Double-interface regulation nano imbibition agent for enhancing imbibition and replacement of shale oil and preparation method of double-interface regulation nano imbibition agent

Abstract

The invention relates to a nano imbibition agent for enhancing shale oil imbibition and displacement dual-interface regulation and a preparation method. The nano imbibition agent comprises the following components: long-chain alkyl aryl sulfonate, a co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic-nonionic surfactant, mineral oil and water, wherein the long-chain alkyl aryl sulfonate accounts for 30-50% of the total mass of the system, the cosurfactant branched-chain fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anion-nonionic surfactant accounts for 10-30% of the total mass of the system, the mineral oil accounts for 5-20% of the total mass of the system, and the balance is water. The shale oil imbibition and replacement mechanism is disclosed, the imbibition agent with the imbibition enhancing function is designed according to the pore distribution characteristics and wettability of the shale reservoir, the imbibition and replacement effect of the imbibition agent applied to the shale oil reservoir is evaluated, effective economic development of shale oil in China is promoted, and therefore the shale oil imbibition and replacement method has wide application prospects.

Description

Technical Field

[0001] This invention relates to the field of shale oil development technology, specifically to the study of permeation and displacement mechanisms and the evaluation of permeator effects, and particularly to a nano-permeator for enhancing shale oil permeation and displacement through a dual-interface regulation and its preparation method. Background Technology

[0002] With the continued growth of global energy demand and the increasing depletion of conventional oil and gas resources, unconventional oil and gas resources, especially shale oil, have become an important area for global energy strategy replacement. Shale oil reservoirs are dominated by nanoscale pores (<100nm) and micron-scale fractures, belonging to "in-source accumulation." Their development highly depends on horizontal well drilling and large-scale hydraulic fracturing technology. How to effectively utilize the crude oil contained in the nanoscale pores is the core challenge in improving shale oil recovery. Against this backdrop, permeation and replacement, as a key shale oil extraction mechanism, has received significant attention from industry and academia. The key to overcoming the bottleneck of shale oil permeation and replacement efficiency lies in permeabilizers.

[0003] Authorization announcement number CN112892394B discloses a sulfonic acid-based anionic gemini surfactant, its preparation, and its application as a shale oil reservoir percolation displacement agent. This invention prepares a sulfonic acid-based anionic gemini surfactant and applies it as a shale oil reservoir percolation displacement agent. This product can change the surface wettability of shale oil reservoirs, treating oil-wet cores to hydrophilic properties, thereby improving shale oil percolation recovery. This patent has the following shortcomings: (1) It does not clearly demonstrate the effect of the developed product in reducing interfacial tension; (2) The wettability evaluation of shale oil reservoirs uses the thin-film contact angle measurement method, which fails to accurately characterize the overall wettability of shale oil reservoirs, resulting in a large error in the wettability evaluation results; (3) The synthesis process of the developed product is complex and costly; (4) The development of the percolation agent does not consider the contribution of different scale reservoir spaces of shale to the percolation recovery rate, especially nanoscale pores.

[0004] Patent application publication number CN116621740A discloses a nano-permeabilizer and its preparation method. This patent proposes a nano-permeabilizer with a mass concentration of 0.3%, whose interfacial tension with kerosene is 3.5 × 10⁻⁶. -4 mN / m, with an interfacial tension of 8.3×10 with crude oil. -3mN / m, the contact angle of water droplets in the core after treatment with the permeabilizing agent solution changed from 175° to 130°, that is, wetting reversal occurred, and the permeabilization recovery rate was improved compared with that of clear water. Although the patent initially explained the effect of the developed product on improving the permeabilization recovery rate from the perspectives of interfacial tension and wettability, there are still the following shortcomings: (1) The wettability evaluation of shale oil reservoirs adopts the thin section contact angle measurement method, which fails to accurately characterize the overall wettability of shale oil reservoirs, and the wettability evaluation results have a large error; (2) The permeabilizing agent development process did not consider the contribution of different scale reservoir spaces of shale to the permeabilization recovery rate, especially the nanoscale pores. Summary of the Invention

[0005] To address the problems existing in the background technology, this application provides a nano-permeabilizer for enhancing shale oil permeation and displacement through dual-interface regulation and its preparation method. It clarifies the influence of overall wettability changes in shale oil reservoirs on permeation and displacement recovery rate, reveals the contribution of different scale reservoir spaces in shale to permeation and displacement recovery rate, including the contribution of nanoscale pores to permeation and displacement recovery rate, and develops a method for preparing a nano-permeabilizer with dual interface regulation functions of "wetting regulation" and "low interfacial tension".

[0006] The technical solution adopted in this application is: a nano-permeabilizer for enhancing shale oil permeation and displacement through a dual interface, comprising the following components: long-chain alkyl aryl sulfonate, co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant, mineral oil, and water.

[0007] The aforementioned nano-permeation agent for enhancing shale oil permeation and displacement through a dual interface comprises long-chain alkyl aryl sulfonates accounting for 30%–50% of the total system mass, a co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic-nonionic surfactant accounting for 10%–30% of the total system mass, mineral oil accounting for 5%–20% of the total system mass, and the remainder being water.

[0008] The aforementioned long-chain alkyl aryl sulfonates, acting as the primary surfactant in the system, can form a high-strength adsorption film at the oil-water interface, significantly reducing the interfacial tension between shale oil and water. Furthermore, through directional adsorption on the rock surface, they facilitate the transformation of reservoir wettability from oil-wet to water-wet. Simultaneously, they synergistically interact with anionic-nonionic block polyether sulfonates as co-surfactants, stabilizing the nanoscale aggregate structure and enhancing the system's interfacial regulation capabilities under complex reservoir conditions, thereby significantly improving the percolation and displacement efficiency of shale oil.

[0009] The branched fatty alcohols used in the raw materials all have terminal primary hydroxyl groups, which can be introduced into nonionic hydrophilic segments and anionic hydrophilic groups through reactions such as ethoxylation, propoxylation, and sulfonation, thereby forming anionic nonionic surfactants. The branched alkyl structure of branched fatty alcohols can effectively reduce molecular crystallinity, lower the freezing point, improve low-temperature fluidity and solubility, and at the same time improve the wettability, penetration and emulsifying ability of surfactants.

[0010] The structures of the above-mentioned co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant compounds are as follows:

[0011] Branched-chain fatty alcohol structural formula: .

[0012] In the formula: R1 = CH3(CH2)3CH(CH2CH5)CH, CH3(CH2)2CH(CH2)5(CH3)CH2,

[0013] CH3(CH2)3CH(CH2)6(CH3)CH2 or CH3(CH2)5CH(CH2)7(CH3)CH2;

[0014] The reaction equation is as follows:

[0015] ; ;

[0016] ;

[0017] ;

[0018] In the formula: a = 3, 4, 5, 6; b = 3, 4, 5, 6.

[0019] The preparation method of the co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant is as follows:

[0020] 1) Etherification reaction of branched fatty alcohols:

[0021] ① Ethylene oxide etherification reaction: Branched fatty alcohol and ethylene oxide with a molar ratio of 1:1 to 1:10 are added to a reaction vessel, and the pressure is controlled at 0.2 to 0.6 MPa. A 30% KOH solution is added as a catalyst, and the amount of KOH solution added is 0.5% to 4% of the mass of the branched fatty alcohol. The reaction vessel is evacuated and nitrogen is circulated three times to maintain the vacuum environment. The reaction is carried out at a temperature of 110℃ to 180℃ until the system pressure no longer changes, and the branched fatty alcohol ethylene oxide etherification product is obtained.

[0022] ② Propylene oxide etherification reaction: The reactor is evacuated and nitrogen is circulated three times to maintain the vacuum environment. The pressure is controlled at 0.2-0.6 MPa. The branched fatty alcohol ethylene oxide etherification product and propylene oxide are added in a molar ratio of 1:1 to 1:10. Then, a 30% potassium hydroxide solution catalyst is added, with the amount added being 1%-5% of the mass of the branched fatty alcohol ethylene oxide etherification product. The reaction is carried out at 120℃-160℃ until the system pressure no longer changes, and the initial product, a branched fatty alcohol polyoxyethylene polyoxypropylene block polyether nonionic surfactant, is obtained.

[0023] 2) Allylation reaction: Branched fatty alcohol polyoxyethylene polyoxypropylene block polyether with a molar ratio of 1:1 to 1:2.5 and allyl chloride are added to a reaction flask, and then a 30% potassium hydroxide solution catalyst is added in an amount of 1% to 3% of the mass of the branched fatty alcohol polyoxyethylene polyoxypropylene block polyether. Nitrogen gas is introduced into the reaction flask to protect the reaction environment. The reaction temperature is controlled at 100℃ to 130℃ and the reaction time is 6h to 10h. After the reaction is completed, unreacted allyl chloride is removed by vacuum distillation, and the by-product is separated by solvent extraction. The solvent is diethyl ether, petroleum ether or ethyl acetate. The by-product is the polyether dehydration product, to obtain an allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether compound.

[0024] 3) Sulfonation reaction: Allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether, sodium bisulfite, and sodium sulfite in a molar ratio of 1:1:1 to 1:2:1 are added to a reaction flask, followed by sodium nitrate catalyst. The amount of catalyst added is 0.5% to 1.5% of the total mass of the reactants. The reaction temperature is 60℃ to 90℃, and the reaction time is 8h to 13h. After the reaction is completed, saturated sodium carbonate solution is added to neutralize to a neutral pH of 6.5 to 7.0. Unreacted monomers are removed by vacuum distillation, and the product is purified by precipitation with anhydrous ethanol or membrane separation to obtain branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant.

[0025] The beneficial effects of this application are as follows: the nano-permeabilizer of this application possesses dual dynamic regulation functions of interfacial components, namely, "regulating wettability" and "low interfacial tension." The raw materials for the synthesis of this permeabilizer are characterized by wide availability, low price, and high product yield. Simultaneously, based on the porosity and wettability distribution characteristics of reservoir spaces at different scales in shale reservoirs, a method for preparing a permeabilizer with enhanced permeation function was designed. The permeabilizer's effect on permeation and replacement in shale oil reservoirs was evaluated, and the optimal wettability index and interfacial tension variation range of the permeabilizer were given. This provides guidance for the research and development of permeabilizers for shale oil reservoirs. Permeabilizers with low interfacial tension, strong wettability reversal, and good micellar solubilization can effectively improve oil recovery. Therefore, this invention has significant theoretical research value and broad prospects for field application. Attached Figure Description

[0026] Appendix Figure 1 This is the two-dimensional T1-T2 NMR spectrum of rock sample #1 (dry sample).

[0027] Appendix Figure 2 This is a graph showing the weight of rock sample #1 after it was saturated with water over time.

[0028] Appendix Figure 3 This is a two-dimensional T1-T2 nuclear magnetic resonance spectrum of rock sample #1 after it was saturated with water;

[0029] Appendix Figure 4 This is a graph showing the weight of rock sample #1 after it was saturated with oil over time.

[0030] Appendix Figure 5 This is a two-dimensional T1-T2 nuclear magnetic resonance spectrum of rock sample #1 after it was saturated with oil;

[0031] Appendix Figure 6 This is a graph showing the changes in NMR signal components and cumulative values ​​after the self-absorption of water and oil in rock sample #1.

[0032] Appendix Figure 7 This is a two-dimensional T1-T2 nuclear magnetic resonance spectrum of rock sample #1 after simulated formation water infiltration.

[0033] Appendix Figure 8 This is a standard diagram for the experimental determination of two-dimensional nuclear magnetic resonance parameters of shale;

[0034] Appendix Figure 9 This is the two-dimensional T1-T2 NMR spectrum of rock sample #2 (dry sample).

[0035] Appendix Figure 10 This is a graph showing the weight change of rock sample #2 over time after saturation with nano-permeabilizer solution #1.

[0036] Appendix Figure 11 This is a two-dimensional T1-T2 nuclear magnetic resonance spectrum of rock sample #2 after saturation with nano-permeabilizer solution #1;

[0037] Appendix Figure 12 This is a graph showing the weight of rock sample #2 after it was saturated with oil over time.

[0038] Appendix Figure 13 This is the two-dimensional T1-T2 NMR spectrum of rock sample #2 after it was saturated with oil;

[0039] Appendix Figure 14 This is a graph showing the changes in NMR signal components and cumulative amounts after the self-absorption of nano-permeable agent #1 and self-absorption of oil in rock sample #2.

[0040] Appendix Figure 15 This is the two-dimensional T1-T2 nuclear magnetic resonance spectrum of rock sample #2 after infiltration with nano-absorbent #1;

[0041] Appendix Figure 16 This is a graph showing the changes in the permeation recovery rate of different formulations of nano-permeabilizers as a function of interfacial tension and wetting index. Detailed Implementation

[0042] The present invention will be further described below with reference to embodiments and accompanying drawings:

[0043] Comparative Example:

[0044] (I) Measurement of oil-water interfacial tension in simulated shale oil and simulated formation water

[0045] 1. Preparation of experimental simulated shale oil and simulated formation water

[0046] 1) Representative wells in the study block were selected to produce degassed crude oil. Based on the crude oil viscosity under formation temperature conditions, a certain proportion of aviation kerosene was added to prepare simulated shale oil for the experiment. The volume ratio of degassed crude oil to aviation kerosene was recorded. The initial viscosity of aviation kerosene and degassed crude oil under formation temperature conditions was measured using a viscometer. Based on the crude oil viscosity under formation temperature conditions, the initial volume ratio of aviation kerosene to degassed crude oil was calculated. Simulated shale oil was prepared according to the calculated initial volume ratio, and its viscosity was measured. Based on the viscosity measurement, the volume ratio of aviation kerosene to degassed crude oil was adjusted until the measured viscosity was the same as the crude oil viscosity under formation temperature conditions. Under the experimental conditions, the crude oil viscosity under formation temperature conditions was 13 mPa∙s, and the volume ratio of degassed crude oil to aviation kerosene was 1:1.33.

[0047] 2) Prepare experimental simulated formation water according to existing methods.

[0048] 2. Measurement of oil-water interfacial tension

[0049] Using an interfacial tensiometer, the interfacial tension between simulated shale oil and simulated formation water in representative wells of the study block was measured. Three consecutive measurements were taken, and the average interfacial tension was used as the interfacial tension between simulated shale oil and simulated formation water in the representative wells of the study block when the relative error of the three measurements was less than 5%. The measurement results are shown in Appendix Table 1.

[0050] Appendix Table 1: Results of Interfacial Tension Measurement with Different Reagents and Simulated Shale Oil

[0051]

[0052] (II) Evaluation of the initial wettability of shale oil reservoir cores

[0053] 1. Shale sample preparation, screening and pretreatment

[0054] 1) Select one cored shale sample from the target layer of a representative well in the study block and number it 1#. Sample 1# should be a standard plunger sample with a length of about 5cm and a diameter of 2.5cm.

[0055] 2) The porosity and permeability of shale sample #1 under overburden pressure conditions were determined using a VINCI overburden pressure porosimeter, with the effective stress set at 350 psi. The results are shown in Appendix Table 2.

[0056] Appendix 2 Basic Parameters of Rock Samples

[0057]

[0058] Shale sample pretreatment: Shale sample #1 was dried in accordance with the standard GB / T 29172-2012 "Core Analysis Methods".

[0059] 2. Initial wettability determination of shale oil reservoir cores

[0060] 1) Prepare simulated shale oil and simulated formation water for the experiment, and put them into the designated piston container for later use. Refer to the preparation method for oil-water interfacial tension measurement for details.

[0061] 2) Referring to standard GB / T 29172-2012 "Methods for Core Analysis", rock sample #1 was dried, weighed, and subjected to two-dimensional T1-T2 NMR spectroscopy. Results are attached. Figure 1 .

[0062] 3) Place rock sample #1 into a piston container and evacuate for 48 hours.

[0063] 4) Place the piston container containing rock sample #1 and the piston container containing simulated formation water in a constant temperature chamber at the same temperature as the reservoir temperature (80℃) of the study block. Use an ISCO pump to inject simulated formation water into the piston container containing rock sample #1, ensuring that the rock sample is completely immersed in the simulated formation water. Afterward, take out rock sample #1 every 12 hours and weigh it; the results are attached. Figure 2 When the weight of the rock sample did not change after self-absorption of simulated formation water, the sample was removed for two-dimensional T1-T2 nuclear magnetic resonance (NMR) spectroscopy. The test results are attached. Figure 3 .

[0064] 5) Referring to the standard GB / T 29172-2012 "Methods for Core Analysis", rock sample #1 was dried and weighed, with m0 = 59.1052 g. m0 represents the dry weight of the rock sample.

[0065] 6) Place rock sample #1 into a piston container and evacuate for 48 hours.

[0066] 7) Place the piston container containing rock sample #1 and the piston container containing simulated shale oil in a constant temperature chamber at the same temperature as the reservoir in the study block. Use an ISCO pump to inject simulated shale oil into the piston container containing rock sample #1, ensuring the rock sample is completely immersed in the simulated shale oil. Afterward, weigh rock sample #1 every 12 hours; the results are shown in the appendix. Figure 4When the weight of the rock sample did not change after self-absorption to simulate shale oil, the rock sample was removed and subjected to two-dimensional T1-T2 nuclear magnetic resonance spectroscopy. The test results are attached. Figure 5 It should be noted that this No. 1 rock sample was used to conduct subsequent simulated formation water percolation and displacement oil recovery experiments.

[0067] 8) Experimental Data Processing. The wettability index of rock sample #1 was calculated using formula (1), and the initial wettability evaluation results for rock sample #1 were given. The formula for calculating the wettability index is shown below:

[0068] (1)

[0069] Wherein, I—total porosity wettability index, dimensionless (oil-loving when 0 < I < 0.4; neutral when 0.4 < I < 0.6; hydrophilic when 0.6 < I < 1); —Accumulated self-absorption signal component, PU; —Accumulated self-priming oil signal component, PU.

[0070] Total wettability index of rock sample #1:

[0071]

[0072] Plot the curves of changes in NMR signal components and cumulative amounts after self-absorption of water and oil in rock sample #1 (attached). Figure 6 Organic matter exists in the shale sample, and the NMR signal of this organic matter appears as the first peak in the two-dimensional T1-T2 NMR spectrum. Therefore, the attached graph was plotted... Figure 6 The amount of NMR signal corresponding to organic matter needs to be subtracted during the process. and According to the appendix Figure 6 The data were obtained from the T2 spectrum.

[0073] The formula for calculating the orifice wettability index is as follows:

[0074] (2)

[0075] in, —Porosity wettability index, dimensionless (when 0 < 0 < 0) When <0.4, it is lipophilic; when 0.4 < Neutral when <0.6; neutral when 0.6 < <1 hour of hydrophilicity); —Accumulated self-absorption signal component from core pores, PU; —Accumulated signal components of self-priming oil wells in core samples, PU.

[0076] The formula for calculating the mesopore wettability index is as follows:

[0077] (3)

[0078] in, —Mesopore wettability index, dimensionless (when 0 < 0 < 0) When <0.4, it is lipophilic; when 0.4 < Neutral when <0.6; neutral when 0.6 < <1 hour of hydrophilicity); —Accumulated self-absorption signal component in the core hole of the rock, PU; —Accumulated self-absorption oil signal component in the core hole of the rock, PU.

[0079] The formula for calculating the macroporous wettability index is as follows:

[0080] (4)

[0081] in, — Macropore wettability index, dimensionless (when 0 < 0 < 0) When <0.4, it is lipophilic; when 0.4 < Neutral when <0.6; neutral when 0.6 < <1 hour of hydrophilicity); —Accumulated signal component of self-absorption water from macropores in core, PU; —Accumulated signal component of self-aspirating oil from macropores in core, PU.

[0082] Shale pores are classified into small pores (including those between clay layers), medium pores, and large pores based on time intervals of 0.2-2.0 ms, 2.0-15 ms, and >15 ms. See the appendix for specific classification criteria. Figure 8 The calculated wetting index results for pores of different sizes are shown below:

[0083] Micropore wetting index:

[0084]

[0085] Mesopore wettability index:

[0086]

[0087] Macropore wettability index:

[0088]

[0089] , , and , , According to the appendix Figure 6 The data were obtained from the T2 spectrum.

[0090] The calculation results above show that rock sample #1 is generally hydrophilic, with water wetting in the small pores and neutral wetting in the medium and large pores.

[0091] (III) Shale core simulation of formation water permeation and displacement oil recovery experiment

[0092] 1. Prepare simulated shale oil and simulated formation water for the experiment, and put them into the designated piston container for later use. Refer to the preparation method in the oil-water interfacial tension measurement procedure for details.

[0093] 2. Take rock sample #1 after self-absorption saturation of simulated shale oil in step 7 of the initial wettability determination of shale oil reservoir. Place rock sample #1 into the high temperature and high pressure percolation test device and inject simulated formation water using an ISCO pump. Place the high temperature and high pressure percolation test device in a constant temperature chamber and pressurize it to the reservoir pressure of 30 MPa to carry out simulated formation water percolation and replacement oil production experiment under the reservoir temperature (80℃) conditions.

[0094] 3. After 20 days, the pressure of the high-temperature and high-pressure percolation experimental device was released, the rock sample was removed, weighed, and subjected to two-dimensional T1-T2 nuclear magnetic resonance spectroscopy after percolation. (See attached image) Figure 7 .

[0095] 4. Experimental Data Processing. Based on the nuclear magnetic resonance data of dry sample No. 1, saturated simulated shale oil, and simulated formation water infiltration, the simulated formation water infiltration and replacement recovery rate under reservoir temperature and pressure conditions was calculated and determined. For the analysis methods and identification criteria of fluid components in different scales of shale core reservoirs, please refer to the appendix. Figure 8 Based on the appendix Figure 8 The schematic diagram shows that the seepage recovery rate and total recovery rate of shale reservoirs at different scales can be calculated using formulas (5)-(8):

[0096] ........................(5)

[0097] ........................(6)

[0098] ........................(7)

[0099] ........................(8)

[0100] In the formula: , , , —Total reservoir space, macropore, mesopore, and micropore (including clay interlayer) NMR signal quantity of rock sample #1 (PU); , , , —NMR signal quantity of total reservoir space, macropores, mesopores, and micropores (including clay interlayers) of saturated simulated oil in rock sample #1, PU; , , , —NMR signal quantity of total reservoir space, macropores, mesopores, and micropores (including clay interlayers) after seepage of rock sample #1, PU; , , , —Total reservoir space, macropore, mesopore, and micropore (including clay interlayer) permeation recovery rate of rock sample #1.

[0101] The experimental results of simulated formation water seepage recovery rate are shown in Appendix Table 3.

[0102] Appendix Table 3. Nuclear Magnetic Resonance Test Results of Rock Sample #1

[0103]

[0104] Example:

[0105] (I) Preparation of Nanoparticles for Enhancing Shale Oil Permeation and Displacement through Dual-Interface Regulation

[0106] The permeating agent comprises the following components: long-chain alkyl aryl sulfonates accounting for 30% to 50% of the total system mass, co-surfactants branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonates anionic-nonionic surfactants accounting for 10% to 30% of the total system mass, mineral oil accounting for 5% to 20% of the total system mass, and the balance being water.

[0107] 1. The preparation method of long-chain alkyl aryl sulfonates is as follows:

[0108] 1) Preparation of long-chain alkyl aryl compounds: 16.8g of C12α-olefin and 28.2g of C20-24α-olefin were mixed and added to an excess of benzene, toluene, or mixed xylenes in a reaction vessel. The mixture was stirred and an acidic ionic liquid was added as a catalyst. The acidic ionic liquid catalyst was a mixture of anhydrous aluminum trichloride and polychlorinated alkanes. 20g of aluminum trichloride and 40g of polychlorinated alkanes were added. The temperature was raised to 70℃ and the reaction was carried out for 4 hours. After the reaction was stopped, the mixture was allowed to stand for a period of time until the ionic liquid catalyst and the reaction mixture completely separated. The lower layer of ionic liquid catalyst was released and placed in a desiccator for recycling. The upper layer was a mixture of the reaction product long-chain alkyl aryl compound and excess benzene, toluene, or mixed xylenes. The mixture was washed with water until neutral and the benzene, toluene, or mixed xylenes were removed by vacuum distillation to obtain the target product long-chain alkyl aryl compound.

[0109] 2) Preparation of long-chain alkyl aryl sulfonic acid: The long-chain alkyl aryl compound prepared in step 1) is subjected to sulfonation reaction in a falling film sulfonation reactor, and the reaction temperature is controlled at 50℃~70℃ and the flow ratio of sulfur trioxide to air is 1:1~1:1.5 to continuously prepare long-chain alkyl aryl sulfonic acid.

[0110] 3) Preparation of long-chain alkyl aryl sulfonates: Aging long-chain alkyl aryl sulfonic acid for 4 hours, adding 8g of anhydrous ethanol, and neutralizing with 30% sodium hydroxide solution to pH 8-10 under strong stirring to obtain long-chain alkyl aryl sulfonates.

[0111] 2. The preparation method of the co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant is as follows:

[0112] 1) Etherification reaction of branched fatty alcohols:

[0113] ① Ethylene oxide etherification reaction: 20g of isotridecyl alcohol and 8.8g of ethylene oxide were added to the reactor, and the pressure was controlled at 0.2-0.6MPa. 0.81g of KOH solution with a mass concentration of 30% was added as a catalyst. The reactor was evacuated and nitrogen gas was circulated three times to ensure the vacuum environment. The reaction was carried out at 120℃ until the system pressure no longer changed, and the branched fatty alcohol ethylene oxide etherification product was obtained.

[0114] ② Etherification reaction of propylene oxide: The reactor was evacuated and nitrogen was circulated three times to maintain the vacuum environment. The pressure was controlled at 0.2-0.6 MPa. 33g of branched fatty alcohol ethylene oxide etherification product and 34.8g of propylene oxide were added, followed by 9g of 30% potassium hydroxide solution catalyst. The reaction was carried out at 130℃ until the system pressure no longer changed, and the initial product, branched fatty alcohol polyoxyethylene polyoxypropylene block polyether nonionic surfactant, was obtained.

[0115] 2) Allylation reaction: 39g of branched fatty alcohol polyoxyethylene polyoxypropylene block polyether and 7.7g of allyl chloride were added to a reaction flask, followed by 0.57g of 30% potassium hydroxide solution catalyst. Nitrogen gas was introduced into the reaction flask to protect the reaction environment. The reaction temperature was controlled at 120℃ and the reaction time was 8h. After the reaction, unreacted allyl chloride was removed by vacuum distillation, and the byproduct was separated by solvent extraction. The solvent was diethyl ether, petroleum ether or ethyl acetate. The byproduct was a polyether dehydration product, yielding an allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether compound.

[0116] 3) Sulfonation reaction: By changing the carbon chain length and the number of ethoxy and propoxy groups of branched fatty alcohols, a series of branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactants with different carbon chain lengths, different numbers of ethoxy groups, and different numbers of propoxy groups can be prepared.

[0117] 47g of allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether, 21g of sodium bisulfite and 12.6g of sodium sulfite were added to a reaction flask, followed by 0.8g of sodium nitrate catalyst. The reaction temperature was 85℃ and the reaction time was 10h. After the reaction was completed, saturated sodium carbonate solution was added to neutralize to a neutral pH of 6.5-7.0. Unreacted monomers were removed by vacuum distillation, and the product was purified by anhydrous ethanol precipitation or membrane separation to obtain branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant.

[0118] Ten types of nano-permeabilizers for enhancing shale oil permeation and displacement through dual-interface regulation, hereinafter referred to as permeabilizers, were prepared according to the above method. See Appendix Table 4 for details.

[0119] Appendix Table 4: Formulation of Nano-Implantants for Enhancing Shale Oil Immersion and Replacement at Two Interfaces (1#-10#)

[0120]

[0121] (II) Determination of interfacial tension of nano-permeabilizer for dual-interface regulation of shale oil and enhanced shale oil permeation and displacement

[0122] 1. Preparation of experimental simulated shale oil and dual-interface regulated nano-permeation agent

[0123] 1) Select degassed crude oil from representative wells in the study block, add a certain proportion of aviation kerosene according to the crude oil viscosity value under formation temperature conditions, and prepare simulated shale oil for the experiment. Record the volume ratio of degassed crude oil to aviation kerosene. Under the experimental conditions, the volume ratio of degassed crude oil to aviation kerosene is 1:1.33.

[0124] 2) Select the dual-interface regulated nano-permeabilizer prepared in step (i), and determine the initial dual-interface regulated nano-permeabilizer for the experiment by adjusting the composition ratio of each component of the permeabilizer.

[0125] 2. Determination of interfacial tension between shale oil and dual-interface regulated nano-permeabilizer

[0126] The interfacial tension between simulated shale oil and the initial dual-interface controlled nano-permeability agent in a representative well of the study block was measured using an interfacial tensiometer. Three consecutive measurements were taken, and the average interfacial tension was used as the interfacial tension between the simulated shale oil and the initial dual-interface controlled nano-permeability agent in the representative well of the study block when the relative error of the three measurements was less than 5%. The measurement results are shown in Appendix Table 1.

[0127] (III) Evaluation of wettability of shale oil reservoir cores after the application of dual-interface controlled nano-permeability agents

[0128] 1. Shale sample preparation, screening and pretreatment

[0129] 1) Select shale rock samples from the target layer of the representative well in the study block. Sample No. 2 should be a standard plunger sample with a length of about 5cm and a diameter of 2.5cm.

[0130] 2) The porosity and permeability of shale sample #2 under overburden pressure conditions were determined using a VINCI overburden pressure porosimeter. The results are shown in Appendix Table 2. The effective stress was set to 350 psi. If the relative error between the porosity measurement value of #1 and that of #2 is less than 15% and the permeability measurement value is within the same order of magnitude, then the selected shale sample is representative and can be used for comparative analysis. If the relative error between the porosity measurement value and that of #2 is greater than 15% or the permeability measurement value is not within the same order of magnitude, then shale sample #2 needs to be selected again.

[0131] 3) Shale sample pretreatment: The qualified No. 2 shale sample was dried in accordance with the standard GB / T 29172-2012 "Core Analysis Methods".

[0132] 2. Wettability determination of shale oil reservoir cores after interaction with dual-interface regulated nano-permeability absorbent

[0133] 1) Prepare experimental simulated shale oil and initial dual-interface controlled nano-permeation agent, and put them into the designated piston container for later use. Refer to the preparation method for oil-water interfacial tension measurement for details.

[0134] 2) Following the standard GB / T 29172-2012 "Core Analysis Methods", rock sample #2 was dried, weighed, and subjected to two-dimensional T1-T2 NMR spectroscopy. The test results are attached. Figure 9 .

[0135] 3) Place rock sample #2 into a piston container and evacuate for 48 hours.

[0136] 4) Place the piston container containing rock sample #2 and the piston container containing the initial dual-interface controlled nano-permeability agent in a constant temperature chamber at the same temperature as the reservoir temperature of the study block. The volume concentration of the nano-permeability agent is 0.3%. Use an ISCO pump to pour the initial dual-interface controlled nano-permeability agent into the piston container containing rock sample #2, ensuring that the rock sample is completely immersed in the initial dual-interface controlled nano-permeability agent. Then, take out rock sample #2 and weigh it every 12 hours. The results are shown in the appendix. Figure 10 When the weight of the rock sample did not change after initial dual-interface regulation of the nano-permeation agent, the rock sample was removed for two-dimensional T1-T2 nuclear magnetic resonance spectroscopy. The results are attached. Figure 11 .

[0137] 5) Referring to standard GB / T 29172-2012 "Methods for Core Analysis", rock sample #2 was dried and weighed (dry weight m0 = 60.3380 g). The results are attached. Figure 12 .

[0138] 6) Place rock sample #2 into a piston container and evacuate for 48 hours.

[0139] 7) Place the piston container containing rock sample #2 and the piston container containing simulated shale oil in a constant temperature chamber at the same temperature as the reservoir in the study block. Use an ISCO pump to inject simulated shale oil into the piston container containing rock sample #2, ensuring the rock sample is completely immersed in the simulated shale oil. Then, remove rock sample #2 and weigh it every 12 hours. When the weight of the rock sample does not change after self-absorbing simulated shale oil, remove the rock sample and perform two-dimensional T1-T2 nuclear magnetic resonance spectroscopy. The test results are attached. Figure 13 It should be noted that this No. 2 rock sample was used to conduct subsequent initial dual-interface controlled nano-permeabilizer permeation displacement oil recovery experiments.

[0140] 8) Experimental data processing. Calculate the wettability index of rock sample #2 using formulas (1)-(4) and give the initial wettability evaluation results of rock sample #2.

[0141] Shale pores are classified into small pores (including those between clay layers), medium pores, and large pores based on time intervals of 0.2-2.0 ms, 2.0-15 ms, and >15 ms. See the appendix for specific classification criteria. Figure 8 The calculated wetting index results for pores of different sizes are shown below:

[0142] Total wettability index of rock sample #2:

[0143]

[0144] Micropore wetting index:

[0145]

[0146] Mesopore wettability index:

[0147]

[0148] Macropore wettability index:

[0149]

[0150] The calculation results above show that rock sample #2 is generally hydrophilic, with water wetting in the small pores and neutral wetting in the medium and large pores.

[0151] Plot the curves of changes in NMR signal components and cumulative amounts after self-absorption of water and oil in rock sample #2 (attached). Figure 14Organic matter exists in the shale sample, and the NMR signal of this organic matter appears as the first peak in the two-dimensional T1-T2 NMR spectrum. Therefore, the attached graph was plotted... Figure 14 The amount of NMR signal corresponding to organic matter needs to be subtracted during the process.

[0152] (iv) Experiment on oil recovery by regulating nano-permeation agent through dual-interface regulation of shale core samples

[0153] 1. The experimental simulated shale oil and the enhanced shale oil permeation displacement dual-interface controlled nano-permeation agent were loaded into the designated piston container for later use. For details, refer to the preparation method for oil-water interfacial tension measurement.

[0154] 2. After taking shale oil reservoir core samples and reacting them with dual-interface controlled nano-permeability agents, the wettability was measured in step 7) after self-absorption saturation of simulated shale oil. The No. 2 rock sample was placed in a high-temperature and high-pressure permeation experimental device, and the initial dual-interface controlled nano-permeability agent solution was injected using an ISCO pump. The high-temperature and high-pressure permeation experimental device was placed in a constant temperature chamber and pressurized to the reservoir pressure of 30 MPa to carry out the initial dual-interface controlled nano-permeability agent permeation and replacement oil recovery experiment under the reservoir temperature (80℃) condition.

[0155] 3. After 20 days, the pressure of the high-temperature and high-pressure percolation experimental device was released, the rock sample was removed, weighed, and a two-dimensional T1-T2 nuclear magnetic resonance spectrum was performed (see attached). Figure 15 .

[0156] 4. Experimental Data Processing. Based on the nuclear magnetic resonance data of the No. 2 rock sample (dry sample), saturated simulated shale oil, and initial dual-interface controlled nano-permeasurant after permeation, the recovery rate of the initial dual-interface controlled nano-permeasurant under reservoir temperature and pressure conditions was calculated. The permeasurant recovery rate and total recovery rate of shale reservoir space at different scales can be calculated using formulas (5)-(8). The experimental calculation results of the nano-permeasurant permeasurant recovery rate are shown in Appendix Table 5.

[0157] Appendix Table 5. Nuclear magnetic resonance test results of rock sample #2

[0158]

[0159] Comparative analysis of Appendix 3 (NMR test results of rock sample #1) and Appendix 5 (NMR test results of rock sample #2) shows that: nano-permeabilizer #1 significantly improved the oil recovery rate of crude oil permeation and displacement in small pores (from 13.98% to 22.22%). Based on the method proposed in this patent, the contribution of different types of nano-permeabilizers to the permeation and displacement recovery rate of pores of different sizes has been clarified.

[0160] (V) Determination of Nanoparticles for Enhancing Shale Oil Permeation and Replacement Dual-Interface Regulation

[0161] 1. Adjust the composition ratio of each component of the permeabilizer to prepare a novel dual-interface regulated nanopermeabilizer (as shown in Appendix Table 4). Refer to step (II) to carry out the interfacial tension measurement between shale oil and the novel dual-interface regulated nanopermeabilizer. The results are shown in Appendix Table 1.

[0162] 2. Take a core sample of shale from the target section of a representative well in the study block (sample #3). Sample #3 should be a standard plunger sample approximately 5cm in length and 2.5cm in diameter. Refer to step (III) to determine the wettability of the shale oil reservoir core after interaction with the novel dual-interface controlled nano-permeability absorber. The results are attached. Figure 16 .

[0163] 3. Using the self-absorption saturation simulated shale oil sample No. 3, conduct an infiltration and displacement oil recovery experiment using a novel dual-interface regulated nano-permeasurant, referring to step (IV). Calculate and determine the recovery rate of the novel dual-interface regulated nano-permeasurant under reservoir temperature and pressure conditions. The calculation process is the same as for samples No. 1 and No. 2. The calculation results are attached. Figure 16 .

[0164] It should be noted that, in order to obtain sufficient experimental sample data points, at least 11 cored shale samples from the target layer of representative wells in the study block were selected to carry out the following experiments: interfacial tension measurement of shale oil and 10 different component ratios of dual-interface controlled nano-permeability agents, wettability evaluation of shale oil reservoir cores after interaction with dual-interface controlled nano-permeability agents, and permeation replacement oil recovery experiments using dual-interface controlled nano-permeability agents.

[0165] 4. Comparative analysis was conducted on the oil recovery rates of 10 different component ratios of dual-interface-regulated nano-permeabilizers and simulated formation water permeation-displacement agents (see Appendix Table 6). Curves showing the relationship between permeation-displacement recovery rate and oil-water interfacial tension and wettability index were plotted (see Appendix Table 6). Figure 16 To maximize the recovery rate of percolation replacement, the optimal range of variation for oil-water interfacial tension and wetting index was determined.

[0166] Appendix 6: Recovery Calculation Results under Different Immersion Media Conditions

[0167]

[0168] 5. Based on the optimal range of oil-water interfacial tension and wetting index values, the composition ratio of each component of the permeabilizer was adjusted to ultimately develop a dual-interface controlled nanopermeabilizer suitable for shale oil reservoirs in the research block. This nanopermeabilizer features adjustable interfacial tension and wettability. The optimal nanopermeabilizer is composed of: long-chain alkyl aryl sulfonate accounting for 38% of the total system mass; branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant accounting for 12% of the total system mass; mineral oil accounting for 10% of the total system mass; and water with a mass concentration of 40%.

[0169] The particle size distribution of the No. 2 enhanced shale oil permeation and displacement dual-interface regulated nano-permeation agent was determined by dynamic light scattering (DLS) characterization technology. The peak particle size results are shown in Appendix Table 7.

[0170] Appendix Table 7. Measurement results of particle size of nano-permeabilizer for enhancing shale oil permeation and displacement through a dual-interface control.

[0171]

Claims

1. A nano-permeability enhancer for shale oil permeation and displacement with dual-interface regulation, characterized in that: It includes the following components: long-chain alkyl aryl sulfonates, co-surfactants, branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonates, anionic nonionic surfactants, mineral oil, and water.

2. The nano-permeability enhancer for shale oil permeation and displacement regulation via a dual interface as described in claim 1, characterized in that: Long-chain alkyl aryl sulfonates account for 30% to 50% of the total system mass, co-surfactants branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonates anionic-nonionic surfactants account for 10% to 30% of the total system mass, mineral oil accounts for 5% to 20% of the total system mass, and the balance is water.

3. The nano-permeability enhancer for shale oil permeation and displacement under dual-interface regulation as described in claim 1, characterized in that: The preparation method of the co-surfactant branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant is as follows: 1) Etherification reaction of branched fatty alcohols: ① Ethylene oxide etherification reaction: Branched fatty alcohol and ethylene oxide with a molar ratio of 1:1 to 1:10 are added to a reaction vessel, and the pressure is controlled at 0.2 to 0.6 MPa. A 30% KOH solution is added as a catalyst, and the amount of KOH solution added is 0.5% to 4% of the mass of the branched fatty alcohol. The reaction vessel is evacuated and nitrogen is circulated three times to maintain the vacuum environment. The reaction is carried out at a temperature of 110℃ to 180℃ until the system pressure no longer changes, and the branched fatty alcohol ethylene oxide etherification product is obtained. ② Propylene oxide etherification reaction: The reactor is evacuated and nitrogen is circulated three times to maintain the vacuum environment. The pressure is controlled at 0.2-0.6 MPa. Branched fatty alcohol ethylene oxide etherification product and propylene oxide are added at a molar ratio of 1:1-1:

10. Then, a 30% potassium hydroxide solution catalyst is added, with the amount added being 1%-5% of the mass of the branched fatty alcohol ethylene oxide etherification product. The reaction is carried out at 120℃-160℃ until the system pressure no longer changes, and the initial product, branched fatty alcohol polyoxyethylene polyoxypropylene block polyether nonionic surfactant, is obtained. 2) Allylation reaction: Branched fatty alcohol polyoxyethylene polyoxypropylene block polyether with a molar ratio of 1:1 to 1:2.5 and allyl chloride are added to a reaction flask, and then a 30% potassium hydroxide solution catalyst is added, the amount of which is 1% to 3% of the mass of the branched fatty alcohol polyoxyethylene polyoxypropylene block polyether. Nitrogen gas is introduced into the reaction flask to protect the reaction environment. The reaction temperature is controlled at 100℃ to 130℃ and the reaction time is 6h to 10h. After the reaction, unreacted allyl chloride is removed by vacuum distillation, and the by-product is separated by solvent extraction. The solvent is diethyl ether, petroleum ether or ethyl acetate. The by-product is the polyether dehydration product, to obtain an allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether compound. 3) Sulfonation reaction: Allyl branched fatty alcohol polyoxyethylene polyoxypropylene block polyether, sodium bisulfite, and sodium sulfite in a molar ratio of 1:1:1 to 1:2:1 are added to a reaction flask, followed by sodium nitrate catalyst. The amount of catalyst added is 0.5% to 1.5% of the total mass of the reactants. The reaction temperature is 60℃ to 90℃, and the reaction time is 8h to 13h. After the reaction is completed, saturated sodium carbonate solution is added to neutralize to a neutral pH of 6.5 to 7.

0. Unreacted monomers are removed by vacuum distillation, and the product is purified by precipitation with anhydrous ethanol or membrane separation to obtain branched fatty alcohol polyoxyethylene polyoxypropylene block polyether sulfonate anionic nonionic surfactant.

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