A method for increasing carbon dioxide storage capacity using aerosol foaming agents

Abstract

This invention relates to the field of carbon storage and utilization technology, specifically disclosing a method for increasing carbon dioxide storage capacity using an aerosolized foaming agent. The invention employs an aerosolized foaming agent, which not only utilizes formation water for in-situ foaming to increase carbon storage space but also achieves dynamic stability after foam collapse. In-situ foaming is achieved around the wellbore through alternating injection of a pre-placed aerosolized foaming agent slug and a post-placed CO2 slug. By setting a real-time injection pressure feedback mechanism to dynamically adjust the injection method, early carbon dioxide breakthrough and loss are reduced, significantly improving storage efficiency and effectively enhancing the carbon dioxide storage effect.

Description

Technical Field

[0001] This invention relates to the field of carbon storage and utilization technology, specifically a method for increasing the amount of carbon dioxide stored using an aerosol foaming agent. Background Technology

[0002] Carbon capture, utilization, and storage (CCUS) technology is a key technology for capturing, converting, and storing carbon dioxide. By injecting carbon dioxide into underground reservoirs, we can permanently store carbon dioxide, thereby reducing its negative impacts on climate change. Currently, geological sites such as deep saline aquifers and depleted oil and gas reservoirs have stable geological characteristics and can effectively store large amounts of carbon dioxide, making them ideal carbon dioxide storage sites.

[0003] Directly injecting carbon dioxide into deep saline aquifers and depleted oil and gas reservoirs (especially high water-cut reservoirs) for storage presents challenges during immiscible flooding. The low viscosity and density of carbon dioxide lead to viscous fingering and gravity differentiation, while reservoir heterogeneity exacerbates the problem, resulting in severe carbon dioxide channeling, low sweep efficiency, and ultimately, low storage efficiency. Currently, one of the most common methods to improve the geological storage capacity of carbon dioxide is to disperse it in the aqueous phase to form foam, which is then injected into the formation for storage. When carbon dioxide foam is injected into saline aquifers, its high viscosity effectively controls carbon dioxide flow, reduces channeling, expands the sweep range, and improves storage efficiency. When injected into high water-cut reservoirs, the foam effectively blocks high-permeability channels, improving both oil recovery and the amount and safety of carbon dioxide stored.

[0004] However, conventional foam flooding technology has some limitations. For example, it is difficult to inject into low-permeability reservoirs, the foam has poor stability leading to collapse and dissipation, and there are problems such as high water content and low gas content, which ultimately result in low foam flooding storage efficiency.

[0005] To address the aforementioned issues, Chinese patent CN115341896A proposes a method for improving CO2 sequestration efficiency using high-dryness foam. This method increases the CO2 phase content and decreases the aqueous phase content in the foam, resulting in a higher carbon sequestration capacity than conventional foam. However, due to the poor stability of this foam, a significant increase in carbon sequestration only begins to appear after a large amount of PV foam has been injected. Furthermore, since the foam is formed on the ground before injection, injection difficulties and extremely high injection pressures are inevitable. Additionally, the foaming agent is only soluble in water and lacks the ability to dissolve in CO2; after being mixed and injected into the reservoir from the ground, it is prone to gas-liquid separation and failure.

[0006] Chinese patent CN118128594A discloses a method for improving the stability of nano-armored carbon dioxide foam, thereby enhancing geological storage. This method primarily achieves strong storage and expanded sweep effect by increasing foam stability. However, increasing foam stability necessitates increasing the viscosity of the base fluid. Increased base fluid viscosity, however, makes it difficult to generate foam underground. Furthermore, nanoparticles can clog the formation, causing reservoir damage. In addition, the foaming agent in this method is only soluble in water and not in CO2. Although nanoparticles improve foam stability to some extent, gas-liquid separation still occurs, resulting in the foam only functioning around the wellbore and failing to penetrate the reservoir, leading to poor CO2 storage performance.

[0007] Chinese patent CN103867169A discloses a method for controlling carbon dioxide mobility using aerosolized surfactants. This method requires the aerosolized surfactant to be uniformly mixed with supercritical carbon dioxide and then directly injected into the reservoir. However, because the mixture of carbon dioxide and aerosolized surfactant is injected in a single step, it is difficult to form a stable foam structure around the wellbore. As the aerosolized surfactant migrates deeper into the reservoir, it is lost through adsorption in the rock, easily leading to early breakthrough and loss of carbon dioxide in the formation, affecting long-term carbon sequestration. Simultaneously, it cannot effectively respond to dynamic changes under complex formation conditions, easily resulting in low carbon dioxide sequestration levels. Furthermore, the aerosolized surfactant used has low solubility in supercritical carbon dioxide, resulting in poor foam stability. Moreover, this method struggles to form a stable foam sealing barrier in the reservoir.

[0008] In summary, existing technologies for improving carbon dioxide sequestration suffer from problems such as high injection pressure, difficult injection, foaming agents that can only dissolve in water and cannot be carried by CO2, low content of water and carbon dioxide phases in the foam, poor foam stability, limited ability to expand the range of impact, and inability to adjust the injection method in real time according to complex geological conditions. As a result, the final geological sequestration of carbon dioxide is low, and there is an urgent need to develop a method for high geological sequestration of carbon dioxide. Summary of the Invention

[0009] This invention addresses the shortcomings of existing technologies by providing a method for increasing carbon dioxide storage capacity using an aerosolized foaming agent. By dissolving the aerosolized foaming agent in supercritical carbon dioxide and injecting it into the formation, in-situ foaming is achieved directly using formation water through the shearing action of a porous medium. This reduces the saturation of bound water, increasing the carbon storage space for carbon dioxide. After the foam bursts, the aerosolized foaming agent is carried to the surface by the supercritical carbon dioxide and re-foams upon encountering formation water, achieving the effects of burst regeneration and dynamic stabilization (dynamic stabilization differs from static stabilization; it no longer solely pursues high foam half-life or liquid half-life, but rather focuses on the regeneration of foam after bursting). This facilitates further expansion of the swept volume. The generated foam, due to its intelligent selectivity of "blocking high-permeability zones but not low-permeability zones," forces carbon dioxide to displace residual oil after blocking high-permeability zones, achieving improved oil recovery. Simultaneously, the production of residual oil provides carbon storage space for carbon dioxide storage. Furthermore, this invention employs a segmented, alternating injection of a pre-placed aerosolized foaming agent slug and a post-placed CO2 slug to achieve in-situ foaming around the wellbore, forming a dynamic foam barrier structure that blocks high-permeability channels. This segmented, alternating injection method leverages the complex pressure field of the formation to enhance the controllability of the aerosolized foaming agent, effectively extending the residence time of carbon dioxide in the formation and continuously expanding the affected area through a foam rupture and regeneration mechanism, thereby significantly increasing carbon sequestration. This invention also incorporates a real-time injection pressure feedback mechanism, dynamically adjusting the injection method by monitoring pressure changes during the injection process to ensure long-term stable distribution of carbon dioxide in the formation, reducing early carbon dioxide breakthrough and loss, significantly improving sequestration efficiency, and effectively enhancing the carbon dioxide sequestration effect.

[0010] To achieve the above objectives, the present invention adopts the following technical solution:

[0011] A method for increasing carbon dioxide storage capacity using an aerosol foaming agent specifically includes the following steps:

[0012] S1. The pre-aerosol foaming agent slug and the post-CO2 slug are injected into the geological storage body in stages and alternately. The injection pressure continues to rise. When the injection pressure reaches the peak pressure, the injection continues. The injection pressure drops. The injection continues until the injection pressure drops to 1 / 2 to 4 / 5 of the peak pressure, and then the injection stops.

[0013] S2. Inject the mixture of aerosolized foaming agent and supercritical CO2 into the injection well, and perform injection and production simultaneously in the injection well and the production well; when the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, stop the injection.

[0014] S3. Repeat S1 and S2 until the water saturation of the geological seal reaches 5-10%.

[0015] In step S2, the pressure and temperature of the aerosol foaming agent and the supercritical CO2 mixture are the same as those of the geological seal body.

[0016] The injection volume ratio of the pre-aerosol foaming agent slug to the post-CO2 slug is 1:(2~5).

[0017] Under the pressure and temperature of the geological storage body, the solubility of the aerosol foaming agent in supercritical carbon dioxide must be no less than 0.2; otherwise, stable foam will not be formed, and effective foam-driven oil sequestration cannot be achieved.

[0018] Preferably, the aerosol blowing agent is a hydrocarbon ether with an amidation site sequence and the following structural formula:

[0019] ;

[0020] Wherein, R is any one of 3,5,5-trimethyl-1-hexyl, 2,3-dimethyl-2-heptyl, 2,4,4-trimethyl-1-pentyl, 2,2,4-trimethyl-3-pentyl, 3,4,5-trimethyl-4-heptyl, 3,4,4-trimethyl-3-pentyl, 2,3,4-trimethyl-3-pentyl, 2,3,3-trimethyl-2-pentyl, 2,4,6-trimethyl-4-heptyl, 2,4,4-trimethyl-2-pentyl, 2,6,6-trimethyl-4-heptyynyl, 3,4,4-trimethyl-1-pentyynyl, 3,4,4-trimethyl-1-pentenyl, 3-(tert-butyl)-2,2,4,4,-tetramethylpentyl, 2,3,3-trimethyl-2-butyl, and 3-methyl-2-butyl.

[0021] The value of m ranges from 5 to 20;

[0022] The value of n ranges from 5 to 20.

[0023] In the mixture of aerosolized foaming agent and supercritical CO2, the mass ratio of aerosolized foaming agent to supercritical CO2 is (0.2~1.5):100; preferably, the mass ratio is (0.3~0.5):100.

[0024] The geological reservoirs include saline aquifers and depleted gas reservoirs.

[0025] Preferably, the depleted gas reservoir is a high water-cut oil reservoir.

[0026] Furthermore, the pressure of the geological containment body is greater than 10 MPa, and the temperature is 35~90 ℃.

[0027] The injection rate of the aerosolized foaming agent and supercritical CO2 mixture is 20~100 t / d.

[0028] The aerosolized foaming agent and supercritical CO2 mixture are injected via a tubing injection method, with the annulus sealed using a packer.

[0029] This invention solves the problem of high viscosity of conventional surfactant base liquids and difficulty in generating foam underground by replacing conventional surfactants with aerosol foaming agents. In addition, after the foam bursts, the aerosol foaming agent is carried to the surface by supercritical carbon dioxide and floats up, where it foams again upon encountering formation water, achieving the effect of burst regeneration and dynamic stability, which is conducive to further expanding the swept volume.

[0030] Beneficial effects

[0031] 1. This invention utilizes an aerosol foaming agent to increase the carbon dioxide storage capacity of geological storage bodies. When the aerosol foaming agent and supercritical CO2 mixture are injected into the geological storage body, in-situ foaming is directly achieved through the shearing action of porous media using formation water, thereby reducing the saturation of bound water and increasing the carbon storage space for carbon dioxide. The generated foam exhibits intelligent selectivity, "blocking high-permeability zones but not low-permeability zones," forcing carbon dioxide to displace residual oil after blocking high-permeability zones, thus improving oil recovery. Simultaneously, the production of residual oil provides carbon storage space for carbon dioxide. After the foam bursts, the aerosol foaming agent is carried to the surface by supercritical carbon dioxide, where it re-foams upon encountering formation water, achieving a burst regeneration and dynamic stabilization effect, which is beneficial for further expanding the swept volume. Ultimately, through the superposition of the effects of in-situ foaming with formation water, burst regeneration, and dynamic stabilization, a significant increase in the final carbon dioxide storage capacity is achieved. Furthermore, this invention achieves in-situ foaming in the formation by directly injecting a mixture of aerosolized foaming agent and supercritical CO2, without the need for surface foaming followed by injection, thus avoiding the problems of high injection pressure and injection difficulties.

[0032] 2. This invention addresses the shortcomings of existing technologies in increasing carbon dioxide storage capacity by providing a method of alternating injection of a pre-positioned aerosolized foaming agent slug and a post-positioned CO2 slug. Through this alternating injection, in-situ foaming is achieved around the wellbore, forming a dynamic foam barrier structure that blocks high-permeability channels. This alternating injection method utilizes the complex pressure field of the formation to enhance the controllability of the aerosolized foaming agent, effectively prolonging the residence time of carbon dioxide in the formation and continuously expanding the affected area through a foam rupture and regeneration mechanism, thereby significantly increasing carbon storage capacity.

[0033] 3. This invention introduces a real-time injection pressure feedback mechanism. By monitoring changes in injection pressure during the injection process, the injection method is dynamically adjusted; during the injection of the aerosolized foaming agent and supercritical CO2 mixture, it ensures that the foam maintains a good sealing effect in the formation; during segmented alternating injection, the foam barrier is restored and strengthened. This real-time injection pressure feedback mechanism, through continuous monitoring and adjustment, ensures the long-term stable distribution of carbon dioxide in the formation, reduces early carbon dioxide breaching and loss, significantly improves storage efficiency, and effectively enhances the carbon dioxide burial effect. Attached Figure Description

[0034] Figure 1 A schematic diagram of a site for increasing the amount of carbon dioxide stored using aerosol foaming agents;

[0035] Figure 2 This is a schematic diagram of the swept volume for increasing carbon dioxide storage in Example 1;

[0036] Figure 3 A schematic diagram of the swept volume of comparative example 1, showing the increased carbon dioxide storage capacity.

[0037] Figure 4 A schematic diagram of the swept volume for increasing carbon dioxide storage in Comparative Example 2;

[0038] Figure 5 This is a schematic diagram of the connection of the simulation experimental setup;

[0039] Figure 6 The injection volume-gas phase saturation diagrams for improving carbon dioxide storage in saline aquifers in Examples 2, 3, and 4 are shown.

[0040] Figure 7 Injection volume-gas phase saturation diagrams for improving carbon dioxide storage in high water-cut reservoirs in Examples 3, 5, and 6;

[0041] Figure 8 The injection volume-displacement efficiency diagrams for improving carbon dioxide storage in high water-cut reservoirs are shown in Examples 3, 5, and 6.

[0042] Figure 9 This is a schematic diagram of the swept volume for increasing carbon dioxide storage in Example 4;

[0043] Figure 10 A schematic diagram of the swept volume of the increased carbon dioxide storage in Comparative Example 7;

[0044] Figure 11 Injection volume-gas phase saturation diagrams for improving carbon dioxide storage in saline aquifers in Examples 5, 8, and 4.

[0045] Figure 12Injection volume-gas phase saturation diagrams for improving carbon dioxide storage in high water-cut reservoirs in Examples 6, 9, and 10;

[0046] Figure 13 The injection volume-displacement efficiency diagrams for improving carbon dioxide storage in high water-cut reservoirs in Examples 6, 9, and 10 are shown.

[0047] Among them, 1. High-pressure CO2 gas source; 2. Gas-soluble foaming agent solution storage tank; 3. Injection well; 4. Production well; 5. Geological seal body; 6. Near-well foam zone; 7. Regenerated foam zone; 8. Deep unaffected area of ​​geological seal body; 9. Supercritical carbon dioxide zone after foam rupture; 10. Supercritical carbon dioxide zone. Detailed Implementation

[0048] To more clearly illustrate the objectives, technical solutions, and advantages of this invention, the technical solutions of this invention are described in detail below with reference to the accompanying drawings and embodiments. These embodiments represent only a part of the implementation of this invention and are not all of them. The scope of protection of this invention is not limited thereto.

[0049] The aerosol blowing agents described in Examples 1-3 and Comparative Examples 1-6 are hydrocarbon ethers with amidation site sequences, synthesized in the laboratory, while all other raw materials were purchased commercially. The structural formula of the hydrocarbon ether with amidation site sequences is as follows:

[0050] .

[0051] The preparation method of the amidation site sequence hydrocarbon ether is as follows: In a dry and clean high-temperature and high-pressure reactor equipped with a stirrer, 1.0 mol (144 g) of 3,5,5-trimethyl-1-hexanol and 8.3 g of barium hydroxide catalyst are added. After purging with high-purity nitrogen for 15 min, 5 mol (290 g) of propylene oxide is introduced and the purging is completed in 2.5 h. The reaction temperature is controlled at 130 ℃ for 3 h to obtain the product 3,5,5-trimethyl-1-hexanol polyoxypropylene ether. After cooling the reactor to 120 ℃, the reaction temperature is controlled at a constant temperature. After purging with 9 mol (396 g) of ethylene oxide for 4.5 h, the reaction is continued for 1.5 h to obtain 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether. The product is then discharged after cooling. 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether was dissolved in anhydrous tetrahydrofuran to prepare a solution with a concentration of 0.5 g / mL, and then 1 mol (101 g) of triethylamine was added. Under stirring, 1 mol (78 g) of acetyl chloride was added dropwise, and the reaction temperature was controlled at 20°C. After the addition of acetyl chloride, the reaction mixture was stirred at 30°C for 1.5 hours to ensure complete reaction. Subsequently, after neutralization with glacial acetic acid, vacuum filtration, dissolution and filtration with ethyl acetate, rotary evaporation, and vacuum drying, acetamido-3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether was obtained.

[0052] Example 1

[0053] like Figure 1 The diagram shows a field illustration of using an aerosolized foaming agent to increase carbon dioxide storage capacity. The site is an oil reservoir in Dongying, Shandong Province. An injection well 3 and a production well 4 are installed in the geological storage body 5. The injection well 3 is connected to a high-pressure CO2 gas source 1 through an aerosolized foaming agent solution storage tank 2. The geological storage body 5 is a high water-cut oil reservoir.

[0054] A method for increasing carbon dioxide storage capacity using an aerosol foaming agent, comprising the following steps:

[0055] S1. A pre-aerosolized foaming agent slug and a post-aerosolized CO2 slug are sequentially injected into the geological containment body through the aerosolized foaming agent solution storage tank 2 and the high-pressure CO2 gas source 1. The pre-aerosolized foaming agent slug and the post-aerosolized CO2 slug are injected alternately in two stages. The volume ratio of the pre-aerosolized foaming agent slug to the post-aerosolized CO2 slug is 1:5 each time, and the total injection volume of the pre-aerosolized foaming agent slug and the post-aerosolized CO2 slug is 1 m³. 3 and 5 m 3 After the peak pressure (18.5 MPa) is reached by the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure drops to 4 / 5 of the peak pressure, at which point injection stops.

[0056] S2. A mixture of aerosol foaming agent and supercritical CO2 is injected from injection well 3 into geological storage body 5 at an injection rate of 40t / d. The injection process adopts the tubing injection method, and injection and production are carried out simultaneously in injection well 3 and production well 4. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0057] The preparation method of the aerosolized foaming agent and supercritical CO2 mixture is as follows: CO2 in the high-pressure CO2 gas source 1 is pressurized and sent to the aerosolized foaming agent solution storage tank 2. In the aerosolized foaming agent solution storage tank 2, supercritical CO2 and aerosolized foaming agent are mixed evenly. During the mixing process, the stirring rotor is started to accelerate phase equilibrium. The mass ratio of aerosolized foaming agent to supercritical CO2 is 0.3:100, the pressure is 12 MPa, and the temperature is 55℃.

[0058] S3. Repeat S1 and S2 until the water saturation of the geological seal reaches 10%.

[0059] Figure 2 This diagram illustrates the swept volume of increased carbon dioxide storage obtained through numerical simulation using CMG software, following the aforementioned implementation steps. The injected aerosolized foaming agent and supercritical CO2 mixture utilizes formation water to foam in situ through the shearing action of porous media, quickly generating a large amount of foam near the injection well, forming near-wellbore foam zone 6. After the foam bursts, the aerosolized foaming agent is carried afloat by supercritical carbon dioxide, encountering formation water and foaming again, forming regenerated foam zone 7. This achieves the effect of rupture regeneration and dynamic stabilization, further expanding the swept volume and reducing the volume of the deep, unaffected zone 8 of the geological reservoir. In near-wellbore foam zone 6 and regenerated foam zone 7, the generation of aerosolized foam consumes formation bound water, thereby reducing water saturation and increasing carbon storage space. The generated foam effectively drives residual oil, improving recovery while reducing residual oil saturation, further increasing carbon storage space. Ultimately, in near-wellbore foam zone 6 and regenerated foam zone 7, CO2 gas phase saturation can reach 95%, significantly increasing CO2 sequestration; crude oil recovery rate can reach 93%, greatly improving recovery rate.

[0060] Example 2

[0061] Experimental objective:

[0062] The effect of using aerosolized foaming agents to increase the carbon dioxide storage capacity of saline aquifers was investigated.

[0063] Experimental conditions:

[0064] according to Figure 5Connect the experimental setup, that is, connect one end of the intermediate container containing crude oil, formation water, CO2, CO2-foaming agent and foaming agent to the ISCO plunger pump through a six-way valve, and connect the other end of the container to the inlet of the core holder and the computer through a six-way valve. The outlet of the core holder is connected in sequence to the back pressure valve and the beaker, which is used to collect the produced fluid.

[0065] The core holder is a sand-filled tube simulating a saline aquifer, and its preparation method is as follows: turn on the ISCO plunger pump and fill the sand-filled tube with formation water at an injection rate of 1 mL / min until saturation. Throughout the process, maintain the temperature of the sand-filled tube at 70℃ and the pressure at 15 MPa.

[0066] The sand-filled pipe has a permeability of 640 mD, a pore volume of 56.5 mL, and a total length of 1 m.

[0067] Experimental steps:

[0068] S1. A pre-aerosolized foaming agent slug and a post-CO2 slug are sequentially injected into the sand-filled tube through an intermediate container containing a foaming agent and an intermediate container containing CO2. The pre-aerosolized foaming agent slug and the post-CO2 slug are injected alternately in three stages. Each stage, the volume ratio of the pre-aerosolized foaming agent slug to the post-CO2 slug is 1:2. The total injection volumes for the pre-aerosolized foaming agent slug and the post-CO2 slug are 2 mL and 4 mL, respectively. The flow rates of both the foaming agent and CO2 are 0.1 mL / min. When the peak pressure (16.8 MPa) is reached during the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure decreases to 4 / 5 of the peak pressure, at which point injection is stopped.

[0069] S2. In the intermediate container storing CO2-foaming agent, the mass ratio of aerosolized foaming agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 70℃.

[0070] A mixture of aerosolized foaming agent and supercritical CO2 was injected into the sand-filled tube using an ISCO plunger pump at a rate of 1 mL / min. Simultaneous injection and production were performed at both the inlet and outlet sections of the sand-filled tube. Throughout the process, the back pressure at the production end was maintained at 15 MPa and the temperature of the sand-filled tube was maintained at 70°C.

[0071] When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection should be stopped.

[0072] S3. Repeat steps S1 and S2 until the water saturation of the sand-filled pipe reaches 5%.

[0073] Example 3

[0074] Experimental objective:

[0075] The effect of using aerosol foaming agents to increase the carbon dioxide storage capacity of high water-cut oil reservoirs was investigated.

[0076] Experimental conditions:

[0077] according to Figure 5 The experimental setup was connected, wherein the core holder was a sand-filled tube simulating a high water-cut oil reservoir, and its preparation method was as follows: An ISCO plunger pump was turned on to fill the sand-filled tube with crude oil at an injection rate of 1 mL / min until saturation. Throughout the process, the temperature of the sand-filled tube was maintained at 60℃ and the pressure at 15 MPa. After saturation, the initial oil saturation of the sand-filled tube was 81.8%, and the viscosity of the experimental oil at 60℃ was 25 mPa·s. The sand-filled tube was placed in a 60℃ oven for constant aging for 24 hours. Then, a water-drive experiment was conducted at 60℃ and 15 MPa with an injection rate of 1 mL / min. After 3.952 PV of water-drive, the oil saturation in the sand-filled tube decreased to 24.3%, while the water saturation increased to 75.7%, thus obtaining a sand-filled tube for a high water-cut oil reservoir.

[0078] The sand-filled pipe has a permeability of 866 mD, a pore volume of 57.3 mL, and a total length of 1 m.

[0079] Experimental steps:

[0080] S1. A pre-aerosolized foaming agent slug and a post-CO2 slug are sequentially injected into the sand-filled tube through an intermediate container containing a foaming agent and an intermediate container containing CO2. The pre-aerosolized foaming agent slug and the post-CO2 slug are injected alternately in three stages. Each stage, the volume ratio of the pre-aerosolized foaming agent slug to the post-CO2 slug is 1:3. The total injection volumes for the pre-aerosolized foaming agent slug and the post-CO2 slug are 3 mL and 9 mL, respectively. The flow rates of both the foaming agent and CO2 are 0.1 mL / min. When the peak pressure (16.5 MPa) is reached after the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure decreases to 4 / 5 of the peak pressure, at which point injection is stopped.

[0081] S2. In an intermediate container storing CO2-blowing agent, the mass ratio of aerosolized blowing agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 60℃.

[0082] A mixture of aerosolized foaming agent and supercritical CO2 was injected into a sand-filled tube simulating a high water-cut reservoir using an ISCO plunger pump at an injection rate of 1 mL / min. Simultaneous injection and production were carried out at the inlet and outlet sections of the sand-filled tube. Throughout the process, the back pressure at the production end was maintained at 15 MPa and the temperature of the sand-filled tube was maintained at 60℃.

[0083] When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection should be stopped.

[0084] S3. Repeat steps S1 and S2 until the water saturation of the sand-filled pipe reaches 5%.

[0085] Comparative Example 1

[0086] Similar to Example 1, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0087] Foam with a dryness of 85% is injected into the sand-filled pipe through an intermediate container containing CO2 foaming agent at an injection rate of 40t / d.

[0088] The preparation method of 85% dryness foam is as follows: supercritical carbon dioxide and aerosol foaming agent are injected at injection rates of 0.85 mL / min and 0.15 mL / min, respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0089] Figure 3 This diagram illustrates the swept volume obtained through numerical simulation using CMG software, based on the aforementioned implementation steps, when 85% dryness foam is used to increase carbon dioxide storage. The injected foam forms a near-wellbore foam zone 6 around the injection well. The area of ​​this near-wellbore foam zone 6 is smaller than in Example 1 because the foam is thermodynamically unstable and cannot effectively rupture and regenerate. Furthermore, in this near-wellbore foam zone 6, the CO2 gas phase saturation can only reach a maximum of 85% because it cannot consume formation bound water to form foam. After the foam ruptures, supercritical carbon dioxide rises and diffuses, forming a post-bubble supercritical carbon dioxide zone 9. In this post-bubble supercritical carbon dioxide zone 9, the CO2 gas phase saturation is only about 30%. After injecting an equal amount of 85% dryness foam, the area of ​​the deep unswept zone 8 is significantly larger than in Example 1.

[0090] Comparative Example 2

[0091] Similar to Example 1, except that this comparative example uses supercritical CO2 for continuous displacement at an injection rate of 40 t / d.

[0092] Figure 4 This diagram illustrates the swept volume of supercritical carbon dioxide when increasing carbon dioxide storage capacity, obtained through numerical simulation using CMG software following the above implementation steps. The injected supercritical carbon dioxide, influenced by density differences, quickly forms a "wider at the top and narrower at the bottom" supercritical carbon dioxide region 10. In this supercritical carbon dioxide region 10, the CO2 gas phase saturation is only about 30%, far lower than in Example 1.

[0093] Comparative Example 3

[0094] Similar to Example 2, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0095] Foam with a dryness of 85% is injected into the sand-filled tube through an intermediate container containing CO2 foaming agent at a rate of 1 mL / min.

[0096] The preparation method of 85% dryness foam is as follows: two ISCO plunger pumps control the injection of supercritical carbon dioxide and aerosol foaming agent respectively, with injection rates of 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0097] Comparative Example 4

[0098] Same as Example 2, except that this comparative example uses supercritical carbon dioxide for continuous displacement, and the specific steps are as follows:

[0099] Supercritical carbon dioxide is continuously injected into the sand-filled tube through an intermediate container containing CO2 at an injection rate of 1 mL / min.

[0100] Comparative Example 5

[0101] Similar to Example 3, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0102] Foam with a dryness of 85% is injected into the sand-filled tube through an intermediate container containing CO2 foaming agent at a rate of 1 mL / min.

[0103] The preparation method of 85% dryness foam is as follows: two ISCO plunger pumps control the injection of supercritical carbon dioxide and aerosol foaming agent respectively, with injection rates of 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0104] Comparative Example 6

[0105] Same as Example 3, except that this comparative example uses supercritical carbon dioxide for continuous displacement, and the specific steps are as follows:

[0106] Supercritical carbon dioxide is continuously injected into the sand-filled tube through an intermediate container containing CO2 at an injection rate of 1 mL / min.

[0107] In Comparative Examples 1-6, there is no segmented alternating injection, making it impossible to achieve in-situ foaming around the wellbore and thus form a dynamic foam barrier structure.

[0108] Because foam formation is controlled by surfactant concentration, porous media shear rate, etc., the foam formation time is uncertain; while in Comparative Examples 1-6, there is no injection pressure feedback mechanism, and it is impossible to determine the foam formation situation under the reservoir, resulting in early carbon dioxide breakthrough and loss.

[0109] Figure 6 Table 1 shows the injection volume-gas phase saturation diagrams for increasing the carbon dioxide storage capacity in saline aquifers in Examples 2, 3, and 4. Specific data are shown in Table 1. The diagrams show that the mixture of aerosolized foaming agent and supercritical CO2, after displacing 1.698 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 92.83%, indicating that aerosolized foam can significantly increase the carbon dioxide storage capacity in the saline aquifer with a small injection volume. Similarly, 85% dryness foam, after displacing 9.910 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 82.13%, indicating that 85% dryness foam can also significantly increase the carbon dioxide storage capacity in the saline aquifer with a large injection volume, but the maximum storage capacity will not exceed the foam dryness. Finally, supercritical carbon dioxide, after displacing 7.524 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 20.86%, indicating that direct CO2 injection has a poor storage effect.

[0110] like Figure 7 The figure shows the injection volume-gas phase saturation diagrams for increasing carbon dioxide storage in high water-cut reservoirs in Examples 3, 5, and 6. Specific data are shown in Table 2. Figure 8 The figure shows the injection volume-displacement efficiency diagrams for increasing the carbon dioxide storage in high water-cut reservoirs in Examples 3, 5, and 6. Specific data are shown in Table 3. After displacement of 3.01 PV, the mixture of aerosolized foaming agent and supercritical CO2 can increase the carbon dioxide storage in high water-cut reservoirs to approximately 91.68% and the oil recovery rate to approximately 94.28%, indicating that aerosolized foam can significantly improve carbon dioxide storage and oil recovery rate even with a small amount of injection. After displacement of 11.62 PV, 85% dryness foam can increase the carbon dioxide storage in high water-cut reservoirs to approximately 71.95% and the oil recovery rate to approximately 80.42%, indicating that 85% dryness foam can effectively improve carbon dioxide storage and oil recovery rate with a large amount of injection, but the improvement is not as great as that of the mixture of aerosolized foaming agent and supercritical CO2. After displacement of 10.31 PV, supercritical carbon dioxide can increase the carbon dioxide storage in water-cut reservoirs to approximately 31.99% and the oil recovery rate to approximately 70.35%, indicating that direct injection of supercritical carbon dioxide results in the lowest carbon storage and oil recovery rates.

[0111] Table 1. Injection volume-gas phase saturation for improving carbon dioxide storage in saline aquifers in Examples 2, 3, and 4.

[0112]

[0113]

[0114] Table 2. Injection Volume-Gas Saturation for Improving Carbon Dioxide Storage in High Water-Cut Reservoirs (Examples 3, 5, and 6)

[0115]

[0116] Table 3. Injection volumetric displacement efficiency for improving carbon dioxide storage in high water-cut reservoirs in Examples 3, 5, and 6.

[0117]

[0118] The aerosol blowing agents described in Examples 4-6 and Comparative Examples 7-10 are hydrocarbon ethers with amidation site sequences, synthesized in the laboratory, while all other raw materials were purchased commercially. The structural formula of the hydrocarbon ether with amidation site sequences is as follows:

[0119] .

[0120] The preparation method of the amidation site sequence hydrocarbon ether is as follows: In a dry and clean high-temperature and high-pressure reactor equipped with a stirrer, 1.0 mol (144 g) of 3,5,5-trimethyl-1-hexanol and 8.3 g of barium hydroxide catalyst are added. After purging with high-purity nitrogen for 15 min, 5 mol (290 g) of propylene oxide is introduced and the purging is completed in 2.5 h. The reaction temperature is controlled at 130 ℃ for 3 h to obtain the product 3,5,5-trimethyl-1-hexanol polyoxypropylene ether. After cooling the reactor to 120 ℃, the reaction temperature is controlled at a constant temperature. After purging with 9 mol (396 g) of ethylene oxide for 4.5 h, the reaction is continued for 1.5 h to obtain 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether. The product is then discharged after cooling. 3,5,5-Trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether was dissolved in anhydrous tetrahydrofuran to prepare a solution with a concentration of 0.5 g / mL. Then, 1 mol (101 g) of triethylamine was added, and the temperature was controlled at 5 °C. Subsequently, 1 mol (190.5 g) of p-toluenesulfonyl chloride was slowly added dropwise, and the reaction was stirred for 6.5 hours, with the temperature controlled at 10 °C to ensure complete reaction. Afterward, the triethylamine hydrochloride was removed by filtration, the filtrate was concentrated under reduced pressure, cold diethyl ether was added to precipitate, and centrifugation was performed to obtain the sulfonated intermediate. The sulfonated intermediate was added together with 5 mol (467.5 g) of chloroacetamide and 2 mol (276 g) of anhydrous potassium carbonate to N,N-dimethylformamide, and heated to 80 °C under nitrogen protection, and stirred for 26 hours to obtain the crude product of amidolated polymethyl hydrocarbon ether. The crude product of amidolated polymethyl hydrocarbon ether was concentrated by rotary evaporation and then slowly added dropwise to cold diethyl ether to induce precipitation. The product was centrifuged to obtain a white solid, and the precipitate was washed three times. Subsequently, it was dissolved in deionized water, placed in a dialysis bag, dialyzed for 72 hours, and finally freeze-dried to obtain amidolated polymethyl hydrocarbon ether.

[0121] Example 4

[0122] like Figure 1 The diagram shows a field illustration of using an aerosolized foaming agent to increase carbon dioxide storage capacity. The site is an oil reservoir in Dongying, Shandong Province. An injection well 3 and a production well 4 are installed in the geological storage body 5. The injection well 3 is connected to a high-pressure CO2 gas source 1 through an aerosolized foaming agent solution storage tank 2. The geological storage body 5 is a high water-cut oil reservoir.

[0123] A method for increasing carbon dioxide storage capacity using an aerosol foaming agent, comprising the following steps:

[0124] S1. A pre-aerosolized foaming agent slug and a post-aerosolized CO2 slug are sequentially injected into the geological containment body through the aerosolized foaming agent solution storage tank 2 and the high-pressure CO2 gas source 1. The pre-aerosolized foaming agent slug and the post-aerosolized CO2 slug are injected alternately in two stages. The volume ratio of the pre-aerosolized foaming agent slug to the post-aerosolized CO2 slug is 1:5 each time, and the total injection volume of the pre-aerosolized foaming agent slug and the post-aerosolized CO2 slug is 1 m³. 3 and 5 m 3 After the peak pressure (18.1 MPa) is reached by the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure drops to 4 / 5 of the peak pressure, at which point injection stops.

[0125] S2. A mixture of aerosol foaming agent and supercritical CO2 is injected from injection well 3 into geological storage body 5 at an injection rate of 40t / d. The injection process adopts the tubing injection method, and injection and production are carried out simultaneously in injection well 3 and production well 4. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0126] The preparation method of the aerosolized foaming agent and supercritical CO2 mixture is as follows: CO2 in the high-pressure CO2 gas source 1 is pressurized and sent to the aerosolized foaming agent solution storage tank 2. In the aerosolized foaming agent solution storage tank 2, supercritical CO2 and aerosolized foaming agent are mixed evenly. During the mixing process, the stirring rotor is started to accelerate phase equilibrium. The mass ratio of aerosolized foaming agent to supercritical CO2 is 0.3:100, the pressure is 12 MPa, and the temperature is 55℃.

[0127] S3. Repeat S1 and S2 until the water saturation of the geological seal reaches 10%.

[0128] Figure 9This diagram illustrates the swept volume of increased carbon dioxide storage obtained through numerical simulation using CMG software, following the aforementioned implementation steps. The injected aerosolized foaming agent and supercritical CO2 mixture utilizes formation water to foam in situ through the shearing action of porous media, quickly generating a large amount of foam near the injection well, forming near-wellbore foam zone 6. After the foam bursts, the aerosolized foaming agent is carried afloat by supercritical carbon dioxide, encountering formation water and foaming again, forming regenerated foam zone 7. This achieves the effect of rupture regeneration and dynamic stabilization, further expanding the swept volume and reducing the volume of the deep, unaffected zone 8 of the geological reservoir. In near-wellbore foam zone 6 and regenerated foam zone 7, the generation of aerosolized foam consumes formation bound water, thereby reducing water saturation and increasing carbon storage space. The generated foam effectively drives residual oil, improving recovery while reducing residual oil saturation, further increasing carbon storage space. Ultimately, in near-wellbore foam zone 6 and regenerated foam zone 7, CO2 gas phase saturation can reach 92%, significantly increasing CO2 sequestration; crude oil recovery rate can reach 94%, greatly improving recovery rate.

[0129] Example 5

[0130] Experimental objective:

[0131] The effect of using aerosolized foaming agents to increase the carbon dioxide storage capacity of saline aquifers was investigated.

[0132] Experimental conditions:

[0133] according to Figure 5 Connect the experimental setup, that is, connect one end of the intermediate container containing crude oil, formation water, CO2, CO2-foaming agent and foaming agent to the ISCO plunger pump through a six-way valve, and connect the other end of the container to the inlet of the core holder and the computer through a six-way valve. The outlet of the core holder is connected in sequence to the back pressure valve and the beaker, which is used to collect the produced fluid.

[0134] The core holder is a sand-filled tube simulating a saline aquifer, and its preparation method is as follows: turn on the ISCO plunger pump and fill the sand-filled tube with formation water at an injection rate of 1 mL / min until saturation. Throughout the process, maintain the temperature of the sand-filled tube at 70℃ and the pressure at 15 MPa.

[0135] The sand-filled pipe has a permeability of 640 mD, a pore volume of 56.5 mL, and a total length of 1 m.

[0136] Experimental steps:

[0137] S1. A pre-aerosolized foaming agent slug and a post-CO2 slug are sequentially injected into the sand-filled tube through an intermediate container containing a foaming agent and an intermediate container containing CO2. The pre-aerosolized foaming agent slug and the post-CO2 slug are injected alternately in three stages. Each stage, the volume ratio of the pre-aerosolized foaming agent slug to the post-CO2 slug is 1:2. The total injection volumes for the pre-aerosolized foaming agent slug and the post-CO2 slug are 2 mL and 4 mL, respectively. The flow rates of both the foaming agent and CO2 are 0.1 mL / min. When the peak pressure (16.6 MPa) is reached after the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure decreases to 4 / 5 of the peak pressure, at which point injection is stopped.

[0138] S2. In the intermediate container storing CO2-foaming agent, the mass ratio of aerosolized foaming agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 70℃.

[0139] A mixture of aerosolized foaming agent and supercritical CO2 was injected into the sand-filled tube using an ISCO plunger pump at a rate of 1 mL / min. Simultaneous injection and production were performed at both the inlet and outlet sections of the sand-filled tube. Throughout the process, the back pressure at the production end was maintained at 15 MPa and the temperature of the sand-filled tube was maintained at 70°C.

[0140] When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection should be stopped.

[0141] S3. Repeat steps S1 and S2 until the water saturation of the sand-filled pipe reaches 5%.

[0142] Example 6

[0143] Experimental objective:

[0144] The effect of using aerosol foaming agents to increase the carbon dioxide storage capacity of high water-cut oil reservoirs was investigated.

[0145] Experimental conditions:

[0146] according to Figure 5The experimental setup was connected, wherein the core holder was a sand-filled tube simulating a high water-cut oil reservoir, and its preparation method was as follows: An ISCO plunger pump was turned on to fill the sand-filled tube with crude oil at an injection rate of 1 mL / min until saturation. Throughout the process, the temperature of the sand-filled tube was maintained at 60℃ and the pressure at 15 MPa. After saturation, the initial oil saturation of the sand-filled tube was 82.1%, and the viscosity of the experimental oil at 60℃ was 25 mPa·s. The sand-filled tube was placed in a 60℃ oven for constant aging for 24 hours. Then, a water-drive experiment was conducted at 60℃ and 15 MPa with an injection rate of 1 mL / min. After 4.1426 PV of water-drive, the oil saturation in the sand-filled tube decreased to 24.8%, and the water saturation increased to 75.2%, thus obtaining a sand-filled tube for a high water-cut oil reservoir.

[0147] The sand-filled pipe has a permeability of 845 mD, a pore volume of 57.5 mL, and a total length of 1 m.

[0148] Experimental steps:

[0149] S1. A pre-aerosolized foaming agent slug and a post-CO2 slug are sequentially injected into the sand-filled tube through an intermediate container containing a foaming agent and an intermediate container containing CO2. The pre-aerosolized foaming agent slug and the post-CO2 slug are injected alternately in three stages. Each stage, the volume ratio of the pre-aerosolized foaming agent slug to the post-CO2 slug is 1:3. The total injection volumes for the pre-aerosolized foaming agent slug and the post-CO2 slug are 3 mL and 9 mL, respectively. The flow rates of both the foaming agent and CO2 are 0.1 mL / min. When the peak pressure (16.3 MPa) is reached after the alternating injection of the pre-aerosolized foaming agent slug and the post-CO2 slug, injection continues until the injection pressure decreases to 4 / 5 of the peak pressure, at which point injection is stopped.

[0150] S2. In an intermediate container storing CO2-blowing agent, the mass ratio of aerosolized blowing agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 60℃.

[0151] A mixture of aerosolized foaming agent and supercritical CO2 was injected into a sand-filled tube simulating a high water-cut reservoir using an ISCO plunger pump at an injection rate of 1 mL / min. Simultaneous injection and production were carried out at the inlet and outlet sections of the sand-filled tube. Throughout the process, the back pressure at the production end was maintained at 15 MPa and the temperature of the sand-filled tube was maintained at 60℃.

[0152] When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection should be stopped.

[0153] S3. Repeat steps S1 and S2 until the water saturation of the sand-filled pipe reaches 5%.

[0154] Comparative Example 7

[0155] Similar to Example 4, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0156] Foam with a dryness of 85% is injected into the sand-filled pipe through an intermediate container containing CO2 foaming agent at an injection rate of 40t / d.

[0157] The preparation method of 85% dryness foam is as follows: supercritical carbon dioxide and aerosol foaming agent are injected at injection rates of 0.85 mL / min and 0.15 mL / min, respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0158] Figure 10 This diagram illustrates the swept volume obtained through numerical simulation using CMG software, following the aforementioned implementation steps, when 85% dryness foam is used to increase carbon dioxide storage. The injected foam forms a near-wellbore foam zone 6 around the injection well. The area of ​​this near-wellbore foam zone 6 is smaller than that in Example 4 because the foam is thermodynamically unstable and cannot effectively rupture and regenerate. Furthermore, in this near-wellbore foam zone 6, the CO2 gas phase saturation can only reach a maximum of 85% because it cannot consume formation bound water to form foam. After the foam ruptures, supercritical carbon dioxide rises and diffuses, forming a post-bubble supercritical carbon dioxide zone 9. In this post-bubble supercritical carbon dioxide zone 9, the CO2 gas phase saturation is only about 30%. After injecting an equal amount of 85% dryness foam, the area of ​​the deep unswept zone 8 is significantly larger than that in Example 4.

[0159] Comparative Example 8

[0160] Similar to Example 5, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0161] Foam with a dryness of 85% is injected into the sand-filled tube through an intermediate container containing CO2 foaming agent at a rate of 1 mL / min.

[0162] The preparation method of 85% dryness foam is as follows: two ISCO plunger pumps control the injection of supercritical carbon dioxide and aerosol foaming agent respectively, with injection rates of 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0163] Comparative Example 9

[0164] Similar to Example 6, except that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows:

[0165] Foam with a dryness of 85% is injected into the sand-filled tube through an intermediate container containing CO2 foaming agent at a rate of 1 mL / min.

[0166] The preparation method of 85% dryness foam is as follows: two ISCO plunger pumps control the injection of supercritical carbon dioxide and aerosol foaming agent respectively, with injection rates of 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dryness foam.

[0167] Comparative Example 10

[0168] Same as Example 6, except that this comparative example uses supercritical carbon dioxide for continuous displacement, and the specific steps are as follows:

[0169] Supercritical carbon dioxide is continuously injected into the sand-filled tube through an intermediate container containing CO2 at an injection rate of 1 mL / min.

[0170] In Comparative Examples 2, 4, and 7-10, there was no segmented alternating injection, making it impossible to achieve in-situ foaming around the wellbore and thus form a dynamic foam barrier structure.

[0171] Because foam formation is controlled by surfactant concentration, porous media shear rate, etc., the foam formation time is uncertain; while in Comparative Examples 2, 4 and 7-10, there is no injection pressure feedback mechanism, so it is impossible to determine the foam formation situation under the reservoir, resulting in early carbon dioxide breakthrough and loss.

[0172] Figure 11 Table 4 shows the injection volume-gas phase saturation diagrams for increasing the carbon dioxide storage capacity in saline aquifers in Examples 5, 8, and 4. Specific data are shown in Table 4. The diagrams show that the mixture of aerosolized foaming agent and supercritical CO2, after displacing 1.678 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 90.15%, indicating that aerosolized foam can significantly increase the carbon dioxide storage capacity in the saline aquifer with a small injection volume. Similarly, 85% dryness foam, after displacing 10.322 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 80.95%, indicating that 85% dryness foam can also significantly increase the carbon dioxide storage capacity in the saline aquifer with a large injection volume, but the maximum storage capacity will not exceed the foam dryness. Supercritical carbon dioxide, after displacing 7.524 PV, can increase the carbon dioxide gas phase saturation in the saline aquifer to approximately 20.86%, indicating that direct CO2 injection has a poor storage effect.

[0173] like Figure 12 The figure shows the injection volume-gas phase saturation diagrams for increasing carbon dioxide storage in high water-cut reservoirs in Examples 6, 9, and 10. Specific data are shown in Table 5. Figure 13The figure shows the injection volume-displacement efficiency diagrams for increasing the carbon dioxide storage in high water-cut reservoirs in Examples 6, 9, and 10. Specific data are shown in Table 6. After displacement of 3.054 PV, the mixture of aerosolized foaming agent and supercritical CO2 can increase the carbon dioxide storage in high water-cut reservoirs to approximately 90.108% and the oil recovery rate to approximately 95.043%, indicating that aerosolized foam can significantly improve carbon dioxide storage and oil recovery rate even with a small amount of injection. After displacement of 14.16 PV, 85% dryness foam can increase the carbon dioxide storage in high water-cut reservoirs to approximately 72.12% and the oil recovery rate to approximately 81.39%, indicating that 85% dryness foam can effectively improve carbon dioxide storage and oil recovery rate with a large amount of injection, but the improvement is not as great as that of the mixture of aerosolized foaming agent and supercritical CO2. After displacement of 11.25 PV, supercritical carbon dioxide can increase the carbon dioxide storage in water-cut reservoirs to approximately 34.05% and the oil recovery rate to approximately 70.88%, indicating that direct injection of supercritical carbon dioxide results in the lowest carbon storage and oil recovery rates.

[0174] Table 4. Injection volume-gas phase saturation for improving carbon dioxide storage in saline aquifers in Examples 5, 8, and 4.

[0175]

[0176] Table 5. Injection Volume-Gas Saturation for Improving Carbon Dioxide Storage in High Water-Cut Reservoirs (Examples 6, 9, and 10)

[0177]

[0178] Table 6. Injection volumetric displacement efficiency for improving carbon dioxide storage in high water-cut reservoirs in Examples 6, 9, and 10.

[0179]

[0180] The embodiments provided in this document are intended to illustrate the technical solutions of the present invention and are not intended to limit it. Although the solutions of the present invention have been described in detail, those skilled in the art should understand that they can still modify the technical solutions described in the above examples or make equivalent substitutions for some or all of the technical features; such modifications or substitutions will not cause the essence of the corresponding technical solutions to exceed the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for increasing the amount of carbon dioxide sequestration using a gas soluble foaming agent, characterized by, Includes the following steps: S1. The pre-aerosol foaming agent slug and the post-CO2 slug are injected into the geological storage body in stages and alternately. The injection pressure continues to rise. When the injection pressure reaches the peak pressure, the injection continues. The injection pressure drops. The injection continues until the injection pressure drops to 1 / 2 to 4 / 5 of the peak pressure, and then the injection stops. S2. Inject the mixture of aerosolized foaming agent and supercritical CO2 into the injection well, and perform injection and production simultaneously in the injection well and the production well; when the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, stop the injection. S3. Repeat S1 and S2 until the water saturation of the geological seal reaches 5-10%; The aerosol-soluble foaming agent is a hydrocarbon ether with an amidation site sequence and the following structural formula: ； Wherein, R is any one of 3,5,5-trimethyl-1-hexyl, 2,3-dimethyl-2-heptyl, 2,4,4-trimethyl-1-pentyl, 2,2,4-trimethyl-3-pentyl, 3,4,5-trimethyl-4-heptyl, 3,4,4-trimethyl-3-pentyl, 2,3,4-trimethyl-3-pentyl, 2,3,3-trimethyl-2-pentyl, 2,4,6-trimethyl-4-heptyl, 2,4,4-trimethyl-2-pentyl, 2,6,6-trimethyl-4-heptyynyl, 3,4,4-trimethyl-1-pentyynyl, 3,4,4-trimethyl-1-pentenyl, 3-tert-butyl-2,2,4,4,-tetramethylpentyl, 2,3,3-trimethyl-2-butyl, and 3-methyl-2-butyl. The value of m ranges from 5 to 20; The value of n ranges from 5 to 20; The injection rate of the aerosolized foaming agent and supercritical CO2 mixture is 20~100 t / d; In step S2, the pressure and temperature of the aerosol foaming agent and the supercritical CO2 mixture are the same as those of the geological seal body.

2. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, The injection volume ratio of the pre-aerosol foaming agent slug to the post-CO2 slug is 1:(2~5).

3. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, In the mixture of aerosolized foaming agent and supercritical CO2, the mass ratio of aerosolized foaming agent to supercritical CO2 is (0.2~1.5):

100.

4. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, Under the pressure and temperature of the geological containment body, the solubility of the aerosol foaming agent in supercritical carbon dioxide is not less than 0.

2.

5. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, The geological reservoirs include saline aquifers and depleted gas reservoirs.

6. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 5, characterized in that, The pressure of the geological seal is greater than 10 MPa, and the temperature is 35~90 ℃.

7. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, The injection method for the mixture of aerosolized foaming agent and supercritical CO2 is through tubing injection.

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