Active nano particles, fracturing oil displacement agent and application of active nano particles and fracturing oil displacement agent

Abstract

The invention provides active nanoparticles, a fracturing oil-displacing agent and application of the active nanoparticles and the fracturing oil-displacing agent, and belongs to the technical field of oil reservoir exploitation. The active nanoparticles are obtained by reacting a first silane coupling agent containing sulfydryl with hydrogen peroxide and then reacting with a second silane coupling agent containing phenyl, propyl or octyl. The fracturing oil displacement agent comprises active nanoparticles, an anionic or anionic-nonionic surfactant and water. The active nanoparticles provided by the invention are small in particle size, and have good dispersing performance, amphipathy, interfacial activity and capability of reducing oil-water interfacial tension; the fracturing oil-displacing agent constructed based on the active nanoparticles has the advantages of high temperature and high salt resistance, wetting reversal, strong imbibition and oil discharge capability and good drag reduction performance, and can reduce injection pressure, improve sweep efficiency, improve pressure-driven oil displacement effect and improve recovery efficiency.

Description

Technical Field

[0001] The present invention belongs to the technical field of reservoir exploitation, and particularly relates to an active nanoparticle, a fracturing oil displacement agent and their applications. Background Art

[0002] In the field of reservoir exploitation, low-permeability reservoirs are characterized by dense reservoirs, fine pore throats, large seepage resistance, strong heterogeneity, etc. During the process of water injection development, affected by reservoir physical properties, water injection quality, etc., low-permeability reservoirs face the severe problems of "difficult to inject and produce", with rapid decline of formation energy, inability to establish effective displacement between oil wells and water wells, and rapid decline of production capacity or even shut-down. In view of this problem, oilfield experts have proposed the pressure-driven water injection technology. Pressure-driven water injection is a measure and means to improve water injection efficiency. By means of large-displacement and high-pressure pump injection equipment, with a pump injection pressure higher than the rock fracture pressure, a large amount of water is pumped in a short period, and then pressure dissipation methods such as well shut-in and soaking are adopted to provide energy for the corresponding oil wells in the well group and improve the development effect of the well group. However, the pressure-driven technology has high requirements for process equipment, and the use of water alone as the pressure-driven fluid has poor exploitation effect.

[0003] At present, chemical reagents such as polymers, alkaline water, surfactants and other oil displacement agents are often injected to improve the recovery rate of oil reservoirs. However, conventional chemical agents have their own advantages and disadvantages and are difficult to meet the pressure-driven requirements of various low-permeability reservoirs. For example, polymers and alkaline water have poor applicability in the development of ultra-low to extra-low permeability reservoirs. The former has large molecules and is difficult to enter tiny pores, while the latter is easy to change the formation pH value, causing alkali sensitivity and precipitation scaling, etc.; although surfactants have small molecules, good oil displacement effect and certain ability to reduce pressure and increase injection, they are more easily concerned in the development of low-permeability reservoirs, but most surfactant systems have poor high-temperature and high-salt resistance, or only have good performance in one aspect, and it is difficult to meet the performance requirements of high-temperature and high-salt resistance at the same time.

[0004] Nanoparticles have characteristics such as nano-effects and structural separation pressure, which are beneficial to reducing interfacial tension, changing wettability, stripping oil films, etc. Nanoparticles can change the wettability of the rock surface, making the rock surface change from oleophilic to hydrophilic or neutral, thereby reducing the adhesion of crude oil in the rock pores, making it easier for the crude oil to be stripped from the rock surface and displaced. When nanofluid flows in the reservoir, it has strong adsorption ability, is easy to adsorb on the interfaces of oil, water and solid phases, can regulate the interfacial properties, has strong imbibition and oil stripping ability, and has a certain plugging and regulation ability. Therefore, nanoparticles have good application prospects in reservoir exploitation. However, conventional nanoparticles have large particle sizes, are easy to agglomerate, have poor interfacial activity, general oil displacement effect and are easy to block the reservoir.

[0005] Therefore, it is necessary to develop an active nanoparticle with small particle size, easy dispersion, high interfacial activity, high temperature and high salt resistance, as well as a corresponding pressure-driven fluid to promote the exploitation of low-permeability reservoirs. Summary of the Invention

[0006] Aiming at the deficiencies of the existing technology, the purpose of the present invention is to provide an active nanoparticle, a fracturing oil displacement agent and its application. The active nanoparticle has a small particle size and has good dispersion performance, amphiphilicity, interfacial activity and the ability to reduce the oil-water interfacial tension; the fracturing oil displacement agent based on the active nanoparticle has the advantages of high temperature and high salt resistance, wettability reversal, strong imbibition oil displacement ability and good drag reduction performance, can reduce the injection pressure, improve the sweep efficiency, improve the fracturing oil displacement effect and increase the oil recovery rate.

[0007] To achieve this purpose, the present invention adopts the following technical solutions:

[0008] In the first aspect, the present invention provides a preparation method of an active nanoparticle, and the preparation method includes the following steps:

[0009] (1) The first silane coupling agent reacts with hydrogen peroxide in water under anaerobic, acidic and stirring conditions to obtain an active nanoparticle precursor solution;

[0010] (2) The active nanoparticle precursor solution is mixed with the second silane coupling agent and reacts under stirring conditions to generate active nanoparticles;

[0011] Wherein, the first silane coupling agent is (3-mercaptopropyl)trimethoxysilane and / or (3-mercaptopropyl)triethoxysilane; the second silane coupling agent is selected from one or more of phenyltrimethoxysilane, phenyltriethoxysilane, propyltrimethoxysilane, propyltriethoxysilane, octyltrimethoxysilane and octyltriethoxysilane;

[0012] The mass ratio of the first silane coupling agent to the second silane coupling agent is (1-3):(0.1-0.3); for example, it can be 1:0.3, 1:0.2, 1:0.1, 2:0.3, 2:0.1, 3:0.2 or 3:0.1, etc.

[0013] In the present invention, the first silane coupling agent contains a mercapto group, which can be oxidized by hydrogen peroxide to a sulfonic acid group, and then undergoes a hydrolysis condensation reaction with the second silane coupling agent containing phenyl, propyl or octyl, thereby forming an active nanoparticle.

[0014] The sulfonic acid group modified on the surface of the nanoparticle provided by the present invention improves the hydrophilicity of the nanoparticle and its dissolution and dispersion effect in water; the grafted phenyl, propyl or octyl improves the lipophilicity of the nanoparticle, so that the nanoparticle has good amphiphilic ability, and improves its interfacial activity and the ability to reduce the oil-water interfacial tension.

[0015] The fracturing oil displacement agent provided by the present invention is prepared by compounding active nanoparticles with anionic or anionic-nonionic surfactants. The surfactant will gradually adsorb on the surface of the nanoparticles, increasing the electrostatic repulsion and steric hindrance between the nanoparticles, reducing the compression effect of high salinity on the diffuse double layer, and reducing the probability of collision and aggregation caused by the intensified thermal motion of the particles at high temperature. As a result, the high temperature and high salt resistance of the fracturing oil displacement agent can be improved. At the same time, the active nanoparticles and the surfactant can improve the drag reduction performance, imbibition oil displacement capacity and oil film stripping performance of the fracturing oil displacement agent in the core matrix by regulating the oil-water interface and solid-liquid interface, and the wedge-shaped structure separation pressure generated by the nanoparticles. During the water injection pressure displacement process, the nanoparticles and the surfactant can enter the reservoir to change the wettability of the rock wall surface, reduce the adhesion force of crude oil in the rock pores, reduce the oil-water interfacial tension, reduce the difficulty of crude oil stripping, expand the swept volume, improve the oil displacement effect of pressure displacement, and increase the recovery rate.

[0016] In some embodiments of the present invention, the second silane coupling agent is phenyltrimethoxysilane and / or phenyltriethoxysilane, and the D 50 particle size of the active nanoparticles is 10 - 20 nm.

[0017] In some embodiments of the present invention, the second silane coupling agent is propyltrimethoxysilane and / or propyltriethoxysilane, and the D 50 particle size of the active nanoparticles is 30 - 60 nm.

[0018] In some embodiments of the present invention, the second silane coupling agent is octyltrimethoxysilane and / or octyltriethoxysilane, and the D 50 particle size of the active nanoparticles is 80 - 300 nm.

[0019] In the present invention, when the second silane coupling agent is phenyltrimethoxysilane and / or phenyltriethoxysilane, the obtained active nanoparticles have a smaller particle size, higher interfacial activity, and stronger ability to reduce the oil-water interfacial tension. Therefore, the second silane coupling agent is preferably phenyltrimethoxysilane and / or phenyltriethoxysilane.

[0020] In some embodiments of the present invention, the mass ratio of water, hydrogen peroxide, the first silane coupling agent to the second silane coupling agent is (5.6-9):(2.4-3):(1-3):(0.1-0.3); for example, it can be 5.6:2.4:1:0.1, 6:2.6:1.5:0.1, 7:2.8:2:0.2, 8:3:2.5:0.3, 9:2.4:3:0.1, 5.6:3:1:0.3, 6:2.5:2:0.2, 6.5:2.6:1.2:0.15, 7:2.4:2.2:0.25, 8:3:1.8:0.2, 9:2.7:2.6:0.18 or 9:2.4:3:0.1, etc.

[0021] In the present invention, controlling the raw material ratio within the above range helps to obtain active nanoparticles with small particle size and good performance. Among them, if the proportion of the first silane coupling agent is too low and the proportion of the second silane coupling agent is too high, it will cause the particle size of the active nanoparticles to be larger, the lipophilicity to be too strong, the water dispersibility to become worse, the drag reduction effect of the fracturing oil displacement agent to become worse, and the imbibition recovery rate to decrease; if the proportion of the first silane coupling agent is too high and the proportion of the second silane coupling agent is too low, it will cause the lipophilicity of the active nanoparticles to decrease, the interfacial activity to decrease, the ability to reduce the oil-water interfacial tension to decrease, the oil film stripping effect of the fracturing oil displacement agent to decrease, and the pressure-driven recovery rate to decrease. If the proportion of hydrogen peroxide is too low, the mercapto group in the first silane coupling agent cannot be completely converted into sulfonic acid group, which will cause the hydrophilicity of the active nanoparticles to decrease, the water dispersibility to weaken, the particle size to increase significantly, the ability to reduce the oil-water interfacial tension to weaken, the drag reduction effect of the fracturing oil displacement agent to decrease, the imbibition and oil drainage ability to weaken, the oil film stripping ability to weaken, and the pressure-driven recovery rate to decrease; if the proportion of hydrogen peroxide is too high, it will cause waste of synthetic raw materials, increase the production cost, and the production cost of the fracturing oil displacement agent will also increase significantly. If the proportion of water is too low, it is easy to cause the synthesized nanoparticles to agglomerate, the particle size to increase, the dispersibility to become worse, the imbibition and oil stripping ability of the fracturing oil displacement agent to decrease, and the pressure-driven recovery rate to decrease; if the proportion of water is too high, it may lead to the weakening of the oxidation performance of hydrogen peroxide, resulting in an increase in by-products of nanoparticles, generating disulfide bonds or sulfinic acid groups, unable to form the expected active nanoparticles, and at the same time, it will also cause a decrease in production efficiency.

[0022] In some embodiments of the present invention, the pH of the reaction in step (1) is 3 - 5 (for example, it can be 3, 3.2, 3.5, 3.8, 4, 4.2, 4.5, 4.8 or 5, etc.), the temperature is 20 - 30 °C (for example, it can be 20 °C, 22 °C, 23 °C, 25 °C, 26 °C, 28 °C or 30 °C, etc.), the reaction time is 2 - 12 h (for example, it can be 2 h, 4 h, 5 h, 6 h, 8 h, 10 h or 12 h, etc.), and the stirring speed is above 300 rpm (for example, it can be 300 rpm, 400 rpm, 500 rpm, 600 rpm, 800 rpm, 1000 rpm, 1200 rpm or 1500 rpm, etc.).

[0023] In some embodiments of the present invention, the temperature of the reaction in step (2) is 20 - 30 °C (for example, it can be 20 °C, 22 °C, 23 °C, 25 °C, 26 °C, 28 °C or 30 °C, etc.), the reaction time is 2 - 12 h (for example, it can be 2 h, 4 h, 5 h, 6 h, 8 h, 10 h or 12 h, etc.), and the stirring speed is above 300 rpm (for example, it can be 300 rpm, 400 rpm, 500 rpm, 600 rpm, 800 rpm, 1000 rpm, 1200 rpm or 1500 rpm, etc.).

[0024] In the present invention, controlling the reaction conditions within the above ranges helps to obtain active nanoparticles with small particle sizes and good performance. If the pH value in step (1) is too high, it will lead to a decrease in the ability of the active nanoparticles to reduce the oil - water interfacial tension, a reduction in the drag - reducing performance of the fracturing flooding agent, a weakening of the imbibition and oil - displacement ability, and a deterioration of the oil - displacement effect. If the reaction temperatures in steps (1) and (2) are too high, it will cause a significant increase in the particle size of the active nanoparticles, a deterioration of the dispersibility, a poor drag - reducing effect of the fracturing flooding agent, and a weakening of the imbibition and oil - displacement ability.

[0025] In a second aspect, the present invention provides an active nanoparticle prepared by the preparation method described in the first aspect.

[0026] In a third aspect, the present invention provides a fracturing flooding agent, which comprises the active nanoparticle described in the second aspect, an anionic or anionic - nonionic surfactant, and water.

[0027] In some embodiments of the present invention, the anionic or anionic - nonionic surfactant is a sulfonate - type anionic - nonionic surfactant.

[0028] In some embodiments of the present invention, the sulfonate - type anionic or anionic - nonionic surfactant is sodium fatty acid methyl ester polyether sulfonate.

[0029] In the present invention, the combination of anionic or anionic-nonionic surfactants of sulfonates with active nanoparticles helps to increase the electrostatic repulsion and steric hindrance between the nanoparticles, improve their dispersibility, and enhance the interfacial activity and imbibition and oil stripping effects of the fracturing oil displacement agent through synergistic effects. Among them, when using sodium fatty acid methyl ester polyether sulfonate, the effect is the best.

[0030] In some embodiments of the present invention, the mass ratio of the active nanoparticles to the surfactant is (0.8 - 1.2):(0.6 - 1); for example, it can be 0.8:1, 1:1, 1.2:1, 1:0.8, 0.8:0.6, 1:0.6 or 1.2:0.6, etc.

[0031] In the present invention, controlling the mass ratio of the active nanoparticles to the surfactant within the above range helps to give full play to the synergistic effect. If the mass ratio of the active nanoparticles to the surfactant is too small, the surfactant tends to form its own micelles, reducing the synergistic effect and weakening the ability of the fracturing oil displacement agent to reduce the oil-water interfacial tension; if the mass ratio of the active nanoparticles to the surfactant is too large, it is not conducive to fully exerting the synergistic effect of the surfactant, and the dispersion effect of the nanoparticles becomes poor.

[0032] In some embodiments of the present invention, in the fracturing oil displacement agent, the total content of the active nanoparticles and the surfactant is 0.1 - 0.3 wt%; for example, it can be 0.1 wt%, 0.12 wt%, 0.15 wt%, 0.18 wt%, 0.2 wt%, 0.22 wt%, 0.25 wt%, 0.28 wt% or 0.3 wt%, etc.

[0033] Fourthly, the present invention provides an application of the fracturing oil displacement agent as described in the third aspect in the exploitation of low-permeability oil reservoirs.

[0034] In some embodiments of the present invention, the steps of exploiting the low-permeability oil reservoir include: through an injection well, injecting a displacement fluid into the formation at a displacement rate greater than the formation absorption capacity, and after opening the main formation fracture, injecting the fracturing oil displacement agent as described in the third aspect.

[0035] In the present invention, no special limitation is imposed on the type of the displacement fluid, and it can be a conventional displacement fluid in the art.

[0036] Compared with the prior art, the present invention has the following beneficial effects:

[0037] The nanoparticles provided by the present invention have a small particle size and have good dispersion performance, amphiphilicity, interfacial activity and the ability to reduce the oil-water interfacial tension.

[0038] The fracturing oil displacement agent provided by the present invention has the advantages of high temperature and high salt resistance, wetting reversal, strong imbibition oil displacement ability, and good drag reduction performance. It can reduce the injection pressure, improve the sweep efficiency, enhance the oil displacement effect of pressure drive, and increase the recovery rate. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] Figure 1 Particle size distribution diagram of the active nanoparticles provided for Example 1;

[0040] Figure 2 Oil-water interfacial tension curve diagram of the fracturing oil displacement agent provided for Example 1 at different concentrations;

[0041] Figure 3 Oil film stripping effect diagram of the fracturing oil displacement agent provided for Example 1;

[0042] Figure 4 Imbibition recovery rate curve diagram of the fracturing oil displacement agent provided for Example 1 at different concentrations;

[0043] Figure 5 Wetting reversal effect diagram of the fracturing oil displacement agent provided for Example 1. DETAILED DESCRIPTION OF THE INVENTION

[0044] The technical solution of the present invention will be further described below in conjunction with the drawings and through specific embodiments. Those skilled in the art should understand that the specific embodiments are only for helping to understand the present invention and should not be regarded as specific limitations to the present invention.

[0045] Example 1

[0046] This example provides an active nanoparticle and a fracturing oil displacement agent, and their preparation methods are as follows:

[0047] (1) Under normal temperature conditions, add 1 g of water and 9 g of hydrogen peroxide solution with a concentration of 30 wt% to the reaction flask, adjust the pH = 5, and introduce nitrogen for 10 min to remove the oxygen in the solution and the flask;

[0048] (2) Add 2 g of (3-mercaptopropyl)triethoxysilane to the solution obtained in step (1), and stir and react at 25 °C and a rotation speed of 800 rpm for 5 h to obtain an active nanoparticle precursor solution;

[0049] (3) Maintain the reaction temperature and stirring rate, add 0.2 g of phenyltrimethoxysilane to the active nanoparticle precursor solution, and continue to react for 6 h to obtain an active nanoparticle solution;

[0050] (4) Mix the active nanoparticles and fatty acid methyl ester polyether sulfonate (Shandong Yousuo Chemical Technology Co., Ltd.) evenly with water. Among them, the mass ratio of the active nanoparticles to the fatty acid methyl ester polyether sulfonate is 1.0:0.8, and the total content of the two is 0.2 wt%, to obtain a fracturing oil displacement agent.

[0051] Example 2

[0052] This example provides an active nanoparticle and a fracturing oil displacement agent, and its preparation method is as follows:

[0053] (1) Under normal temperature conditions, add 10 g of hydrogen peroxide solution with a concentration of 30 wt% to the reaction flask, adjust the pH = 3, and introduce nitrogen for 10 min to remove the oxygen in the solution and the flask;

[0054] (2) Add 1 g of (3-mercaptopropyl)triethoxysilane to the solution obtained in step (1), and stir and react at 30 °C and a rotation speed of 800 rpm for 12 h to obtain an active nanoparticle precursor solution;

[0055] (3) Maintain the reaction temperature and stirring rate, add 0.3 g of phenyltrimethoxysilane to the active nanoparticle precursor solution, and continue to react for 2 h to obtain an active nanoparticle solution;

[0056] (4) Mix the active nanoparticles and fatty acid methyl ester polyether sulfonate (Shandong Yousuo Chemical Technology Co., Ltd.) evenly with water. Among them, the mass ratio of the active nanoparticles to the fatty acid methyl ester polyether sulfonate is 0.8:1.0, and the total content of the two is 0.2 wt%, to obtain a fracturing oil displacement agent.

[0057] Example 3

[0058] This example provides an active nanoparticle and a fracturing oil displacement agent, and its preparation method is as follows:

[0059] (1) Under normal temperature conditions, add 2 g of water and 8 g of hydrogen peroxide solution with a concentration of 30 wt% to the reaction flask, adjust the pH = 4, and introduce nitrogen for 10 min to remove the oxygen in the solution and the flask;

[0060] (2) Add 3 g of (3-mercaptopropyl)triethoxysilane to the solution obtained in step (1), and stir and react at 20 °C and a rotation speed of 800 rpm for 2 h to obtain an active nanoparticle precursor solution;

[0061] (3) Maintain the reaction temperature and stirring rate, add 0.1 g of phenyltrimethoxysilane to the active nanoparticle precursor solution, and continue to react for 12 h to obtain an active nanoparticle solution;

[0062] (4) Mix the active nanoparticles and fatty acid methyl ester polyether sulfonate (Shandong Yousuo Chemical Technology Co., Ltd.) evenly with water. Among them, the mass ratio of the active nanoparticles to the fatty acid methyl ester polyether sulfonate is 1.2:0.6, and their total content is 0.2 wt%, to obtain a fracturing oil displacement agent.

[0063] Example 4

[0064] This example provides an active nanoparticle and a fracturing oil displacement agent. The difference from Example 1 is only that phenyltrimethoxysilane is replaced with the same mass of octyltrimethoxysilane.

[0065] Example 5

[0066] This example provides an active nanoparticle and a fracturing oil displacement agent. The difference from Example 1 is only that phenyltrimethoxysilane is replaced with the same mass of propyltrimethoxysilane.

[0067] Example 6

[0068] This example provides an active nanoparticle and a fracturing oil displacement agent. The difference from Example 1 is only that the fatty acid methyl ester polyether sulfonate is replaced with the same mass of α-olefin sulfonate (Shandong Yousuo Chemical Technology Co., Ltd.).

[0069] Comparative Example 1

[0070] Use simulated water (an aqueous solution of sodium chloride at 3000 mg / L) as the fracturing oil displacement agent.

[0071] Comparative Example 2

[0072] Use an aqueous solution of 0.2 wt% petroleum sulfonate (Shandong Yousuo Chemical Technology Co., Ltd.) as the fracturing oil displacement agent.

[0073] Comparative Example 3

[0074] Use an aqueous solution of 0.2 wt% SC101 (Shandong Yinfeng New Nanomaterials Co., Ltd.) as the fracturing oil displacement agent.

[0075] Comparative Example 4

[0076] This comparative example provides an active nanoparticle and a fracturing oil displacement agent. The difference from Example 2 is only that 0.5 g of phenyltrimethoxysilane is added in step (3).

[0077] Comparative Example 5

[0078] This comparative example provides an active nanoparticle and a fracturing oil displacement agent. The difference from Example 3 is only that 0.06 g of phenyltrimethoxysilane is added in step (3).

[0079] Comparative Example 6

[0080] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that the pH in steps (2) and (3) is 7.

[0081] Comparative Example 7

[0082] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that the reaction temperature in steps (2) and (3) is 40 °C.

[0083] Comparative Example 8

[0084] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that the mass ratio of the active nanoparticle to fatty acid methyl ester polyether sulfonate is 1:1.5 (the total content of the two in the fracturing oil displacement agent remains unchanged).

[0085] Comparative Example 9

[0086] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that the mass ratio of the active nanoparticle to fatty acid methyl ester polyether sulfonate is 3:1 (the total content of the two in the fracturing oil displacement agent remains unchanged).

[0087] Comparative Example 10

[0088] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that fatty acid methyl ester polyether sulfonate is replaced by phenol ether carboxylate (APEC-6Na, Zibo Yonghong New Materials Co., Ltd.).

[0089] Comparative Example 11

[0090] This comparative example provides an active nanoparticle and a fracturing oil displacement agent, which is only different from Example 1 in that the preparation method of the active nanoparticle is as follows: Weigh phenyltriethoxysilane (14.4 g) and dissolve it in 180 mL of ethanol, add 0.2 mL of tetramethylammonium hydroxide and 3 mL of deionized water, and stir and react at 80 °C; after 2 h, add (3-mercaptopropyl)triethoxysilane (14.28 g) to the reaction system and continue to react for 24 h; then add 20 mL of a 30 wt% hydrogen peroxide solution to the reaction system and react for 24 h. After the reaction is completed, adjust the pH to neutral with NaOH, filter and dry the product to obtain a white powder, which is the active nanoparticle.

[0091] Performance Test

[0092] The performance of the active nanoparticles and fracturing oil displacement agents provided in the above examples and comparative examples was tested, and the test methods are as follows:

[0093] 1. Particle size: Use a multi-angle particle size and high-sensitivity Zeta potential analyzer (Brookhaven Instruments Corporation, USA) to measure the particle sizes of the active nanoparticles at room temperature and after aging at 130°C for 7 days respectively.

[0094] 2. Oil-water interfacial tension: Use a rotating drop interfacial tensiometer (Beijing Hake) to measure the oil-water interfacial tension. The rotation speed for measurement is 6000 r / min, and the experimental temperature is 80°C. Note: Use a sodium chloride aqueous solution with a salinity of 50000 mg / L to replace water, and re-prepare the fracturing oil displacement agent for testing.

[0095] 3. Oil film stripping efficiency: Drop the crude oil from the Shengli Oilfield site evenly on a glass plate and place it in an oven at 80°C for one day of aging. Then, immerse the glass plates with the paved oil films in the fracturing oil displacement agents provided in the above examples and comparative examples at 80°C respectively, observe the oil film stripping situation, use a high-definition camera to record the experimental results of the oil film stripping at different times until the oil film stripping state is stable, and use Image J to calculate the oil film area. The oil film stripping efficiency = (S - S t ) / S × 100%;

[0096] where S is the initial area of the oil film, and S t is the area of the oil film when the stripping state is stable.

[0097] 4. Drag reduction rate: Conduct a core displacement experiment at an injection rate of 0.3 mL / min. First, perform a simulated water drive and record the injection pressure p1 after pressure balance. Then, inject 1 PV of the fracturing oil displacement agents provided in the above examples and comparative examples respectively, close the outlet end, and after aging and adsorption for 12 h, continue to inject simulated water and record the injection pressure p2 when the pressure is stable. Calculate its matrix drag reduction rate according to the following formula;

[0098]

[0099] 5. Core imbibition oil production effect: Use a core evacuation, pressurization, and saturation experimental device to pressurize the core to 20 MPa to saturate it with simulated oil (the simulated oil is prepared by mixing Shengli Oilfield crude oil and kerosene at a mass ratio of 2:1). Immerse the cores saturated with oil (calculate the saturated oil mass by measuring the core mass before and after saturation) in the fracturing oil displacement agents provided in the above examples and comparative examples respectively, conduct an imbibition oil drainage experiment, record the oil production mass, and calculate the imbibition recovery rate based on the oil production volume and the saturated oil mass to evaluate the imbibition oil drainage ability.

[0100] 6. Contact angle test: Immerse the glass slide in a mixture of liquid paraffin and simulated oil (the simulated oil is prepared by mixing Shengli Oilfield crude oil and kerosene in a mass ratio of 2:1) with a mass ratio of 1:1, and place it in an oven at 80 °C for 3 days to obtain an oil-wet glass slide. Immerse the oil-wet glass slide in the fracturing flooding agent solutions provided in the above examples and comparative examples at 80 °C for 48 h, and use a contact angle measuring instrument to measure the oil droplet contact angle of the oil-wet glass slide before and after treatment. Compare the changes in the oil droplet contact angle of the oil-wet glass slide before and after treatment, and analyze the effect of the fracturing flooding agent on changing wettability.

[0101] 7. Pressure-driven oil recovery rate: Using a core displacement device, first carry out simulated water (salinity of 10,000 mg / L) flooding until no more oil is produced. Calculate the primary simulated water flooding recovery rate R1 according to the volume of crude oil discharged from the core. Then, inject 1 PV of the fracturing flooding agent provided in the above examples and comparative examples respectively, close the water outlet end, age for 12 h, and then continue to carry out simulated water flooding until no more oil is produced. Record the secondary simulated water flooding recovery rate R2, and calculate the recovery rate increment = R2 - R1. The experimental temperature is 80 °C, the salinity is 10,000 mg / L, and the displacement rate is 0.1 mL / min (recovery rate calculation method: Record the core mass M1 and M2 before and after saturating the core, M2 - M1 is the mass of saturated crude oil. Measure the volume of displaced crude oil V1 after simulated water flooding, and calculate the mass of displaced crude oil M3 through the density of crude oil. Then R1 = M3 / (M2 - M1), and calculate the secondary simulated water flooding recovery rate R2 using the same method).

[0102] Among them, D 50 The test results of particle size and oil-water interfacial tension are shown in Table 1. The particle size distribution of the active nanoparticles provided in Example 1 is as Figure 1 shown, and the oil-water interfacial tension curve diagram of the fracturing flooding agent provided in Example 1 at different concentrations is as Figure 2 shown.

[0103] The test results of oil film stripping efficiency, drag reduction rate, and imbibition recovery rate are shown in Table 2. The oil film stripping effect of the fracturing flooding agent provided in Example 1 is as Figure 3 shown, and the imbibition recovery rate curve diagram of the fracturing flooding agent provided in Example 1 at different concentrations is as Figure 4 shown.

[0104] The contact angle test results are shown in Table 3. The wettability reversal effect of the fracturing flooding agent provided in Example 1 is as Figure 5 shown.

[0105] The test results of pressure-driven oil recovery rate are shown in Table 4.

[0106] Table 1

[0107]

[0108]

[0109] Table 2

[0110] Group Oil film stripping efficiency (%) Drag reduction rate (%) Imbibition recovery rate (%) Example 1 92.6 19.1 53.1 Example 2 90.3 17.6 50.7 Example 3 90.8 18.1 51.5 Example 4 86.4 13.0 46.3 Example 5 89.3 15.7 49.1 Example 6 90.3 18.3 52.1 Comparative Example 1 29.5 / 28.1 Comparative Example 2 82.1 13.9 44.9 Comparative Example 3 61.3 10.3 31.3 Comparative Example 4 88.4 12.9 47.3 Comparative Example 5 90.1 15.9 50.3 Comparative Example 6 87.3 16.2 43.1 Comparative Example 7 86.2 13.8 46.9 Comparative Example 8 89.7 16.7 48.7 Comparative Example 9 90.1 16.3 50.1 Comparative Example 10 87.9 15.3 46.6 Comparative Example 11 88.1 14.9 47.2

[0111] Table 3

[0112] Group Contact angle before treatment (°) Contact angle after treatment (°) Change in contact angle (°) Example 1 29.3 140.7 111.4 Example 2 26.6 134.5 107.9 Example 3 31.3 137.9 106.6 Example 4 30.5 131.3 100.8 Example 5 31.5 138.7 107.2 Example 6 30.8 137.1 106.3 Comparative Example 1 28.5 41.7 13.2 Comparative Example 2 31.0 130.7 99.7 Comparative Example 3 29.5 128.3 98.8 Comparative Example 4 29.7 112.3 82.6 Comparative Example 5 27.2 124.7 97.5 Comparative Example 6 31.4 131 99.6 Comparative Example 7 30.5 127.9 97.4 Comparative Example 8 28.6 130.2 101.6 Comparative Example 9 29.4 127.9 98.5 Comparative Example 10 30.8 130.4 99.6 Comparative Example 11 32.3 131.8 99.5

[0113] Table 4

[0114]

[0115]

[0116] As can be seen from the above experimental results, the active nanoparticles provided in Examples 1-3 of the present invention have a D 50 particle size of 10-20 nm, and the D 50 particle size change after aging at 130°C for 7 days is 2-5 nm. The oil-water interfacial tension of the fracturing oil displacement agent at a high salinity of 50,000 mg / L is 0.83-1.17 mN / m, and it has good high temperature and high salt resistance, oil film stripping ability, drag reduction performance, imbibition and oil drainage ability, wettability alteration ability, and oil displacement ability. Moreover, the above performances are significantly superior to those of the simulated water, surfactant solution, and SC101 solution in Comparative Examples 1-3.

[0117] Among them, compared with Example 1, in Comparative Example 4, the mass ratio of phenyltrimethoxysilane to (3-mercaptopropyl)triethoxysilane is relatively large, resulting in larger particle size, poorer dispersibility, reduced interfacial activity of the obtained active nanoparticles, and weakened drag reduction, imbibition, and oil stripping abilities of the fracturing oil displacement agent, and reduced oil displacement efficiency.

[0118] Compared with Example 1, in Comparative Example 5, the mass ratio of phenyltrimethoxysilane to (3-mercaptopropyl)triethoxysilane is relatively small, resulting in poor lipophilicity and low interfacial activity of the obtained active nanoparticles, an increase in the interfacial tension of the fracturing oil displacement agent, and weakened oil displacement effect.

[0119] Compared with Example 1, in Comparative Example 6, the pH during the reaction is relatively high, resulting in a decrease in the ability of the obtained active nanoparticles to reduce the oil-water interfacial tension, a larger oil-water interfacial tension of the fracturing oil displacement agent, and weakened oil displacement effect.

[0120] Compared with Example 1, in Comparative Example 7, the reaction temperature is relatively high, resulting in larger particle size of the obtained active nanoparticles, affecting the interfacial regulation and imbibition effects, and weakened imbibition, oil stripping, etc. abilities of the fracturing oil displacement agent.

[0121] Compared with Example 1, the mass of active nanoparticles and sodium fatty acid methyl ester polyether sulfonate in Comparative Example 8 is relatively small, and the mass of active nanoparticles and sodium fatty acid methyl ester polyether sulfonate in Comparative Example 9 is relatively large, both of which lead to an unbalanced ratio between active nanoparticles and sodium fatty acid methyl ester polyether sulfonate, affecting the synergistic effect of the two, thereby resulting in a large oil-water interfacial tension of the obtained fracturing oil displacement agent, and weakened capabilities such as wetting reversal, imbibition, and oil displacement.

[0122] Compared with Example 1, Comparative Example 10 uses sodium phenol ether carboxylate instead of sodium fatty acid methyl ester polyether sulfonate. The surfactant has a poor coordination effect with the active nanoparticles, resulting in a weakened ability of the obtained fracturing oil displacement agent to reduce interfacial tension, and poor effects of imbibition, oil stripping, and oil displacement.

[0123] Compared with Example 1, the active nanoparticles prepared in Comparative Example 11 have a larger particle size, which affects the compounding effect with sodium fatty acid methyl ester polyether sulfonate, and the obtained fracturing oil displacement agent has weakened effects such as reducing interfacial tension, imbibition, oil stripping, and oil displacement.

[0124] The above description is only a specific embodiment of the present disclosure, so that those skilled in the art can understand or implement the present disclosure. Various modifications to these embodiments will be apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of the present disclosure. Therefore, the present disclosure will not be limited to the embodiments described herein, but will conform to the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A method for preparing active nanoparticles, characterized in that, The preparation method comprises the following steps: (1) A first silane coupling agent reacts with hydrogen peroxide in water under anaerobic, acidic, and stirring conditions to obtain an active nanoparticle precursor solution; (2) The active nanoparticle precursor solution is mixed with a second silane coupling agent and reacts under stirring conditions to generate active nanoparticles; Wherein, the first silane coupling agent is (3-mercaptopropyl)trimethoxysilane and / or (3-mercaptopropyl)triethoxysilane; the second silane coupling agent is selected from one or more of phenyltrimethoxysilane, phenyltriethoxysilane, propyltrimethoxysilane, propyltriethoxysilane, octyltrimethoxysilane, and octyltriethoxysilane; The mass ratio of the first silane coupling agent to the second silane coupling agent is (1 - 3):(0.1 - 0.3).

2. The preparation method according to claim 1, wherein The second silane coupling agent is phenyltrimethoxysilane and / or phenyltriethoxysilane, and the D 50 particle size of the active nanoparticles is 10-20 nm; Or, the second silane coupling agent is propyltrimethoxysilane and / or propyltriethoxysilane, and the D 50 particle size of the active nanoparticles is 30 - 60 nm; Or, the second silane coupling agent is octyltrimethoxysilane and / or octyltriethoxysilane, and the D of the active nanoparticles 50 particle size is 80 - 300 nm.

3. The preparation method according to claim 1 or 2, characterized in that, The mass ratio of water, hydrogen peroxide, the first silane coupling agent, and the second silane coupling agent is (5.6 - 9):(2.4 - 3):(1 - 3):(0.1 - 0.3).

4. The preparation method according to any one of claims 1-3, characterized in that, In step (1), the pH of the reaction is 3 - 5, the temperature is 20 - 30 °C, the reaction time is 2 - 12 h, and the stirring speed is above 300 rpm; And / or, in step (2), the temperature of the reaction is 20 - 30 °C, the reaction time is 2 - 12 h, and the stirring speed is above 300 rpm.

5. An active nanoparticle, characterized in that, Prepared by the preparation method according to any one of claims 1 - 4.

6. A fracturing oil displacement agent, characterized in that, The fracturing oil displacement agent comprises the active nanoparticles according to claim 5, an anionic or anionic-nonionic surfactant, and water.

7. The fracturing oil displacement agent according to claim 6, wherein The anionic or anionic-nonionic surfactant is a sulfonate-based anionic or anionic-nonionic surfactant; Preferably, the sulfonate-based anionic or anionic-nonionic surfactant is sodium fatty acid methyl ester polyether sulfonate.

8. The fracturing oil displacement agent according to claim 6 or 7, characterized in that The mass ratio of the active nanoparticles to the surfactant is (0.8 - 1.2):(0.6 - 1); Preferably, in the fracturing oil displacement agent, the total content of the active nanoparticles and the surfactant is 0.1 - 0.3 wt%.

9. Application of a fracturing oil displacement agent according to any one of claims 6 - 8 in the exploitation of low-permeability oil reservoirs.

10. The application according to claim 9, wherein The steps of the exploitation of the low-permeability oil reservoir include: through an injection well, injecting a displacement fluid into the formation at a displacement rate greater than the formation absorption capacity, and after the main formation fracture is opened, injecting the fracturing oil displacement agent according to any one of claims 6 - 8.

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