Compositions for preparing gels, gels and their preparation methods, and methods for synergistically improving CO2 oil recovery and geological sequestration rates.

Abstract

This invention relates to the field of crude oil displacement technology, and discloses a composition for preparing a gel, the gel itself, a method for preparing the gel, and a method for synergistically improving CO2 oil recovery and geological sequestration rates. The composition contains component A and component B. Component A contains the following components: a tertiary amine polymer monomer, a supporting monomer, a crosslinking agent I, an initiator I, and an accelerator I; component B contains the following components: a primary amine polymer monomer, a crosslinking agent II, an initiator II, and an accelerator II. The gel prepared using the composition provided by this invention can directionally recognize CO2 in the formation, and after reacting with CO2, it can form a high-strength, water-insoluble three-dimensional mesh structure, significantly improving both volume and strength, resulting in excellent sealing performance and high practical value. The gel prepared using the method provided by this invention has the advantage of stable performance, higher mechanical strength, and excellent acid resistance.

Description

Technical Field

[0001] This invention relates to the field of crude oil displacement technology, specifically to compositions for preparing gels, gels and methods for preparing the same, and methods for synergistically improving CO2 crude oil recovery and geological sequestration. Background Technology

[0002] CO2 gas-driven oil recovery and geological storage are research hotspots in the oil and gas industry under the "dual carbon" background, attracting the interest of many experts and scholars. Due to CO2's low viscosity and easy flow, and the fact that most reservoirs are highly heterogeneous, the formulation of sealing schemes is a key issue that both CO2 flooding and geological storage fields need to address. The problem of CO2 channeling along high-permeability channels such as fractures in reservoirs seriously affects the synergy between CO2 flooding and storage.

[0003] To address the gas channeling problem during CO2 enhanced oil recovery, researchers have employed various methods, including alternating water-gas injection, chemical precipitation, foam sealing, gel sealing, cement sealing, resin sealing, and CO2 thickening. While these methods have all played a positive role, they also have their own limitations.

[0004] For example, the water-gas alternating injection method is poorly adapted to highly heterogeneous reservoirs, and the precipitates formed by chemical precipitation methods easily clog low-permeability formations, causing secondary damage to the reservoir. Cement and resin, due to their high viscosity and poor fluidity, cannot be injected into deep formations and cause significant reservoir damage. Although foam has good injection capabilities, it is difficult to maintain the necessary stability in the formation for extended periods; once the foam film ruptures, it loses its CO2-blocking effect. CO2 thickening is costly and unlikely to achieve ideal economic benefits.

[0005] Therefore, it is urgent to develop new technologies to overcome the shortcomings of existing technologies, effectively control CO2 gas channeling and leakage, improve CO2 oil recovery while ensuring CO2 geological sequestration.

[0006] As the most widely used CO2 gas channeling plugging agent, gel is widely used in oilfields for CO2 plugging or consistency control due to its excellent cost performance. After CO2 enters the formation, it will lower the pH of the formation water and turn the formation environment acidic.

[0007] However, existing gels have poor acid resistance and are prone to hydrolysis under acidic conditions; moreover, the formations where gels are applied are mostly under high pressure conditions, and ordinary gels still have defects such as low mechanical strength. Summary of the Invention

[0008] The purpose of this invention is to overcome the defects of existing gels, such as low mechanical strength, and to provide a plugging gel that can improve CO2 oil recovery and geological sequestration rates.

[0009] To achieve the above objectives, a first aspect of the present invention provides a composition for preparing a dual-network CO2-responsive hydrogel, the composition comprising component A and component B, wherein component A comprises the following components: a tertiary amine polymer monomer, a supporting monomer, a crosslinking agent I, an initiator I, and an accelerator I; and component B comprises the following components: a primary amine polymer monomer, a crosslinking agent II, an initiator II, and an accelerator II.

[0010] The tertiary amine polymer monomer is selected from at least one of N-dodecylacrylamide and dimethylaminopropylmethacrylamide;

[0011] The supporting monomer is selected from at least one of 2-acrylamido-2-methylpropanesulfonic acid and isoamyl chloroformate;

[0012] The primary amine polymer monomer is selected from at least one of acrylamide and N-vinylformamide;

[0013] In component A, relative to 100 parts by weight of the tertiary amine polymer monomer, the content of the supporting monomer is 5-15 parts by weight, the content of the crosslinking agent I is 10-20 parts by weight, the content of the initiator I is 0.03-0.2 parts by weight, and the content of the accelerator I is 0.03-0.2 parts by weight.

[0014] In component B, relative to 100 parts by weight of the primary amine polymer monomer, the content of crosslinking agent II is 0.3-1 parts by weight, the content of initiator II is 0.03-0.2 parts by weight, and the content of accelerator II is 0.03-0.2 parts by weight;

[0015] In the composition, the weight ratio of component A to component B is 1:20-50.

[0016] A second aspect of the present invention provides a method for preparing a dual-network CO2-responsive hydrogel, the method being carried out using the composition described in the first aspect above, comprising:

[0017] (1) In the presence of crosslinking agent I, initiator I, accelerator I and water, the tertiary amine polymer monomer and the supporting monomer are subjected to a first reaction to obtain mixture I;

[0018] (2) In the presence of crosslinking agent II, initiator II, accelerator II and water, the primary amine polymer monomers undergo a second reaction in the mixture I to obtain mixture II;

[0019] (3) The mixture II is subjected to a third reaction in the presence of a reinforcing agent and water.

[0020] A third aspect of the present invention provides a dual-network CO2-responsive hydrogel prepared by the method described in the second aspect above.

[0021] A fourth aspect of the present invention provides an application of the dual-network CO2-responsive hydrogel described in the third aspect above as a plugging agent.

[0022] The fifth aspect of the present invention provides a method for synergistically improving CO2 crude oil recovery and geological storage rate. The method applies the dual-network CO2-responsive hydrogel described in the third aspect above in a core displacement experimental device, which includes: a raw material storage unit, an experimental unit, a data acquisition unit, and a data processing unit.

[0023] The method includes: injecting raw materials from the raw material storage unit into the target core in the experimental unit, obtaining the oil recovery rate and geological sequestration rate through the data acquisition unit and the data processing unit, so as to determine the injection rate, injection pressure, injection concentration and particle diameter of the hydrogel when displacing oil in the target reservoir.

[0024] This invention has at least the following advantages over the prior art:

[0025] (1) The gel prepared by the composition provided by the present invention can directionally identify CO2 in the formation, and after reacting with CO2, it can form a high-strength, water-insoluble three-dimensional mesh structure, which significantly improves both volume and strength, has a good sealing effect, and has high practical value.

[0026] (2) The method for preparing gel provided by the present invention has the advantage of simple operation. At the same time, the gel prepared by the method provided by the present invention has the advantage of stable performance. Compared with existing gels, the gel of the present invention has higher mechanical strength and excellent acid resistance.

[0027] (3) The method for synergistically improving CO2 crude oil recovery and geological storage provided by the present invention can achieve synergistic enhancement of CO2 oil displacement and storage. Attached Figure Description

[0028] Figure 1 This is an example diagram illustrating the formation mechanism of the dual-network CO2-responsive hydrogel provided by the present invention;

[0029] Figure 2 This is a schematic diagram of the molecular chains formed after the dual-network CO2-responsive hydrogel provided by the present invention comes into contact with CO2;

[0030] Figure 3 This is a schematic diagram of the three-dimensional network structure formed after the dual-network CO2-responsive hydrogel provided by the present invention comes into contact with CO2;

[0031] Figure 4 This is a schematic diagram of a preferred CO2 core displacement experimental device provided by the present invention;

[0032] Figure 5 This is a schematic diagram of the chemical reaction that occurs when the dual-network CO2-responsive hydrogel provided by the present invention comes into contact with CO2;

[0033] Figure 6 This is a graph showing the changes in CO2 recovery rate and CO2 geological storage rate over time before and after the oil reservoir is plugged by the dual-network CO2 responsive hydrogel in Example 1 of this invention.

[0034] Figure 7 This is a schematic diagram of the gel strength grade standard provided by the present invention.

[0035] Figure Labels

[0036] 101-Automatic pump; 102a-First six-way valve; 102b-Second six-way valve; 103a-Formation water tank; 103b-Crude oil tank; 103c-Carbon dioxide gas tank; 103d-Nitrogen tank; 103e-Hydrogel tank; 104-Flow rate regulator; 105a-First valve; 105b-Second valve;

[0037] 201-Core holder; 202-Third valve; 203-Back pressure valve; 204-Thermostatic chamber;

[0038] 301 - Data acquisition device; 302 - Gas chromatograph; 303 - Fourth valve; 304 - Mass sensing device;

[0039] 401 - Weighing device; 402 - Oil-gas separation device; 403a - Fifth valve; 403b - Sixth valve; 404 - Carbon dioxide recovery device; 405 - Crude oil recovery device. Detailed Implementation

[0040] The endpoints and any values ​​of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0041] As previously stated, a first aspect of the present invention provides a composition for preparing a dual-network CO2-responsive hydrogel, the composition comprising component A and component B, wherein component A comprises the following components: a tertiary amine polymer monomer, a supporting monomer, a crosslinking agent I, an initiator I, and an accelerator I; and component B comprises the following components: a primary amine polymer monomer, a crosslinking agent II, an initiator II, and an accelerator II.

[0042] The tertiary amine polymer monomer is selected from at least one of N-dodecylacrylamide and dimethylaminopropylmethacrylamide;

[0043] The supporting monomer is selected from at least one of 2-acrylamido-2-methylpropanesulfonic acid and isoamyl chloroformate;

[0044] The primary amine polymer monomer is selected from at least one of acrylamide and N-vinylformamide;

[0045] In component A, relative to 100 parts by weight of the tertiary amine polymer monomer, the content of the supporting monomer is 5-15 parts by weight, the content of the crosslinking agent I is 10-20 parts by weight, the content of the initiator I is 0.03-0.2 parts by weight, and the content of the accelerator I is 0.03-0.2 parts by weight.

[0046] In component B, relative to 100 parts by weight of the primary amine polymer monomer, the content of crosslinking agent II is 0.3-1 parts by weight, the content of initiator II is 0.03-0.2 parts by weight, and the content of accelerator II is 0.03-0.2 parts by weight;

[0047] In the composition, the weight ratio of component A to component B is 1:20-50.

[0048] Preferably, the crosslinking agent I is selected from at least one of diatomaceous earth and lithium diatomaceous earth.

[0049] In a preferred embodiment, the crosslinking agent II is selected from at least one of N,N'-methylenebisacrylamide and 2-ketoglutaric acid.

[0050] More preferably, the crosslinking agent II is a combination of N,N'-methylenebisacrylamide and 2-ketoglutaric acid in a weight ratio of 1-5:1. The inventors of this invention have found that, under this preferred condition, the prepared gel exhibits better mechanical strength and acid resistance.

[0051] Preferably, initiator I and initiator II are each independently selected from at least one of ammonium persulfate, potassium persulfate, and sodium persulfate.

[0052] According to a particularly preferred embodiment, both accelerator I and accelerator II are tetramethylethylenediamine.

[0053] As previously described, a second aspect of the present invention provides a method for preparing a dual-network CO2-responsive hydrogel, the method being carried out using the composition described in the first aspect, comprising:

[0054] (1) In the presence of crosslinking agent I, initiator I, accelerator I and water, the tertiary amine polymer monomer and the supporting monomer are subjected to a first reaction to obtain mixture I;

[0055] (2) In the presence of crosslinking agent II, initiator II, accelerator II and water, the primary amine polymer monomers undergo a second reaction in the mixture I to obtain mixture II;

[0056] (3) The mixture II is subjected to a third reaction in the presence of a reinforcing agent and water.

[0057] In this invention, water in steps (1), (2), and (3) is used as a solvent, and there is no particular limitation on its amount. Those skilled in the art can select according to known technical means in the art. The following text of this invention provides a particularly preferred embodiment, which should not be construed as a limitation of this invention.

[0058] Preferably, the reinforcing agent is selected from at least one of calcium chloride, magnesium chloride, and copper chloride.

[0059] It should be noted that the present invention does not impose any particular limitation on the ratio of the reinforcing agent to the mixture II, as long as the mixture II can be immersed in the reinforcing agent solution. For example, the concentration of the reinforcing agent solution can be 0.01-0.05 mol / L.

[0060] According to a preferred embodiment, the conditions for the first reaction and the second reaction each independently include: a temperature of 30-40°C and a time of 24-72 hours. The inventors of this invention have found that the gel obtained under this preferred condition has better mechanical strength and acid resistance.

[0061] According to another preferred embodiment, the conditions for the third reaction include: a temperature of 20-40°C and a time of 1-3 hours.

[0062] According to a particularly preferred embodiment, the preparation method of the dual-network CO2-responsive hydrogel includes the following steps:

[0063] (1) Under anaerobic conditions, the crosslinking agent I and the water are first mixed to obtain mixture I; the mixture I, the initiator I, the accelerator I, the tertiary amine polymer monomer and the supporting monomer are second mixed to obtain mixture II; under sealed conditions, mixture II is subjected to a first reaction to obtain mixture I;

[0064] (2) The crosslinking agent II, the initiator II, the accelerator II, the water and the primary amine polymer monomer are mixed in a third way to obtain mixture III; under sealed conditions, mixture I is swollen in mixture III at 0-5°C and then subjected to a second reaction to obtain mixture II;

[0065] (3) In the presence of the reinforcing agent and the water, the mixture II is subjected to a third reaction to obtain a solution containing the dual-network CO2 responsive hydrogel.

[0066] Preferably, the conditions for the first mixing include: being carried out under stirring conditions, with a stirring speed of 800-1200 rpm, a temperature of 30-40℃, and a time of 1-3 hours.

[0067] In a preferred embodiment, the conditions for the second mixing include: being carried out under stirring conditions, with a stirring speed of 800-1200 rpm, a temperature of 30-40°C, and a time of 1-3 hours.

[0068] Preferably, the conditions for the third mixing include: being carried out under stirring conditions, with a stirring speed of 800-1200 rpm, a temperature of 20-40℃, and a time of 1-3 hours.

[0069] This invention may also include various post-processing methods known in the art, such as solid-liquid separation, water washing, and drying. For example, in this invention, a solution containing the dual-network CO2-responsive hydrogel may be subjected to solid-liquid separation and water washing sequentially to obtain the dual-network CO2-responsive hydrogel.

[0070] Figure 1 This is an example diagram illustrating the formation mechanism of the dual-network CO2-responsive hydrogel provided by this invention. From... Figure 1 As can be seen, under the action of crosslinking agent I, initiator and accelerator, the tertiary amine polymer monomer and the supporting monomer form the first network. Then, under the action of crosslinking agent II, initiator and accelerator, the primary amine monomer forms the second network in the first network. After being strengthened by the reinforcing agent, a double-network CO2 responsive hydrogel is obtained, which blocks CO2 molecules.

[0071] As previously described, a third aspect of the present invention provides a dual-network CO2-responsive hydrogel prepared by the method described in the second aspect above.

[0072] As previously stated, a fourth aspect of the present invention provides an application of the dual-network CO2-responsive hydrogel described in the third aspect above as a plugging agent.

[0073] As mentioned above, the fifth aspect of the present invention provides a method for synergistically improving CO2 crude oil recovery and geological storage rate. The method applies the dual-network CO2 responsive hydrogel described in the third aspect above in a core displacement experimental device, which includes: a raw material storage unit, an experimental unit, a data acquisition unit, and a data processing unit.

[0074] The method includes: injecting raw materials from the raw material storage unit into the target core in the experimental unit, obtaining the oil recovery rate and geological sequestration rate through the data acquisition unit and the data processing unit, so as to determine the injection rate, injection pressure, injection concentration and particle diameter of the hydrogel when displacing oil in the target reservoir.

[0075] Preferably, the raw material storage unit includes a formation water tank, a crude oil tank, a carbon dioxide gas tank, and a hydrogel tank.

[0076] In a preferred embodiment, the experimental unit includes a core holder and a constant temperature chamber.

[0077] Preferably, the data acquisition unit includes a data acquisition device, a gas chromatograph, and a mass sensing device.

[0078] Preferably, the data processing unit includes a weighing device, an oil-gas separation device, a carbon dioxide recovery device, and a crude oil recovery device.

[0079] The dual-network CO2-responsive hydrogel provided by this invention undergoes the following reaction upon contact with CO2: Figure 5 The reaction shown forms as follows Figure 2 The molecular chains shown eventually form as follows. Figure 3 The three-dimensional network structure shown.

[0080] Figure 4 This is a schematic diagram of a preferred CO2 core displacement experimental apparatus provided by the present invention. The following is in conjunction with... Figure 4 The present invention will be described in detail as follows:

[0081] After evacuating the target core to a vacuum, the core was saturated with formation water and placed in the core holder 201 in the experimental unit. The temperature of the constant temperature chamber 204 in the experimental unit was adjusted to the target temperature and maintained at a constant temperature. Then, the automatic pump 101, the first valve 105a, the first six-way valve 102a and the second six-way valve 102b in the raw material storage unit, as well as the third valve 202 and the back pressure valve 203 in the experimental unit, and the sixth valve 403b in the data processing unit were opened to pump the formation crude oil from the crude oil tank 103b in the raw material storage unit. Oil flooding is performed on the target core using flow rate regulator 104 until no formation water flows out of the target core. Then, automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, and sixth valve 403b are shut down, and the core is aged. After centrifugation of the oil-water mixture in the crude oil recovery device 405 in the data processing unit, the mass of formation water and formation crude oil in the oil-water mixture is obtained by weighing device 401 in the data processing unit.

[0082] Automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, and sixth valve 403b are activated to drive formation water from formation water tank 103a to the target core for oil flooding via flow rate regulator 104 until no more formation crude oil flows out of the target core. Automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, and sixth valve 403b are then closed. The mass of the formation crude oil is obtained through weighing device 401, and the water flooding recovery rate is calculated.

[0083] Automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, sixth valve 403b, and fifth valve 403a are activated. Carbon dioxide from carbon dioxide gas tank 103c in the raw material storage unit is used to gas drive the target core through flow rate regulator 104. The oil-gas mixture is separated by oil-gas separation device 402 in the data processing unit, so that the formation crude oil enters the crude oil recovery device 405 and the carbon dioxide enters the carbon dioxide recovery device 404 in the data processing unit. During this period, the mass of formation crude oil in crude oil recovery device 405 and the mass of CO2 gas in carbon dioxide recovery device 404 are recorded every 20 seconds by data acquisition device 301 in the data acquisition unit. The gas-oil ratio at different times is calculated to obtain the corresponding dissolved gas-oil ratio change curve over time. Recording stops when no formation crude oil flows out of the target core.

[0084] Close the second six-way valve 102b and the third valve 202, open the fourth valve 303 in the data acquisition unit, and record the mass of CO2 gas in the target core, the mass of CO2 gas in the carbon dioxide recovery device 404, and the mass of formation crude oil in the crude oil recovery device 405 obtained by the gas chromatograph 302 in the data acquisition unit through the data acquisition device 301, and calculate the CO2 burial rate and total oil recovery rate in the target core.

[0085] Adjust the back pressure valve 203, simultaneously close the fourth valve 303, and open the second valve 105b; inject the hydrogel solution in the hydrogel tank 103e in the raw material storage unit into the target core through the flow rate regulator 104 until the pressure at the inlet of the back pressure valve 203 reaches the set pressure, then close the second valve 105b and stop injecting the hydrogel solution; then use the carbon dioxide in the carbon dioxide gas tank 103c to perform gas drive treatment on the target core through the flow rate regulator 104; during this period, every 20 seconds, record the mass of formation crude oil in the crude oil recovery device 405 and the mass of CO2 gas in the carbon dioxide recovery device 404 obtained by the mass sensor 304 at different times through the data acquisition device 301, and calculate the gas-oil ratio at different times, thereby obtaining the corresponding dissolved gas-oil ratio change curve over time, until no formation crude oil flows out of the target core and stop recording;

[0086] Close the second six-way valve 102b and the third valve 202, open the fourth valve 303, and record the mass of CO2 gas in the core obtained by the gas chromatograph 302, the mass of CO2 gas in the carbon dioxide recovery device 404, and the mass of formation crude oil in the crude oil recovery device 405 through the data acquisition device 301. Calculate the CO2 burial rate and total oil recovery rate in the target core. Based on the burial rate and total oil recovery rate, determine the injection rate, injection pressure, injection concentration, and particle diameter at which the hydrogel can achieve the highest burial rate and the highest total oil recovery rate when displacing crude oil in the target reservoir.

[0087] The present invention will be described in detail below through examples.

[0088] In the following examples, unless otherwise specified, all raw materials used were commercially purchased.

[0089] In the following examples, unless otherwise specified, each part by weight represents 1g.

[0090] Example 1

[0091] The components and their contents in the composition used in this embodiment are as follows:

[0092] Component A: 100 parts by weight of N-dodecylacrylamide (tertiary amine polymer monomer), 5 parts by weight of 2-acrylamido-2-methylpropanesulfonic acid (supporting monomer), 10 parts by weight of diatomaceous earth (crosslinking agent I), 0.05 parts by weight of ammonium persulfate (initiator I), and 0.05 parts by weight of tetramethylethylenediamine (accelerator I).

[0093] Component B: 100 parts by weight of acrylamide (primary amine polymer monomer), 0.5 parts by weight of N,N'-methylenebisacrylamide (crosslinking agent II), 0.05 parts by weight of ammonium persulfate (initiator II), and 0.05 parts by weight of tetramethylethylenediamine (accelerator II);

[0094] The weight ratio of component A to component B is 1:30;

[0095] The following method was used to prepare a dual-network CO2-responsive hydrogel:

[0096] (1) Under anaerobic conditions, crosslinking agent I was mixed with water (1000 parts by weight) to obtain mixture I. The conditions for the first mixing were: stirring was carried out, with a stirring speed of 800 rpm, a temperature of 30°C, and a time of 2 h.

[0097] Mixture I, initiator I, accelerator I, tertiary amine polymer monomer and supporting monomer are mixed a second time to obtain mixture II; the conditions for the second mixing are: stirring is carried out under stirring conditions, with a stirring speed of 800 rpm, a temperature of 30℃ and a time of 2 h.

[0098] Under sealed conditions, mixture II was subjected to a first reaction to obtain mixture I. The conditions for the first reaction were: temperature 30℃ and time 24h.

[0099] (2) Crosslinking agent II, initiator II, accelerator II, water (1000 parts by weight) and primary amine polymer monomer are mixed in the third mixture to obtain mixture III; the conditions for the third mixture are: it is carried out under stirring conditions, with a stirring speed of 800 rpm, a temperature of 30°C, and a time of 2 h.

[0100] Under sealed conditions, mixture I was swollen in mixture III at 0°C until the liquid was completely absorbed before the second reaction was carried out to obtain mixture II; the conditions for the second reaction were: temperature 30°C and time 24h.

[0101] (3) Immerse mixture II in a 0.01 mol / L calcium chloride aqueous solution (reinforcing agent) to carry out the third reaction, and obtain a solution containing a double-network CO2 responsive hydrogel J1; the conditions for the third reaction are: temperature 30℃ and time 2h.

[0102] The above solution was subjected to solid-liquid separation and water washing in sequence to obtain hydrogel J1.

[0103] Example 2

[0104] This embodiment uses a similar formula and method to Example 1, except that:

[0105] Hydrogel J2 was prepared by replacing N-dodecylacrylamide with an equal weight of dimethylaminopropylmethacrylamide, replacing 2-acrylamido-2-methylpropanesulfonic acid with an equal weight of isoamyl chloroformate, and replacing acrylamide with an equal weight of N-vinylformamide, with all other conditions being the same as in Example 1.

[0106] Example 3

[0107] This embodiment uses a similar formula and method to Example 1, except that:

[0108] Hydrogel J3 was prepared by replacing 0.5 parts by weight of N,N'-methylenebisacrylamide with a combination of 0.25 parts by weight of N,N'-methylenebisacrylamide and 0.25 parts by weight of 2-ketoglutaric acid, while keeping all other conditions the same as in Example 1.

[0109] Example 4

[0110] This embodiment uses a similar formula and method to Example 1, except that:

[0111] Hydrogel J4 was prepared by replacing 0.5 parts by weight of N,N'-methylenebisacrylamide with a combination of 0.45 parts by weight of N,N'-methylenebisacrylamide and 0.05 parts by weight of 2-ketoglutaric acid, while keeping all other conditions the same as in Example 1.

[0112] Example 5

[0113] This embodiment uses a similar formula and method to Example 1, except that:

[0114] The temperature in the first reaction was adjusted to 50°C, and all other conditions were the same as in Example 1, to prepare hydrogel J5.

[0115] Comparative Example 1

[0116] This comparative example uses a similar formulation and method to Example 1, except that:

[0117] Hydrogel DJ1 was prepared by setting the weight ratio of component A to component B to 1:10, and keeping all other conditions the same as in Example 1.

[0118] Comparative Example 2

[0119] This comparative example uses a similar formulation and method to Example 1, except that:

[0120] The content of 2-acrylamide-2-methylpropanesulfonic acid was adjusted to 1 part by weight, and all other conditions were the same as in Example 1, to prepare hydrogel DJ2.

[0121] Comparative Example 3

[0122] This comparative example uses a similar formulation and method to Example 1, except that:

[0123] The content of diatomaceous earth was adjusted to 5 parts by weight, and all other conditions were the same as in Example 1, to prepare hydrogel DJ3.

[0124] Test Case

[0125] The hydrogels prepared in the examples and comparative examples were subjected to performance tests according to the following methods, and the specific results are shown in Table 1:

[0126] Mechanical strength: 14 mL of a 6.67 wt% hydrogel aqueous solution was prepared in a round-bottomed glass test tube with an outer diameter of 20 mm and a height of 150 mm. After inverting the glass test tube 180°, the flow of the hydrogel aqueous solution was observed, and the results were reported according to Table 2 and... Figure 7 The standards in the document are used to classify levels;

[0127] Acid resistance: Immerse the hydrogel in water and allow it to swell until its mass no longer increases, and record the mass m0 of the hydrogel at this point; then immerse the swollen gel in a hydrochloric acid solution with pH=5, remove it after one week and remove the free water adhering to the surface; record the mass m1 of the hydrogel at this point.

[0128] The mass retention rate of the hydrogel is defined as α, and α = m1 / m0 × 100%. The larger the value of α, the better the acid resistance of the hydrogel.

[0129] Figure 7 This is a schematic diagram of the gel strength grade standard provided by the present invention. Figure 7 In the diagram, each glass test tube is in the state after being flipped 180°.

[0130] Table 1

[0131] Mechanical strength (grade) Acid resistance (%) Example 1 H 83.37 Example 2 H 84.26 Example 3 I 89.34 Example 4 H 87.22 Example 5 E 68.77 Comparative Example 1 I 57.63 Comparative Example 2 D 62.52 Comparative Example 3 F 67.63

[0132] Table 2

[0133]

[0134]

[0135] Application Example 1

[0136] The hydrogel prepared in Example 1 was used as a sealing agent, and... Figure 4 The core displacement experimental setup shown was used to test the core CO2 enhanced oil recovery rate and CO2 geological storage rate. The specific steps are as follows:

[0137] A sandstone core with cracks (core cross-section diameter D = 2.5 cm, length L = 20.4 cm, total porosity) was collected. Penetration rate K d =11mD; Core fracture aperture L f =100μm, permeability K f =7D) After being evacuated to a vacuum, density ρ is used w =1.18g / cm 3 After the core is saturated with formation water, it is placed in the core holder 201. The temperature of the constant temperature chamber 204 is adjusted to 40℃. After 5 hours, the automatic pump 101, the first valve 105a, the first six-way valve 102a, the second six-way valve 102b, the third valve 202, the back pressure valve 203, and the sixth valve 403b are turned on to release the crude oil from the oil tank 103b. o =0.81g / cm 3 The formation crude oil is injected into the core at a rate of 0.5 mL / min through the flow rate regulator 104 until no formation water flows out of the core. Then, the automatic pump 101, the first valve 105a, the first six-way valve 102a, the second six-way valve 102b, the third valve 202, the back pressure valve 203, and the sixth valve 403b are closed, and the core is aged (for 72 hours at 50°C).

[0138] After centrifuging the oil-water mixture in the crude oil recovery unit 405, the mass m of formation water in the oil-water mixture is obtained by weighing device 401. w0 =16.24g, and the mass m of the formation crude oil in the oil-water mixture was calculated using formula (1). o0 =11.19g and the bound water saturation S calculated by formula (2) wi =24.28%;

[0139] m o0 =m w0 / ρ w ×ρ o Formula (1),

[0140]

[0141] The automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, and sixth valve 403b are activated to increase the density ρ in the formation water tank 103a. w=1.18g / cm 3 The formation water is injected into the core at a rate of 1 mL / min through the flow rate regulator 104 to perform oil drive treatment until no formation crude oil flows out of the core. Then, the automatic pump 101, the first valve 105a, the first six-way valve 102a, the second six-way valve 102b, the third valve 202, the back pressure valve 203, and the sixth valve 403b are closed.

[0142] The mass m of the formation crude oil is obtained through weighing device 401. or =4.35g, and the water drive recovery rate R was calculated using formula (3). w =38.87%;

[0143] R w =m or / m o0 ×100% formula (3);

[0144] The automatic pump 101, first valve 105a, first six-way valve 102a, second six-way valve 102b, third valve 202, back pressure valve 203, sixth valve 403b, and fifth valve 403a are turned on. Carbon dioxide in carbon dioxide gas tank 103c is injected into the core at a rate of 1 mL / min through flow rate regulator 104 for gas drive treatment. The oil and gas mixture is separated by oil and gas separator 402, so that the formation crude oil enters the crude oil recovery device 405 and the carbon dioxide enters the carbon dioxide recovery device 404.

[0145] During this period, the mass m of the formation crude oil in the crude oil recovery unit 405 is recorded every 20 seconds via data acquisition device 301. oi The mass m of CO2 gas in the carbon dioxide recovery device 404 obtained by the mass sensing device 304. gi The gas-oil ratio GOR at different times was calculated using formula (4). i1 Thus, the corresponding dissolved gas-oil ratio change curve over time is obtained, and recording stops when no more formation crude oil flows out of the core.

[0146] GOR i =Δm gi / Δm oi Formula (4);

[0147] Close the second six-way valve 102b and the third valve 202, open the fourth valve 303, and record the mass m of CO2 gas in the core obtained by the gas chromatograph 302 through the data acquisition device 301. gr1 =0.75g, the mass m of CO2 gas in carbon dioxide recovery device 404 gr2 =2.44g, and the mass m of the formation crude oil in crude oil recovery unit 405.or1 =5.72g, and the CO2 burial rate S in the core was calculated using formula (5). g =23.47% and the total oil recovery rate R1 = 51.12% was calculated using formula (6);

[0148] S g =m gr1 / (m gr1 +m gr2 )×100% formula (5);

[0149] R1=m or1 / m o0 ×100% formula (6);

[0150] The hydrogel prepared in Example 1 was prepared into particles with an average particle size of 0.5 mm, and a solution with a concentration of 0.05 kg / L was prepared with distilled water. The back pressure valve 203 was adjusted to control the pressure at the outlet end to 5 MPa, while the fourth valve 303 was closed and the second valve 105b was opened.

[0151] The hydrogel solution in hydrogel tank 103e is injected into the core at an injection rate of 0.5 mL / min through flow regulator 104 until the pressure at the inlet of back pressure valve 203 reaches 15 MPa. Then, the second valve 105b is closed to stop the injection of gel. After 2 hours, carbon dioxide in carbon dioxide gas tank 103c is injected into the core at an injection rate of 1 mL / min through flow regulator 104 for gas drive treatment.

[0152] During this period, the mass m′ of the formation crude oil in the crude oil recovery unit 405 is recorded every 20 seconds via data acquisition device 301. oi The mass m′ of CO2 gas in the carbon dioxide recovery device 404 obtained by the mass sensing device 304. gi The gas-oil ratio GOR′ at different times was calculated using formula (7). i Thus, the corresponding dissolved gas-oil ratio change curve over time is obtained, and recording stops when no more formation crude oil flows out of the core.

[0153] GOR′ i =Δm′ gi / Δm′ oi Formula (7);

[0154] Close the second six-way valve 102b and the third valve 202, open the fourth valve 303, and record the mass m′ of CO2 gas in the core obtained by the gas chromatograph 302 through the data acquisition device 301. gr1 =2.15g, the mass m′ of CO2 gas in carbon dioxide recovery device 404 gr2=3.77g, and the mass m′ of the formation crude oil in crude oil recovery unit 405. or1 =8.51g, and the CO2 burial rate S′ in the core was calculated using formula (8). g =36.34% and the total oil recovery rate R′1 =76.06% was calculated by formula (9);

[0155] S′ g =m′ gr1 / (m′ gr1 +m′ gr2 )×100% formula (8);

[0156] R′1=m′ or1 / m o0 ×100% Formula (9).

[0157] Application Example 2

[0158] The hydrogel prepared in Example 1 was used as a sealing agent, and the CO2 enhanced oil recovery rate and CO2 geological storage rate of the reservoir were tested by numerical simulation. The specific steps are as follows:

[0159] A single-layer conceptual reservoir with a closed boundary and dimensions of 315m × 315m × 10m was established. Two parallel horizontal wells (an injection well and a production well) were arranged within the reservoir, with a well spacing of 300m and a horizontal section length of 300m. The horizontal section of the wells is located in the middle of the reservoir, and three high-permeability channels with a width of 9m exist within the reservoir, penetrating both the injection and production wells. The initial oil saturation of the reservoir is 0.56, the reservoir permeability is 3mD, and the permeability of the high-permeability channels is 10D.

[0160] CO2 was injected into the injection well to drive oil recovery, and the CO2 oil recovery rate R was obtained. a and CO2 geological burial rate S a ;

[0161] A hydrogel solution with an average particle size of 0.5 mm and a concentration of 0.5 kg / L was injected into the injection well to block half the length of the high-permeability channel. Then, CO2 was injected into the injection well to drive oil recovery, resulting in a CO2-driven oil recovery rate R. b and CO2 geological burial rate S b .

[0162] As can be seen from the results in Table 1, the hydrogel prepared using the composition and preparation method provided by this invention exhibits higher mechanical strength and excellent acid resistance. When the hydrogel provided by this invention is used as a plugging agent, combined with the hydrogel injection parameters obtained by the method provided by this invention, it can significantly and synergistically improve the CO2 enhanced oil recovery rate and geological sequestration rate of the reservoir.

[0163] Similar to the curves showing the changes in CO2 recovery rate and CO2 geological burial rate over time before and after reservoir plugging treatment with the dual-network CO2-responsive hydrogel in Examples 1-5 of this invention, this invention, by way of example, provides curves showing the changes in CO2 recovery rate and CO2 geological burial rate over time before and after reservoir plugging treatment with the dual-network CO2-responsive hydrogel in Example 1. See details... Figure 6 .

[0164] from Figure 6 As can be seen from this, the CO2 enhanced oil recovery rate R a and R b The increase gradually increases over time, and the improvement in CO2 oil recovery rate when using the hydrogel provided by this invention as a plugging agent is greater than that when not using hydrogel as a plugging agent; at the same time, the CO2 geological burial rate S a and S b The decrease gradually over time, and the reduction in CO2 geological burial rate when using the hydrogel provided by the present invention as a plugging agent is less than that when not using hydrogel as a plugging agent; this indicates that the hydrogel provided by the present invention can effectively improve CO2 oil recovery rate and CO2 geological burial rate when used as a plugging agent.

[0165] The preferred embodiments of the present invention have been described in detail above; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solutions of the present invention, including combinations of various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A composition for preparing a dual-network CO2-responsive hydrogel, characterized in that, The composition contains component A and component B. Component A contains the following components: a first polymer monomer, a supporting monomer, a crosslinking agent I, an initiator I, and an accelerator I. Component B contains the following components: a second polymer monomer, a crosslinking agent II, an initiator II, and an accelerator II. The first polymer monomer is selected from at least one of N-dodecylacrylamide and dimethylaminopropylmethacrylamide; The supporting monomer is selected from at least one of 2-acrylamido-2-methylpropanesulfonic acid and isoamyl chloroformate; The second polymer monomer is selected from at least one of acrylamide and N-vinylformamide; The crosslinking agent I is selected from at least one of diatomaceous earth and lithium diatomaceous earth; The crosslinking agent II is a combination of N,N'-methylenebisacrylamide and 2-ketoglutaric acid in a weight ratio of 1-5:

1. In component A, relative to 100 parts by weight of the first polymer monomer, the content of the supporting monomer is 5-15 parts by weight, the content of the crosslinking agent I is 10-20 parts by weight, the content of the initiator I is 0.03-0.2 parts by weight, and the content of the accelerator I is 0.03-0.2 parts by weight. In component B, relative to 100 parts by weight of the second polymer monomer, the content of crosslinking agent II is 0.3-1 parts by weight, the content of initiator II is 0.03-0.2 parts by weight, and the content of accelerator II is 0.03-0.2 parts by weight; In the composition, the weight ratio of component A to component B is 1:20-50.

2. The composition according to claim 1, wherein, Initiator I and initiator II are each independently selected from at least one of ammonium persulfate, potassium persulfate, and sodium persulfate; and / or, Both accelerator I and accelerator II are tetramethylethylenediamine.

3. A method for preparing a dual-network CO2-responsive hydrogel, characterized in that, This method is performed using the composition of claim 1 or 2, comprising: (1) In the presence of crosslinking agent I, initiator I, accelerator I and water, the first polymer monomer and the supporting monomer undergo a first reaction to obtain mixture I; (2) In the presence of crosslinking agent II, initiator II, accelerator II and water, the second polymer monomer is subjected to a second reaction in the mixture I to obtain mixture II; (3) The mixture II is subjected to a third reaction in the presence of a reinforcing agent and water.

4. The method according to claim 3, wherein, The reinforcing agent is selected from at least one of calcium chloride, magnesium chloride, and copper chloride.

5. The method according to claim 3 or 4, wherein, The conditions for the first reaction and the second reaction each independently include: The temperature is 30-40℃, and the time is 24-72h.

6. The method according to claim 3 or 4, wherein, The conditions for the third reaction include: a temperature of 20-40℃ and a time of 1-3 hours.

7. A dual-network CO2-responsive hydrogel prepared by the method according to any one of claims 3-6.

8. The application of the dual-network CO2-responsive hydrogel of claim 7 as a plugging agent.

9. A method for synergistically improving CO2 crude oil recovery and geological storage rate, characterized in that, This method applies the dual-network CO2-responsive hydrogel described in claim 7 to a core displacement experimental device, which includes: a raw material storage unit, an experimental unit, a data acquisition unit, and a data processing unit. The method includes: injecting raw materials from the raw material storage unit into the target core in the experimental unit, obtaining the oil recovery rate and geological sequestration rate through the data acquisition unit and the data processing unit, so as to determine the injection rate, injection pressure, injection concentration and particle diameter of the hydrogel when displacing oil in the target reservoir.

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