Method for improving carbon dioxide burying amount by using gas-soluble foaming agent

Abstract

The invention relates to the technical field of carbon burying and utilization, and particularly discloses a method for increasing the carbon dioxide burying amount by using a gas-soluble foaming agent. The gas-soluble foaming agent is adopted, in-situ foaming can be achieved through formation water, the carbon storage space is increased, and the dynamic stability effect can be achieved after foam is broken; in-situ foaming is realized around a shaft through segmented alternate injection of a front gas-soluble foaming agent slug and a rear CO2 slug; by setting a real-time injection pressure feedback mechanism and dynamically adjusting the injection mode, early breakthrough and loss of carbon dioxide are reduced, the sealing efficiency is remarkably improved, and the burying effect of carbon dioxide is effectively improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of carbon sequestration and utilization, and particularly relates to a method for improving carbon dioxide sequestration capacity by using gas-soluble foaming agent. BACKGROUND

[0002] The increase of carbon dioxide emissions leads to the continuous rise of global temperature and the frequent occurrence of extreme weather events. Climate change and carbon emission reduction have become important issues of international concern. 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 and thus reduce its negative impact on climate change. At present, deep saline aquifers and depleted oil and gas reservoirs, etc. have stable geological characteristics and can effectively store a large amount of carbon dioxide, which are ideal carbon dioxide storage sites.

[0003] Direct injection of carbon dioxide into deep saline aquifers and depleted oil and gas reservoirs (especially high water cut reservoirs) for storage, in the process of immiscible displacement, due to the effects of viscous fingering and gravity differentiation caused by the low viscosity and low density of carbon dioxide, and the influence of reservoir heterogeneity, carbon dioxide channeling is serious, sweep efficiency is low, and finally the storage efficiency is low. At present, in order to improve the geological storage capacity of carbon dioxide, one of the most commonly used methods is to disperse carbon dioxide in the water phase to form a foam, and then inject the foam into the formation for storage. When carbon dioxide foam is injected into saline aquifers, due to the high viscosity of carbon dioxide foam, it can effectively control the flow of carbon dioxide, reduce gas channeling, and expand the sweep area, thereby improving the storage efficiency. When carbon dioxide foam is injected into high water cut reservoirs, carbon dioxide foam has the characteristics of "blocking large channels but not small channels, and blocking water but not oil", which can effectively block high permeability channels, thereby improving oil recovery and improving the storage capacity and safety of carbon dioxide.

[0004] However, conventional foam flooding technology has some limitations. For example, it is difficult to inject in low permeability reservoirs, foam stability is poor, leading to rupture and dissipation, water phase content is high, gas phase content is low, etc., ultimately resulting in low foam flooding storage efficiency.

[0005] In order to solve the above problems, Chinese patent CN115341896A proposes a method for improving CO2 storage efficiency by using high dryness foam. This method increases the CO2 phase content in the foam and reduces the water phase content, thereby achieving higher carbon storage capacity than conventional foam. However, due to the poor stability of the foam, the phenomenon of significant improvement in carbon storage capacity does not occur until a large amount of PV of foam is injected. In addition, the foam is formed on the ground before injection, which inevitably leads to injection difficulties and very high injection pressure. At the same time, the foaming agent of the foam can only be dissolved in water and does not have the ability to dissolve in CO2. After mixing and injecting into the reservoir on the ground, the foam is prone to gas-liquid separation and failure.

[0006] Chinese patent CN118128594A provides a method for improving the stability of carbon dioxide foam by using nanoscale armor to strengthen the foam, thereby improving the stability of the foam and ultimately achieving improved geological storage. This method mainly improves the stability of the foam, thereby achieving strong sealing of the foam and expanding the sweep effect. However, in order to improve the stability of the foam, the viscosity of the base fluid must be increased. Increasing the viscosity of the base fluid makes it difficult to generate foam underground, and at the same time, the nanoscale particles can block the formation, causing reservoir damage. In addition, the foaming agent of this foam can only be dissolved in water and cannot be dissolved in CO2. Although the nanoscale particles improve the stability of the foam to some extent, the foam still undergoes gas-liquid separation, resulting in the foam only being able to function around the wellbore and being unable to penetrate the reservoir, leading to poor CO2 storage effect.

[0007] Chinese patent CN103867169A provides a method for using gas-soluble surfactants for carbon dioxide mobility control. This method requires that the gas-soluble surfactants be mixed uniformly with supercritical carbon dioxide and then injected directly into the oil reservoir. However, since the carbon dioxide and gas-soluble surfactant mixture is injected all at once, it is difficult to form a stable foam structure around the wellbore. During the migration of the gas-soluble surfactants to the deep part of the reservoir, they are easily lost due to adsorption on the rock, which can lead to early breakthrough and loss of carbon dioxide in the formation, affecting long-term carbon storage. At the same time, this method cannot effectively respond to dynamic changes in complex formation conditions, which can lead to low carbon dioxide storage. In addition, the gas-soluble surfactants used have low solubility in supercritical carbon dioxide, and the foam formed has poor stability. This method also has difficulty in forming a stable foam plugging barrier in the reservoir.

[0008] In summary, the existing technologies for improving carbon dioxide storage have the problems of high injection pressure, difficulty in injection, foaming agents that can only be dissolved in water and cannot be carried by CO2, low water phase and carbon dioxide phase content in the foam, poor foam stability, limited ability to expand the sweep range, and inability to adjust the injection method in real time according to complex formation conditions, resulting in low carbon dioxide geological storage. Therefore, there is an urgent need to develop a method for high carbon dioxide geological storage. SUMMARY

[0009] The present application aims at the deficiencies of the prior art and provides a method for improving carbon dioxide storage capacity by using gas-soluble foaming agent. The gas-soluble foaming agent is dissolved in supercritical carbon dioxide, injected into the formation, and directly foamed in situ by the shearing action of the porous medium using formation water, thereby reducing the irreducible water saturation and improving the carbon storage space for carbon dioxide. The gas-soluble foaming agent is carried upward by the supercritical carbon dioxide after the foam breaks, foams again when encountering formation water, and achieves the effect of breaking and regenerating and dynamic stability (dynamic stability is different from static stability, and instead of blindly pursuing high foam half-life or liquid separation half-life, the regeneration after foam breaking is pursued), thereby being beneficial to further expanding the swept volume. The generated foam has the intelligent selectivity of "blocking high and not blocking low", blocks the high permeability channels after blocking the high permeability channels, forces carbon dioxide to displace the residual oil, and achieves the effect of improving the recovery efficiency. Meanwhile, the production of residual oil provides carbon storage space for carbon dioxide storage. In addition, the present application realizes in-situ foaming around the wellbore by injecting the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug in sections alternately, forms a dynamic foam barrier structure, and blocks the high permeability channels. This way of injecting in sections alternately enhances the regulation and control ability of the gas-soluble foaming agent by using the complex pressure field of the formation, effectively prolongs the residence time of carbon dioxide in the formation, and continuously expands the swept range through the foam breaking and regenerating mechanism, thereby greatly improving the carbon storage capacity. The present application also sets a real-time injection pressure feedback mechanism, dynamically adjusts the injection mode by monitoring the pressure change in the injection process, ensures the long-term stable distribution of carbon dioxide in the formation, reduces the early breakthrough and loss of carbon dioxide, significantly improves the storage efficiency, and effectively improves the carbon dioxide storage effect.

[0010] In order to achieve the above-mentioned purpose, the present application adopts the following technical solutions: A method for improving carbon dioxide storage capacity by using gas-soluble foaming agent, specifically comprising the following steps: S1, pre-positioned gas-soluble foaming agent slug and post-positioned CO2 slug are injected into the geological storage body in sections alternately, the injection pressure continuously rises, when the injection pressure reaches the peak pressure, the injection is continued, the injection pressure falls, and the injection is stopped when the injection pressure is reduced to 1 / 2-4 / 5 of the peak pressure; S2, the gas-soluble foaming agent and supercritical CO2 mixture are injected into the injection well, and injection and production are simultaneously performed on the injection well and the production well; when the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped; S3, S1 and S2 are repeatedly executed until the water saturation of the geological storage body reaches 5-10%.

[0011] In step S2, the pressure and temperature of the gas-soluble foaming agent and supercritical CO2 mixture are the same as those of the geological storage body.

[0012] The volume ratio of the front gas-soluble foaming agent plug to the rear CO2 plug is 1: (2-5).

[0013] The solubility of the gas-soluble foaming agent in supercritical CO2 is not less than 0.2 under the pressure and temperature of the geological storage body, otherwise a stable foam cannot be formed and effective foam flooding storage cannot be performed.

[0014] Preferably, the gas-soluble foaming agent is an amido-alkyl ether with the following structure: ; 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-heptynyl, 3,4,4-trimethyl-1-pentynyl, 3,4,4-trimethyl-1-pentenyl, 3-(tert-butyl)-2,2,4,4,-tetramethylpentyl, 2,3,3-trimethyl-2-butyl, 3-methyl-2-butyl; m is in the range of 5-20; n is in the range of 5-20.

[0015] The mass ratio of the gas-soluble foaming agent to supercritical CO2 in the mixture is (0.2-1.5):100; preferably, the mass ratio is (0.3-0.5):100.

[0016] The geological storage body includes a saline aquifer and a depleted gas reservoir.

[0017] Preferably, the depleted gas reservoir is a high water cut reservoir.

[0018] Further, the pressure of the geological storage body is greater than 10 MPa, and the temperature is 35-90 ℃.

[0019] The injection rate of the gas-soluble foaming agent and supercritical CO2 mixture is 20-100 t / d.

[0020] The injection mode of the gas-soluble foaming agent and supercritical CO2 mixture is tubing injection, injection from the inside of the tubing, and the use of a packer to isolate the tubing-casing annulus.

[0021] The present application solves the problem of high viscosity of conventional surfactant base fluid and difficulty in generating foam underground by replacing the conventional surfactant with a gas-soluble foaming agent; in addition, the gas-soluble foaming agent is carried by supercritical carbon dioxide after the foam is broken, and is re-foamed when encountering formation water, achieving the effect of breaking and regenerating, dynamic stability, thereby facilitating further expansion of the swept volume.

[0022] Advantages 1. The present application uses a gas-soluble foaming agent to increase the carbon dioxide storage capacity of a geological storage body. When the gas-soluble foaming agent and supercritical CO2 mixture is injected into the geological storage body, it is directly in-situ foamed by the shearing action of the porous medium using formation water, thereby reducing the irreducible water saturation and providing carbon storage space for carbon dioxide; the generated foam has intelligent selectivity of "blocking high and not blocking low", and after blocking the high permeability zone, it forces carbon dioxide to displace residual oil, achieving the effect of improving recovery, and the production of residual oil provides carbon storage space for carbon dioxide storage. The gas-soluble foaming agent is carried by supercritical carbon dioxide after the foam is broken, and is re-foamed when encountering formation water, achieving the effect of breaking and regenerating, dynamic stability, thereby facilitating further expansion of the swept volume; ultimately, the effects of in-situ foaming by formation water, breaking and regenerating, and dynamic stability are superimposed, thereby achieving the effect of significantly increasing the final carbon dioxide storage capacity. In addition, the present application achieves in-situ foaming in the formation by directly injecting a gas-soluble foaming agent and supercritical CO2 mixture, without the need for foaming on the ground before injection, thereby avoiding the problems of high injection pressure and difficulty in injection.

[0023] 2. The present application provides a method of segmented and alternating injection by pre-injecting a gas-soluble foaming agent slug and post-injecting a CO2 slug to address the shortcomings of the prior art in increasing carbon dioxide storage capacity. By segmented and alternating injection, in-situ foaming is achieved around the wellbore, forming a dynamic foam barrier structure to block high permeability channels. This segmented and alternating injection method takes advantage of the complex pressure field of the formation to enhance the control ability of the gas-soluble foaming agent, effectively prolonging the residence time of carbon dioxide in the formation and continuously expanding the swept volume through the foam breaking and regenerating mechanism, thereby significantly increasing the carbon storage capacity.

[0024] 3. The present application introduces a real-time injection pressure feedback mechanism. By monitoring the injection pressure change during injection, the injection method is dynamically adjusted; when the gas-soluble foaming agent and supercritical CO2 mixture is injected, the foam is ensured to maintain good blocking effect in the formation; when segmented and alternating injection is performed, the foam barrier is restored and strengthened. The real-time injection pressure feedback mechanism ensures the long-term stable distribution of carbon dioxide in the formation through continuous monitoring and adjustment, reduces the early breakthrough and loss of carbon dioxide, significantly improves the storage efficiency, and effectively improves the carbon dioxide storage effect. BRIEF DESCRIPTION OF DRAWINGS

[0025] Figure 1 A site diagram for increasing the amount of carbon dioxide sequestration using a gas-soluble foaming agent; Figure 2 A swept volume diagram for increasing the amount of carbon dioxide sequestration of Example 1; Figure 3 A swept volume diagram for increasing the amount of carbon dioxide sequestration of Comparative Example 1; Figure 4 A swept volume diagram for increasing the amount of carbon dioxide sequestration of Comparative Example 2; Figure 5 A connection diagram of a simulation experiment device; Figure 6 An injection volume-gas phase saturation diagram for increasing the amount of carbon dioxide sequestration of saline aquifers of Example 2, Comparative Example 3 and Comparative Example 4; Figure 7 An injection volume-gas phase saturation diagram for increasing the amount of carbon dioxide sequestration of high water cut reservoirs of Example 3, Comparative Example 5 and Comparative Example 6; Figure 8 An injection volume-oil displacement efficiency diagram for increasing the amount of carbon dioxide sequestration of high water cut reservoirs of Example 3, Comparative Example 5 and Comparative Example 6; Figure 9 A swept volume diagram for increasing the amount of carbon dioxide sequestration of Example 4; Figure 10 A swept volume diagram for increasing the amount of carbon dioxide sequestration of Comparative Example 7; Figure 11 An injection volume-gas phase saturation diagram for increasing the amount of carbon dioxide sequestration of saline aquifers of Example 5, Comparative Example 8 and Comparative Example 4; Figure 12 An injection volume-gas phase saturation diagram for increasing the amount of carbon dioxide sequestration of high water cut reservoirs of Example 6, Comparative Example 9 and Comparative Example 10; Figure 13 An injection volume-oil displacement efficiency diagram for increasing the amount of carbon dioxide sequestration of high water cut reservoirs of Example 6, Comparative Example 9 and Comparative Example 10; Wherein, 1, a high pressure CO2 gas source; 2, a gas-soluble foaming agent solution storage tank; 3, an injection well; 4, a production well; 5, a geological sequestration body; 6, a near wellbore foam zone; 7, a regenerated foam zone; 8, a deep un-swept zone of the geological sequestration body; 9, a supercritical carbon dioxide zone after the foam is broken; 10, a supercritical carbon dioxide zone. DETAILED DESCRIPTION

[0026] In order to more clearly illustrate the objects, technical solutions and advantages of the present application, the technical solutions of the present application will be described in detail below with reference to the accompanying drawings and examples. These examples only represent some implementation manners of the present application, and are not all. The protection scope of the present application is not limited thereto.

[0027] The gas-soluble foaming agent described in Examples 1-3 and Comparative Examples 1-6 is an amido-alkylation site sequence ether, which is prepared in the laboratory, and the other raw materials are purchased through commercial channels. The structural formula of the amido-alkylation site sequence ether is as follows: .

[0028] The preparation method of the amido-alkylation site sequence ether is as follows: 1.0 mol (144 g) of 3,5,5-trimethyl-1-hexanol and 8.3 g of barium hydroxide catalyst are added to a dry and clean high-temperature and high-pressure reaction kettle with a stirrer, and after purging with high-purity nitrogen for 15 min, 5 mol (290 g) of propylene oxide is introduced, which is completed in 2.5 h, and the reaction temperature is controlled at 130°C for 3 h to obtain the product 3,5,5-trimethyl-1-hexanol polyoxypropylene ether. After cooling the reaction kettle to a temperature of 120°C, the reaction temperature is controlled unchanged, and after 9 mol (396 g) of ethylene oxide is introduced for 4.5 h, the reaction is continued for 1.5 h to prepare 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether, which is discharged after cooling. The 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether is dissolved in anhydrous tetrahydrofuran to prepare a solution with a concentration of 0.5 g / mL, and then 1 mol (101 g) of triethylamine is added. Under stirring conditions, 1 mol (78 g) of acetyl chloride is added dropwise, and the reaction temperature is controlled at 20°C. After the addition of acetyl chloride, the reaction mixture is kept at 30°C and continues to be stirred for 1.5 hours to ensure that the reaction is complete. Subsequently, after neutralization with glacial acetic acid, vacuum filtration, dissolution and filtration with ethyl acetate, rotary evaporation and vacuum drying, the acetylamide 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether is prepared.

[0029] Example 1 As Figure 1 shown in the following is a schematic diagram of using a gas-soluble foaming agent to improve the carbon dioxide storage capacity, and the site is a certain reservoir in Dongying, Shandong, and an injection well 3 and a production well 4 are arranged in a geological storage body 5, and the injection well 3 is connected with a high-pressure CO2 gas source 1 through a gas-soluble foaming agent solution storage tank 2. The geological storage body 5 is a high-water-cut reservoir.

[0030] A method for improving the carbon dioxide storage capacity by using a gas-soluble foaming agent, the specific steps are as follows: S1, a pre-positioned gas-soluble foaming agent slug and a post-positioned CO2 slug are sequentially injected into the geological storage body through the gas-soluble foaming agent solution storage tank 2 and the high-pressure CO2 gas source 1, wherein the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are alternately injected in two times, and the volume ratio of the injection amount of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug is 1:5, and the total amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug is 1 m 3 and 5 m3 When the front gas-dissolved foaming agent slug and the rear CO2 slug are injected alternately, the injection continues after the peak pressure (18.5 MPa) appears, and stops until the injection pressure reduces to 4 / 5 of the peak pressure.

[0031] S2, injecting the gas-dissolved foaming agent and supercritical CO2 mixture from the injection well 3 into the geological storage body 5 at a rate of 40 t / d, adopting the tubing injection method during the injection process, and simultaneously injecting and producing from the injection well 3 and the production well 4; when the injection pressure reduces and the fluctuation range exceeds 0.1 MPa, stopping the injection; The preparation method of the gas-dissolved foaming agent and supercritical CO2 mixture is as follows: the CO2 in the high-pressure CO2 gas source 1 is pressurized and sent to the gas-dissolved foaming agent solution storage tank 2, and the supercritical CO2 and the gas-dissolved foaming agent are uniformly mixed in the gas-dissolved foaming agent solution storage tank 2; during the mixing process, the stirring rotor is started to accelerate the phase equilibrium; the mass ratio of the gas-dissolved foaming agent to the supercritical CO2 during the mixing is 0.3:100, the pressure is 12 MPa, and the temperature is 55°C.

[0032] S3, repeatedly performing S1 and S2 until the water saturation of the geological storage body reaches 10%.

[0033] Figure 2 To improve the carbon dioxide storage capacity, the swept volume obtained by numerical simulation calculation through CMG software according to the above implementation steps is shown in the figure. The injected gas-dissolved foaming agent and supercritical CO2 mixture is in-situ foamed by the shearing action of the porous medium using the formation water, and a large amount of foam is quickly generated near the injection well to form a near-well foam zone 6. The gas-dissolved foaming agent is carried upward by the supercritical carbon dioxide after the foam breaks, and is foamed again when encountering the formation water to form a regenerated foam zone 7, achieving the effect of breaking and regenerating, dynamic stability, further expanding the swept volume, and reducing the volume of the un-swept zone 8 in the deep part of the geological storage body. In the near-well foam zone 6 and the regenerated foam zone 7, the generation of the gas-dissolved foam consumes the formation bound water, thereby reducing the water saturation and improving the carbon storage space; the generated foam effectively drives the residual oil, thereby improving the recovery efficiency and reducing the residual oil saturation, and further improving the carbon storage space. Finally, in the near-well foam zone 6 and the regenerated foam zone 7, the CO2 gas phase saturation can reach 95%, significantly improving the CO2 storage capacity; the oil recovery efficiency can reach 93%, greatly improving the recovery efficiency; and the economic and environmental win-win effect is achieved.

[0034] Example 2 Experimental purpose: To investigate the effect of using a gas-dissolved foaming agent to improve the carbon dioxide storage capacity of a saline aquifer.

[0035] Experimental conditions: According to Figure 5Connect the experimental device, that is, connect the intermediate containers respectively storing crude oil, formation water, CO2, CO2-foaming agent and foaming agent to the ISCO plunger pump through the six-way valve at one end, and to the inlet end of the core holder and the computer through the six-way valve at the other end, and connect the outlet end of the core holder to the back pressure valve and the beaker in turn, wherein the beaker is used to receive the produced liquid.

[0036] The core holder is a sandpack pipe simulating a saline aquifer, and the preparation method is as follows: open the ISCO plunger pump to fill the sandpack pipe with formation water to a saturated state at an injection rate of 1 mL / min, and keep the temperature of the sandpack pipe at 70°C and the pressure at 15 MPa during the whole process.

[0037] The permeability of the sandpack pipe is 640 mD, the pore volume is 56.5 mL, and the total length is 1 m.

[0038] Experimental steps: S1, inject a pre-positioned gas-soluble foaming agent slug and a post-positioned CO2 slug into the sandpack pipe through the intermediate containers storing the foaming agent and CO2 in turn, wherein the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are injected alternately in three times, the volume ratio of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug is 1:2, the total injection amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug is 2 mL and 4 mL respectively, and the flow rate of the gas-soluble foaming agent and CO2 is 0.1 mL / min. When the peak pressure (16.8 MPa) appears during the injection of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug, continue to inject until the injection pressure decreases to 4 / 5 of the peak pressure, and stop the injection.

[0039] S2, in the intermediate container storing CO2-foaming agent, the mass ratio of the gas-soluble foaming agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 70°C; Inject the gas-soluble foaming agent and supercritical CO2 mixture into the sandpack pipe through the ISCO plunger pump at an injection rate of 1 mL / min, and simultaneously inject and produce at the inlet end and the outlet section of the sandpack pipe, and keep the back pressure at the production end at 15 MPa and the temperature of the sandpack pipe at 70°C during the whole process. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, stop the injection.

[0040] S3, repeat S1 and S2 until the water saturation of the sandpack pipe reaches 5%.

[0041] Example 3 Experimental purpose: To investigate the effect of using gas-soluble foaming agent to improve the carbon dioxide storage capacity of high water cut reservoirs.

[0042] Experimental conditions: According to Figure 5 The experimental device was connected, wherein the core holder was a sandpack pipe simulating a high water cut reservoir, and the preparation method was as follows: the ISCO piston pump was opened to fill the sandpack pipe with crude oil at an injection rate of 1 mL / min until the sandpack pipe was saturated, and the temperature of the sandpack pipe was maintained at 60℃ and the pressure was maintained at 15 MPa during the whole process. After the sandpack pipe was saturated with oil, the initial oil saturation was 81.8%, and the viscosity of the experimental oil was 25 mPa·s at 60℃. The sandpack pipe was placed in a 60℃ oven for constant temperature aging for 24h, and then water flooding was carried out at a temperature of 60℃, a pressure of 15 MPa and an injection rate of 1 mL / min. After 3.952 PV of water flooding, the oil saturation in the sandpack pipe was reduced to 24.3% and the water saturation was increased to 75.7%, and a sandpack pipe simulating a high water cut reservoir was prepared.

[0043] The permeability of the sandpack pipe was 866 mD, the pore volume was 57.3 mL, and the total length was 1 m.

[0044] Experimental steps: S1. The pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug were injected into the sandpack pipe in sequence through the intermediate container storing the foaming agent and the intermediate container storing CO2, wherein the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug were injected alternately in 3 times, and the volume ratio of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug was 1:3, the total amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug was 3 mL and 9 mL respectively, and the flow rate of the gas-soluble foaming agent and CO2 was 0.1 mL / min. When the peak pressure (16.5 MPa) appeared during the injection of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug, the injection was continued until the injection pressure was reduced to 4 / 5 of the peak pressure, and then the injection was stopped.

[0045] S2. In the intermediate container storing CO2-foaming agent, the mass ratio of the gas-soluble foaming agent to supercritical CO2 was 0.2:100, the pressure was 15 MPa, and the temperature was 60℃. The gas-soluble foaming agent and supercritical CO2 mixture was injected into the sandpack pipe simulating a high water cut reservoir through the ISCO piston pump at an injection rate of 1 mL / min, and the inlet end and outlet section of the sandpack pipe were simultaneously injected and produced, and the whole process was maintained at a back pressure of 15 MPa and a sandpack pipe temperature of 60℃. When the injection pressure decreased and the fluctuation range exceeded 0.1 MPa, the injection was stopped.

[0046] S3, repeat S1, S2 until the water saturation of the sandpack pipe reaches 5%.

[0047] Comparative Example 1 The same as example 1, the difference is that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows: The 85% dryness foam is injected into the sandpack through the intermediate container storing the CO2-foaming agent, and the injection rate is 40 t / d.

[0048] The preparation method of the 85% dryness foam is as follows: supercritical carbon dioxide and gas-soluble foaming agent are injected at a speed of 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in the foam generator to form 85% dryness foam.

[0049] Figure 3 The swept volume diagram of the 85% dryness foam for improving the carbon dioxide storage capacity is obtained by numerical simulation calculation of the CMG software according to the above implementation steps. The injected foam forms a near-well foam zone 6 around the injection well, and the range of the near-well foam zone 6 is smaller than that of example 1, which is caused by the thermodynamic instability of the foam and the failure to effectively break and regenerate; and in the near-well foam zone 6, the CO2 gas phase saturation can only reach 85%, because the formation bound water cannot be consumed to form foam; after the foam breaks, the supercritical carbon dioxide migrates upward and forms a supercritical carbon dioxide zone 9 after the foam breaks, and in the supercritical carbon dioxide zone 9 after the foam breaks, the CO2 gas phase saturation is only about 30%. After injecting the same amount of 85% dryness foam, the range of the deep un-swept zone 8 is obviously larger than that of example 1.

[0050] Comparative example 2 The same as example 1, the difference is that this comparative example uses supercritical CO2 for continuous displacement, and the injection rate is 40 t / d.

[0051] Figure 4 The swept volume diagram of the supercritical carbon dioxide for improving the carbon dioxide storage capacity is obtained by numerical simulation calculation of the CMG software according to the above implementation steps. The injected supercritical carbon dioxide is affected by the density difference, and soon forms a supercritical carbon dioxide zone 10 which is "wide at the top and narrow at the bottom". In the supercritical carbon dioxide zone 10, the CO2 gas phase saturation is only about 30%, which is much lower than that of example 1.

[0052] Comparative example 3 The same as example 2, the difference is that this comparative example uses 85% dryness foam for continuous displacement, and the specific steps are as follows: The 85% dryness foam is injected into the sandpack through the intermediate container storing the CO2-foaming agent, and the injection rate is 1 mL / min.

[0053] The 85% dryness foam is prepared by controlling the injection of supercritical carbon dioxide and gas-soluble foaming agent by two ISCO plunger pumps at a speed of 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in a foam generator to form the 85% dryness foam.

[0054] Comparative Example 4 The same as Example 2, except that the supercritical carbon dioxide is used for continuous displacement in the present comparative example, and the specific steps are as follows: The supercritical carbon dioxide is continuously injected into the sandpack through the intermediate container storing CO2 at a rate of 1 mL / min.

[0055] Comparative Example 5 The same as Example 3, except that the 85% dryness foam is used for continuous displacement in the present comparative example, and the specific steps are as follows: The 85% dryness foam is injected into the sandpack through the intermediate container storing CO2-foaming agent at a rate of 1 mL / min.

[0056] The 85% dryness foam is prepared by controlling the injection of supercritical carbon dioxide and gas-soluble foaming agent by two ISCO plunger pumps at a speed of 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in a foam generator to form the 85% dryness foam.

[0057] Comparative Example 6 The same as Example 3, except that the supercritical carbon dioxide is used for continuous displacement in the present comparative example, and the specific steps are as follows: The supercritical carbon dioxide is continuously injected into the sandpack through the intermediate container storing CO2 at a rate of 1 mL / min.

[0058] In Comparative Examples 1-6, there is no segmented and alternating injection, and in-situ foaming cannot be achieved around the wellbore, thereby forming a dynamic foam barrier structure.

[0059] Since the formation of foam is controlled by the concentration of surfactant, the shear rate of porous medium, etc., the foam formation time is uncertain; and in Comparative Examples 1-6, there is no injection pressure feedback mechanism, and the formation of foam under the reservoir cannot be determined, resulting in early carbon dioxide breakthrough and loss.

[0060] Figure 6is the injection volume-gas phase saturation graph of the example 2, the comparative example 3 and the comparative example 4 for improving the carbon dioxide storage capacity of the saline aquifer, and the specific data are shown in table 1. As can be seen from the graph, the gas-soluble foaming agent and the supercritical CO2 mixture can increase the carbon dioxide gas phase saturation of the saline aquifer to about 92.83% after 1.698 PV displacement, which shows that the gas-soluble foam can significantly improve the carbon dioxide storage capacity in the saline aquifer under a small amount of injection; the 85% dryness foam can increase the carbon dioxide gas phase saturation of the saline aquifer to about 82.13% after 9.910 PV displacement, which shows that the 85% dryness foam can also significantly improve the carbon dioxide storage capacity in the saline aquifer under a large amount of injection, but the maximum storage capacity will not exceed the dryness of the foam; the supercritical carbon dioxide can increase the carbon dioxide gas phase saturation of the saline aquifer to about 20.86% after 7.524 PV displacement, which shows that the direct injection of CO2 has poor storage effect.

[0061] As shown in Figure 7 is the injection volume-gas phase saturation graph of the example 3, the comparative example 5 and the comparative example 6 for improving the carbon dioxide storage capacity of the high water cut reservoir, and the specific data are shown in table 2. As shown in Figure 8 is the injection volume-oil displacement efficiency graph of the example 3, the comparative example 5 and the comparative example 6 for improving the carbon dioxide storage capacity of the high water cut reservoir, and the specific data are shown in table 3. The gas-soluble foaming agent and the supercritical CO2 mixture can increase the carbon dioxide storage capacity of the high water cut reservoir to about 91.68% and the oil recovery to about 94.28% after 3.01 PV displacement, which shows that the gas-soluble foam can significantly improve the carbon dioxide storage capacity and the oil recovery after a small amount of injection, achieving a win-win of economy and environment; the 85% dryness foam can increase the carbon dioxide storage capacity of the high water cut reservoir to about 71.95% and the oil recovery to about 80.42% after 11.62 PV displacement, which shows that the 85% dryness foam can effectively improve the carbon dioxide storage capacity and the oil recovery after a large amount of injection, but the improvement degree is not as good as the gas-soluble foaming agent and the supercritical CO2 mixture; the supercritical carbon dioxide can increase the carbon dioxide storage capacity of the high water cut reservoir to about 31.99% and the oil recovery to about 70.35% after 10.31 PV displacement, which shows that the direct injection of supercritical carbon dioxide has the lowest carbon dioxide storage capacity and oil recovery.

[0062] Table 1 injection volume-gas phase saturation of the example 2, the comparative example 3 and the comparative example 4 for improving the carbon dioxide storage capacity of the saline aquifer

[0063]

[0064] Table 2 injection volume-gas phase saturation of the example 3, the comparative example 5 and the comparative example 6 for improving the carbon dioxide storage capacity of the high water cut reservoir

[0065] Table 3 Injection volume - oil displacement efficiency of increasing carbon dioxide storage capacity in high water cut reservoirs for Example 3, Comparative Example 5 and Comparative Example 6

[0066] The gas soluble foaming agent described in Examples 4-6, Comparative Examples 7-10 was an amidoated site sequence hydrocarbon ether that was made in the laboratory and the remaining materials were purchased commercially. The amidoated site sequence hydrocarbon ether had the following structure: .

[0067] The amidoated site sequence hydrocarbon ether was made by adding 1.0 mol (144 g) of 3,5,5-trimethyl-1-hexanol and 8.3 g of barium hydroxide catalyst to a dry and clean high temperature and pressure reaction vessel with a stirrer. After purging with high purity nitrogen for 15 minutes, 5 mol (290 g) of propylene oxide was added over 2.5 hours while controlling the reaction temperature at 130 °C. The product, 3,5,5-trimethyl-1-hexanol polyoxypropylene ether, was obtained after 3 hours of reaction. After cooling the reaction vessel to a temperature of 120 °C, 9 mol (396 g) of ethylene oxide was added over 4.5 hours while controlling the reaction temperature. The reaction was continued for 1.5 hours to produce 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether, which was discharged after cooling. The 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether was dissolved in anhydrous tetrahydrofuran to make a 0.5 g / mL solution, which was then added to 1 mol (101 g) of triethylamine while controlling the temperature at 5 °C. Subsequently, 1 mol (190.5 g) of p-toluenesulfonyl chloride was slowly added dropwise while stirring for 6.5 hours at a temperature of 10 °C to ensure complete reaction. The triethylamine hydrochloride salt was then removed by filtration, and the filtrate was concentrated under reduced pressure. The precipitate was obtained by adding cold diethyl ether and centrifuging. The sulfonylated intermediate was obtained by adding the sulfonylated intermediate, 5 mol (467.5 g) of chloroacetamide, and 2 mol (276 g) of anhydrous potassium carbonate to N,N-dimethylformamide, heating to 80 °C under nitrogen protection, and stirring for 26 hours to obtain the amidoated polymethyl hydrocarbon ether crude product. The amidoated polymethyl hydrocarbon ether crude product was concentrated by rotary evaporation, slowly added dropwise to cold diethyl ether to induce precipitation, and centrifuged to obtain a white solid, which was washed by repeating the precipitation and washing three times. The amidoated polymethyl hydrocarbon ether was obtained by dissolving the white solid in deionized water, placing it in a dialysis bag, dialyzing for 72 hours, and finally freeze-drying.

[0068] Example 4 As Figure 1The figure shows the field diagram for improving the amount of carbon dioxide storage by using gas-soluble foaming agent. The field is a certain reservoir in Dongying, Shandong. Injection well 3 is connected to high-pressure CO2 gas source 1 through gas-soluble foaming agent solution storage tank 2. Production well 4 is arranged in geological storage body 5. The geological storage body 5 is a high-water-content reservoir.

[0069] A method for improving the amount of carbon dioxide storage by using gas-soluble foaming agent. The specific steps are as follows: S1. Inject a pre-positioned gas-soluble foaming agent slug and a post-positioned CO2 slug into the geological storage body in sequence through gas-soluble foaming agent solution storage tank 2 and high-pressure CO2 gas source 1. The pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are injected alternately in two times. The volume ratio of the injection amount of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug is 1:5. The total injection amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug is 1 m 3 and 5 m 3 . After the peak pressure (18.1 MPa) appears when the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are injected alternately, continue to inject until the injection pressure decreases to 4 / 5 of the peak pressure, and stop injecting.

[0070] S2. Inject the gas-soluble foaming agent and supercritical CO2 mixture from injection well 3 into geological storage body 5 at an injection rate of 40 t / d. The injection process adopts the tubing injection method, and injection well 3 and production well 4 are simultaneously injected and produced. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, stop injecting. The preparation method of the gas-soluble foaming agent and supercritical CO2 mixture is as follows: CO2 in high-pressure CO2 gas source 1 is pressurized and sent to gas-soluble foaming agent solution storage tank 2. In the gas-soluble foaming agent solution storage tank 2, supercritical CO2 is mixed uniformly with the gas-soluble foaming agent. The stirring rotor is started to accelerate the phase equilibrium during the mixing process. The mass ratio of the gas-soluble foaming agent to the supercritical CO2 is 0.3:100. The pressure is 12 MPa, and the temperature is 55℃.

[0071] S3. Repeat S1 and S2 until the water saturation of the geological storage body reaches 10%.

[0072] Figure 9The swept volume diagram for improving the carbon dioxide storage capacity obtained by the CMG software numerical simulation according to the above implementation steps is shown in the figure. The injected gas-soluble foaming agent and supercritical CO2 mixture are in-situ foamed by the shearing action of the porous medium using the formation water, and a large amount of foam is quickly generated near the injection well to form a near-well foam zone 6. The gas-soluble foaming agent is carried upward by the supercritical carbon dioxide after the foam is broken, and is foamed again when encountering the formation water to form a regenerated foam zone 7, achieving the effect of breaking and regenerating, dynamic stability, further expanding the swept volume, and reducing the volume of the un-swept zone 8 in the deep part of the geological storage body. In the near-well foam zone 6 and the regenerated foam zone 7, the generation of the gas-soluble foam consumes the formation bound water, thereby reducing the water saturation and improving the carbon storage space; the generated foam effectively drives the residual oil, thereby improving the recovery efficiency while reducing the residual oil saturation and further improving the carbon storage space. Finally, in the near-well foam zone 6 and the regenerated foam zone 7, the CO2 gas phase saturation can reach 92%, significantly improving the CO2 storage capacity; the oil recovery efficiency can reach 94%, greatly improving the recovery efficiency; and the economic and environmental win-win effect is achieved.

[0073] Example 5 Experimental purpose: To investigate the effect of using a gas-soluble foaming agent to improve the carbon dioxide storage capacity in a saline aquifer.

[0074] Experimental conditions: According to Figure 5 After connecting the experimental device, that is, connecting the intermediate containers respectively storing crude oil, formation water, CO2, CO2-foaming agent and foaming agent to the ISCO plunger pump through the six-way valve, and connecting the inlet end of the core holder to the computer through the six-way valve, and connecting the outlet end of the core holder to the back pressure valve and the beaker in turn, the beaker is used to collect the produced liquid.

[0075] The core holder is a sandpack pipe simulating a saline aquifer, and the preparation method is as follows: open the ISCO plunger pump to fill the sandpack pipe with formation water to a saturated state at an injection rate of 1 mL / min, and maintain the temperature of the sandpack pipe at 70°C and the pressure at 15 MPa during the whole process.

[0076] The permeability of the sandpack pipe is 640 mD, the pore volume is 56.5 mL, and the total length is 1 m.

[0077] Experimental steps: S1, injecting a pre-positioned gas-soluble foaming agent slug and a post-positioned CO2 slug into the sandpack in sequence through an intermediate container storing the foaming agent and an intermediate container storing CO2, wherein the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are alternately injected in three times, the volume ratio of the injection amount of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug is 1:2 each time, the total injection amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug is 2 mL and 4 mL respectively, and the flow rate of the gas-soluble foaming agent and CO2 is 0.1 mL / min. When the peak pressure (16.6 MPa) appears after the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are alternately injected in segments, and the injection continues until the injection pressure decreases to 4 / 5 of the peak pressure, the injection is stopped.

[0078] S2, in the intermediate container storing CO2-foaming agent, the mass ratio of the gas-soluble foaming agent to supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 70℃; The gas-soluble foaming agent and supercritical CO2 mixture is injected into the sandpack through the ISCO plunger pump at an injection rate of 1 mL / min, and the inlet end and outlet section of the sandpack are simultaneously injected and sampled, the whole process maintains the back pressure at the outlet end at 15 MPa, and the temperature of the sandpack is 70℃; When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0079] S3, repeating S1 and S2 until the water saturation of the sandpack reaches 5%.

[0080] Example 6 Purpose of the experiment: To investigate the effect of using a gas-soluble foaming agent to improve the carbon dioxide storage capacity of a high water cut reservoir.

[0081] Experimental conditions: According to Figure 5 The experimental device is connected, wherein the core holder is a sandpack simulating a high water cut reservoir, and the preparation method is as follows: open the ISCO plunger pump to fill the sandpack with oil at an injection rate of 1 mL / min until the sandpack is saturated, and maintain the temperature of the sandpack at 60℃ and the pressure at 15 MPa during the whole process. The initial oil saturation of the sandpack after being saturated with oil is 82.1%, and the viscosity of the oil used in the experiment is 25 mPa·s at 60℃. The sandpack is placed in a 60℃ oven for constant temperature aging for 24h, and then a water flooding experiment is carried out at a temperature of 60℃ and a pressure of 15 MPa with an injection rate of 1 mL / min. After 4.1426 PV of water flooding, the oil saturation in the sandpack decreases to 24.8%, and the water saturation increases to 75.2%, thereby obtaining a sandpack of a high water cut reservoir.

[0082] The permeability of the sandpack is 845 mD, the pore volume is 57.5 mL, and the total length is 1 m.

[0083] Experimental steps: S1. A pre-positioned gas-soluble foaming agent slug and a post-positioned CO2 slug are sequentially injected into the sandpack through the intermediate container storing the foaming agent and the intermediate container storing CO2, wherein the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug are alternately injected in three times, the volume ratio of the injection amount of the pre-positioned gas-soluble foaming agent slug to the post-positioned CO2 slug is 1:3, the total injection amount of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug is 3 mL and 9 mL respectively, and the flow rate of the gas-soluble foaming agent and CO2 is 0.1 mL / min. When the peak pressure (16.3 MPa) appears during the segmented and alternating injection of the pre-positioned gas-soluble foaming agent slug and the post-positioned CO2 slug, the injection is continued until the injection pressure decreases to 4 / 5 of the peak pressure, and then the injection is stopped.

[0084] S2. In the intermediate container storing CO2-foaming agent, the mass ratio of the gas-soluble foaming agent to the supercritical CO2 is 0.2:100, the pressure is 15 MPa, and the temperature is 60℃; The gas-soluble foaming agent and supercritical CO2 mixture is injected into the sandpack of the simulated high water cut reservoir through the ISCO plunger pump at an injection rate of 1 mL / min, and the inlet end and outlet section of the sandpack are simultaneously injected and produced, the whole process maintains the back pressure of the production end at 15 MPa, and the temperature of the sandpack is 60℃; When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0085] S3, repeat S1, S2 until the water saturation of the sandpack reaches 5%.

[0086] Comparative Example 7 The same as Example 4, except that the dryness 85% foam is used for continuous displacement in this comparative example, and the specific steps are as follows: The dryness 85% foam is injected into the sandpack through the intermediate container storing CO2-foaming agent, and the injection rate is 40 t / d.

[0087] The preparation method of the dryness 85% foam is as follows: supercritical carbon dioxide and gas-soluble foaming agent are injected at a speed of 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in the foam generator to form 85% dryness foam.

[0088] Figure 10To follow the above implementation steps, the swept volume diagram of the 85% dryness foam to improve the carbon dioxide storage capacity is obtained by CMG software numerical simulation calculation. The injected foam forms a near-well foam zone 6 around the injection well, the range of the near-well foam zone 6 is smaller than that of example 4, which is caused by the thermodynamic instability of the foam and the failure to effectively break and regenerate; and in the near-well foam zone 6, the CO2 gas phase saturation can only reach 85% at most, because the formation of foam cannot consume the formation bound water; after the foam breaks, the supercritical carbon dioxide gas channeling upward, forming a supercritical carbon dioxide zone 9 after the foam breaks, in the supercritical carbon dioxide 9 after the foam breaks, the CO2 gas phase saturation is only about 30%. After injecting the same amount of 85% dryness foam, the range of the deep un-swept zone 8 is significantly larger than that of example 4.

[0089] Comparative example 8 The same as example 5, the difference is that this comparative example uses 85% dryness foam for continuous displacement, the specific steps are as follows: The 85% dryness foam is injected into the sandpack through the intermediate container storing CO2-foaming agent, and the injection rate is 1 mL / min.

[0090] Among them, the preparation method of 85% dryness foam is: the injection of supercritical carbon dioxide and gas-soluble foaming agent is controlled by two ISCO plunger pumps respectively, the injection speed of the two is 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in the foam generator to form 85% dryness foam.

[0091] Comparative example 9 The same as example 6, the difference is that this comparative example uses 85% dryness foam for continuous displacement, the specific steps are as follows: The 85% dryness foam is injected into the sandpack through the intermediate container storing CO2-foaming agent, and the injection rate is 1 mL / min.

[0092] Among them, the preparation method of 85% dryness foam is: the injection of supercritical carbon dioxide and gas-soluble foaming agent is controlled by two ISCO plunger pumps respectively, the injection speed of the two is 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in the foam generator to form 85% dryness foam.

[0093] Comparative example 10 The same as example 6, the difference is that this comparative example uses supercritical carbon dioxide for continuous displacement, the specific steps are as follows: The supercritical carbon dioxide is continuously injected into the sandpack through the intermediate container storing CO2, and the injection rate is 1 mL / min.

[0094] 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.

[0095] 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.

[0096] 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 saline aquifers 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 saline aquifers 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.

[0097] 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 injection volume-gas saturation graph of improving the carbon dioxide storage capacity of high water cut reservoirs of Example 6, Comparative Example 9 and Comparative Example 10 is shown, and the specific data is shown in Table 6. The gas-soluble foaming agent and supercritical CO2 mixture can increase the carbon dioxide storage capacity of high water cut reservoirs by about 90.108% and the oil recovery by about 95.043% after 3.054 PV displacement, which shows that the gas-soluble foam can significantly improve the carbon dioxide storage capacity and oil recovery after a small amount of injection, achieving a win-win in economy and environment; the 85% dryness foam can increase the carbon dioxide storage capacity of high water cut reservoirs by about 72.12% and the oil recovery by about 81.39% after 14.16 PV displacement, which shows that the 85% dryness foam can effectively improve the carbon dioxide storage capacity and oil recovery after a large amount of injection, but the improvement degree is not as good as that of the gas-soluble foaming agent and supercritical CO2 mixture; the supercritical carbon dioxide can increase the carbon dioxide storage capacity of high water cut reservoirs by about 34.05% and the oil recovery by about 70.88% after 11.25 PV displacement, which shows that direct injection of supercritical carbon dioxide has the lowest carbon dioxide storage capacity and oil recovery.

[0098] Table 4 Injection volume-gas saturation graph of improving the carbon dioxide storage capacity of saline aquifers of Example 5, Comparative Example 8 and Comparative Example 4

[0099] Table 5 Injection volume-gas saturation graph of improving the carbon dioxide storage capacity of high water cut reservoirs of Example 6, Comparative Example 9 and Comparative Example 10

[0100] Table 6 Injection volume-displacement efficiency graph of improving the carbon dioxide storage capacity of high water cut reservoirs of Example 6, Comparative Example 9 and Comparative Example 10

[0101] The examples provided in the file are intended to illustrate the technical solutions of the present application, but not to limit them. Although the present application has 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 replacements for part or all of the technical features; these modifications or replacements will not make the essence of the corresponding technical solutions beyond the scope of the technical solutions of the embodiments of the present application.

Claims

1. A method for increasing carbon dioxide storage capacity using an aerosolized foaming agent, characterized in that, 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%.

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

5. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 1, characterized in that, 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.

6. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 5, 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.

7. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 6, characterized in that, 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.

8. 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.

9. The method for increasing carbon dioxide storage capacity using an aerosolized foaming agent according to claim 8, characterized in that, The pressure of the geological seal is greater than 10 MPa, and the temperature is 35~90 ℃.

10. 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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