamic inhibitor of CO2 hydrate.

[0072] The injection method of CO2 mainly includes the selection and matching of injection platform, injection well type, injection location, injection pressure, injection rate and time. The CO2 injection pressure is generally greater than the reservoir pressure and less than the formation fracture pressure; the injection rate and time need to be determined according to the specific formation mechanical properties and required reserves. According to the previous investigation of reservoir geological conditions and the previous injection experiments and simulations, choosing a suitable injection method is the key to achieving efficient conversion of CO2 into CO2 hydrate.

[0073] In some embodiments, the sequestration target area may include a sedimentary layer, wherein the sedimentary layer includes a near-wellbore end close to the injection well and a far-wellbore end far from the injection well.

[0074] Step S3 specifically includes: CO2 enters the near well end from the injection well, and seeps and diffuses into the far well end through the near well end, and the seepage and diffusion rate of CO2 at the near well end is greater than the seepage and diffusion rate at the far well end.

[0075] The injection methods of additives mainly include the selection and matching of single injection, injection with CO2, injection in stages, and injection in different positions. The injection matching principle of additives is to inhibit the formation of CO2 hydrates at the near well end and promote the formation of CO2 hydrates at the far well end, so as to ensure that CO2 is fully diffused in the sedimentary layer of the storage target area, avoid pore blockage caused by the formation of CO2 hydrates near the injection well, and affect the total amount of CO2 storage. At the same time, ensure that CO2 hydrates are quickly generated when CO2 is fully diffused, and convert CO2 into CO2 hydrates to the greatest extent. Through the injection of additives, the controllable formation of CO2 hydrates can be achieved.

[0076] In some embodiments, the kinetic promoter may include at least one of methionine, tryptophan, leucine, isoleucine, phenylalanine, sodium dodecyl sulfate, and sodium lignin sulfonate. Adding a kinetic promoter at the time stage and regional location where rapid generation of CO2 hydrate is required can effectively shorten the induction time of CO2 hydrate generation, accelerate the generation rate of CO2 hydrate, and improve the conversion rate of CO2 hydrate. Ultimately, efficient conversion of CO2 hydrate is achieved when CO2 hydrate needs to be generated, achieving the goals of generating a CO2 hydrate cap, improving the stability and storage capacity of CO2 storage by the hydrate method, and preventing CO2 from leaking in liquid or gaseous form.

[0077] In some embodiments, the thermodynamic promoter may include at least one of tetrahydrofuran, 1,3-dioxolane and cyclopentane. Thermodynamic promoters include substances that can reduce the phase equilibrium conditions for the formation of CO2 hydrates. Usually, the formation of CO2 hydrates requires low temperature and high pressure conditions. After adding thermodynamic promoters, CO2 hydrates can be generated at higher temperatures and lower pressures, that is, the temperature and pressure range of CO2 hydrate formation is increased, and the range of CO2 hydrate storage target areas is expanded. In addition, the seabed environmental conditions are complex, and the most significant is that high salinity will inhibit the phase equilibrium of CO2 hydrates, that is, salt substances are thermodynamic inhibitors of CO2 hydrates. In order to generate CO2 hydrates under high salinity conditions on the seabed, it is necessary to increase thermodynamic promoters to increase the driving force for the formation of CO2 hydrates, so as to achieve the purpose of promoting the rapid and efficient generation of CO2 hydrates.

[0078] In some embodiments, the kinetic inhibitor may include at least one of an ionic liquid and a hydrophilic amino acid, etc. The ionic liquid may include at least one of N-butyl-N-methylpyrrolidino tetrafluoroborate ([BMP][BF4]), tetramethylammonium chloride ([TMA][CL]), and tetraethylammonium chloride ([TEA][CL]), etc.; the hydrophilic amino acid may include at least one of glycine, alanine, and valine, etc.

[0079] In some embodiments, the thermodynamic inhibitor includes an alcohol compound, which may include at least one of methanol, ethanol, and ethylene glycol.

[0080] The purpose of adding kinetic inhibitors and thermodynamic inhibitors is the same, that is, to inhibit the formation of CO2 hydrates at the time stage and regional location where CO2 hydrate formation is not desired, such as preventing the formation of CO2 hydrates near the wellbore to block the wellbore, and generating a large amount of hydrates in the pores near the wellbore to hinder the subsequent CO2 seepage and diffusion, etc. However, the action principle of kinetic inhibitors and thermodynamic inhibitors is different. Thermodynamic inhibitors are achieved by increasing the thermodynamic conditions required for the formation of CO2 hydrates, that is, reducing the temperature required for the formation of CO2 hydrates, increasing the pressure required for the formation of CO2 hydrates, and making the formation of CO2 hydrates more difficult; kinetic inhibitors do not change the phase equilibrium conditions for the formation of CO2 hydrates, but can significantly prolong the induction time of CO2 hydrate crystal nucleation, or slow down the formation rate of CO2 hydrate crystal growth process, so that the formed hydrates are not enough to aggregate into clusters, thereby avoiding blocking the wellbore or pore channels, etc.

[0081] CO2 and additives are injected into the storage target area through the injection well. For example, after the initial injection of CO2, a CO2 hydrate promoter is injected at the upper position of the storage target area to form a CO2 hydrate cap layer to prevent CO2 from floating up and leaking. The CO2 hydrate promoter includes the aforementioned kinetic promoter and the aforementioned thermodynamic promoter; a CO2 hydrate inhibitor is injected near the wellhead to prevent CO2 hydrate from forming and blocking the wellbore, thereby affecting the diffusion and migration of CO2. The CO2 hydrate inhibitor includes the aforementioned kinetic inhibitor and thermodynamic inhibitor; when the CO2 injection in the storage target area reaches saturation, a CO2 hydrate promoter is injected into the entire storage target area to achieve the maximum conversion rate of CO2 hydrates. The controllable generation of CO2 hydrates is achieved by the combined injection of CO2 hydrate promoters and inhibitors.

[0082] Before step S3, the method further includes:

[0083] The CO2 is transported to the injection well by at least one of road transport, pipeline transport and ship transport. This process is the transportation of CO2, that is, the CO2 captured at the CO2 point source is transported to the storage target area by different means. In addition, during the transportation of CO2, the CO2 needs to be compressed.

[0084] In some embodiments, CO2 is transported by road, pipeline and ship. Specifically, CO2 captured from a CO2 point source is initially compressed by a compression pump and stored in a storage tank, then transported to the coast by road, and then further compressed and stored in a coastal storage tank. The storage tank transports the further compressed CO2 to a coastal CO2 supply station through a pipeline, and finally, the CO2 is transported to the injection platform on the storage target area by ship.

[0085] Step S4, CO2 forms CO2 hydrate in the storage target area to store CO2 in the storage target area.

[0086] Specifically, CO2 enters the near well end from the injection well, diffuses through the near well end into the far well end and forms CO2 hydrate at the far well end.

[0087] CO2 hydrate formation is the process of CO2 hydrate formation from gaseous CO2 or liquid CO2 and water, which includes the seepage, diffusion and phase change reaction of CO2 in the sedimentary layer. As mentioned above, the design of the aforementioned injection method can effectively improve the seepage and diffusion efficiency of CO2 and the conversion efficiency of CO2 hydrate. In addition, through the combination of the aforementioned additives, the rapid seepage and diffusion of CO2 near the wellbore end and the rapid phase change reaction of hydrate at the far wellbore end can be further achieved.

[0088] CO2 hydrate is a stable solid structure that can exist stably in the low temperature, high pressure and relatively closed environment of seabed sediments. Compared with other forms of CO2 (liquid CO2, supercritical CO2, etc.), CO2 hydrate has higher stability and can prevent CO2 leakage, which can be compared to the long-term stable existence of natural gas hydrates in nature. CO2 hydrate has a high gas storage density. 1 volume of CO2 hydrate can store 150 to 170 volumes of CO2. Compared with the existing CO2 storage technology (such as saline layer storage, depleted oil and gas reservoir storage, etc.), the hydrate method provided in the embodiment of the present application can store a large amount of CO2 in a relatively small pore space, thereby improving the storage efficiency. The CO2 hydrate in the sedimentary layer can form a self-sealing system. The generated CO2 hydrate can not only serve as a low-permeability caprock to limit the further migration of CO2, but also self-seal the original cracks in the formation to prevent the possible escape of CO2. The sealing method of the embodiment of the present application can effectively reduce the requirements for formation conditions and improve the sealing stability. The hydrate method CO2 storage technology provided in the embodiment of the present application is suitable for the low temperature and high pressure environment of the seabed, and can be carried out without disturbing the ecological environment of the ocean surface and seabed, reducing the damage to the marine environment, and at the same time, compared with the existing storage methods, it can also reduce the waste of land resources. In addition, the large-scale storage of CO2 through the seabed hydrate method will help mitigate climate change, reduce the concentration of greenhouse gases in the atmosphere, and reduce the rate of global temperature rise.

[0089] In addition to the above steps, the method further comprises:

[0090] The monitoring system is used to monitor before, during and after CO2 injection.

[0091] In some embodiments, formation water and seismic monitoring are required before injection, and basic conditions of the target formation, including salinity, pH, burial depth, temperature, etc., need to be monitored. During the injection process, the injection well temperature and pressure, wellbore integrity and corrosiveness need to be monitored to ensure the smooth progress of the injection process. Detection during the CO2 injection process can specifically include: monitoring of the CO2 injection stage, the CO2 diffusion and migration stage, and the CO2 hydrate formation stage. During and after the injection process, the formation rate of CO2 hydrates needs to be monitored to ensure the timeliness and effectiveness of hydrate formation, track the migration and diffusion of CO2 underground, monitor whether there is a risk of CO2 leakage, and monitor the uplift of the formation to prevent the instability of the sealed formation.

[0092] In some embodiments, the monitoring methods may include seismic monitoring, resistivity logging, pressure monitoring, temperature monitoring, geomagnetic monitoring, hydrate imaging technology, etc., through which the diffusion and migration of CO2, the stratigraphic distribution of CO2 hydrates and the long-term storage stability of CO2 hydrates are determined.

[0093] In some embodiments, the monitoring system may include monitoring wells. The layout of the monitoring wells needs to be determined according to the specific formation properties and injection methods. In the embodiment of the present application, for muddy silt sand formations, the monitoring wells can be located 10m to 15m from the injection well. For sandy formations, the monitoring wells can be located 20m to 50m from the injection well.

[0094] The method for solidifying and storing carbon dioxide on the seabed provided in the embodiment of the present application utilizes the storage target area (i.e., the vast hydrate stable area on the seabed) to store CO2 on a large scale in the form of hydrates, which can achieve safe, stable, efficient, and environmentally friendly geological storage of CO2. This method reduces energy consumption and saves costs by selecting the storage target area; by optimizing the design of injection wells and using additives, a large degree of rapid injection and diffusion migration of CO2 in the storage target area and a high CO2 hydrate conversion rate are achieved; the formation of CO2 hydrates has high stability and safety, and the generated CO2 hydrates can not only serve as a low-permeability caprock to limit the further migration of CO2, but also self-block the original fractures of the formation to prevent CO2 from escaping.

[0095] See also Figure 3 , the embodiment of the present application also provides a system 100 for the solidification and sealing of carbon dioxide on the seabed, which can be used to perform the aforementioned method for the solidification and sealing of carbon dioxide on the seabed. The system 100 for the solidification and sealing of carbon dioxide on the seabed may include: a CO2 collection system 10, a CO2 transportation system 20, an injection system 40, and a storage target area 50. Among them, the CO2 collection system 10 is used to collect CO2 emitted from the CO2 emission point, the CO2 transportation system 20 is used to transport the CO2 collected by the CO2 collection system 10 to the injection system 40, and the injection system 40 is used to inject CO2 and additives into the storage target area 50. Under the action of the additive, CO2 diffuses into the storage target area 50 and undergoes a phase change reaction to form CO2 hydrates, so as to be sealed in the storage target area 50.

[0096] The CO2 collection system 10 may include a CO2 collection device 11. CO2 is emitted from a CO2 emission point and collected by the CO2 collection device 11. It is understood that before the CO2 collection device 11 collects CO2, the CO2 may be compressed by a compression device 12. In some embodiments, the compression device 12 may be a reciprocating compression pump.

[0097] The CO2 transport system 20 may include at least one of a road transport device, a pipeline transport device, and a ship transport device. Specifically, the embodiments of the present application may use the above three methods to transport CO2. In some embodiments, the road transport device may be a CO2 tanker, the pipeline transport device may be a transport pipeline, and the ship transport device may be a CO2 transport ship.

[0098] In some embodiments, a coastal temporary storage area 30 may be set up along the coast near the storage target area 50, wherein the coastal temporary storage area 30 may include a coastal storage tank 31 and a coastal supply station 32, and the coastal storage tank 31 and the coastal supply station 32 may be connected via a pipeline transportation device.

[0099] Specifically, CO2 is transported to the coastal storage tank 31 for temporary storage by road transportation equipment, and then the CO2 in the coastal storage tank 31 is transported to the small sub-storage tank at the coastal supply station 32 by pipeline transportation equipment for easy handling, and then the small sub-storage tank is transported to the injection system 40 by ship transportation equipment.

[0100] In some embodiments, the CO2 in the CO2 tanker truck may be further compressed by a compression device and then transported to the coastal storage tank 31 for temporary storage.

[0101] The injection system 40 may include an injection platform 41 located on the sea surface above the sealing target area 50 and an injection well 42, and the injection well 42 extends into the sealing target area 50. In some embodiments, the injection platform 41 may include a fixed drilling platform, a self-elevating drilling platform, a semi-submersible drilling platform, and a drilling ship. In some embodiments, the well type of the injection well 42 may be a vertical well, a horizontal well, a multi-branch well, and a well network system. In some embodiments, the injection position of the injection well 42 may be located inside the sealing target area 50, or may be set outside the sealing target area 50.

[0102] The system 100 for subsea solidification storage of carbon dioxide may further include a monitoring system 60, which includes a monitoring device 61 and a monitoring well 62, and the monitoring well 62 may be connected to the storage target area 50 to monitor the interior of the storage target area 50. The monitoring device 61 may include a seismic monitoring device, a resistivity monitoring device, a pressure monitoring device, a temperature monitoring device, a geomagnetic monitoring device, and a hydrate imaging device.

[0103] The above-mentioned CO2 seabed storage method is further described below through specific examples.

[0104] like Figure 4 As shown, in this embodiment, the coal-fired power plant is used as the CO2 emission point, and the specific process of the method for subsea solidification and storage of carbon dioxide includes the following steps:

[0105] Step 1: Estimate the cumulative CO2 emissions and estimated storage capacity of coal-fired power plants.

[0106] Step 2: Analyze the storage target area of ​​seabed CO2 hydrates in the local area of ​​the coal-fired power plant based on temperature, pressure and reservoir conditions.

[0107] Step 3: Determine the optimal seabed CO2 hydrate storage target area based on the matching of storage distance and storage capacity.

[0108] The sea surface temperature, depth from the sea surface, temperature and pressure conditions of the CO2 hydrate storage target area in this embodiment are as follows: Figure 2 As shown, the sea surface temperature is 295.2K, the depth of the storage target area is 1500m, the corresponding temperature range of the storage target area is 277.6K~284.0K, the pressure range of the storage target area is 15.0MPa~18.2MPa, and the reservoir thickness is 300m.

[0109] Step 4: The CO2 emitted by the coal-fired power plant is separated and collected from the flue gas after passing through a CO2 collection device (such as a CO2 capture separator), and then compressed by a compression device (such as a CO2 reciprocating compression pump) and injected into a CO2 storage tank.

[0110] Step 5: The CO2 in the storage tank is transported to the CO2 coastal supply station via road transportation equipment (such as a CO2 tanker).

[0111] Step 6: The CO2 transported by the CO2 tanker is pumped into the coastal storage tank by a reciprocating compression pump, and is further distributed into small sub-storage tanks at the coastal supply station through pipelines for temporary storage.

[0112] Step 7: Transport the small sub-storage tanks at the coastal supply station to the offshore CO2 injection platform via transport ships.

[0113] Step 8: Inject CO2 and CO2 hydrate additives into the target area for storing seabed CO2 hydrates through injection wells. In this embodiment, a single-well injection method is adopted. While injecting, smooth seepage and diffusion of CO2 can be achieved near the well end, and CO2 hydrates can be generated quickly and efficiently at the far well end.

[0114] Step 9: Set up a CO2 hydrate storage stability monitoring station and supporting CO2 hydrate storage monitoring equipment to monitor the geological exploration stage before injection, the CO2 injection stage and the stable storage stage after CO2 hydrate formation. The monitoring time starts from the beginning of storage implementation and maintains a stable monitoring period of at least 100 years.

[0115] The description of the above embodiments is only used to help understand the method of the present application and its core idea; in addition, for ordinary technicians in this field, various other corresponding changes and deformations can be made according to the technical concept of the present application, and all these changes and deformations should fall within the scope of protection of the claims of the present application.

Claims

1. A method for solidifying and storing carbon dioxide on the seabed, characterized in that: include: Identify storage targets on the seafloor; An injection well is designed according to the geological environment of the sealing target area, the injection well extends into the interior of the sealing target area and / or below the sealing target area, the sealing target area includes a sedimentary layer, and the sedimentary layer includes a near well end close to the injection well and a far well end far from the injection well; Injecting CO2 and additives into the storage target area through the injection well, wherein the additives include a kinetic promoter, a thermodynamic promoter, a kinetic inhibitor and a thermodynamic inhibitor of CO2 hydrate; and CO2 forms CO2 hydrate in the storage target area to store CO2 in the storage target area, The additives are injected into the sealing target area in stages and positions. In the initial stage, the kinetic promoter and the thermodynamic promoter are injected into the upper position of the sealing target area. The kinetic inhibitor and the thermodynamic inhibitor are injected at the near well end, and the kinetic promoter and the thermodynamic promoter are injected at the far well end; when the CO2 injection in the storage target area reaches saturation, the kinetic promoter and the thermodynamic promoter are injected into the entire storage target area.

2. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: The kinetic promoter includes at least one of methionine, tryptophan, leucine, isoleucine, phenylalanine, sodium dodecyl sulfate and sodium lignin sulfonate; The thermodynamic promoter includes at least one of tetrahydrofuran, 1,3-dioxolane and cyclopentane; The kinetic inhibitor comprises at least one of an ionic liquid and a hydrophilic amino acid; The thermodynamic inhibitor includes an alcohol compound.

3. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: The step of injecting CO2 and additives into the storage target area through the injection well comprises: CO2 enters the near well end from the injection well, and seeps and diffuses through the near well end into the far well end, and the seepage and diffusion rate of CO2 at the near well end is greater than the seepage and diffusion rate at the far well end; The step of forming CO2 hydrate in the storage target area includes: CO2 forms the CO2 hydrate at the remote wellhead.

4. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: In the step of injecting CO2 and additives into the storage target area through the injection well, the injection pressure of CO2 is 15 MPa~20 MPa.

5. The method for seafloor solidification and storage of carbon dioxide according to claim 3, characterized in that: The injection matching principle of the additive is to inhibit the formation of CO2 hydrate at the near well end and promote the formation of CO2 hydrate at the far well end; The conversion rate of the CO2 hydrate is greater than or equal to 45%.

6. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: The seabed within a range of 1200 m to 1800 m from the sea surface is the storage target area; The temperature of the sealed target area is 275 K~285 K; The pressure of the sealing target area is 12 MPa~20 MPa; The porosity of the sealing target area is 0.3-0.5; The permeability of the sealing target area is 1 mD~2000 mD; The permeability anisotropy of the sealing target area is 1-10.

7. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: Before the step of injecting CO2 and additives into the storage target area through the injection well, the method further includes: The CO2 is transported to the injection well by at least one of road transportation, pipeline transportation and ship transportation.

8. The method for subsea solidification and storage of carbon dioxide according to claim 1, characterized in that: The method further comprises: The monitoring system is used to monitor before, during and after CO2 injection.

9. The method for subsea solidification and storage of carbon dioxide according to claim 8, characterized in that: The monitoring system includes a monitoring well. For muddy silt sand formations, the monitoring well is located 10 m to 15 m away from the injection well. For sandy formations, the monitoring well is located 20 m to 50 m away from the injection well.

10. A system for solidifying and storing carbon dioxide on the seabed, characterized in that: The system for seabed solidification and sealing of carbon dioxide is used to perform the method for seabed solidification and sealing of carbon dioxide as described in any one of claims 1 to 9, and the system for seabed solidification and sealing of carbon dioxide comprises: a CO2 collection system, a CO2 transportation system, an injection system and a storage target area, the CO2 collection system is used to collect CO2 emitted from a CO2 emission point, the CO2 transportation system is used to transport the CO2 collected by the CO2 collection system to the injection system, and the injection system is used to inject CO2 and additives into the storage target area so that the CO2 forms CO2 hydrates in the storage target area and is sealed.

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