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 invention relates to the technical field of carbon sequestration and utilization, and in particular to a method for increasing the amount of carbon dioxide sequestration by utilizing a gas-soluble foaming agent. Background Art

[0002] Human beings are overly dependent on fossil fuels, such as coal, oil and natural gas, which leads to large amounts of greenhouse gas emissions, mainly carbon dioxide. The increase in carbon dioxide emissions has led to a continuous rise in global temperatures and frequent extreme weather events. Climate change and carbon emission reduction have become important issues of concern to the international community. 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 impact on climate change. At present, geological storage 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 water layers and depleted oil and gas reservoirs (especially high water-content reservoirs) for storage. During the immiscible drive process, due to the viscous fingering and gravity differentiation caused by the low viscosity and low density of carbon dioxide, as well as the influence of reservoir heterogeneity, carbon dioxide crossflow is serious, the sweep efficiency is low, and the final 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 foam, and inject the foam into the formation for sealing. When carbon dioxide foam is injected into the saline water layer, due to its high viscosity, it can effectively control the flow of carbon dioxide, reduce gas crossflow, expand the sweep range, and improve the storage efficiency. When carbon dioxide foam is injected into a high water-content reservoir, it has the characteristics of "blocking large but not small, blocking water but not oil", which can effectively block high permeability channels, while improving the recovery rate of crude oil, increasing the storage volume and safety of carbon dioxide.

[0004] However, conventional foam flooding technology has some limitations, such as difficulty in injecting into low permeability reservoirs, poor foam stability leading to foam fracturing and dissipation, high water content and low gas content, which ultimately lead to low foam flooding storage efficiency.

[0005] In order to solve the above problems, Chinese patent CN115341896A proposes a method of using high-dryness foam to increase CO 2 This method increases the CO storage efficiency by increasing the CO 2The carbon sequestration capacity of the foam is higher than that of conventional foams because the foam has poor stability and requires the injection of a large amount of PV foam before the carbon sequestration capacity can be significantly increased. In addition, the foam is injected after the foam is formed on the ground, 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 CO 2 The ability to dissolve in the medium is poor. After being mixed on the ground and injected into the reservoir, it is easy for the gas and liquid to separate and become ineffective.

[0006] Chinese patent CN118128594A provides a method for enhancing geological storage by strengthening carbon dioxide foam with nano armor, thereby improving foam stability. This method mainly improves the stability of the foam, thereby achieving a strong foam storage and expanding the spread effect. However, in order to improve the stability of the foam, it is necessary to increase the viscosity of the base fluid. The increase in base fluid viscosity will make it difficult to generate foam underground. At the same time, nanoparticles will block the formation and cause reservoir damage. In addition, the foaming agent of the foam can only be dissolved in water and cannot be dissolved in CO2. 2 Although nanoparticles have improved the stability of foam to a certain extent, the foam still undergoes gas-liquid separation, resulting in the foam being able to function only around the wellbore and unable to penetrate into the reservoir, leading to CO 2 The storage effect is poor.

[0007] Chinese patent CN103867169A provides a method for controlling the mobility of carbon dioxide using an aerosol surfactant. The method requires that the aerosol surfactant be evenly mixed with supercritical carbon dioxide and then directly injected into the oil reservoir. However, since the mixture of carbon dioxide and aerosol surfactant is injected at one time, it is difficult to form a stable foam structure around the wellbore. As the aerosol surfactant is lost in the rock adsorption process during the migration of the aerosol surfactant to the deep reservoir, it is easy to cause early breakthrough and loss of carbon dioxide in the formation, affecting the long-term storage of carbon; at the same time, it cannot effectively respond to dynamic changes under complex formation conditions, and it is easy to have a low carbon dioxide storage capacity. In addition, the aerosol surfactant used has low solubility in supercritical carbon dioxide, and the foam formed has poor stability. And this method is difficult to form a stable foam plugging barrier in the reservoir.

[0008] In summary, the existing technologies for improving carbon dioxide storage have the disadvantages of high injection pressure and difficulty in injection, and the foaming agent can only be dissolved in water and cannot be absorbed by CO. 2 The foam always has low water phase and carbon dioxide phase content, poor foam stability, limited ability to expand the affected area, and inability to adjust the injection method in real time according to complex formation conditions, resulting in low final carbon dioxide geological storage capacity. It is urgent to develop a method for high carbon dioxide geological storage capacity. Summary of the invention

[0009] In view of the deficiencies of the prior art, the present invention provides a method for increasing the storage capacity of carbon dioxide by using a 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 the formation water, thereby reducing the bound water saturation and increasing the carbon storage space for carbon dioxide; the gas-soluble foaming agent is carried up by the supercritical carbon dioxide after the foam breaks, and foams again when it encounters the formation water, achieving the effects of rupture regeneration and dynamic stability (dynamic stability is different from static stability, no longer blindly pursuing a high foam half-life or liquid separation half-life, but instead pursuing regeneration after the foam breaks), which is conducive to further expanding the affected volume; the generated foam has the intelligent selectivity of "blocking high but not low", and after blocking the high permeability strip, it forces carbon dioxide to displace residual oil, thereby achieving the effect of improving the recovery rate, and at the same time, the output of residual oil provides carbon storage space for carbon dioxide storage. In addition, the present invention uses a pre-placed gas-soluble foaming agent plug and a post-placed CO 2 The segmented plugs are injected alternately in sections to achieve in-situ foaming around the wellbore, forming a dynamic foam barrier structure to block the high permeability channel. This segmented alternating injection method utilizes the complex pressure field of the formation to enhance the regulation ability of the gas-soluble foaming agent, which not only effectively prolongs the retention time of carbon dioxide in the formation, but also continuously expands the affected range through the foam rupture regeneration mechanism, thereby greatly increasing the carbon storage capacity. The present invention also sets a real-time injection pressure feedback mechanism, which dynamically adjusts the injection method by monitoring the pressure changes during the injection process to ensure the long-term stable distribution of carbon dioxide in the formation, reduce the early breakthrough and loss of carbon dioxide, significantly improve the storage efficiency, and effectively improve the storage effect of carbon dioxide.

[0010] In order to achieve the above object, the present invention adopts the following technical solution: A method for increasing the storage capacity of carbon dioxide using a gas-soluble foaming agent comprises the following steps: S1, front gas soluble foaming agent plug and rear CO 2 The slugs are injected alternately into the geological storage body in sections, and the injection pressure continues to increase. When the injection pressure reaches the peak pressure, the injection continues. When the injection pressure drops, the injection is continued until the injection pressure drops to 1 / 2~4 / 5 of the peak pressure, and then the injection is stopped. S2, gas soluble foaming agent and supercritical CO 2 The mixture is injected into the injection well, and injection and production are carried out simultaneously in 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. Repeat S1 and S2 until the water saturation of the geological storage body reaches 5-10%.

[0011] In step S2, the gas-soluble foaming agent and supercritical CO 2The pressure and temperature of the mixture are respectively the same as the pressure and temperature of the geological storage body.

[0012] The front gas-soluble foaming agent segment plug and the rear CO 2 The injection volume ratio of the slug is 1:(2~5).

[0013] Under the pressure and temperature of the geological storage body, the solubility of the gas-soluble foaming agent in supercritical carbon dioxide is not less than 0.2, otherwise stable foam will not be formed and effective foam flooding and oil storage cannot be carried out.

[0014] Preferably, the gas-soluble foaming agent is an amidation site sequence hydrocarbon ether, the structural formula of which is: ; 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, and 3-methyl-2-butyl; The value range of m is 5~20; The value range of n is 5~20.

[0015] The gas-soluble foaming agent and supercritical CO 2 In the mixture, the gas-soluble foaming agent and supercritical CO 2 The mass ratio is (0.2-1.5):100; preferably, the mass ratio is (0.3-0.5):100.

[0016] The geological storage body includes saline water layer and depleted gas reservoir.

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

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

[0019] The gas-soluble foaming agent and supercritical CO 2 The injection rate of the mixture is 20~100 t / d.

[0020] The gas-soluble foaming agent and supercritical CO 2The mixture is injected through the tubing from the inside of the tubing, and the casing annulus is sealed with a packer.

[0021] The present invention solves the problem that the conventional surfactant base liquid has high viscosity and is difficult to generate foam underground by replacing the conventional surfactant with an aerosol foaming agent. In addition, the aerosol foaming agent is carried upward by supercritical carbon dioxide after the foam bursts, and foams again when it encounters formation water, achieving the effects of rupture regeneration and dynamic stabilization, which is conducive to further expanding the affected volume.

[0022] Beneficial Effects 1. The present invention uses a gas-soluble foaming agent to increase the carbon dioxide storage capacity of a geological storage body. 2 After the mixture is injected into the geological storage body, the formation water is directly used for in-situ foaming through the shearing action of the porous medium, thereby reducing the bound water saturation and increasing the carbon storage space for carbon dioxide; the generated foam has the intelligent selectivity of "blocking high but not low", and after blocking the high permeability band, it forces the carbon dioxide to displace the residual oil, thereby achieving the effect of improving the recovery rate. At the same time, the output of the residual oil provides carbon storage space for carbon dioxide storage. After the foam bursts, the gas-soluble foaming agent is carried up by the supercritical carbon dioxide and foams again when it encounters the formation water, achieving the effects of rupture regeneration and dynamic stabilization, which is conducive to further expanding the affected volume; finally, the three effects of in-situ foaming of formation water, rupture regeneration, and dynamic stabilization are superimposed, thereby achieving the effect of significantly increasing the final carbon dioxide storage capacity. In addition, the present invention directly injects the gas-soluble foaming agent and the supercritical CO 2 The mixture is foamed in situ in the formation without the need for surface foaming before injection, thus avoiding the problems of high injection pressure and difficult injection.

[0023] 2. Aiming at the shortcomings of the prior art in increasing the storage capacity of carbon dioxide, the present invention provides a method for increasing the storage capacity of carbon dioxide by using a pre-placed gas-soluble foaming agent segment plug and a post-placed CO 2 The method of segmented alternating injection of plugs. Through segmented alternating injection, in-situ foaming is achieved around the wellbore to form a dynamic foam barrier structure to block the high permeability channel. This segmented alternating injection method uses the complex pressure field of the formation to enhance the control ability of the gas-soluble foaming agent, which not only effectively prolongs the retention time of carbon dioxide in the formation, but also continuously expands the scope of influence through the foam rupture regeneration mechanism, thereby greatly increasing the carbon storage capacity.

[0024] 3. The present invention introduces a real-time injection pressure feedback mechanism. By monitoring the injection pressure changes during the injection process, the injection method can be dynamically adjusted; the gas-soluble foaming agent and supercritical CO 2When the mixture is injected, ensure that the foam maintains a good plugging effect in the formation; when the segments are injected alternately, 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 storage effect of carbon dioxide. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] Figure 1 A schematic diagram of the site for increasing the carbon dioxide storage capacity by using gas-soluble foaming agents; Figure 2 This is a schematic diagram of the swept volume for increasing the carbon dioxide storage capacity in Example 1; Figure 3 This is a schematic diagram of the swept volume for increasing the carbon dioxide storage capacity in Comparative Example 1; Figure 4 This is a schematic diagram of the swept volume for increasing the carbon dioxide storage capacity in Comparative Example 2; Figure 5 It is the connection diagram of the simulation experimental device; Figure 6 Injection volume-gas saturation diagram for increasing carbon dioxide storage in saline layers for Example 2, Comparative Example 3 and Comparative Example 4; Figure 7 Injection volume-gas saturation diagram for increasing carbon dioxide storage capacity in high water-content oil reservoirs for Example 3, Comparative Example 5 and Comparative Example 6; Figure 8 The injection volume-oil displacement efficiency diagram for increasing the carbon dioxide storage capacity in high water-content oil reservoirs for Example 3, Comparative Example 5 and Comparative Example 6; Among them, 1. High-pressure CO 2 1. Gas source; 2. Gas-soluble foaming agent solution storage tank; 3. Injection well; 4. Production well; 5. Geological storage body; 6. Near-well foam area; 7. Regeneration foam area; 8. Unaffected area deep inside the geological storage body; 9. Supercritical carbon dioxide area after foam rupture; 10. Supercritical carbon dioxide area. DETAILED DESCRIPTION

[0026] In order to more clearly explain the purpose, technical solutions and advantages of the present invention, the technical solutions of the present invention are described in detail below in conjunction with the accompanying drawings and embodiments of the specification. These embodiments represent only a part of the implementation of the present invention, not all. The protection scope of the present invention is not limited to this.

[0027] The gas-soluble foaming agent in each embodiment and comparative example is an amidation site sequence hydrocarbon ether, which is synthesized in the laboratory, and the remaining raw materials are purchased through commercial channels. The structural formula of the amidation site sequence hydrocarbon ether is as follows: .

[0028] The preparation method of the amidation site sequence hydrocarbon 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 reactor with a stirrer, and 5 mol (290 g) of propylene oxide is introduced after purging with high-purity nitrogen for 15 minutes, and the introduction is completed in 2.5 hours, and the reaction temperature is controlled at 130°C for 3 hours to obtain the product 3,5,5-trimethyl-1-hexanol polyoxypropylene ether. After cooling the reactor to a temperature of 120°C, the reaction temperature is controlled to remain unchanged, and after 9 mol (396 g) of ethylene oxide is introduced in 4.5 hours, the reaction is continued for 1.5 hours to obtain 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether, and the temperature is lowered and the material is discharged. 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 conditions, 1 mol (78 g) of acetyl chloride was added dropwise, and the reaction temperature was controlled to be 20°C. After adding acetyl chloride, the reaction mixture was kept stirring at 30°C for 1.5 hours to ensure complete reaction. Subsequently, acetamido 3,5,5-trimethyl-1-hexanol polyoxypropylene polyoxyethylene ether was obtained after neutralization with glacial acetic acid, vacuum filtration, ethyl acetate dissolution and filtration, rotary evaporation and vacuum drying.

[0029] Example 1 like Figure 1 The figure shows a schematic diagram of a field for increasing the storage capacity of carbon dioxide by using a gas-soluble foaming agent. The field is an oil reservoir in Dongying, Shandong. An injection well 3 and a production well 4 are set in a geological storage body 5. The injection well 3 is connected to a high-pressure CO2 storage tank 2 through a gas-soluble foaming agent solution storage tank 2. 2 Gas source 1. The geological storage body 5 is a high water content oil reservoir.

[0030] A method for increasing the storage capacity of carbon dioxide using a gas-soluble foaming agent, the specific steps are as follows: S1, through the gas-soluble foaming agent solution storage tank 2 and high-pressure CO 2 Gas source 1 injects the front gas-soluble foaming agent plug and the rear CO into the geological storage body in sequence. 2 Segment plug, wherein the front gas-soluble foaming agent segment plug and the rear CO 2 The slugs are injected alternately twice, with the front gas-soluble foaming agent slug and the rear CO 2 The injection volume ratio of the slug is 1:5, and the front gas-soluble foaming agent slug and the rear CO 2 The total injection volume of the slug is 1 m 3 and 5 m 3 When the front gas-soluble foaming agent plug and the rear CO 2After the peak pressure (18.5 MPa) appears during the alternating injection of the slugs, the injection is continued until the injection pressure drops to 4 / 5 of the peak pressure, and then the injection is stopped.

[0031] S2, gas soluble foaming agent and supercritical CO 2 The mixture is injected into the geological storage body 5 from the injection well 3 at an injection rate of 40 t / d. The injection process adopts the tubing positive injection method, and the injection well 3 and the production well 4 are injected and produced simultaneously. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped. Wherein, the gas-soluble foaming agent and supercritical CO 2 The mixture is prepared by: 2 CO in gas source 1 2 After pressurization, it is sent to the gas-soluble foaming agent solution storage tank 2, where supercritical CO 2 Mix evenly with the gas-soluble foaming agent. Start the stirring rotor to accelerate the phase equilibrium during the mixing process. The gas-soluble foaming agent and supercritical CO 2 The mass ratio during mixing was 0.3:100, the pressure was 12 MPa, and the temperature was 55°C.

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

[0033] Figure 2 Schematic diagram of the swept volume for increasing the carbon dioxide storage capacity obtained by numerical simulation with CMG software according to the above implementation steps. 2 The mixture uses formation water to foam in situ through the shearing action of porous media, and quickly produces a large amount of foam near the injection well, forming a near-well foam zone 6. After the foam breaks, the gas-soluble foaming agent is carried up by supercritical carbon dioxide and foams again when it encounters formation water to form a regenerated foam zone 7, achieving the effects of rupture regeneration and dynamic stability, further expanding the affected volume, and reducing the volume of the deep unaffected area 8 of the geological storage body. In the near-well foam zone 6 and the regenerated foam zone 7, the generation of gas-soluble foam consumes the formation bound water, thereby reducing the water saturation and increasing the carbon storage space; the generated foam effectively drives the residual oil, while increasing the recovery rate, reducing the residual oil saturation and further increasing the carbon storage space. Finally, in the near-well foam zone 6 and the regenerated foam zone 7, CO 2 The gas phase saturation can reach 95%, significantly increasing CO 2 The storage volume; the crude oil recovery rate can reach 93%, which greatly improves the recovery rate; achieving a win-win effect in economy and environment.

[0034] Example 2 Purpose: To investigate the effect of using gas-soluble foaming agents to increase the storage capacity of carbon dioxide in saline aquifers.

[0035] Experimental conditions: according to Figure 5 Connect the experimental device, that is, store crude oil, formation water, and CO 2 , CO 2 - One end of the foaming agent and the intermediate container of the foaming agent is connected to the ISCO plunger pump through a six-way valve, and the other end is connected to the inlet end of the core holder and the computer through a six-way valve. The outlet end of the core holder is connected to the back pressure valve and the beaker in sequence, and the beaker is used to receive the produced fluid.

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

[0037] The sand-filled tube has a permeability of 640 mD, a pore volume of 56.5 mL, and a total length of 1 m.

[0038] Experimental steps: S1, through the intermediate container storing the foaming agent and the intermediate container storing the CO 2 The intermediate container injects the front gas-soluble foaming agent plug and the rear CO into the sand filling pipe in sequence. 2 Segment plug, wherein the front gas-soluble foaming agent segment plug and the rear CO 2 The slugs were injected alternately three times, with the gas-soluble foaming agent slug in front and the CO slug in the back. 2 The injection volume ratio of the slug is 1:2, and the front gas-soluble foaming agent slug and the rear CO 2 The total amount of slug injection was 2 mL and 4 mL, respectively, and the gas-soluble foaming agent and CO 2 The flow rate of the gas-soluble foaming agent plug at the front and the CO at the rear are 0.1 mL / min. 2 After the peak pressure (16.8 MPa) appears during the segmented alternating injection of the slugs, the injection is continued until the injection pressure drops to 4 / 5 of the peak pressure, and then the injection is stopped.

[0039] S2, CO storage 2 -In the intermediate container of the blowing agent, the gas-soluble blowing agent and the supercritical CO 2 The mass ratio is 0.2:100, the pressure is 15 MPa, and the temperature is 70°C; The gas-soluble foaming agent and supercritical CO 2The mixture was injected into the sand-filling pipe by an ISCO plunger pump at an injection rate of 1 mL / min, and the inlet and outlet sections of the sand-filling pipe were injected and produced simultaneously. During the whole process, the back pressure at the production end was kept at 15 MPa and the temperature of the sand-filling pipe was kept at 70°C. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0040] S3. Repeat S1 and S2 until the water saturation of the sand filling pipe reaches 5%.

[0041] Example 3 Purpose: To investigate the effect of using gas-soluble foaming agents to increase the carbon dioxide storage capacity in high water-content oil reservoirs.

[0042] Experimental conditions: according to Figure 5 The experimental device was connected, wherein the core holder was a sand-filled tube simulating a high water-cut reservoir, and the preparation method was as follows: the ISCO plunger pump was turned on to fill the sand-filled tube with crude oil at an injection rate of 1 mL / min to a saturated state, and the temperature of the sand-filled tube was kept at 60°C and the pressure was kept at 15 MPa during the whole process. The initial oil saturation of the sand-filled tube after saturation with oil was 81.8%, and the viscosity of the experimental oil at 60°C was 25 mPa·s. The sand-filled tube was placed in a 60°C oven for constant temperature aging for 24 hours, and then a water flooding experiment was carried out at a temperature of 60°C and a pressure of 15 MPa at an injection rate of 1 mL / min. After 3.952 PV of water flooding, the oil saturation in the sand-filled tube dropped to 24.3%, and the water saturation increased to 75.7%, and a sand-filled tube for a high water-cut reservoir was obtained.

[0043] The permeability of the sand-filled tube is 866 mD, the pore volume is 57.3 mL, and the total length is 1 m.

[0044] Experimental steps: S1. Through the intermediate container containing the blowing agent and the intermediate container containing CO 2 The intermediate container injects the front gas-soluble foaming agent plug and the rear CO into the sand filling pipe in sequence. 2 Segment plug, wherein the front gas-soluble foaming agent segment plug and the rear CO 2 The slugs were injected alternately three times, with the gas-soluble foaming agent slug in front and the CO slug in the back. 2 The injection volume ratio of the slug is 1:3, and the front gas-soluble foaming agent slug and the rear CO 2 The total amount of slug injection was 3 mL and 9 mL, respectively, and the gas-soluble foaming agent and CO 2 The flow rate of the gas-soluble foaming agent plug at the front and the CO at the rear are 0.1 mL / min. 2After the peak pressure (16.5 MPa) appears during the segmented alternating injection of the slugs, the injection is continued until the injection pressure drops to 4 / 5 of the peak pressure, and then the injection is stopped.

[0045] S2. CO storage 2 -In the intermediate container of the blowing agent, the gas-soluble blowing agent and the supercritical CO 2 The mass ratio is 0.2:100, the pressure is 15 MPa, and the temperature is 60°C; The gas-soluble foaming agent and supercritical CO 2 The mixture was injected into the sand-filled pipe simulating a high water-cut reservoir by an ISCO plunger pump at an injection rate of 1 mL / min. The inlet and outlet sections of the sand-filled pipe were injected and produced simultaneously. The back pressure at the production end was kept at 15 MPa and the temperature of the sand-filled pipe was kept at 60°C during the whole process. When the injection pressure decreases and the fluctuation range exceeds 0.1 MPa, the injection is stopped.

[0046] S3. Repeat S1 and S2 until the water saturation of the sand filling pipe reaches 5%.

[0047] Comparative Example 1 The same as Example 1, except that this comparative example uses 85% dry foam for continuous displacement, and the specific steps are as follows: By storing CO 2 -The intermediate container of the foaming agent injects 85% dry foam into the sand filling pipe at a rate of 40t / d.

[0048] Among them, the preparation method of 85% dry foam is: inject supercritical carbon dioxide and gas-soluble foaming agent, the injection speeds of the two are 0.85 mL / min and 0.15 mL / min respectively, and the two are mixed in a foam generator to form 85% dry foam.

[0049] Figure 3 The schematic diagram of the swept volume when the 85% dryness foam increases the carbon dioxide storage capacity is obtained by numerical simulation calculation using CMG software according to the above implementation steps. The injected foam forms a near-wellbore foam zone 6 around the injection well. The range of the near-wellbore foam zone 6 is smaller than that of Example 1. This is because the foam is thermodynamically unstable and cannot be effectively broken and regenerated; and in the near-wellbore foam zone 6, CO 2 The maximum gas phase saturation can only reach 85%, because the formation bound water cannot be consumed to form foam; after the foam bursts, the supercritical carbon dioxide floats up and forms a post-foam supercritical carbon dioxide zone 9, in which CO 2 The gas phase saturation is only about 30%. After injecting an equal amount of 85% dry foam, the range of the deep unswept zone 8 is significantly larger than that of Example 1.

[0050] Comparative Example 2 The same as Example 1, except that this comparative example uses supercritical CO 2 Continuous displacement was carried out with an injection rate of 40t / d.

[0051] Figure 4 The schematic diagram of the swept volume when supercritical carbon dioxide increases the carbon dioxide storage capacity is obtained by numerical simulation calculation using CMG software according to the above implementation steps. The injected supercritical carbon dioxide is affected by the density difference and quickly forms a supercritical carbon dioxide zone 10 that is "wide at the top and narrow at the bottom". In the supercritical carbon dioxide zone 10, CO 2 The gas phase saturation is only about 30%, which is much lower than that in Example 1.

[0052] Comparative Example 3 The same as Example 2, except that this comparative example uses 85% dry foam for continuous displacement, and the specific steps are as follows: By storing CO 2 -The intermediate container of the foaming agent injects 85% dry foam into the sand filling pipe at a rate of 1 mL / min.

[0053] Among them, the preparation method of 85% dry foam is: two ISCO plunger pumps control the injection of supercritical carbon dioxide and gas-soluble foaming agent respectively, and the injection speeds of the two are 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dry foam.

[0054] Comparative Example 4 The difference is the same as Example 2, except that this comparative example uses supercritical carbon dioxide for continuous displacement, and the specific steps are as follows: By storing CO 2 Supercritical carbon dioxide is continuously injected into the sand-filled tube through an intermediate container at a rate of 1 mL / min.

[0055] Comparative Example 5 The same as Example 3, except that this comparative example uses 85% dry foam for continuous displacement, and the specific steps are as follows: By storing CO 2 -The intermediate container of the foaming agent injects 85% dry foam into the sand filling pipe at a rate of 1 mL / min.

[0056] Among them, the preparation method of 85% dry foam is: two ISCO plunger pumps control the injection of supercritical carbon dioxide and gas-soluble foaming agent respectively, and the injection speeds of the two are 0.85 mL / min and 0.15 mL / min respectively. The two are mixed in a foam generator to form 85% dry foam.

[0057] Comparative Example 6 The difference is the same as Example 3, in which supercritical carbon dioxide is used for continuous displacement in this comparative example, and the specific steps are as follows: By storing CO 2 Supercritical carbon dioxide is continuously injected into the sand-filled tube through an intermediate container at a rate of 1 mL / min.

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

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

[0060] Figure 6 The injection volume-gas saturation diagram of Example 2, Comparative Example 3 and Comparative Example 4 when increasing the carbon dioxide storage capacity of the saline layer is shown in Table 1. It can be seen from the figure that the gas-soluble foaming agent and the supercritical CO 2 After displacing 1.698 PV, the mixture can increase the carbon dioxide gas saturation of the saline layer to about 92.83%, indicating that the gas-soluble foam can significantly increase the carbon dioxide storage in the saline layer with a small amount of injection; the 85% dry foam can increase the carbon dioxide gas saturation of the saline layer to about 82.13% after displacing 9.910 PV, indicating that the 85% dry foam can also significantly increase the carbon dioxide storage in the saline layer with a large amount of injection, but the maximum storage will not exceed the foam dryness; supercritical carbon dioxide can increase the carbon dioxide gas saturation of the saline layer to about 20.86% after displacing 7.524 PV, indicating that direct injection of CO 2 , the burial effect is poor.

[0061] like Figure 7 The graphs are shown in Example 3, Comparative Example 5 and Comparative Example 6 for increasing the carbon dioxide storage capacity in high water-content oil reservoirs. The specific data are shown in Table 2. Figure 8 The graphs are shown in Table 3 for increasing the carbon dioxide storage capacity in high water content oil reservoirs in Example 3, Comparative Example 5 and Comparative Example 6. The specific data are shown in Table 3. Gas-soluble foaming agent and supercritical CO 2After displacing 3.01 PV, the mixture can increase the carbon dioxide storage capacity of high water-content reservoirs to about 91.68%, and increase the oil recovery rate to about 94.28%, indicating that after a small amount of gas-soluble foam is injected, it can significantly increase the carbon dioxide storage capacity and oil recovery rate, achieving a win-win situation in terms of economy and environment; after displacing 11.62 PV, the 85% dry foam can increase the carbon dioxide storage capacity of high water-content reservoirs to about 71.95%, and increase the oil recovery rate to about 80.42%, indicating that after a large amount of 85% dry foam is injected, it can effectively increase the carbon dioxide storage capacity and oil recovery rate, but the degree of improvement is not as good as that of gas-soluble foaming agent and supercritical CO 2 mixture; after displacing 10.31 PV of supercritical carbon dioxide, the carbon dioxide storage capacity of the water-bearing reservoir was increased to about 31.99%, and the crude oil recovery factor was about 70.35%, indicating that direct injection of supercritical carbon dioxide has the lowest carbon storage capacity and crude oil recovery factor.

[0062] Table 1 Injection volume-gas saturation of increasing carbon dioxide storage capacity in saline aquifers in Example 2, Comparative Example 3 and Comparative Example 4

[0063]

[0064] Table 2 Injection volume-gas saturation of increasing carbon dioxide storage capacity in high water-content oil reservoirs in Example 3, Comparative Example 5 and Comparative Example 6

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

[0066] The embodiments provided in the document are intended to illustrate the technical solutions of the present invention, not to limit them. 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 replace some or all of the technical features therein by equivalents; these modifications or replacements 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 storage capacity of carbon dioxide using a gas-soluble foaming agent, characterized in that: The steps include: S1, the front gas-soluble foaming agent plug and the rear CO2 plug are injected into the geological storage body alternately in stages, and the injection pressure continues to increase. When the injection pressure reaches the peak pressure, the injection continues. When the injection pressure drops, the injection is continued until the injection pressure drops to 1 / 2~4 / 5 of the peak pressure, and then the injection is stopped; S2, injecting the gas-soluble foaming agent and supercritical CO2 mixture into the injection well, and injecting and producing the injection well and the production well at the same time; 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 storage body reaches 5-10%.

2. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 1, characterized in that: The injection volume ratio of the front gas-soluble foaming agent plug to the rear CO2 plug is 1:(2-5).

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

100.

4. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 1, characterized in that: The injection rate of the gas-soluble foaming agent and supercritical CO2 mixture is 20-100 t / d.

5. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 1, characterized in that: In step S2, the pressure and temperature of the mixture of the gas-soluble foaming agent and supercritical CO2 are respectively the same as the pressure and temperature of the geological storage body.

6. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 5, characterized in that: Under the pressure and temperature of the geological storage body, the solubility of the gas-soluble foaming agent in supercritical carbon dioxide is not less than 0.

2.

7. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 6, characterized in that: The gas-soluble foaming agent is an amidation site sequence hydrocarbon ether, and the structural formula is: ； 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, and 3-methyl-2-butyl; The value range of m is 5~20; The value range of n is 5~20.

8. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 1, characterized in that: The geological storage body includes saline water layer and depleted gas reservoir.

9. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 8, characterized in that: The pressure of the geological storage body is greater than 10 MPa and the temperature is 35~90°C.

10. The method for increasing carbon dioxide storage capacity by using a gas-soluble foaming agent according to claim 1, characterized in that: The gas-soluble foaming agent and supercritical CO2 mixture is injected through the oil pipe.

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