In-crack hydrolytic polymer surfactant for fracturing as well as preparation method and application of in-crack hydrolytic polymer surfactant

Abstract

The invention discloses an in-crack hydrolytic polymer surfactant for fracturing as well as a preparation method and application thereof, and belongs to the field of oil production engineering of oil reservoirs. The polymer surfactant has a structure as shown in a formula I: # imgabs0 #, wherein R is selected from one of # imgabs1 # imgabs2 #; r1 is selected from the group consisting of C1-C3 hydrocarbon groups or # imgabs3 # R2 is selected from the group consisting of C1-C3 hydrocarbon groups or # imgabs4 # R3 is selected from the group consisting of C12-C18 hydrocarbon groups or # imgabs5 # R4 is selected from the group consisting of # imgabs6 # a: b: c = 4-6: 1: 0-2; c is not 0. The polymeric surfactant avoids premature adsorption near the wellbore; when reaching a far-end gap, the oil-displacing agent can be quickly dissolved (dozens of minutes) in a soaking process (several days or weeks), and permeates into an oil layer to play an oil-displacing role, and after hydrolysis, the residue rate can be lower than 0.1%, so that an oil-water channel of a reservoir is prevented from being blocked.

Description

Technical Field

[0001] The present application relates to an intra-fracture hydrolyzable polymer surfactant for fracturing and a preparation method and application thereof, belonging to the field of oil reservoir production engineering. Background Art

[0002] In the oil field, fracturing refers to a method of using hydraulic force to create cracks in oil and gas layers during oil or gas production, also known as hydraulic fracturing. Fracturing is the process of artificially creating cracks in the formation to improve the flow environment of oil underground and increase the production of oil wells. It plays an important role in improving the flow conditions at the bottom of the oil well, slowing down the interlayer and improving the production of oil layers.

[0003] At present, the main method of fracturing is hydraulic fracturing. Hydraulic fracturing relies on the ground high-pressure pump truck group to inject fluid into the well at high speed, and with the help of the high pressure at the bottom of the well, the oil layer rock is broken and cracks are formed. In order to prevent the pressure from dropping after the pump truck stops working, and the cracks close again by themselves, sand with a density several times greater than that of the formation is mixed into the injected liquid after the formation is broken. It enters the cracks together with the fluid and stays in the cracks permanently, supporting the cracks in an open state, so that the oil flow environment can be improved for a long time. At present, hydraulic fracturing technology is very mature, and the effect of increasing oil well production is obvious. It has long become the preferred common technology. Especially for oil layers with small oil flow channels, that is, low permeability, the production increase effect is particularly outstanding.

[0004] Fracturing fluid is an important part of fracturing technology. Its main function is to create cracks and transport proppant along the opened cracks, so the viscosity of the fluid is crucial. Successful fracturing operations require that the fluid not only has high viscosity in the cracks, but also can break gel quickly; can be quickly returned after the operation; can well control liquid loss; has low friction during pumping; and is economically feasible.

[0005] There are about 60×10 8 t of low permeability reservoir reserves, ultra-low permeability reservoirs (Class II 1×10 -3 -10×10 -3 μm 2 , Class III 0.1×10 -3 -1×10 -3 μm 2 ) account for more than 58%, and there are more than 300 oil fields. The recovery rate of ultra-low and ultra-low permeability oil fields is generally between 5% and 28%, with an average level of 13.6%. There are generally low formation pressure (low crude oil driving energy), low permeability, low recovery rate, difficult water injection, and many formation sensitivity problems. In addition, my country's continental shale oil resources are about 1500×10 8 t, with recoverable resources of approximately 30×10 8 -60×10 8Shale oil reservoirs have low porosity and very low permeability. Under natural conditions, they have no natural production capacity or commercial mining value, and special mining technologies such as fracturing are required.

[0006] Extra-low and ultra-low permeability oil and gas reservoirs and shale oil and gas reservoirs are the main targets for further exploitation in the future. The reason why they can be developed is related to the fracture systems (natural fractures and artificial fractures caused by hydraulic fracturing) existing in their reservoirs. For such extra-low and ultra-low permeability oil and gas reservoirs containing natural fractures or after hydraulic fracturing, the main mechanism of oil recovery is to cause water in the fractures to be absorbed into the matrix through imbibition, thereby replacing crude oil and producing oil. Therefore, the properties of the fracturing fluid are one of the key factors affecting the recovery rate of such reservoirs. (Note: Due to the extremely low permeability of such reservoirs, it is often impossible to increase oil production through methods such as water injection, polymer injection, and surfactant injection like traditional reservoirs; therefore, the rational use of tens of thousands (hundreds of thousands) of cubic meters of fracturing fluid during fracturing to improve the imbibition and oil recovery performance of the fracturing fluid is a method that is currently receiving attention.)

[0007] At present, under the condition of certain reservoir properties and fracturing technology, in order to further improve the recovery rate of ultra-low and ultra-low permeability reservoirs and shale reservoirs, it is necessary to use fracturing fluid to supplement energy, improve seepage, prevent scaling, and improve water injection efficiency. Furthermore, it is necessary to explore fluid dynamics, improve oil seepage efficiency, improve oil and water migration capacity, and allow crude oil to fully enter the main fracture channel to improve single well productivity and achieve the purpose of increasing production.

[0008] Based on the above needs, the industry has developed an integrated fracturing fluid system for reducing resistance and flooding oil. While meeting the needs of fracturing projects, it has excellent absorption-promoting effects and can effectively increase the recovery effect of fracturing fluids. The component that plays a role is the absorption-promoting surfactant added to the fracturing fluid. The surfactant has an ionic polar head or a lone pair of electrons, which is easily adsorbed on the formation. During the construction process, it will be adsorbed in large quantities in the formation near the wellbore of the fracturing wellbore, resulting in a loss of effective concentration, and it cannot reach the far end of the fracture in a high concentration. In addition, many of the current imbibing agents are formulated, and "chromatographic separation" will occur during the migration of the reservoir, that is, the multiple components cannot always remain evenly distributed, so the comprehensive performance achieved in indoor experimental tests cannot be achieved. Summary of the invention

[0009] As mentioned above, existing imbibition oil-displacing agents have the disadvantages of large-scale adsorption in the formation near the wellbore and "chromatographic separation" during migration. The invention prepares a fracture-hydrolyzable polymer surfactant for fracturing. The finished surfactant can be in liquid state, which is convenient for pumping; after encountering water, the solvent dissolves in water, and the surfactant precipitates in the fracturing fluid in solid form, enters the formation together with the fracturing fluid, and migrates to the far end with the extension of the fracture; because the hydrolyzable functional groups in the molecular structure need a certain time to hydrolyze, the surfactant is in solid form during migration to avoid premature adsorption near the wellbore; when reaching the far end of the fracture, it will quickly dissolve during the well soaking (several days or weeks), and penetrate into the oil layer to play the role of oil displacement; and because the surfactant is a polymer surfactant, it is not a formula, and it will not undergo "chromatographic separation" during the migration of the reservoir like the traditional formula surfactant, that is, the multiple components cannot be kept uniformly distributed all the time, and the comprehensive performance achieved in the indoor experimental test cannot be achieved. In the prior art, there are alternating copolymers obtained from styrene and maleic anhydride in other industries, but they are not used in this industry, let alone in imbibition oil displacement agents. Moreover, they cannot be completely hydrolyzed, and are prone to produce a large amount of residues, with a residue rate far greater than 1%, and cannot be used in fracturing. In this application, the polymer surfactant obtained by copolymerizing styrene, maleic anhydride, and cationic monomers can be completely hydrolyzed, with a residue rate of less than 0.1%, which improves the oil displacement efficiency while avoiding clogging the oil-water channel of the reservoir.

[0010] According to the first aspect of the present application, a hydrolyzable polymer surfactant for fracturing is provided, wherein the styrene polymer part of the polymer surfactant provides hydrophobicity, maleic anhydride provides two carboxyl groups after hydrolysis, and the cationic monomer provides a cationic head and partial hydrophobicity. It is required that after complete hydrolysis, the molar content of the cationic monomer is less than half of the molar content of maleic anhydride (to ensure that the molecule as a whole is neutral or negatively charged); the single mole ion head (COO after hydrolysis) - The effective carbon number corresponding to the total number of cations (the benzene ring is equivalent to about 3.5 carbons) should preferably be less than 18 carbons (the water solubility will deteriorate if it is greater than this value).

[0011] A fracture-hydrolyzable polymer surfactant for fracturing, wherein the polymer surfactant has a structure shown in Formula I:

[0012]

[0013] Among them, R is selected from One of;

[0014] R1 is selected from a C1-C3 hydrocarbon group or

[0015] R2 is selected from a C1-C3 hydrocarbon group or

[0016] R3 is selected from C 12 -C 18 Hydrocarbon or

[0017] R4 is selected from

[0018] a:b:c=4-6:1:0-2;

[0019] c is not 0.

[0020] Preferably, a:b:c=4-6:1:0.5-2.

[0021] Optionally, the values ​​of a:b are independently selected from any value of 4:1, 4.5:1, 5:1, 5.5:1, 6:1, or any range therebetween.

[0022] Optionally, the values ​​of b:c are independently selected from any value among 1:0.1, 1:0.2, 1:0.3, 1:0.4, 1:0.5, 1:0.6, 1:0.7, 1:0.8, 1:0.9, 1:1.0, 1:1.1, 1:1.2, 1:1.3, 1:1.4, 1:1.5, 1:1.6, 1:1.7, 1:1.8, 1:1.9, 1:2.0, or any range between two of them.

[0023] The m in Formula I represents the degree of polymerization, which is not limited in the present application.

[0024] It is connected to other groups of formula I through the nitrogen atom on it.

[0025] According to one embodiment of the present application, R1, R2, R3, and R4 are independently selected from C1-C3 alkyl, C 12 -C 18 The alkyl group

[0026] According to one embodiment of the present application, R1, R2, R3, and R4 are independently selected from methyl, ethyl, propyl, (CH2) 11 CH3, (CH2) 13 CH3, (CH2) 15 CH3, (CH2) 17 CH3,

[0027]

[0028] According to one embodiment of the present application, the polymer surfactant has the structure shown below:

[0029]

[0030] According to one embodiment of the present application, when R is When the anion is selected from one of chloride ion, bromide ion and fluoride ion.

[0031] According to one embodiment of the present application, the interfacial tension of the polymer surfactant is less than 1 mN / m.

[0032] According to one embodiment of the present application, the surface tension of the polymer surfactant is less than 28 mN / m.

[0033] According to one embodiment of the present application, the wetting contact angle of the hydrolyzate of the polymer surfactant is less than 75°.

[0034] According to a second aspect of the present application, a method for preparing a polymer surfactant is provided.

[0035] A method for preparing a polymer surfactant comprises the following steps:

[0036] The polymer surfactant is obtained by reacting a mixture containing styrene, maleic anhydride, a cationic monomer, an initiator and a solvent.

[0037] According to one embodiment of the present application, the cationic monomer is an amine / ammonium hydrophilic monomer.

[0038] According to one embodiment of the present application, the cationic monomer is selected from at least one of tetraallylammonium chloride, diallylamine, dimethyldiallylammonium chloride, dodecyldimethylallylammonium chloride, tetradecyldimethylallylammonium chloride, hexadecyldimethylallylammonium chloride, and octadecyldimethylallylammonium chloride.

[0039] According to one embodiment of the present application, the initiator is selected from at least one of azobisisobutyronitrile, benzoyl peroxide, and di-tert-butyl peroxide.

[0040] According to one embodiment of the present application, the solvent is selected from at least one of N,N-dimethylformamide, dimethyl sulfoxide, and acetone.

[0041] According to one embodiment of the present application, the molar ratio of the styrene, the maleic anhydride, and the cationic monomer is 4-6:1:0-2.

[0042] Wherein, the content of the cationic monomer is not zero.

[0043] Preferably, the molar ratio of the styrene, the maleic anhydride and the cationic monomer is 4-6:1:0.5-2.

[0044] Optionally, the molar ratio of the styrene to the maleic anhydride is independently selected from any value of 4:1, 4.5:1, 5:1, 5.5:1, 6:1, or any range between the two.

[0045] Optionally, the molar ratio of the maleic anhydride to the cationic monomer is independently selected from any value among 1:0.1, 1:0.2, 1:0.3, 1:0.4, 1:0.5, 1:0.6, 1:0.7, 1:0.8, 1:0.9, 1:1.0, 1:1.1, 1:1.2, 1:1.3, 1:1.4, 1:1.5, 1:1.6, 1:1.7, 1:1.8, 1:1.9, 1:2.0 or any range value therebetween.

[0046] According to one embodiment of the present application, the amount of the initiator used is 0.1%-0.5% of the total mass of all monomer raw materials.

[0047] According to one embodiment of the present application, the reaction conditions are as follows:

[0048] Temperature is 75-85℃;

[0049] The time is 0.5-1.5h.

[0050] According to one embodiment of the present application, the following steps are included:

[0051] S1, obtaining a solution A containing maleic anhydride and a cationic monomer;

[0052] S2, obtaining a solution B containing an initiator;

[0053] S3, obtaining a solution C containing styrene;

[0054] S4. Add the solution A and the solution B into the solution C, control the dropping time to be 90-180 min, and react at 75-85° C. for 0.5-1.5 h to obtain the polymer surfactant.

[0055] According to one embodiment of the present application, the reaction uses DMF as solvent.

[0056] The reactant is polymerized from a hydrophobic monomer styrene, a hydrophilic monomer maleic anhydride and one or more amine / ammonium hydrophilic monomers.

[0057] Pre-mixing outside the kettle is adopted. Pre-mixing: ①Part of the solvent DMF, hydrophilic monomer maleic anhydride and more than one amine / ammonium hydrophilic monomer are dissolved at room temperature (≤30℃). ②Part of the solvent DMF and initiator azobisisobutyronitrile are dissolved at room temperature (≤30℃). Note that the temperature should not be too high to prevent accidental polymerization of the monomer due to impurities.

[0058] First add DMF and styrene into the kettle, then heat to 75-85℃ and stir at 80-200r / min;

[0059] Use a diaphragm pump to slowly drop the prepared solutions ① and ② into the kettle, respectively, and control the dropping time to 90-180 minutes. During this period, the temperature in the kettle cannot exceed 90℃. If it exceeds 90℃, stop dropping, and continue dropping when the temperature drops below 85℃ until all the solutions are added. Keep the temperature at 75-85℃ and continue the reaction for 0.5-1.5 hours.

[0060] After the final reaction was completed, the reactants in the kettle turned into a light yellow, uniform, stable, slightly viscous liquid.

[0061] (3) Principle of hydrolysis in cracks

[0062] The styrene polymerization part in the polymer provides hydrophobicity, maleic anhydride provides two carboxyl groups after hydrolysis, and the cationic monomer provides a cationic head and partial hydrophobicity.

[0063]

[0064] The product itself is a liquid with DMF as solvent, which is easy to pump. When the product is pumped into the fracturing fluid, DMF will dissolve in water. At this time, because the anhydride part of the polymer has not yet been hydrolyzed, the whole molecule is highly hydrophobic. Under stirring, it will precipitate in the form of loose solid particles and enter the wellbore with the fracturing fluid, further enter the fracture system generated by fracturing, and gradually move to the far end of the fracture network.

[0065] The fracturing operation has a large displacement (about 10-20m / min). 3 ), the precipitated solid polymer will quickly (within a few minutes) enter the formation fracture system with the fracturing fluid, and migrate with the fracturing gap, avoiding premature adsorption near the wellbore, making it easier to approach the oil layer. When it reaches the distal gap, it will quickly (tens of minutes) dissolve during the soaking process (several days or weeks), and penetrate into the oil layer to play the role of oil displacement (a well will be soaked according to the specific situation after the fracturing is completed, usually for a few days or longer, and the wellhead will be closed at this time. After the designed soaking time is reached, the well will be opened for backflow (part of the fracturing fluid will be discharged, and oil and gas will gradually appear). Because the dissolution time of the polymer drainage agent is short, most of it will be dissolved during fracturing, and a small amount of undissolved will also be completely dissolved in this process), thereby obtaining a hydrolyzed polymer surfactant and playing a role.

[0066] According to a third aspect of the present application, a resistance-reducing and oil-displacing integrated fracturing fluid system is provided.

[0067] An integrated fracturing fluid system for reducing resistance and flooding oil, comprising a polymer surfactant and a solvent;

[0068] The polymer surfactant is selected from the polymer surfactant described above or the polymer surfactant obtained by the preparation method described above;

[0069] The solvent is selected from at least one of N,N-dimethylformamide, dimethyl sulfoxide and acetone.

[0070] The integrated fracturing fluid system for reducing drag and flooding oil further comprises a drag reducing agent, an anti-swelling agent, a drainage aid, and a gel breaker.

[0071] According to a fourth aspect of the present application, a use of a polymer surfactant is provided.

[0072] Application of the polymer surfactant described above or the polymer surfactant obtained by the preparation method described above in a resistance reduction and oil recovery integrated fracturing fluid system.

[0073] According to one embodiment of the present application, the polymer surfactant is mixed with the solvent to form a liquid, which is then pumped into the fracturing fluid, and finally the well is soaked.

[0074] The polymer can be a liquid with DMF as solvent, which is easy to pump. When the product is pumped into the fracturing fluid, DMF will dissolve in water. At this time, because the anhydride part of the polymer has not yet been hydrolyzed, the whole molecule exhibits strong hydrophobicity. Under stirring, it will precipitate in the form of loose solid particles and enter the wellbore together with the fracturing fluid, further enter the fracture system generated by fracturing, and gradually migrate to the far end of the fracture network.

[0075] In this application, C1-C3, C 12 -C 18 The numbers refer to the number of carbon atoms in the group.

[0076] In the present application, the term "alkyl" refers to a group formed by losing any hydrogen atom from an alkane compound molecule.

[0077] In the present application, the term "hydrocarbon group" refers to a group formed by losing any hydrogen atom from a hydrocarbon.

[0078] The beneficial effects of this application include:

[0079] 1) The present application provides a fracture hydrolyzable polymer surfactant for fracturing. The polymer surfactant introduces a cationic monomer and copolymerizes styrene and maleic anhydride, so that the polymer surfactant avoids premature adsorption near the wellbore; when it reaches the distal gap, it will quickly (tens of minutes) dissolve during the well soaking (several days or weeks) and penetrate into the oil layer to play the role of oil displacement. After hydrolysis, the residue rate can be less than 0.1%, avoiding clogging the oil-water channel of the reservoir. Because the surfactant is a polymer surfactant, not a formula, it will not undergo "chromatographic separation" during the migration of the reservoir like the traditional formula surfactant, that is, the multiple components cannot be kept uniformly distributed all the time, and the comprehensive performance achieved in the indoor experimental test cannot be achieved.

[0080] 2) The present application provides a hydrolyzable polymer surfactant for fracturing, which is a light yellow liquid after being dissolved in N,N-dimethylformamide (DMF). The performance test of its hydrolyzate shows that the interfacial tension of a 0.1% aqueous solution is less than 1mN / m, and the surface tension is less than 28mN / m; the capillary self-imbibition height test shows that the imbibition performance is excellent, and it effectively promotes oil phase imbibition, which meets the standards of imbibition agents for fracturing; the wettability test shows that the wetting contact angle of its hydrolyzate is less than 75°, that is, it can convert the wettability of the oleophilic surface into hydrophilic. BRIEF DESCRIPTION OF THE DRAWINGS

[0081] Figure 1 This is the liquid product obtained in the examples of this application.

[0082] Figure 2 The liquid product obtained in the embodiment of the present application becomes a loose solid after contacting water.

[0083] Figure 3 This is the liquid product (1%) obtained in the examples of the present application before hydrolysis.

[0084] Figure 4 The liquid product (1%) obtained in the example of the present application is hydrolyzed. DETAILED DESCRIPTION

[0085] The present application is described in detail below with reference to embodiments, but the present application is not limited to these embodiments.

[0086] Unless otherwise specified, the raw materials in the examples of this application were purchased through commercial channels, including:

[0087] Styrene: molecular weight 104.14 boiling point 145.2°C;

[0088] Maleic anhydride: molecular weight 98.06;

[0089] Tetraallylammonium chloride: molecular weight 135.64;

[0090] Diallylamine: molecular weight 97.16;

[0091] Dimethyldiallylammonium chloride: molecular weight 161.67;

[0092] Dodecyl dimethyl allyl ammonium chloride: molecular weight 289.93;

[0093] Tetradecyl dimethyl allyl ammonium chloride: molecular weight 317.69;

[0094] Hexadecyl dimethyl allyl ammonium chloride: molecular weight 346.04;

[0095] Octadecyldimethylallylammonium chloride: molecular weight 374.09;

[0096] N,N-dimethylformamide (DMF): molecular weight 73.10 boiling point 153°C;

[0097] Azobisisobutyronitrile: molecular weight 164.21.

[0098] Unless otherwise specified, conventional test methods or test methods recommended by the instrument shall be used.

[0099] The analysis method in the examples of this application is as follows:

[0100] (1) Surface interfacial tension test

[0101] The surface tension test is carried out in accordance with standards SY / T 5370 and Q / SH 3580 0160.

[0102] (2) Capillary self-priming height test

[0103] ① Preparation of lipophilic capillaries.

[0104] A capillary with an inner diameter of 0.3 mm was ultrasonically treated with carbon tetrachloride and a mixed solvent (benzene:acetone:ethanol=7:1.5:1.5 (volume ratio)) for 20 min in sequence to remove organic matter on the surface.

[0105] Then, ultrasonic treatment was performed for 20 minutes with dilute hydrochloric acid solution (1:10) and hydrofluoric acid solution (10%) respectively to roughen and activate the capillary surface; then ultrasonic cleaning was performed with distilled water to remove residual acid until pH>6.5, and then drying was performed at 105°C.

[0106] The simulated oil was prepared according to kerosene:90# asphalt=7:3 (mass ratio), and the treated capillary was completely immersed in the simulated oil and allowed to stand at 60°C for 30 days.

[0107] Take out the capillary and wipe the outside of the tube clean to obtain an oleophilic capillary for later use.

[0108] ② Capillary self-priming test.

[0109] Prepare a 0.3% osmotic agent solution with distilled water and add a drop of red ink. Keep the solution temperature at (25(3)℃. Pour the solution to be tested into the cuvette to the top edge and place the ruler close to the back wall.

[0110] Place the three processed capillaries vertically in a cuvette, read and record the rising liquid level of the aqueous solution in the capillaries, record the liquid level when the capillaries are submerged in the liquid for 10 minutes, and take the arithmetic mean as the measurement result.

[0111] ③ Capillary self-absorption test after high temperature aging.

[0112] Prepare 200 g of 0.3% imbibition agent solution with distilled water, put it into a high-temperature aging tank, place it in a 150°C oven for aging for 3 days, take it out and cool it to room temperature, and determine the capillary self-imbibition height of the 3% aqueous solution of the imbibition agent after high-temperature aging according to method ②.

[0113] ④ Capillary self-imbibition test of high mineralization aqueous solution.

[0114] Simulated water for fracturing imbibition agent experiment: 1L volumetric flask, add 750g distilled water; add the following substances in order, 5g calcium chloride, 5g magnesium chloride, 240g sodium chloride, each time adding a reagent, shake until it is completely dissolved before adding another reagent. The total mineralization of the prepared solution is 25×10 4 mg / L, homogeneous and transparent, without precipitation, valid for 7 days.

[0115] Prepare 0.3% imbibition agent solution with simulated water, measure according to method ②, and record the self-imbibition height value.

[0116] (3) Wettability evaluation

[0117] According to the classification in standard SY / T 5153, the method of judging wettability by wetting angle is shown in Table 1.

[0118] Table 1 Contact angle method wettability judgment standard

[0119] Contact angle θ 0°≤θ<75° 75°≤θ≤105° 105°<θ≤180° Wettability Hydrophilic neutral Lipophilic

[0120] Using a quartz sheet, refer to the method in SY / T 5153 to measure the wetting contact angle of the polymer hydrolyzed solution on the quartz sheet at 30°C.

[0121] (4) Evaluation of residue rate

[0122] Seal 200 ml of a solution containing 1% effective polymer surfactant and place it in a 90°C oven for 2 hours. Weigh the filter paper and filter the solution. Put the filtered filter paper and the filter residue into an oven and dry at 100°C to constant weight. Calculate the difference before and after to obtain the residue mass M grams. The residue rate is (M / 2)×100%. If it is less than 0.1%, it is recorded as <0.1%.

[0123] Comparative Example 1

[0124] (1) Raw materials

[0125] Styrene 416g

[0126] Maleic anhydride 98g

[0127] (2) Process

[0128] The reactants used DMF as solvent, and the total amount used was the total weight of all monomers, 514 g.

[0129] Pre-mixing outside the autoclave is adopted. Pre-mixing: ① Maleic anhydride is mixed with 98g of solvent DMF of equal mass, and dissolved at room temperature (≤30°C). ② The initiator azobisisobutyronitrile is 0.1% of the total mass of the monomer, and an additional 50g of solvent DMF is added to dissolve, and dissolved at room temperature (≤30°C). Note that the temperature should not be too high to prevent accidental polymerization or decomposition of the monomer due to impurities.

[0130] First, add 416 g of DMF and styrene into the kettle, then heat it to 75°C and stir at 80 r / min.

[0131] Use a diaphragm pump to slowly add the prepared solutions ① and ② to the kettle, respectively, and control the dropping time to 90 minutes. During this period, the temperature in the kettle cannot exceed 90℃. If it exceeds 90℃, stop dropping, and continue dropping when the temperature drops below 85℃ until all the solutions are added, and keep the temperature at 75℃ to continue the reaction for 0.5h.

[0132] After the final reaction, the reactants in the kettle turned into a light yellow, uniform, stable, slightly viscous liquid. Its structural formula is as follows:

[0133]

[0134] A 0.1% concentration polymer surfactant solution was prepared with deionized water, placed at 90°C and hydrolyzed for 2 hours, and the surface tension, capillary self-absorption height and wettability of the hydrolyzate were tested.

[0135] The synthesis process of the following comparative examples is the same as that of comparative example 1-1, except that the raw material ratio is changed; the surface tension, capillary self-imbibition height, wettability and residue rate of the hydrolyzate are also tested.

[0136] Comparative Example 1-2

[0137] Styrene 521g

[0138] Maleic anhydride 98g

[0139] Comparative Examples 1-3

[0140] Styrene 625g

[0141] Maleic anhydride 98g

[0142] Example 2-1

[0143] The synthesis process of this embodiment is the same as that of comparative example 1-1, except that 68 g of tetraallyl ammonium chloride is added to solution ①; the surface tension, capillary self-imbibition height and wettability of the hydrolyzate are also tested.

[0144] Styrene 416g

[0145] Maleic anhydride 98g

[0146] Tetraallyl ammonium chloride 68g

[0147] The structure of the synthesized polymer is as follows:

[0148]

[0149] The synthesis process of the following examples is the same as that of Example 2-1, except that different types of cationic monomers and raw materials in different ratios are added to solution ①; the surface tension, capillary self-imbibition height, wettability, and residue rate of the hydrolyzate are also tested.

[0150] Example 2-2

[0151] Styrene 468g

[0152] Maleic anhydride 98g Tetraallylammonium chloride 135g

[0153] Example 2-3

[0154] Styrene 520g

[0155] Maleic anhydride 98g Tetraallylammonium chloride 271g

[0156] Example 3-1

[0157] Styrene 416g

[0158] Maleic anhydride 98g Diallylamine 97g

[0159] The structure of the synthesized polymer is as follows:

[0160]

[0161] Example 3-2

[0162] Styrene 416g

[0163] Maleic anhydride 98g Diallylamine 45g

[0164] Example 3-3

[0165] Styrene 468g

[0166] Maleic anhydride 98g Diallylamine 25g

[0167] Example 4-1

[0168] Styrene 572g

[0169] Maleic anhydride 98g

[0170] Dimethyldiallylammonium chloride 162g

[0171] The structure of the synthesized polymer is as follows:

[0172]

[0173] Example 4-2

[0174] Styrene 520g

[0175] Maleic anhydride 98g

[0176] Dimethyldiallylammonium chloride 324g Example 4-3

[0177] Styrene 520g

[0178] Maleic anhydride 98g

[0179] Dimethyldiallylammonium chloride 85g Example 5-1

[0180] Styrene 416g

[0181] Maleic anhydride 98g

[0182] The polymer structure of 579g of dodecyl dimethyl allyl ammonium chloride is as follows:

[0183]

[0184] Example 5-2

[0185] Styrene 521g

[0186] Maleic anhydride 98g

[0187] Dodecyl dimethyl allyl ammonium chloride 435g Example 5-3

[0188] Styrene 625g

[0189] Maleic anhydride 98g

[0190] Dodecyl dimethyl allyl ammonium chloride 289g Example 6-1

[0191] Styrene 416g

[0192] Maleic anhydride 98g

[0193] Tetradecyl dimethyl allyl ammonium chloride 635g The polymer structure of its synthesis is as follows:

[0194]

[0195] Example 6-2

[0196] Styrene 521g

[0197] Maleic anhydride 98g

[0198] Tetradecyl dimethyl allyl ammonium chloride 476g Example 6-3

[0199] Styrene 625g

[0200] Maleic anhydride 98g

[0201] Tetradecyl dimethyl allyl ammonium chloride 317g Example 7-1

[0202] Styrene 416g

[0203] Maleic anhydride 98g

[0204] The polymer structure of 692g of hexadecyl dimethyl allyl ammonium chloride is as follows:

[0205]

[0206] Example 7-2

[0207] Styrene 521g

[0208] Maleic anhydride 98g

[0209] Hexadecyl dimethyl allyl ammonium chloride 519 g Example 7-3

[0210] Styrene 625g

[0211] Maleic anhydride 98g

[0212] Hexadecyl dimethyl allyl ammonium chloride 346 g Example 8-1

[0213] Styrene 416g

[0214] Maleic anhydride 98g

[0215] Octadecyl dimethyl allyl ammonium chloride 748g The polymer structure of its synthesis is as follows:

[0216]

[0217] Example 8-2

[0218] Styrene 521g

[0219] Maleic anhydride 98g

[0220] Octadecyl dimethyl allyl ammonium chloride 561 g Example 8-3

[0221] Styrene 625g

[0222] Maleic anhydride 98g

[0223] Octadecyl dimethyl allyl ammonium chloride 374g

[0224] Table 2 Surface interfacial tension, capillary self-absorption height, and wettability test of 0.1% polymer hydrolyzate

[0225]

[0226] Summary: Experiments show that 0.1% polymer hydrolyzates have low surface interfacial tension, most of which are less than 30mN / m; they have good capillary self-absorption height, most of which are greater than 50mm; contact angle tests show that all test samples are less than 75°, that is, the surface becomes hydrophilic after treatment with polymer hydrolyzate.

[0227] Table 3 Residue rate test

[0228]

[0229]

[0230] In summary, the polymer in comparative example 1-1 produces a large amount of residue after hydrolysis, and the residue rate is much greater than 1%, which will block the oil and water channels of the reservoir. However, the polymers in examples 2-1, 3-1, 4-1, and 5-1 have cationic monomers introduced, and their residue rates are less than 0.1% after hydrolysis, which improves the oil displacement efficiency while avoiding blocking the oil and water channels of the reservoir.

[0231] The polymer product itself is a liquid with DMF as solvent (such as Figure 1 When the product is pumped into the fracturing fluid, DMF will dissolve in water. At this time, because the anhydride part of the polymer has not yet been hydrolyzed, the entire molecule exhibits strong hydrophobicity and will precipitate in the form of loose solid particles under stirring (as shown in Figure 2 As shown in the figure, it enters the wellbore along with the fracturing fluid, further enters the fracture system created by the fracturing, and gradually moves to the far end of the fracture network.

[0232] The fracturing operation has a large displacement (about 10-20m / min). 3 ), the precipitated solid polymer will quickly (within a few minutes) enter the formation fracture system with the fracturing fluid and migrate along the fracturing gap, avoiding premature adsorption near the wellbore, making it easier to approach the oil layer. When it reaches the distal gap, it will quickly (tens of minutes) dissolve during the soaking process (several days or weeks) (such as Figure 4 As shown in the figure), it penetrates into the oil layer and plays the role of oil displacement.

[0233] The above are only a few embodiments of the present application and do not constitute any form of limitation to the present application. Although the present application is disclosed as above with preferred embodiments, it is not intended to limit the present application. Any technician familiar with the profession, without departing from the scope of the technical solution of the present application, using the technical content disclosed above to make slight changes or modifications are equivalent to equivalent implementation cases and fall within the scope of the technical solution.

Claims

1. A hydrolyzable polymer surfactant for fracturing, characterized in that: The polymer surfactant has the structure shown in Formula I: Among them, R is selected from One of; R1 is selected from a C1-C3 hydrocarbon group or R2 is selected from a C1-C3 hydrocarbon group or R3 is selected from C 12 -C 18 Hydrocarbon or R4 is selected from a:b:c=4-6:1:0-2; c is not 0.

2. The polymer surfactant according to claim 1, characterized in that R1, R2, R3, and R4 are independently selected from C1-C3 alkyl, C 12 -C 18 The alkyl group Preferably, R1, R2, R3, and R4 are independently selected from methyl, ethyl, propyl, (CH2) 11 CH3, (CH2) 13 CH3, (CH2) 15 CH3, (CH2) 17 CH3, Preferably, the polymer surfactant has the structure shown below: And / or, when R is When the anion is selected from one of chloride ion, bromide ion and fluoride ion.

3. The polymer surfactant according to claim 1 or 2, characterized in that a:b:c=4-6:1:0.5-2.

4. The polymer surfactant according to claim 1 or 2, characterized in that The interfacial tension of the polymer surfactant is less than 1 mN / m; and / or, the surface tension of the polymer surfactant is less than 28 mN / m; And / or, the wetting contact angle of the hydrolyzate of the polymer surfactant is less than 75°.

5. A method for preparing a polymer surfactant, characterized in that ,, including the following steps: The polymer surfactant is obtained by reacting a mixture containing styrene, maleic anhydride, a cationic monomer, an initiator and a solvent.

6. The preparation method according to claim 5, characterized in that: The cationic monomer is an amine / ammonium hydrophilic monomer; Preferably, the cationic monomer is selected from at least one of tetraallylammonium chloride, diallylamine, dimethyldiallylammonium chloride, dodecyldimethylallylammonium chloride, tetradecyldimethylallylammonium chloride, hexadecyldimethylallylammonium chloride and octadecyldimethylallylammonium chloride; And / or, the initiator is at least one selected from azobisisobutyronitrile, benzoyl peroxide, and di-tert-butyl peroxide; And / or, the solvent is selected from at least one of N,N-dimethylformamide, dimethyl sulfoxide and acetone.

7. The preparation method according to claim 5 or 6, characterized in that: The molar ratio of the styrene, the maleic anhydride and the cationic monomer is 4-6:1:0-2; the molar number of the cationic monomer is not 0; Preferably, the molar ratio of the styrene, the maleic anhydride, and the cationic monomer is 4-6:1:0.5-2; And / or, the amount of the initiator used is 0.1%-0.5% of the total mass of all monomer raw materials; And / or, the reaction conditions are as follows: Temperature is 75-85℃; The time is 0.5-1.5h.

8. The preparation method according to claim 5, characterized in that: The following steps are involved: S1, obtaining a solution A containing maleic anhydride and a cationic monomer; S2, obtaining a solution B containing an initiator; S3, obtaining a solution C containing styrene; S4. Add the solution A and the solution B into the solution C, control the dropping time to be 90-180 min, and react at 75-85° C. for 0.5-1.5 h to obtain the polymer surfactant.

9. An integrated fracturing fluid system for reducing resistance and flooding oil, characterized in that: Including polymer surfactants, solvents; The polymer surfactant is selected from the polymer surfactant described in any one of claims 1 to 4 or the polymer surfactant obtained by the preparation method described in any one of claims 5 to 8; The solvent is selected from at least one of N,N-dimethylformamide, dimethyl sulfoxide and acetone.

10. Use of the polymer surfactant according to any one of claims 1 to 4 or the polymer surfactant obtained by the preparation method according to any one of claims 5 to 8 in a resistance reduction and oil displacement integrated fracturing fluid system; And / or, the polymer surfactant is mixed with the solvent to form a liquid, which is then pumped into the fracturing fluid and finally the well is sealed.

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