A multi-hydroxyl bridged osmotic thickening agent, its preparation method and application

Abstract

This invention proposes a multi-hydroxyl-bridged percolation thickener, its preparation method, and its application, relating to the field of oilfield engineering. The method of this invention includes the following steps: mixing long-chain fatty acids with N-methyl-1,3-propanediamine at a molar ratio of 1:1.05-1.2, and then carrying out an amidation reaction under anaerobic conditions to obtain a long-chain fatty acid amination containing a secondary amine structure; then dissolving the long-chain fatty acid amination with 1,4-butanediol diglycidyl ether at a molar ratio of 2-2.2:1 in an organic solvent to carry out a ring-opening reaction, thereby obtaining a clean fracturing fluid thickener. The thickener molecule synthesized by this invention simultaneously contains long-chain hydrophobic groups and multi-hydroxyl structures, which can form a stable associative thickening network in aqueous solution, thus exhibiting good thickening performance; furthermore, due to the introduction of long-chain hydrophobic groups, multi-hydroxyl bridging structures, and amine linking units, the system possesses certain interfacial activity, improving the spontaneous percolation capacity of fracturing fluid into matrix pores, achieving synergistic production enhancement through "fracturing + percolation".

Description

Technical Field

[0001] This invention relates to the field of oilfield engineering, and more specifically, to a multi-hydroxyl-bridged permeation thickener, its preparation method, and its application. Background Technology

[0002] Hydraulic fracturing is a primary technology for enhancing production in low-permeability and ultra-low-permeability reservoirs. Currently, this technology mainly employs polymer-based fracturing fluid systems, including plant-based fracturing fluids such as hydroxypropyl guar gum and carboxymethyl hydroxypropyl guar gum, as well as synthetic polymer-based fracturing fluids. While polymer-based fracturing fluids exhibit good proppant carrying capacity during operation, they produce polymer residues with uneven particle size distribution after fracturing. Most of these residue particles are larger than the pore throat radius of low-permeability reservoirs, easily accumulating in fractures and near-wellbore areas during filtration, thus clogging pores and fracture channels and reducing fracture conductivity. Furthermore, in low-permeability and ultra-low-permeability reservoirs, the smaller pore throat radius makes residual solids in the fracturing fluid more likely to damage the formation, affecting fracturing effectiveness and subsequent production capacity.

[0003] To address the residue problem in polymer fracturing fluids, clean fracturing fluid systems based on surfactants have been developed in recent years. These fluids thicken by forming associative structures through the self-assembly of surfactant molecules in aqueous solutions, leaving no solid residue after gel breaking and causing minimal formation damage. However, existing clean fracturing fluid systems still have certain shortcomings: firstly, most systems rely on high concentrations of inorganic salts (such as sodium chloride and potassium chloride) and alkaline substances to maintain structural stability, resulting in complex formulations and limited adaptability; secondly, some cationic surfactants exhibit poor biodegradability, while anionic and amphoteric surfactants lack stability under high salinity conditions or require stringent operating conditions, making it difficult to meet the application requirements of complex reservoirs.

[0004] Furthermore, for low- to ultra-low-permeability reservoirs, relying solely on fracturing to create a fracture network is insufficient to fully utilize the matrix reserves. After fracturing operations, the ability of the fracturing fluid to rapidly enter the matrix pores and establish sustained percolation is a crucial factor in improving post-fracturing recovery. Existing polymer fracturing fluids, due to their weak interfacial activity, struggle to significantly reduce oil-water interfacial tension and effectively alter rock wettability, thus limiting their sustained percolation and oil displacement capabilities after fracturing fluid flowback.

[0005] Therefore, developing a clean fracturing fluid thickener that still has good thickening properties under high salinity conditions, low dosage, low residue, and also has interface regulation capabilities is of great significance for improving fracturing efficiency and reducing reservoir damage. Summary of the Invention

[0006] The purpose of this invention is to provide a multi-hydroxyl-bridged permeation thickener, its preparation method, and its application. Through the simultaneous presence of long-chain hydrophobic groups and multi-hydroxyl structures in the thickener molecule, a stable associative thickening network can be formed in aqueous solution via hydrophobic association and hydrogen bonding, thus exhibiting excellent thickening performance. Furthermore, due to the introduction of long-chain hydrophobic groups, multi-hydroxyl bridging structures, and amine linkage units into the molecule, the system possesses certain interfacial activity. Under high salinity conditions, it can effectively reduce the oil-water interfacial tension, promote the wetting of the rock surface by fracturing fluid, and enhance the spontaneous permeation capacity of fracturing fluid into the matrix pores, achieving synergistic production enhancement through "fracturing + permeation".

[0007] The technical problem solved by this invention is achieved by the following technical solution.

[0008] In a first aspect, embodiments of this application provide a multi-hydroxyl-bridged permeation-type thickener, the structure of which is shown in Formula I: Formula I; Where R represents an alkyl or alkenyl group with more than 16 carbon atoms.

[0009] Secondly, embodiments of this application provide a method for preparing the above-mentioned multi-hydroxyl-bridged thickener, comprising the following steps: S1. Long-chain fatty acids and N-methyl-1,3-propanediamine are mixed in a molar ratio of 1:1.05-1.2 and then subjected to an amidation reaction under anaerobic conditions to obtain long-chain fatty acid aminations containing secondary amine structures. S2. A ring-opening reaction is carried out by dissolving the amination of long-chain fatty acids and 1,4-butanediol diglycidyl ether in an organic solvent at a molar ratio of 2-2.2:1 to obtain a clean fracturing fluid thickener.

[0010] Furthermore, step S1 also includes adding a catalyst, which is sodium hydroxide or sodium methoxide.

[0011] Furthermore, the temperature conditions for the amidation reaction are 140-150℃.

[0012] Furthermore, in step S2, the ring-opening reaction includes: first dissolving the amination of the long-chain fatty acid in an organic solvent and heating it to 50-60°C, then adding 1,4-butanediol diglycidyl ether dropwise to the reaction system and continuing the reaction by heating.

[0013] Furthermore, the organic solvent is isopropanol or ethanol, and the final temperature of the ring-opening reaction is 68-72℃.

[0014] Thirdly, the embodiments of this application provide the application of the above-mentioned polyhydroxy-bridged thickener in the preparation of clean fracturing fluid, wherein the thickener accounts for 0.5%-2.0% of the total mass of the clean fracturing fluid.

[0015] Compared with the prior art, the embodiments of the present invention have at least the following advantages or beneficial effects: 1. The multi-hydroxy bridged thickener molecule prepared by this invention contains long-chain hydrophobic groups, multi-hydroxy structures and amine linkage units. In aqueous solution, it can form a spatial network structure through hydrophobic association and hydrogen bonding, exhibiting good thickening performance. At the same time, it has certain surface activity, which can reduce the oil-water interfacial tension and improve reservoir wettability, thereby enhancing the permeation capacity. 2. The clean fracturing fluid synthesized from the polyhydroxy bridging thickener prepared in this invention can rapidly form an oil-water displacement interface in the reservoir pores after entering the fracture, promoting spontaneous adsorption of the fracturing fluid into the deeper matrix and improving its spontaneous adsorption capacity into the matrix pores, thus achieving synergistic production enhancement through fracturing and adsorption. Compared with traditional polymer fracturing fluids, this clean fracturing fluid not only has good proppant carrying capacity but also further expands the effective working volume of the fracturing fluid, improving the reservoir utilization rate; moreover, the fracturing fluid system does not contain polymer residues, causing less damage to the reservoir and exhibiting good environmental compatibility and application prospects. Attached Figure Description

[0016] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0017] Figure 1 This is a schematic diagram showing the results of the temperature resistance, shear resistance, flow properties, and viscoelastic properties of J-TO in an embodiment of the present invention. Figure 2 This is a schematic diagram showing the results of the temperature resistance, shear resistance, flow properties, and viscoelastic properties of J-LO in an embodiment of the present invention. Figure 3 This is a schematic diagram showing the results of the temperature resistance, shear strength, flow properties, and viscoelastic properties of HPG in the embodiments of the present invention; Figure 4 This is a schematic diagram showing the results of measuring the relationship between capillary rise height and concentration under the same core conditions for J-TO, J-LO, and HPG in an embodiment of the present invention; Figure 5 The results of oil-water surface tension tests at different concentrations for three gel-breaking solutions prepared by J-TO, J-LO, and HPG in embodiments of the present invention. Figure 6 The results show the contact angle changes of three gel-breaking solutions (J-TO, J-LO, and HPG) prepared in the embodiments of the present invention under three conditions. Detailed Implementation

[0018] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below. Where specific conditions are not specified in the embodiments, conventional conditions or conditions recommended by the manufacturer shall apply. Reagents or instruments whose manufacturers are not specified are all conventional products that can be purchased commercially.

[0019] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. The present invention will now be described in detail with reference to specific embodiments.

[0020] Example 1 This embodiment provides a detailed method for preparing a multi-hydroxyl-bridged permeation thickener, the basic principle of which is as follows: A surfactant thickener with a multi-hydroxyl-bridged structure was synthesized from long-chain fatty acids and amine-containing compounds as starting materials through a two-step chemical reaction. First, the long-chain fatty acid was reacted with N-methyl-1,3-propanediamine via an amidation reaction to generate an intermediate containing a secondary amine structure. Subsequently, the amine group in this intermediate underwent an epoxy ring-opening reaction with 1,4-butanediol diglycidyl ether to introduce a multi-hydroxyl structure and form a bridged amphiphilic molecule, thereby obtaining a clean fracturing fluid thickener with associative thickening ability.

[0021] Long-chain fatty acids can be saturated or unsaturated fatty acids with a main carbon chain of C16 or more. Taking oleic acid as an example, its reaction process is as follows: .

[0022] The specific preparation steps include: S1. Add 1 mol of oleic acid to a reaction vessel, heat to a molten state, and purge with nitrogen to remove oxygen for 5 min; add 1.10 mol of N-methyl-1,3-propanediamine, and add 1.5 g of sodium hydroxide or 1.9 g of sodium methoxide as a catalyst. React at 140 °C for 5-6 h to obtain the amidation product of intermediate oleic acid.

[0023] It is worth noting that in this step, the temperature conditions for the amidation reaction can be in the range of 140-170℃. Within this temperature range, the conversion rate of long-chain fatty acids is relatively high. After the reaction, they can be used directly for the next reaction without separation and purification, which helps to simplify the process and reduce production costs.

[0024] S2. Add 100g of the above intermediate to another reaction vessel, add an appropriate amount of isopropanol as a solvent, heat to 65℃ and stir to dissolve; slowly add 1,4-butanediol diglycidyl ether to make the molar ratio of intermediate to epoxy compound 2.2:1, and react at 60-80℃ for 6-8h to obtain the target polyhydroxy-bridged thickener, denoted as J-TO.

[0025] Furthermore, in step S2, the ring-opening reaction is carried out in isopropanol or ethanol solvent at a temperature of 60-80°C. Too low a temperature results in a slow reaction rate, while too high a temperature can lead to an increase in side reactions, thus affecting the product performance. Therefore, the above-mentioned temperature range is preferred.

[0026] In addition, as a preferred embodiment, during the ring-opening reaction, it is preferable to first dissolve the long-chain fatty acid amine in an organic solvent and heat it to 50-60°C, and then add 1,4-butanediol diglycidyl ether dropwise to the reaction system to continue the reaction, so as to improve the uniformity of the reaction and reduce the risk of side reactions caused by excessively rapid local reactions.

[0027] Example 2 The steps in this embodiment are basically the same as those in Embodiment 1, except that the second step of epoxy ring-opening reaction is not performed, and the amidation product obtained in the first step is directly used as a thickener, denoted as J-LO.

[0028] Example 3 This embodiment, based on Embodiment 1, further prepares a clean fracturing fluid, and the specific steps include: (1) Preparation of simulated formation water To prepare simulated formation water with a target mineralization of 60273 mg / L, approximately 800 mL of deionized water was taken and magnetically stirred at room temperature. Then, 36.60 g of NaCl, 0.73 g of KCl, 0.85 g of MgCl2·6H2O, 17.20 g of CaCl2, 0.08 g of Na2SO4, and 0.22 g of NaHCO3 were added sequentially. After each inorganic salt was added, the mixture was stirred thoroughly until completely dissolved before adding the next inorganic salt. Once all inorganic salts were completely dissolved, the volume was adjusted to 1 L with deionized water to obtain simulated high-mineralization formation water. The total amount of inorganic salts added was 55.68 g. Based on the total mass of inorganic salts, the mass percentages of NaCl, CaCl2, MgCl2·6H2O, KCl, Na2SO4, and NaHCO3 were 65.73%, 30.89%, 1.53%, 1.31%, 0.14%, and 0.40%, respectively, with a total mass percentage of 100%. The simulated high-salinity formation water was then used as the base fluid for clean fracturing fluid. A clean fracturing fluid thickener, J-TO, was added, and the mixture was continuously magnetically stirred at room temperature to ensure thorough dispersion and a homogeneous system. The mass fraction of J-TO was controlled between 0.5% and 2.0%, with a preferred mass fraction of 1.0%, thus obtaining a high-salinity clean fracturing fluid system for evaluating rheological and permeability properties.

[0029] (2) Preparation of clean fracturing fluid The J-TO thickener obtained in Example 1 was added to the simulated formation water to make its mass fraction 1.0%, and stirred at room temperature for 30 min to fully dissolve the system and form a homogeneous, transparent, and clean fracturing fluid.

[0030] (3) After standing for 30 minutes to degas, a clean fracturing fluid is obtained, which is used for subsequent rheological, permeation, interfacial tension and fracturing fluid performance tests.

[0031] Example 4 The steps in this embodiment are basically the same as those in embodiment 3, the only difference being that the J-LO thickener prepared in embodiment 2 is used.

[0032] Comparison Example The steps in this comparative example are basically the same as those in Example 3, except that an equal amount of commercially available hydroxypropyl guar gum (HPG) is used as a thickener.

[0033] Performance testing The performance of the clean fracturing fluids prepared in Examples 3, 4, and the control example was tested, including the following methods: (i) Temperature resistance and shear strength test results, fracturing fluid system variable shear test results, and dynamic frequency scanning results (1) Temperature resistance and shear resistance test: After the prepared clean fracturing fluid was allowed to stand for 30 minutes to eliminate air bubbles, approximately 25 mL of sample was added to the coaxial cylindrical fixture of the rheometer for testing. The test was conducted in constant shear mode at 170 s. - ¹At the shear rate, the temperature was raised to 110 °C and kept constant for 60 min, and the change in system viscosity over time was recorded in real time to evaluate the temperature resistance and shear resistance of the clean fracturing fluid system.

[0034] (2) Variable shear rheological test: The prepared clean fracturing fluid was added to the rheometer testing system, and shear rate scanning was performed in steady-state rheological mode at 25 °C. The shear rate was measured from 0.1 s⁻¹. - ¹ Gradually increase to 1000 s - ¹, each shear rate was maintained for 10 s, and the viscosity change of the system was recorded to evaluate the shear thinning characteristics and flow properties of the fracturing fluid system.

[0035] (3) Dynamic frequency scanning test: The prepared clean fracturing fluid was added to the parallel plate fixture of the rheometer, and strain scanning was first performed at 25 °C to determine the linear viscoelastic range of the system. Then, a fixed strain of 1% was selected, and frequency scanning was performed in the range of 0.1 to 10 Hz. At the same time, the storage modulus (G′) and loss modulus (G″) were measured to evaluate the internal network structure and viscoelastic properties of the system.

[0036] Experimental results are as follows Figure 1 - Figure 3 As shown, it can be seen that, by Figure 1 It can be seen that the J-TO clean fracturing fluid system at 170 s - ¹Under continuous shear conditions, as the temperature increases from room temperature to 110 ℃, the viscosity of the system gradually decreases and tends to stabilize. After continuous shearing at a constant temperature of 110 ℃ for 90 min, it still maintains a stable viscosity of about 50 mPa·s, indicating that the system has good temperature resistance and shear resistance, which can meet the requirements of the proppant-carrying fluid for rheological properties during fracturing operations.

[0037] Depend on Figure 2 It is evident that the J-TO system exhibits rapid viscosity response to shear changes during alternating high and low shear rates, quickly recovering to a higher level in the low shear phase. Even after three consecutive cycles, the viscosity recovery rate remains high, indicating excellent shear recovery and thixotropic properties. During fracturing operations, this system can reduce flow resistance under high shear pumping conditions and rapidly recover higher viscosity upon entering the fracture, thus improving proppant suspension and carrying capacity.

[0038] Depend on Figure 3It can be seen that within the frequency range of 0.01–10 Hz, the storage modulus (G′) of the J-TO system is consistently higher than the loss modulus (G″), and both change relatively smoothly with frequency, indicating that the system exhibits predominantly elastic behavior and forms a stable three-dimensional associative network structure. This network structure mainly originates from the hydrophobic association between long-chain hydrophobic groups in the molecule and the hydrogen bonding effect formed by the polyhydroxy bridging structure. Both synergistically enhance the spatial network strength of the system, giving the fracturing fluid good structural stability and proppant carrying capacity.

[0039] comprehensive Figures 1-3 It can be seen that, compared with the J-LO system without bridging modification and traditional HPG fracturing fluid, the J-TO system exhibits more stable rheological properties in terms of temperature resistance, shear resistance, shear recovery, and viscoelastic properties. This indicates that the introduction of the multi-hydroxyl bridging structure can effectively enhance intermolecular association and improve the network stability of the system, thereby giving the fracturing fluid better comprehensive rheological properties and making it more suitable for clean fracturing operations in medium- and high-temperature reservoirs.

[0040] (II) Immersion capacity test: The volumetric method was used to evaluate the impact of different clean fracturing fluid treatments on the recovery rate of core samples to assess their permeability. The process included the following steps: After the core samples were cleaned, they were dried in an electric heating drying oven at 105°C until constant weight, and the mass of the dried core was recorded as m3. Then, the dried core was completely immersed in simulated reservoir oil and subjected to vacuum aging treatment at 60°C for 2-4 weeks. After aging, the core was removed and residual floating oil was cleaned from its surface, and the mass of its saturated oil was measured as m4. Next, the core was transferred into a percolation bottle with an accuracy of 0.1 mL. Under a constant temperature of 60°C, the volume of simulated oil replaced by the narrow neck of the percolation bottle was periodically observed and recorded as Vt. Based on the recorded percolation oil volume at different times, the spontaneous percolation efficiency under 60°C conditions was calculated using formula (1).

[0041] (1) Where: m3—core weight (g); m4—core weight after saturation with aged oil (g); ρ o —Simulated oil density (g / mL); V t —The volume (mL) of simulated oil that the core absorbs at time t. R1—The permeation efficiency of the core sample at time t in the volumetric method test.

[0042] The relationship between capillary rise height and concentration was determined for three clean fracturing fluids under the same core conditions. The experimental results are as follows: Figure 4As shown, the J-TO system exhibits a higher cumulative oil recovery rate, with a significantly higher adsorption rate than the HPG and J-LO systems within the same adsorption time. Analysis suggests that the polyhydroxy bridging structure enhances the system's interaction with the rock surface, while the long-chain hydrophobic groups effectively reduce the oil-water interfacial tension, making it easier for fracturing fluid to enter the matrix pores. This promotes crude oil migration towards the fractures and increases the degree of matrix mobilization after fracturing.

[0043] Furthermore, based on the above experiments, the oil-water interfacial tension and rock contact angle after using three different clean fracturing fluids were tested. This included: ① Oil-water interfacial tension test procedure: During the seepage process, the non-wetting and wetted phases within the core are mainly affected by gravity and capillary forces. However, tight oil reservoirs are characterized by low porosity, low permeability, and capillary forces that are much greater than gravity. Therefore, the main driving force during the seepage process can be considered to be capillary force. The expression for capillary force is: (1) Where: P—capillary force (unit: N); σ—oil-water interfacial tension (unit: mN / m); θ—contact angle of water on the core surface in the oil-water permeation system (unit: º); r—capillary radius (unit: μm).

[0044] From formula (1), it can be seen that capillary force is mainly related to capillary radius, contact angle, and oil-water interfacial tension. However, the capillary radius is determined by the degree of rock porosity development. Therefore, the magnitude of capillary force can only be affected by changing the oil-water interfacial tension and contact angle. The greater the oil-water interfacial tension, the stronger the capillary force and the stronger the seepage drive. The more hydrophilic the rock surface and the smaller the contact angle, the stronger the capillary force and the stronger the seepage drive.

[0045] Tight sandstone cores contain numerous micro-throats. During the seepage process, there is not only driving force but also flow resistance caused by crude oil viscosity and the "Jamin effect." The seepage process requires overcoming the adhesion work involved in the oil droplet detaching from the core surface, thus making the crude oil flowable and extractable. The expression for the adhesion work of the oil droplet is: (2) Where: W—adhesion work required for oil droplets to detach from the rock surface (unit: mJ); σ—interfacial tension between oil and water (unit: mN / m); θ—contact angle of water on the core surface in the oil-water permeation system (unit: º).

[0046] As can be seen from formula (2), the adhesion work required for an oil droplet to detach from the core surface is determined by both the oil-water interfacial tension and the contact angle. The smaller the oil-water interfacial tension, the smaller the adhesion work, and the easier it is for the oil droplet to detach from the rock surface; the smaller the contact angle, the smaller the adhesion work, and the easier it is for the oil droplet to detach from the rock surface.

[0047] According to formulas (1) and (2), increasing the oil-water interfacial tension can enhance capillary force, but at the same time, the adhesion work of oil droplets detaching from the rock surface will also increase; if the oil-water interfacial tension is reduced, although the adhesion work can be reduced, the infiltration and adsorption force will also be weakened.

[0048] (III) Evaluation of interfacial tension: In capillary adsorption and oil displacement processes, surfactants can effectively reduce the oil-water interfacial tension, thereby weakening the adsorption work of oil droplets on the reservoir rock surface, promoting droplet deformation to reduce the seepage resistance as it passes through micropore throats, and ultimately improving oil recovery. The oil-water surface tension test results of the three prepared breaker solutions at different concentrations are shown in Table 1 below. Figure 5 .

[0049] Table 1. Interfacial tension test results (mN / m)

[0050] from Figure 5 As can be seen, all three systems exhibited good interfacial activity, with the oil-water interfacial tension showing a pattern of initial sharp decrease followed by a gradual plateauing as the surfactant mass fraction increased. The oil-water interfacial tension of the simulated formation water without surfactant was 45.37 mN / m; when the surfactant mass fraction in the breaker was 0.1 wt%, the oil-water interfacial tension of the system decreased significantly to around 2 mN / m. Subsequently, with further increases in mass fraction, the interfacial tension gradually stabilized. A horizontal comparison shows that, under the same concentration conditions, the overall ability of the three breakers to reduce oil-water interfacial tension is ranked as follows: J-TO > HPG > J-LO.

[0051] ② Rock contact angle test procedure: 1) The core was subjected to continuous ultrasonic cleaning in sequence using carbon tetrachloride, a mixed cleaning solution (acetone, ethanol, and benzene in a mass ratio of 15:15:70), dilute hydrochloric acid, and hydrofluoric acid. The purpose was to thoroughly remove all kinds of adsorbed impurities from the solid surface. 2) Rinse the solid surface repeatedly with deionized water, then place it in an electric heating drying oven and dry at a constant temperature of 105°C for 30 minutes. Immediately after removal, transfer it to a desiccator and seal it for storage to prevent secondary contamination. 3) Prepare reservoir simulation oil by thoroughly mixing asphalt, kerosene and crude oil in a mass ratio of 3:5:2. Immerse the sealed core samples from step 2) in the simulation oil and perform a closed aging treatment at a constant temperature of 60°C in a vacuum environment for 2 to 4 weeks to simulate the actual wetting conditions of the reservoir. 4) Remove the aged core, remove any deposits adhering to the surface, wipe off any residual oil, and allow it to air dry naturally. After air drying, soak it in different concentrations of gelling solution for a period of time; 5) Use a contact angle meter to test the three-phase contact angle of deionized water-core-air in aged rock cores that are not soaked, soaked for 12 h, and soaked for 24 h. Take the average value of the three tests.

[0052] Experimental results are as follows Figure 6 As shown, the natural rock cores after crude oil aging treatment are oil-wet with a contact angle of approximately 120°. Immersing them in different concentrations of breaking agents resulted in varying degrees of decrease in the contact angle of the core surface, with the decrease increasing with the mass fraction of the breaking agent. Comparing the three systems, J-LO breaking agent showed a relatively smaller improvement in core wettability. After 12 hours of immersion, the contact angle was generally still greater than 90°; cores immersed in low-concentration J-LO were in a neutral wettable state, while cores immersed in high-concentration J-LO only began to show water-wet characteristics. In contrast, J-TO and HPG breaking agents exhibited stronger wetting reversal capabilities, with roughly the same trend in contact angle decrease. After 24 hours of thorough immersion, the core contact angle significantly decreased to between 40° and 70°, and the higher the concentration of the breaking agent, the smaller the contact angle, indicating that the aged rock cores had successfully transitioned from oil-wet to water-wet.

[0053] Analysis suggests that the surfactant molecules in the breaking fluid can effectively adsorb onto the solid-liquid interface of the rock, peeling off the oil film attached to the surface of the rock pores and exposing the hydrophilic core matrix, thus altering the wettability of the reservoir rock.

[0054] In summary, the embodiments of the present invention provide a multi-hydroxyl-bridged permeation-absorbing thickener, its preparation method, and its application. The multi-hydroxyl-bridged thickener molecule prepared by the present invention simultaneously contains long-chain hydrophobic groups, multi-hydroxyl structures, and amine linkage units. In aqueous solution, it can form a spatial network structure through hydrophobic association and hydrogen bonding, exhibiting good thickening performance. At the same time, it has certain surface activity, which can reduce the oil-water interfacial tension and improve reservoir wettability, thereby enhancing permeation capacity. The clean fracturing fluid synthesized from the polyhydroxy bridging thickener prepared in this invention can rapidly form an oil-water displacement interface in the reservoir pores after entering the fracture, promoting spontaneous adsorption of the fracturing fluid into the deeper matrix and enhancing its spontaneous adsorption capacity into the matrix pores, thus achieving synergistic production enhancement through fracturing and adsorption. Compared with traditional polymer fracturing fluids, this clean fracturing fluid not only has excellent proppant-carrying capacity but also further expands the effective working volume of the fracturing fluid, improving reservoir utilization; moreover, the fracturing fluid system does not contain polymer residues, causing minimal damage to the reservoir and exhibiting good environmental compatibility and application prospects.

[0055] The embodiments described above are some, but not all, embodiments of the present invention. The detailed description of the embodiments of the present invention is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort are within the scope of protection of the present invention.

Claims

1. A multi-hydroxyl-bridged permeation-absorbing thickener, characterized in that, The structure of the thickener is shown in Formula I: Formula I; Where R represents an alkyl or alkenyl group with more than 16 carbon atoms.

2. A method for preparing the polyhydroxy-bridged thickener as described in claim 1, characterized in that, Includes the following steps: S1. Long-chain fatty acids and N-methyl-1,3-propanediamine are mixed in a molar ratio of 1:1.05-1.2 and then subjected to an amidation reaction under anaerobic conditions to obtain long-chain fatty acid aminations containing secondary amine structures. S2. The long-chain fatty acid amination and 1,4-butanediol diglycidyl ether are dissolved in an organic solvent at a molar ratio of 2-2.2:1 to carry out a ring-opening reaction, thereby obtaining a clean fracturing fluid thickener.

3. The preparation method according to claim 2, characterized in that, Step S1 also includes adding a catalyst, wherein the catalyst is sodium hydroxide or sodium methoxide.

4. The preparation method according to claim 3, characterized in that, The temperature conditions for the amidation reaction are 140-150℃.

5. The preparation method according to claim 4, characterized in that, In step S2, the ring-opening reaction includes: first dissolving the amination of the long-chain fatty acid in the organic solvent and heating it to 50-60°C, then adding the 1,4-butanediol diglycidyl ether dropwise to the reaction system and continuing the reaction by heating.

6. The preparation method according to claim 5, characterized in that, The organic solvent is isopropanol or ethanol, and the final temperature of the ring-opening reaction is 68-72°C.

7. The application of the polyhydroxy-bridged thickener as described in claim 1 in the preparation of clean fracturing fluid, characterized in that, The thickener accounts for 0.5%-2.0% of the total mass of the clean fracturing fluid.

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