CO2 flooding response type channeling sealing agent as well as preparation method and application thereof

Abstract

The invention provides a CO2 flooding response type channeling sealing agent and a preparation method and application thereof, and the CO2 flooding response type channeling sealing agent comprises 0.3-2 wt% of gemini amine, 1-5 wt% of organic tertiary amine, 0.3-1 wt% of a nanometer reinforcing agent, 0-3 wt% of an auxiliary agent and 98.4-89 wt% of water based on the total weight of 100%. The CO2 flooding response type channeling sealing agent system does not contain polymer components, the initial viscosity of the system is low, the initial viscosity is lower than 6 mPa.s, the injection performance is good, the viscosity reaches 100 Pa.s or above under the condition of zero shear rate after the CO2 flooding response type channeling sealing agent and CO2 are responded to form gel, the viscosity reaches 450 mPa.s or above under the condition of the shear rate of 170 s <-1 >, deep cracks and / or large pore channels of a reservoir can be effectively sealed, and the CO2 flooding response type channeling sealing agent can be used for sealing the reservoir. The CO2 flooding oil-retaining agent has the advantages that the sweep efficiency of CO2 in oil reservoirs is increased, the CO2 flooding recovery rate is increased, the temperature resistance is excellent, and the applicable oil reservoir temperature can reach 120 DEG C.

Description

Technical Field

[0001] The present invention relates to a CO2 flooding-responsive channel plugging agent and its preparation method and application, belonging to the technical field of enhanced oil recovery by CO2 flooding. Background Art

[0002] With the continuous development of the petroleum industry, the number of conventional oil fields that can be exploited is decreasing, and the exploitation of unconventional oil is attracting more and more attention. It has also become an important alternative oil resource. However, the development of low-permeability unconventional oil fields faces problems such as difficulty in establishing effective displacement by water flooding and rapid decline in production by natural energy development.

[0003] As a displacement medium, CO2 in its supercritical state has characteristics such as low viscosity, high density, high diffusion coefficient, and high solubility, and has good injectability. It can cause the volume of crude oil to expand, play the role of solution gas drive, and at the same time can reduce the viscosity of crude oil, improve the mobility ratio, reduce / eliminate the interfacial tension, and improve the oil displacement efficiency. However, CO2 is prone to viscous fingering and gravity segregation in heterogeneous reservoirs, reducing the sweep efficiency and causing premature gas channeling, resulting in a significant reduction in the enhanced oil recovery compared to the expected situation. Therefore, the CO2 gas channeling control technology has become a key research field in the CO2 flooding supporting technology.

[0004] Currently, the main methods for CO2 gas channeling control include changing the injection method, optimizing the injection medium, and injecting chemical plugging agents. Among them, changing the injection method is mainly divided into water-alternating-gas and water-and-gas co-injection, which generally has poor effects on heterogeneous reservoirs and serious corrosion of wellbores and pipelines. The methods for optimizing the injection medium mainly include CO2 foam technology and CO2 thickening technology. The CO2 foam technology injects a foaming agent and CO2 into the reservoir to generate foam and increase the fluid flow resistance, thereby achieving the purpose of controlling gas channeling. However, this method has poor effects in fractured reservoirs with large permeability contrasts, and also faces many problems such as poor stability of CO2 foam and harsh injection conditions. The CO2 thickening technology is to directly thicken CO2 gas to improve the mobility ratio of CO2 and formation fluids to achieve the purpose of gas channeling control. However, this method is not yet mature and has a high cost. The method of injecting chemical plugging agents mainly uses polymer gels for plugging. The polymer gel can effectively plug the near-well high-permeability strip with high plugging strength. However, most polymer gels are not acid-resistant, resulting in a short plugging validity period, a relatively high initial viscosity of the system, poor injectability, inability to effectively plug the deep part of the reservoir, and easy bypassing and breakthrough of CO2. At the same time, the degradation of polymer gels is difficult, which is likely to cause damage to the reservoir matrix and environmental hazards.

[0005] Therefore, the research on CO2-driven responsive plugging agents has gradually become a hot topic. Such plugging agents have a low initial viscosity, and their viscosity increases significantly after contacting with CO2. Moreover, their viscosity can be restored by injecting nitrogen or other non-acidic gases. At the same time, they also have good injection performance, deep plugging performance, and do not damage the reservoir matrix. Although the CO2-driven responsive plugging agents currently used in this field have the above advantages, they also have many defects. For example, the CO2-driven responsive plugging agents have problems such as poor temperature resistance and low plugging strength, and the hydrophobic modified polyacrylamide used in them will cause permanent damage to the reservoir matrix.

[0006] To sum up, the gel plugging agents currently used in this field have problems such as poor injectability, near-wellbore plugging, easy damage to the reservoir matrix and environmental hazards. The CO2-driven responsive plugging agents currently used have poor temperature resistance and low plugging strength, and there is also an artificial polymer (generally a polyacrylamide polymer) component in the system, which will cause permanent damage to the reservoir.

[0007] Therefore, providing a new type of CO2-driven responsive plugging agent and its preparation method and application has become an urgent technical problem to be solved in this field. Summary of the Invention

[0008] In order to solve the above-mentioned disadvantages and deficiencies, one object of the present invention is to provide a CO2-driven responsive plugging agent.

[0009] Another object of the present invention is to provide a preparation method of the above-mentioned CO2-driven responsive plugging agent.

[0010] Another object of the present invention is to provide the application of the above-mentioned CO2-driven responsive plugging agent as a plugging agent or profile control and water shutoff agent in oilfield exploitation.

[0011] In order to achieve the above objects, on the one hand, the present invention provides a CO2-driven responsive plugging agent, wherein, based on the total weight of the CO2-driven responsive plugging agent being 100%, it comprises:

[0012] 0.3-2 wt% gemini amine, 1-5 wt% organic tertiary amine, 0.3-1 wt% nano-enhancer, 0-3 wt% auxiliary agent and 98.4-89 wt% water.

[0013] As a specific embodiment of the CO2-driven responsive plugging agent of the present invention described above, wherein, the gemini amine includes dimethylene-1,2-bis(dodecyldimethylammonium bromide), dimethylene-1,2-bis(tetradecyldimethylammonium bromide), N,N'-dilauroyl ethylenediamine diacrylate and N,N-bis(N-methyl, N-isopropyl alcohol C 12 -C 18 acyl)C6-C12 One or a combination of several of alkylamines, wherein, N,N-di(N-methyl, N-isopropyl C 12 -C 18 -acyl)C6-C 12 The structural formula of the alkylamine is as follows:

[0014]

[0015] Wherein, R1 is an alkyl group of C6-C 12 ;

[0016] R2 is an acyl group of C 12 -C 18 .

[0017] As a specific embodiment of the above-mentioned CO2 flooding-responsive plugging agent of the present invention, wherein, R1 is a normal alkyl group of C6-C 12 ;

[0018] R2 is a normal acyl group of C 12 -C 18 .

[0019] The above-mentioned gemini amine used in the present invention can be obtained by commercial purchase or prepared by existing conventional methods.

[0020] Compared with the existing conventional plugging agent system that only uses a single organic tertiary amine, adding the gemini amine with the above structure to the CO2 flooding-responsive plugging agent of the present invention can improve the temperature resistance and gelation strength.

[0021] As a specific embodiment of the above-mentioned CO2 flooding-responsive plugging agent of the present invention, wherein, the N,N-di(N-methyl, N-isopropyl C 12 -C 18 -acyl)C6-C 12 The synthesis method of the alkylamine includes:

[0022] Step (a): Dissolve the C6-C 12 alkylamine in absolute ethanol, heat it in a water bath to 60-70 °C, add an absolute ethanol solution of epichlorohydrin, react under reflux for 6-9 h (preferably 8 h), then cool and crystallize, filter to obtain an intermediate product, namely N,N-di(1-chloro-2-propanolyl)C6-C 12 alkylamine;

[0023] Step (b): Take N,N-di(1-chloro-2-propanolyl)C6-C 12 alkylamine and dissolve it in acetone, add N-methyl C 12 -C 18An amide and a strong base catalyst are used, and after refluxing for 14 - 18 h (preferably 16 h), acetone is removed to obtain a solid product, and then the solid product is washed and dried to obtain the gemini amine;

[0024] Among them, C6 - C 12 The molar ratio of alkylamine, epichlorohydrin, N,N - bis(1 - chloro - 2 - propanol) C6 - C 12 alkylamine and N - methyl C 12 -C 18 amide is 1:2.0 - 2.2:1:1.8 - 2.0.

[0025] In the present invention, in step (a) of the synthesis method of the gemini amine, the cooling crystallization is carried out at room temperature.

[0026] In the present invention, in step (b) of the synthesis method of the gemini amine, after refluxing, it is cooled to 40 - 50 °C in an indoor environment and the solvent, such as acetone, etc., is removed under this temperature and vacuum conditions, then washed with absolute ethanol (such as washing 3 times), and finally dried at a low temperature of 40 - 50 °C to obtain a solid product.

[0027] In the present invention, the strong base catalyst used in step (b) of the synthesis method of the gemini amine is a conventional substance, and a suitable strong base catalyst can be reasonably selected and its dosage can be adjusted according to actual operation needs, as long as the purpose of catalytic reaction can be achieved. In some embodiments of the present invention, the strong base catalyst can be, for example, sodium hydroxide, etc.

[0028] As a specific embodiment of the CO2 - flooding responsive plugging agent described above in the present invention, among them, the organic tertiary amine includes an alkyl tertiary amine or an amide - based tertiary amine with the longest carbon chain carbon number greater than 14.

[0029] As a specific embodiment of the CO2 - flooding responsive plugging agent described above in the present invention, among them, the organic tertiary amine includes one or a combination of several of cetyl dimethyl tertiary amine, octadecyl dimethyl tertiary amine, bis - hexadecyl methyl tertiary amine, N - dimethylaminopropyl erucamide, N - dimethylaminopropyl stearamide, etc.

[0030] As a specific embodiment of the CO2 - flooding responsive plugging agent described above in the present invention, among them, the nano - enhancer includes carbon - based nanomaterials. In the CO2 - flooding responsive plugging agent, the nano - enhancer is used to improve the temperature resistance and gelation strength. In some embodiments of the present invention, the carbon - based nanomaterials are graphene - like materials.

[0031] As a specific embodiment of the above-mentioned CO₂ flooding-responsive plugging agent of the present invention, among them, the auxiliary agent includes one or a combination of several of sodium oleate, sodium salicylate, sodium dodecyl sulfonate, etc. In the CO₂ flooding-responsive plugging agent, the auxiliary agent is used to increase the initial viscosity of the system when plugging high-permeability reservoirs.

[0032] As a specific embodiment of the above-mentioned CO₂ flooding-responsive plugging agent of the present invention, among them, the CO₂ flooding-responsive plugging agent system does not contain polymer components, has a low initial viscosity, and its initial viscosity (which is the initial viscosity without adding auxiliary agents) is lower than 6 mPa·s, with good injection performance. After gelling in response to CO₂, the viscosity under zero shear rate conditions reaches more than 100 Pa·s, and the viscosity reaches more than 450 mPa·s under the condition of a shear rate of 170 s -1 conditions, which can effectively plug deep fractures and / or large pore channels in the reservoir, expand the sweep coefficient of CO₂ in the reservoir, and improve the recovery rate of CO₂ flooding.

[0033] On the other hand, the present invention also provides a preparation method of the above-mentioned CO₂ flooding-responsive plugging agent, among which, the preparation method includes:

[0034] Sequentially add gemini amine and organic tertiary amine to water and mix evenly, then add nano-enhancer and mix evenly, and finally add or not add auxiliary agent and mix evenly to obtain the CO₂ flooding-responsive plugging agent.

[0035] In the above-mentioned preparation method of the present invention, the mixing evenly can be achieved by stirring.

[0036] In the above-mentioned preparation method of the present invention, it is determined whether to add an auxiliary agent according to the initial viscosity required by the high-permeability reservoir. If the required initial viscosity of the high-permeability reservoir is relatively high, such as not less than 30 mPa·s, then an auxiliary agent needs to be added, otherwise no auxiliary agent needs to be added.

[0037] On yet another aspect, the present invention also provides the application of the above-mentioned CO₂ flooding-responsive plugging agent as a plugging agent or profile control and water plugging agent in oilfield exploitation.

[0038] As a specific embodiment of the above-mentioned application of the present invention, among them, the method of the application includes the following steps:

[0039] Inject the CO₂ flooding-responsive plugging agent into the oilfield, and then introduce CO₂ to crosslink and form a plugging gel.

[0040] As a specific embodiment of the above-mentioned application of the present invention, among them, the method of the application further includes: after forming the plugging gel, inject a non-acidic gas into the oilfield for removal, which has no harm to the reservoir matrix.

[0041] As a specific embodiment of the above-mentioned application of the present invention, the non-acidic gas includes non-acidic gases such as nitrogen.

[0042] As a specific embodiment of the above-mentioned application of the present invention, the reservoir temperature of the oilfield is 60-120 °C, that is, the CO2 flooding response type plugging agent has excellent temperature resistance, and the applicable reservoir temperature of the oil reservoir can be as high as 120 °C.

[0043] Compared with the prior art, the beneficial technical effects that can be achieved by the CO2 flooding response type plugging agent provided by the present invention include:

[0044] (1) The CO2 flooding response type plugging agent does not contain polymer substances, and its main components are small molecule chemical reagents with surface activity and nanomaterials. Therefore, the initial viscosity of the system is low (<6 mPa·s), and it has good injection performance and can reach the deep part of the reservoir.

[0045] (2) By adding gemini amines with multi-carbon chains and carbon-based nanomaterials to the CO2 flooding response type plugging agent of the present invention, the temperature resistance and shear resistance of the system are improved. Under formation temperature and flow shear conditions, the gelation strength in response to CO2 is greatly improved (120 °C, 170 s -1 , and the viscosity reaches more than 450 mPa·s), which can effectively block cracks and large pore gas channeling channels, and thus can be suitable for deep plugging of fractured reservoirs with large permeability differences.

[0046] (3) The CO2 flooding response type plugging agent is a non-polymer gel system, which can be removed by injecting non-acidic gases such as nitrogen, and has no harm to the reservoir matrix. Specifically, see Figure 3 .

[0047] (4) When the CO2 flooding response type plugging agent is used for CO2 flooding plugging, it can effectively block deep fractures and / or large pores in the reservoir, expand the sweep efficiency of CO2 in the oil reservoir, and improve the CO2 flooding recovery rate. The CO2 flooding response type plugging agent has a very broad application prospect. Description of the Drawings

[0048] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for the description of the embodiments. Obviously, the following drawings are some embodiments of the present invention. For those of ordinary skill in the art, without creative efforts, other drawings can also be obtained based on these drawings.

[0049] Figure 1 In Test Example 1 of the present invention, it is a graph of the shear viscosity test results of the plugging agent d1 under the conditions of 60 °C and 170S -1 conditions.

[0050] Figure 2 In Test Example 1 of the present invention, the shear viscosity test result diagram of the channel plugging agent d1 at 120°C and 170S -1 Condition.

[0051] Figure 3 In Test Example 1 of the present invention, the zero-shear viscosity test result diagram of the system after introducing CO2 and N2 into the channel plugging agent d1.

[0052] Figure 4 Schematic structural diagram of the test experimental device used in Test Example 2 and Test Example 3 of the present invention. Detailed implementation mode

[0053] It should be noted that the term "including" and any deformation thereof in the description, claims and above-mentioned drawings of the present invention are intended to cover non-exclusive inclusion. For example, a process, method, system, product or device including a series of steps or units does not necessarily have to be limited to those clearly listed steps or units, but may include other steps or units not clearly listed or inherent to these processes, methods, products or devices.

[0054] The "range" disclosed in the present invention is given in the form of a lower limit and an upper limit. There can be one or more lower limits, and one or more upper limits respectively. A given range is defined by selecting a lower limit and an upper limit. The selected lower limit and upper limit define the boundary of a particular range. All ranges defined in this way are combinable, that is, any lower limit can be combined with any upper limit to form a range. For example, if ranges of 60-120 and 80-110 are listed for a specific parameter, ranges of 60-110 and 80-120 are also expected. In addition, if the minimum range values listed are 1 and 2, and the maximum range values listed are 3, 4 and 5, then the following ranges are all expected: 1-3, 1-4, 1-5, 2-3, 2-4 and 2-5.

[0055] In the present invention, unless otherwise stated, the numerical range "a-b" represents an abbreviated representation of any real number combination between a and b, where a and b are both real numbers. For example, the numerical range "0-5" means that all real numbers between "0-5" have been fully listed in the present invention, and "0-5" is only an abbreviated representation of these numerical combinations.

[0056] In the present invention, if there is no special description, all the implementation modes and preferred implementation modes mentioned in the present invention can be combined with each other to form a new technical solution.

[0057] In the present invention, if there is no special description, all the technical features and preferred features mentioned in the present invention can be combined with each other to form a new technical solution.

[0058] In the present invention, unless otherwise specified, all steps mentioned herein can be carried out sequentially or randomly, but preferably sequentially. For example, the method includes steps (a) and (b), which means that the method may include steps (a) and (b) carried out sequentially, or may also include steps (b) and (a) carried out sequentially. For example, it is mentioned that the method may further include step (c), which means that step (c) can be added to the method in any order. For example, the method may include steps (a), (b) and (c), or may also include steps (a), (c) and (b), or may also include steps (c), (a) and (b), etc.

[0059] In order to make the objectives, technical solutions and advantages of the present invention clearer and more understandable, the present invention will be further described in detail below in conjunction with the attached tables, drawings and embodiments. The following described embodiments are some embodiments of the present invention, rather than all embodiments, and are only used to illustrate the present invention and should not be construed as limiting the scope of the present invention. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts belong to the scope of protection of the present invention. For those conditions not specified in the embodiments, they are carried out according to the conventional conditions or the conditions recommended by the manufacturer. For the reagents or instruments not specified for the manufacturer, they are all conventional products that can be obtained through commercial purchase.

[0060] Gemini amine examples

[0061] Example 1

[0062] This example provides a gemini amine, denoted as gemini amine A, and its structural formula is as follows:

[0063]

[0064] In the formula, R1 is a n-hexyl group;

[0065] R2 is a n-dodecanoyl group;

[0066] The synthesis method of this gemini amine includes the following specific steps:

[0067] Step (a): Dissolve 0.5 mol of n-hexylamine in absolute ethanol, heat it in a water bath to 60 °C, add an absolute ethanol solution containing 1 mol of epichlorohydrin, reflux for 8 h, cool and crystallize at room temperature, and after filtration, obtain an intermediate product, namely N,N-bis(1-chloro-2-propanol)n-hexylamine;

[0068] Step (b): Dissolve 0.5 mol of the intermediate obtained in step (a) in acetone. Add 1 mol of N-methyldodecanamide and NaOH under the condition of a 70 °C oil bath, and reflux for 16 h. Cool to 40 °C in an indoor environment and remove acetone under this temperature and vacuum conditions. Then wash with absolute ethanol three times, and finally dry at a low temperature (50 °C) to obtain the target product, namely N,N-bis(N-methyl, N-isopropanolyl n-dodecanoyl) hexylamine.

[0069] Example 2

[0070] This example provides a gemini amine, denoted as gemini amine B, whose structural formula is as follows:

[0071]

[0072] In the formula, R1 is a n-octyl group;

[0073] R2 is a n-hexadecanoyl group;

[0074] The synthesis method of this gemini amine includes the following specific steps:

[0075] Step (a): Dissolve 0.5 mol of n-octylamine in absolute ethanol, heat in a water bath to 65 °C, add an absolute ethanol solution containing 1 mol of epichlorohydrin, reflux for 8 h, cool and crystallize at room temperature, and after filtration, obtain the intermediate, namely N,N-bis(1-chloro-2-propanolyl) n-octylamine;

[0076] Step (b): Dissolve 0.5 mol of the intermediate obtained in step (a) in acetone. Add 1 mol of N-methylhexadecanamide and NaOH under the condition of a 75 °C oil bath, and reflux for 16 h. Cool to 45 °C in an indoor environment and remove acetone under this temperature and vacuum conditions. Then wash with absolute ethanol three times, and finally dry at a low temperature (50 °C) to obtain the target product, namely N,N-bis(N-methyl, N-isopropanolyl n-hexadecanoyl) n-octylamine.

[0077] Example 3

[0078] This example provides a gemini amine, denoted as gemini amine C, whose structural formula is as follows:

[0079]

[0080] In the formula, R1 is a n-hexyl group;

[0081] R2 is a n-octadecanoyl group;

[0082] The synthesis method of this gemini amine includes the following specific steps:

[0083] Step (a): Dissolve 0.5 mol of n - hexylamine in absolute ethanol, heat it in a water bath to 60 °C, add an absolute ethanol solution containing 1 mol of epichlorohydrin, reflux for 8 h, cool and crystallize at room temperature. After filtration, obtain the intermediate product, namely N,N - bis(1 - chloro - 2 - propanol)n - hexylamine;

[0084] Step (b): Dissolve 0.5 mol of the intermediate product obtained in step (a) in acetone, add 1 mol of N - methyl octadecanamide and NaOH under the condition of an oil bath at 75 °C, reflux for 16 h, cool to 45 °C in an indoor environment and remove acetone under this temperature and vacuum condition, then wash with absolute ethanol 3 times, and finally dry at a low temperature (50 °C) to obtain the target product, namely N,N - bis(N - methyl, N - isopropanol octadecanoyl)n - hexylamine.

[0085] Example 4

[0086] This example provides a gemini amine, denoted as gemini amine D, and its structural formula is as follows:

[0087]

[0088] In the formula, R1 is a dodecyl group;

[0089] R2 is a dodecanoyl group;

[0090] The synthesis method of this gemini amine includes the following specific steps:

[0091] Step (a): Dissolve 0.5 mol of dodecylamine in absolute ethanol, heat it in a water bath to 70 °C, add an absolute ethanol solution containing 1 mol of epichlorohydrin, reflux for 8 h, cool and crystallize at room temperature. After filtration, obtain the intermediate product, namely N,N - bis(1 - chloro - 2 - propanol)dodecylamine;

[0092] Step (b): Dissolve 0.5 mol of the intermediate product obtained in step (a) in acetone, add 1 mol of N - methyl dodecanamide and NaOH under the condition of an oil bath at 74 °C, reflux for 16 h, cool to 46 °C in an indoor environment and remove acetone under this temperature and vacuum condition, then wash with absolute ethanol 3 times, and finally dry at a low temperature (50 °C) to obtain the target product, namely N,N - bis(N - methyl, N - isopropanol dodecanoyl)dodecylamine.

[0093] Example 5

[0094] This example provides a gemini amine, denoted as gemini amine E, and its structural formula is as follows:

[0095]

[0096] Wherein, R1 is n-dodecyl;

[0097] R2 is n-octadecanoyl;

[0098] The synthesis method of the gemini amine includes the following specific steps:

[0099] Step (a): Dissolve 0.5 mol of dodecylamine in absolute ethanol, heat it in a water bath to 70 °C, add an absolute ethanol solution containing 1 mol of epichlorohydrin, reflux for 8 h, cool and crystallize at room temperature, and filter to obtain an intermediate product, namely N,N-bis(1-chloro-2-propanol)n-dodecylamine;

[0100] Step (b): Dissolve 0.5 mol of the intermediate product obtained in step (a) in acetone, add 1 mol of N-methyl octadecanamide and NaOH under the condition of an 80 °C oil bath, reflux for 16 h, cool to 50 °C in an indoor environment and remove acetone under this temperature and vacuum conditions, then wash with absolute ethanol 3 times, and finally dry at a low temperature (50 °C) to obtain the target product, namely N,N-bis(N-methyl, N-isopropanol n-octadecanoyl)n-dodecylamine.

[0101] CO2 flooding response type plugging agent examples

[0102] Example 1-1

[0103] This example provides a CO2 flooding response type plugging agent, denoted as plugging agent a. Based on the total weight of the CO2 flooding response type plugging agent being 100%, it contains:

[0104] 2 wt% gemini amine A, 5 wt% cetyl dimethyl tertiary amine, 0.3 wt% carbon-based nanomaterials (specifically graphene oxide materials), and the balance water.

[0105] Example 2-1

[0106] This example provides a CO2 flooding response type plugging agent, denoted as plugging agent b. Based on the total weight of the CO2 flooding response type plugging agent being 100%, it contains:

[0107] 1.5 wt% gemini amine B, 3 wt% octadecyl dimethyl tertiary amine, 0.5 wt% carbon-based nanomaterials (specifically graphene oxide materials), and the balance water.

[0108] Example 3-1

[0109] This example provides a CO2 flooding response type plugging agent, denoted as plugging agent c. Based on the total weight of the CO2 flooding response type plugging agent being 100%, it contains:

[0110] 1 wt% Gemini amine C, 4 wt% dihexadecylmethyl tertiary amine, 0.3 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0111] Example 4-1

[0112] This example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent d1. Based on the total weight of the CO2 flooding-responsive channel plugging agent being 100%, it contains:

[0113] 2 wt% Gemini amine D, 2 wt% N-dimethylaminopropyl stearamide, 1 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0114] Example 4-2

[0115] This example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent d2. Based on the total weight of the CO2 flooding-responsive channel plugging agent being 100%, it contains:

[0116] 2 wt% dimethylene-1,2-bis(dodecyldimethylammonium bromide), 2 wt% N-dimethylaminopropyl stearamide, 1 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0117] Example 4-3

[0118] This example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent d3. Based on the total weight of the CO2 flooding-responsive channel plugging agent being 100%, it contains:

[0119] 1 wt% dimethylene-1,2-bis(tetradecyldimethylammonium bromide), 1 wt% N,N'-dilauroyl ethylenediamine diacrylate sodium, 2 wt% N-dimethylaminopropyl stearamide, 1 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0120] Example 5-1

[0121] This example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent e1. Based on the total weight of the CO2 flooding-responsive channel plugging agent being 100%, it contains:

[0122] 0.3 wt% Gemini amine E, 1 wt% N-dimethylaminopropyl erucamide, 0.5 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0123] Example 5-2

[0124] This embodiment provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent e2. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0125] 0.3 wt% of gemini amine E, 1 wt% of N-dimethylaminopropyl erucamide, 0.3 wt% of carbon-based nanomaterials (specifically graphene oxide-based materials), 1 wt% of sodium oleate, and the balance of water.

[0126] Example 5-3

[0127] This embodiment provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent e3. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0128] 0.3 wt% of gemini amine E, 1 wt% of N-dimethylaminopropyl erucamide, 0.3 wt% of carbon-based nanomaterials (specifically graphene oxide-based materials), 2 wt% of sodium salicylate, and the balance of water.

[0129] Example 5-4

[0130] This embodiment provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent e4. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0131] 0.3 wt% of gemini amine E, 1 wt% of N-dimethylaminopropyl erucamide, 0.3 wt% of carbon-based nanomaterials (specifically graphene oxide-based materials), 1 wt% of sodium oleate, 2 wt% of sodium dodecyl sulfate, and the balance of water.

[0132] Comparative Example 1

[0133] This comparative example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent f1. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0134] 7 wt% of cetyl dimethyl tertiary amine, 0.3 wt% of carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance of water.

[0135] Comparative Example 2

[0136] This comparative example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent f2. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0137] 2 wt% of gemini amine A, 5 wt% of cetyl dimethyl tertiary amine, and the balance of water.

[0138] Comparative Example 3

[0139] This comparative example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent f3. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0140] 0.2 wt% gemini amine E, 1 wt% N-dimethylaminopropyl erucamide, 0.5 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0141] Comparative Example 4

[0142] This comparative example provides a CO2 flooding-responsive channel plugging agent, denoted as channel plugging agent f4. Based on 100% of the total weight of the CO2 flooding-responsive channel plugging agent, it contains:

[0143] 3 wt% gemini amine E, 1 wt% N-dimethylaminopropyl erucamide, 0.5 wt% carbon-based nanomaterials (specifically graphene oxide-based materials), and the balance water.

[0144] Test Example 1

[0145] This test example measures the viscosities of channel plugging agents a - c, channel plugging agents d1 - d3, channel plugging agents e1 - e4, and channel plugging agents f1 - f4 respectively, including the following specific steps:

[0146] Pass CO2 gas (gas flow rate is 1.5 mL / min) into channel plugging agents a - c, channel plugging agents d1 - d3, channel plugging agents e1 - e4, and channel plugging agents f1 - f4 respectively until a uniform high-viscosity gel state is formed in the system. Let it stand until the trapped bubbles dissipate, and finally obtain a stable high-viscosity gel system;

[0147] Use a high-temperature and high-pressure rheometer to measure the shear viscosity of the above systems at 170 s when the temperature is 60 °C, 80 °C, 100 °C, and 120 °C respectively. -1 The test results are shown in Table 1 and Figures 1 - 2 as shown, where Figures 1 - 2 the "viscosity before contact" and "viscosity after release" in

[0148] correspond to the "initial viscosity" and "gel viscosity" in the table respectively;

[0149] At the same time, select channel plugging agent d1 and conduct a zero-shear viscosity test on it at a temperature of 120 °C, including: Pass CO2 gas (gas flow rate is 1.5 mL / min) into channel plugging agent d1, and measure the change of the zero-shear viscosity of the system with time using a high-temperature and high-pressure rheometer during the process of passing CO2 gas;

[0149] Then pass N2 (gas flow rate is 1.5 mL / min) into the system, measure the change of the zero-shear viscosity of the system with time using a high-temperature and high-pressure rheometer, and observe the change of the zero-shear viscosity of the system before and after passing CO2 and passing N2. The obtained test results are asFigure 3 as shown

[0150] Table 1 Viscosity Test Results of CO2 Flooding Response Type Channel Plugging Agent (170 s -1 shear)

[0151]

[0152]

[0153] As can be seen from Table 1 and Figures 1 - 2 it can be seen that the CO2 flooding response type channel plugging agent without additives provided in Examples 1-1 to 5-1 of the present invention has a very low initial viscosity, good injection performance, and is suitable for extra-low to ultra-low permeability reservoirs. Under the condition of a temperature of 60-120 °C, the CO2 flooding response type channel plugging agent can form a shear-resistant high-viscosity gel after reacting with CO2, which is beneficial to plugging high-permeability channels such as fractures; in Examples 5-2 to 5-4, after adding additives such as sodium oleate, sodium salicylate, and sodium dodecyl sulfonate to the CO2 flooding response type channel plugging agent, its initial viscosity becomes higher and it is suitable for medium-high permeability reservoirs, see channel plugging agent e2, channel plugging agent e3, and channel plugging agent e4.

[0154] As can be seen from Table 1 and Figures 1 - 2 it can also be seen that the gemini amine and carbon-based nano-enhanced materials in the CO2 flooding response type channel plugging agent have a great influence on the system viscosity. The absence of any one of the components will cause a significant decrease in the viscosity of the channel plugging agent after gelation, specifically see channel plugging agent f1 and channel plugging agent f2; in addition, too low a concentration of gemini amine will cause a decrease in the viscosity of the channel plugging agent, especially under high-temperature conditions, the viscosity of the channel plugging agent will decrease significantly, see channel plugging agent f3; after the concentration of gemini amine is higher than 2 wt%, it has little effect on the gelation viscosity of the channel plugging agent, but will significantly increase the use cost, see channel plugging agent f4.

[0155] From Figure 3 it can be seen from the zero-shear viscosity test results shown that the zero-shear viscosity of the system can reach more than 100 Pa·s after introducing CO2. After forming the channel plugging gel, N2 can be injected into the system for removal without damage to the reservoir matrix.

[0156] Test Example 2

[0157] In this test example, the oil displacement efficiency of channel plugging agent d1 was tested. The structural schematic diagram of the test experimental device used is as Figure 4 shown, and the test steps include:

[0158] ① Vacuum saturate the treated fractured core with water, and obtain the saturated water mass and porosity data according to the mass of the core before and after saturation with water.

[0159] ②Put the water-saturated core into the holder 1, measure the water flooding permeability, then saturate it with oil and age for 24 h, and calculate the oil saturation according to the water production during oil saturation.

[0160] ③Inject CO2 gas at a flow rate of 0.5 mL / min with a back pressure of 10 MPa, record the pressure and the produced liquid (gas) volume until complete gas channeling occurs, record the pressure and the produced liquid (gas) data, and calculate the oil displacement efficiency.

[0161] ④After injecting a 0.1 PV spacer slug (clear water, active water or simulated formation water are all acceptable) at a flow rate of 0.1 mL / min, inject 0.3 PV of the channeling plugging agent d1.

[0162] ⑤After injecting a 0.1 PV spacer slug (clear water, active water or simulated formation water are all acceptable) at a flow rate of 0.1 mL / min, continuously inject CO2 at a flow rate of 0.5 mL / min until gas channeling occurs, record the pressure and the produced liquid (gas) data, and calculate the oil displacement efficiency.

[0163] The relevant parameters of the core used in this test example, the experimental temperature, and the obtained oil displacement efficiency / recovery data are all shown in Table 2 below.

[0164] Table 2 Test results of oil displacement efficiency / recovery of single-fracture core

[0165]

[0166]

[0167] As can be seen from Table 2, the CO2 flooding responsive channeling plugging agent provided by the embodiments of the present invention can greatly improve the recovery of CO2 flooding through channeling plugging control. Since the increase in temperature has an impact on the viscosity of the system after gelation, the increase in the recovery decreases with the increase in the experimental temperature.

[0168] Test Example 3

[0169] This test example tests the oil displacement efficiency and diversion rate of the channeling plugging agent d1. The structural schematic diagram of the test experimental device used is as Figure 4 shown, and the test steps include:

[0170] ①Vacuum-saturate the fractured core and matrix core that have been treated, and obtain the saturated water mass and porosity data according to the core mass before and after water saturation.

[0171] ②Put the water-saturated fractured core and matrix core into the holder 1 and holder 2 respectively, measure the water flooding permeability, then saturate them with oil and age for 24 h, and calculate the oil saturation according to the water production during oil saturation.

[0172] ③ Inject CO2 gas at a flow rate of 0.5 mL / min with a backpressure of 10 MPa, record the pressure and the produced liquid (gas) volume until complete gas channeling occurs, record the pressure and the produced liquid (gas) data, and calculate the oil displacement efficiency and the split ratio.

[0173] ④ After injecting a 0.1 PV isolation slug (either fresh water, active water, or simulated formation water) at a flow rate of 0.1 mL / min, inject 0.3 PV of the channeling plugging agent d1.

[0174] ⑤ After injecting a 0.1 PV isolation slug (either fresh water, active water, or simulated formation water) at a flow rate of 0.1 mL / min, continuously inject CO2 at a flow rate of 0.5 mL / min until gas channeling occurs, record the pressure and the produced liquid (gas) data, and calculate the oil displacement efficiency and the split ratio.

[0175] The relevant parameters of the core used in this test example, as well as the obtained oil displacement efficiency / recovery rate and split ratio data, are all shown in Table 3 below.

[0176] Table 3 Test results of oil displacement efficiency and split ratio for single-fracture core in parallel with matrix core (experimental temperature is 80 °C)

[0177]

[0178] As can be seen from Table 3, the CO2 flooding responsive channeling plugging agent provided by the embodiments of the present invention can significantly improve the heterogeneity of the reservoir, thereby expanding the sweep efficiency of CO2 flooding and increasing the recovery rate.

[0179] As described above, the above are only specific embodiments of the present invention and cannot limit the scope of the invention implementation. Therefore, the replacement of equivalent components or the equivalent changes and modifications made according to the scope of protection of the present invention patent should still fall within the scope covered by this patent. In addition, the technical features in the present invention can be freely combined with each other between technical features, between technical features and technical inventions, and between technical inventions.

Claims

1. A CO2 flooding-responsive channel plugging agent, characterized in that, Based on the total weight of the CO2 flooding responsive channel plugging agent being 100%, it comprises: 0.3 - 2 wt% gemini amine, 1 - 5 wt% organic tertiary amine, 0.3 - 1 wt% nano enhancer, 0 - 3 wt% auxiliary agent, and 98.4 - 89 wt% water.

2. The CO2 flooding-responsive plugging agent according to claim 1, wherein The gemini amine includes one or a combination of several of dimethylene-1,2-bis(dodecyldimethylammonium bromide), dimethylene-1,2-bis(tetradecyldimethylammonium bromide), N,N'-dilauroyl ethylenediamine diacrylate, and N,N-di(N-methyl, N-isopropyl C 12 -C 18 -acyl)C6-C 12 alkylamine, wherein the structural formula of N,N-di(N-methyl, N-isopropyl C 12 -C 18 -acyl)C6-C 12 alkylamine is shown as follows: Among them, R1 is an alkyl group with C6-C 12 alkyl; R2 is C 12 -C 18 acyl group.

3. The CO2 flooding-responsive channel plugging agent according to claim 2, wherein, The synthesis method of the N,N-bis(N-methyl, N-isopropyl C 12 -C 18 -acyl)C6-C 12 alkylamine includes: Step (a): Dissolve C6-C 12 alkylamine in absolute ethanol, heat it in a water bath to 60-70 °C, add an absolute ethanol solution of epichlorohydrin, and after reacting under reflux for 6-9 h, cool it for crystallization and filter to obtain N,N-bis(1-chloro-2-propanolyl)C6-C 12 alkylamine; Step (b): Take N,N-bis(1-chloro-2-propanol)C6-C 12 alkylamine and dissolve it in acetone. Add N-methyl C 12 -C 18 amide and a strong base catalyst under the condition of an oil bath at 70-80 °C. After reacting under reflux for 14-18 h, remove acetone to obtain a solid product, and then wash and dry the solid product to obtain the gemini amine; Among them, C6-C 12 alkylamine, epichlorohydrin, N,N-bis(1-chloro-2-propanolyl)C6-C 12 alkylamine and N-methyl C 12 -C 18 The molar ratio of the amide is 1:2.0-2.2:1:1.8-2.

0.

4. The CO2 flooding-responsive channel plugging agent according to claim 1, characterized in that, The organic tertiary amine includes an alkyl tertiary amine or an amido tertiary amine with the longest carbon chain having more than 14 carbon atoms.

5. The CO2 flooding responsive channel plugging agent according to claim 4, wherein The organic tertiary amine includes one or a combination of cetyl dimethyl tertiary amine, octadecyl dimethyl tertiary amine, bishexadecyl methyl tertiary amine, N - dimethylaminopropyl erucamide, and N - dimethylaminopropyl stearamide.

6. The CO2 flooding responsive plugging agent according to claim 1, wherein The nano enhancer includes carbon - based nanomaterials.

7. The CO2 flooding-responsive plugging agent according to claim 1, wherein The auxiliary agent includes one or a combination of sodium oleate, sodium salicylate, and sodium dodecyl sulfonate.

8. The CO2 flooding-responsive channel plugging agent according to any one of claims 1-7, characterized in that The initial viscosity of the CO2-responsive plugging agent is less than 6 mPa·s, and its viscosity reaches more than 100 Pa·s under zero shear rate conditions after gelling in response to CO2. When the shear rate is 170 s -1 , its viscosity reaches more than 450 mPa·s.

9. The preparation method of the CO2 flooding responsive channel plugging agent according to any one of claims 1-8, characterized in that, The preparation method includes: Sequentially adding gemini amine and organic tertiary amine to water and mixing evenly, then adding the nano enhancer and mixing evenly, and finally adding or not adding the auxiliary agent and mixing evenly to obtain the CO2 flooding responsive channel plugging agent.

10. The application of the CO2 flooding responsive channel plugging agent according to any one of claims 1 - 8 as a channel plugging agent or a profile control and water plugging agent in oilfield exploitation.

11. The application according to claim 10, wherein The method of the application includes the following steps: Injecting the CO2 flooding responsive channel plugging agent into the oilfield, and then introducing CO2 for cross - linking to form a channel plugging gel.

12. The application according to claim 11, wherein The method of the application further includes: after forming the channel plugging gel, injecting a non - acidic gas into the oilfield for removal.

13. The application according to claim 12, characterized in that, The non - acidic gas includes nitrogen.

14. The application according to any one of claims 10 to 13, characterized in that, The reservoir temperature of the oilfield is 60 - 120 °C.

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