Oil and gas well sand stabilizing and permeability increasing treatment agent and preparation method and application thereof

Abstract

The invention discloses an oil and gas well sand stabilizing and permeability increasing treatment agent and a preparation method and application, and relates to the technical field of oil and gas development, the treatment agent is prepared by mixing and matching the following components: 85%-95% of SCF-A, 3%-8% of a dispersing aid, 1%-5% of a stabilizer and the balance of deionized water, the SCF-A is prepared from the following raw materials: 6.8%-9.5% of an initiator, 45%-49% of ethylene oxide, 17.9%-21.5% of propylene oxide, 5.8%-7.5% of an esterified monomer, 12%-15.2% of a sulfonating reagent and 0.06%-0.08% of a basic catalyst, 0.09%-0.1% of an acidic catalyst, 0.03%-0.04% of a polymerization inhibitor, 2%-2.4% of a dispersion medium, 0.2%-0.3% of an acidic neutralizer and 2.1%-2.4% of an alkaline neutralizer; the zwitter-ion structure of the core component SCF-A can accurately adjust the Zeta potential of particles, migration of sand, pulverized coal, clay particles and the like can be effectively inhibited, reservoir pores can be guaranteed through the steric hindrance effect, the oil and gas permeability is improved, and the contradictory problem that sand stabilization and permeation enhancement cannot be considered at the same time in a traditional sand prevention technology is solved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, specifically to an oil and gas well sand stabilizing and permeability enhancing agent, its preparation method, and its application. Background Technology

[0002] Hydraulic fracturing is a core method for enhancing production in unconventional oil and gas reservoirs: high-pressure fluids split complex fracture networks in coal / shale, proppant enters with the fluid and expands the fractures, forming long-term flow channels, thereby overcoming the low permeability bottleneck caused by "nanopores + microfractures". However, in actual development, the common problem is that "it can be fractured and expanded, but not stabilized". Once a fractured well is put into production, particle migration and sand production become the biggest pain point throughout its entire life cycle, mainly manifested in the following aspects: 1. In the early stage of flowback, the high-speed fluid flow shears and carries unconsolidated proppant and microparticles, which easily erodes the near-wellbore area and buries perforation holes; 2. During the production period, the bottom hole pressure decreases and the effective stress increases, causing microparticles to be generated and block fractures. Especially for coal reservoirs, the skeleton is easily stripped to generate new coal dust, which accumulates in the fracture throat to form micron-level irreversible blockage; 3. In the middle and late stages of production, the water cut of most fractured wells increases, the water phase permeability increases, further eroding the proppant-filled layer, the flow capacity drops sharply, and eventually the well is forced to be shut down for workover.

[0003] Existing sand control technologies each have their shortcomings: mechanical sand control (screen pipes, gravel filling) has a sand-coal powder retention efficiency of less than 60% and is prone to self-clogging; resin bonding can solidify the sand body, but the bonding reaction fills 30-50% of the pores at the same time, and it is more prone to brittleness in high clay environments (>8%); artificial well walls and composite sand control processes are complex, costly, and cannot cope with secondary sand production after stress redistribution.

[0004] Ultimately, traditional mechanical sand control technologies are ill-suited to address the migration of fine particles, while commonly used chemical treatment agents stabilize sand and plug pores, especially in salt-tolerant environments (such as coal and rock reservoirs where formation water levels can reach 20 × 10⁻⁶). 4 mgL -1 The existing sand control and permeability enhancement agents have significant shortcomings in terms of compatibility and formation damage, making it difficult to meet the "sand stabilization and permeability preservation" requirements under deep, high-salt, and complex stress conditions. Therefore, developing a new type of sand control and permeability enhancement agent that stabilizes sand, efficiently solidifies micro-powders, does not plug cracks, has strong salt resistance, good compatibility with working fluids, is easy to construct, and is environmentally friendly has become an urgent issue for the sustainable development of oil and gas reservoirs, and is of great strategic significance for promoting the efficient, green, and sustainable development of oil and gas reservoirs. Summary of the Invention

[0005] In view of this, the present invention provides a sand stabilizing and permeability enhancing agent for fracturing and producing oil and gas wells, which effectively inhibits the migration of sand particles, coal dust, clay particles, etc. in oil and gas wells, prevents fracture blockage and proppant flowback; ensures the stability and high conductivity of the propping filling layer, while improving oil and gas permeability and reducing water phase permeability; is suitable for oil and gas wells with high salinity flowback fluid conditions; has a simple construction process, no formation damage, and low construction risk, and is suitable for fracturing well enhancement and production well remediation.

[0006] To achieve the above objectives, the technical solution adopted by the present invention is as follows: This invention discloses an oil and gas well sand stabilizing and permeability enhancing agent, which comprises the following components by mass fraction: SCF-A 85%~95% Dispersing agent 3%~8% Stabilizer 1%~5% The remaining amount is deionized water; The chemical structural formula of SCF-A is: R1-N-[(CH2CH2O)] m -(CH2CH(CH3)O) n -R2-SO3 - R3 + ]2, where R1 is a straight-chain aliphatic hydrocarbon, R2 is an ester-containing group, and R3 is a chain of ester groups. + It is a metal cation, and m = 10~15, n = 3~5.

[0007] The treatment agent is prepared by compounding and mixing the above materials.

[0008] SCF-A is a tertiary amine Gemini polymer containing bisymmetric polyether-ester-sulfonate branches, which is characterized by a terminal -SO3 - R3 + Hydrogen bonds are formed with -OH groups on the particle surface, and oxygen atoms in the polyether chain react with Si. 4+ / Al³ + It forms coordination bonds to achieve "two-point anchoring," resulting in strong and irreversible adsorption, superior to single-chain structures. Simultaneously, its bi-branched "flat" arrangement and the entangled polyether chains form a three-dimensional cross-linked coating, balancing sand stabilization and flow-through pores. Furthermore, the disulfonate groups enhance charge density, and the terminal straight-chain arrangement of -SO3... - R3 + Excellent contact properties allow the zeta potential of sand particles to be adjusted to the optimal stable range, reducing repulsion and increasing aggregation stability. In contrast, single-chain branched sulfonate structures may have poor contact properties and easily lead to pore blockage in the membrane layer. The steric hindrance of the di-polyether segments can effectively intercept micro powders, while single-chain structures are difficult to achieve this function.

[0009] In one embodiment of the present invention, the dispersing agent is isomeric decaol polyoxyethylene ether XP30, and the stabilizer is vinyltrimethylsilane.

[0010] One embodiment of the present invention is that, by mass fraction, the raw material of SCF-A comprises the following components: Initiator 6.8%~9.5% Ethylene oxide 45%~49% Propylene oxide 17.9%~21.5% Esterified monomers: 5.8%–7.5% Sulfonating agent 12%~15.2% Alkaline catalyst 0.06%~0.08% Acidic catalyst 0.09%~0.1% Polymerization inhibitor 0.03%~0.04% Dispersion medium 2%~2.4% Acid neutralizer 0.2%~0.3% Alkaline neutralizing agent: 2.1%~2.4%

[0011] Furthermore, the preparation method of the SCF-A includes the following steps: Step S1: Nitrogen is purged through the initiator and alkaline catalyst under sealed conditions to remove oxygen. Then, the mixture is stirred at 300 r / min at 120℃~130℃, and ethylene oxide is added at a rate of 0.5 mol / h~1.0 mol / h. The reaction is maintained at 0.3 MPa~0.5 MPa for 2h~3h until the pressure drops below 0.1 MPa and stabilizes. The core function of ethylene oxide is to form strongly hydrophilic segments. Replacing it with other ethylene oxides may result in insufficient hydrophilicity, making it unable to disperse in highly saline solutions and reducing compatibility.

[0012] Step S2: Keep the stirring rate constant, add propylene oxide at a rate of 0.3 mol / h to 0.5 mol / h at 110℃ to 120℃, and keep the reaction at 0.2 MPa to 0.4 MPa for 1.5 h to 2 h until the pressure drops below 0.1 MPa and stabilizes; The methyl branches of propylene oxide are key to the steric hindrance effect. Replacing it with other propylene oxides, such as ethylene oxide, may cause the adsorption layer to detach due to excessive hydrophilicity. Replacing it with other branched propylene oxides, such as isobutane, will excessively increase the steric hindrance and block the reservoir pores.

[0013] Step S3: Cool to 80℃, add acidic neutralizing agent and stir for 30 minutes to adjust to neutral, filter under reduced pressure to remove salt impurities, and collect the pale yellow transparent liquid intermediate A; Step S4: Add esterification monomer, acid catalyst, polymerization inhibitor and dispersion medium to intermediate A, stir and reflux at 80℃~85℃ for 4h~6h, and continue to separate water until no obvious water is produced to complete the reaction; Step S5: After cooling to 40℃, slowly add an alkaline neutralizing agent to adjust the pH of the reaction solution to between 7.0 and 7.3. After standing for 30 minutes to separate the layers, discard the lower aqueous phase and wash with deionized water at least twice. Each time, let the solution stand for 30 minutes to separate the layers and discard the aqueous phase. Collect the remaining organic phase and distill it under reduced pressure at a vacuum of 0.08MPa to 0.09MPa and a temperature of 70℃ to 80℃ to obtain a pale yellow viscous liquid intermediate B. Step S6: Intermediate B and sulfonating reagent are stirred at 250 r / min for 3 h to 4 h at 90℃~95℃, and then cooled to 50℃. During the reaction, the progress of the sulfonation reaction can be detected in real time by Fourier transform infrared spectroscopy (FT-IR). After the sulfonation reaction is completed, water is added to dissolve and stirred for 30 min. The brownish-red transparent liquid is collected by vacuum filtration.

[0014] Furthermore, the initiator is C 10 ~C 14 One of the linear aliphatic primary amines, preferably dodecylamine; The esterifying monomer is either acrylic acid or methacrylic acid; The sulfonating agent is either sodium 2-hydroxyethanesulfonate or potassium 2-hydroxyethanesulfonate. The sulfonating agent and intermediate 2 undergo a nucleophilic addition reaction. Based on the weakly basic system remaining after neutralization in step S5, the nucleophilicity of the hydroxyl group is suppressed, ensuring that the sulfonate group attacks the double bond and forms a C-C single bond. The alkaline catalyst is either sodium hydroxide or potassium hydroxide; The acid catalyst is either p-toluenesulfonic acid or pyridine p-toluenesulfonate; The polymerization inhibitor is one of hydroquinone, tert-butylcatechol, or 2,6-di-tert-butyl-p-cresol; The dispersion medium is one of methanol, ethanol, and isopropanol; The acid neutralizer is either phosphoric acid or formic acid; One of the alkaline neutralizing agents: sodium carbonate solution or sodium hydroxide solution.

[0015] Furthermore, the present invention also discloses the application method of the above-mentioned sand stabilizing and permeability enhancing agent for oil and gas wells. The treatment machine can be used for sand stabilizing and permeability enhancing in production wells and sand stabilizing and permeability enhancing in fractured wells. In the treatment of production wells, the mass fraction of the treatment agent added is 2% to 5%. In the enhancement of fractured wells, the mass fraction added throughout the process is 0.05% to 0.1%, and the mass fraction added at the end is 0.2% to 0.5%.

[0016] Furthermore, the specific method for using the treatment agent to stabilize sand and enhance permeability in production wells includes the following steps: Step 1: Well cleaning pretreatment; Step 2: Prepare a treatment solution containing 2%~5% by mass of treatment agent, and inject the treatment solution into the production layer within a 1-meter radius using a high-pressure pump. The injection rate is controlled at 0.5~1.0 m³ / min. The solvent of the treatment solution is a 2% KCl solution. Step 3: Inject 2% KCl solution to further flush the pipeline, pushing all the treatment fluid into the depth of the reservoir to ensure that the treatment fluid is in full contact with the reservoir; Step 4: Close the well and let it sit for 24-48 hours to allow the treatment agent to fully react with the sand, coal dust, and clay particles; Step 5: Slowly start production and gradually adjust output to the optimal production state.

[0017] Furthermore, the specific method for using the treatment agent to stabilize sand and enhance permeability in fractured wells includes the following steps: Step 1: Prepare fracturing fluid and treatment agent according to the specified ratio; Step 2: Use a treatment agent accounting for 0.05% to 0.1% of the total mass of the fracturing fluid throughout the fracturing operation; Step 3: After each stage of fracturing is completed, inject fracturing fluid containing 0.2% to 0.5% of the treatment agent relative to the volume of the flushing fluid. Step 4: Routine flowback after fracturing is completed.

[0018] The technical advantages of this invention are as follows: (1) The zwitterionic structure of the core component SCF-A can precisely adjust the particle zeta potential, which can effectively inhibit the migration of sand, coal powder, clay particles, etc. (inhibition rate ≥85%), and can also ensure reservoir porosity through the steric hindrance effect, improve oil and gas permeability, and overcome the contradiction that traditional sand control technology cannot simultaneously stabilize sand and increase permeability. (2) The synthesis of SCF-A adopts a three-step directional reaction of "alkoxylation-esterification-sulfonation". The process parameters are clear, the reaction conditions are mild, and it is easy to scale up to industrial scale. By adjusting the mass ratio of ethylene oxide / propylene oxide, the molecular hydrophilic-hydrophobic balance and charge distribution can be flexibly optimized to adapt to the geological conditions of different oil and gas reservoirs. (3) The treatment agent is suitable for pH values ​​of 5 to 11 and can withstand saline and flowback fluids with a salinity of ≤200,000 mg / L. It is suitable for oil and gas wells in various reservoir types such as mudstone, tight oil reservoirs, coal and sandstone. (4) The treatment agent is water-dispersible and is fully compatible with conventional fracturing fluids, requiring no additional special equipment. The application process is divided into two categories: production well repair and fracturing construction. The process is simple, without the curing risk of resin bonding and without the complex construction problems of mechanical sand control. (5) The core component SCF-A forms a semi-permanent coating on the proppant and sand surface. The constructed stable matrix can maintain its integrity as the reservoir moves. The effective period after the production well is repaired is ≥1 year. The sand stabilization and permeability enhancement effect of the fracturing well lasts throughout the entire production cycle. (6) The treatment agent does not contain harmful components such as fluorine and heavy metals. The surface tension of the de-gelling liquid is low and the backflow liquid has little impact on the environment. It does not block the reservoir pores during construction, and the core permeability recovery rate is ≥25%, which does not damage the formation. Attached Figure Description

[0019] Figure 1 (a) is a SEM image of quartz sand particles before the addition of the treatment agent of Example 1 in the sand-aggregating capacity test of the present invention; Figure 1 (b) is a SEM image of quartz sand particles after adding the treatment agent of Example 1 in the sand-aggregating capacity test of the present invention; Figure 1 Image (c) is a SEM image of fine sand particles before the addition of the treatment agent from Example 1 in the maximum sand-free flow rate test of this invention; Figure 1 Image (d) is a SEM image of fine sand particles after adding the treatment agent of Example 1 in the maximum sand-free flow rate test of this invention; Figure 2 This is a graph showing the comparison of the sand-aggregating ability between the sample with the treatment agent prepared in Example 2 and the blank sample in the sand-aggregating ability test of the present invention. Figure 3 The contact angle test results are shown in the figure before and after the coal and rock surfaces were treated with the treatment agent prepared in Example 4 in the contact angle test of this invention. Detailed Implementation

[0020] The present invention will be further described in detail below with reference to the embodiments. However, the implementation of the present invention is not limited thereto. Unless otherwise specified, the experimental methods used in the following embodiments are conventional methods, and the materials and reagents used are commercially available unless otherwise specified.

[0021] Example 1: By mass fraction, 90% SCF-A, 5% isomeric decayl alcohol polyoxyethylene ether XP30, 3% vinyltrimethylsilane, and 2% deionized water were mixed and stirred for 30 min at 25℃ and 200 r / min to obtain a uniform and stable brownish-red amine-odor liquid treatment agent.

[0022] The raw materials and proportions for preparing SCF-A, by mass fraction, are shown below: The composition of the catalyst is as follows: dodecylamine 8.14%, ethylene oxide 46.42%, propylene oxide 20.4%, esterification monomer acrylic acid 6.64%, sulfonation reagent sodium 2-hydroxyethanesulfonate 13.66%, basic catalyst potassium hydroxide 0.06%, acidic catalyst p-toluenesulfonic acid 0.09%, polymerization inhibitor hydroquinone 0.03%, dispersion medium anhydrous ethanol 2.08%, acid neutralizer 85% phosphoric acid solution 0.25%, and basic neutralizer 5% sodium carbonate solution 2.23%.

[0023] The specific synthesis steps are as follows: (1) Add dodecylamine and potassium hydroxide quantitatively to a 500mL high-pressure reactor. After closing the reactor, replace the air in the reactor with nitrogen three times (each replacement pressure is 0.3MPa, and the pressure is maintained for 5min) to completely eliminate the interference of oxygen on the alkoxylation reaction. Start the reactor heating system and mechanical stirring device to raise the temperature in the reactor to 120℃. Set the stirring rate to 300r / min. Under these conditions, slowly introduce ethylene oxide at a rate of 0.5mol / h and maintain the reaction pressure in the range of 0.4MPa. After the introduction is completed, continue to keep the reaction at the temperature for 2h until the pressure in the reactor drops below 0.1MPa and stabilizes. (2) Lower the temperature inside the reactor to 110°C, keep the stirring rate constant, slowly introduce propylene oxide, control the introduction rate to 0.3 mol / h, maintain the reaction pressure at 0.3 MPa, and keep the reaction at the temperature for 2 hours after the introduction is completed until the pressure inside the reactor stabilizes below 0.1 MPa. (3) Stop heating and wait for the temperature inside the reactor to drop to 80°C. Add 85% phosphoric acid solution to the reaction system and stir for 30 min to neutralize the potassium hydroxide in the system. Remove the generated potassium phosphate salt by vacuum filtration to obtain a light yellow transparent liquid dodecylamine polyoxyethylene-polyoxypropylene ether (AEOP), i.e. intermediate A.

[0024] (4) Add the prepared AEOP, acrylic acid, p-toluenesulfonic acid, hydroquinone and anhydrous ethanol to a 250mL three-necked flask in sequence. Assemble a water separator, reflux condenser and precision thermometer to construct the esterification reaction apparatus. Start the heating device and stir to raise the temperature of the reaction system to 85℃ and keep it under reflux for 5h. The water generated during the reaction is continuously separated by the water separator until no obvious water is released. The esterification reaction is then determined to have reached the endpoint. (5) Stop heating and wait for the system temperature to drop to 40℃. Then slowly add 5% sodium carbonate solution to adjust the pH of the reaction solution to 7.0~7.3 (residual HCO3). - / CO3² -The buffer system was used as a catalyst for the subsequent sulfonation reaction. After standing for 30 minutes, the system separated into layers. The lower aqueous phase (containing unreacted sodium carbonate and generated salt impurities) was discarded. The organic phase was washed twice with 30 mL of deionized water. After each wash, the system was allowed to stand and separate into layers, and the aqueous phase was discarded. The organic phase was then placed in a vacuum distillation apparatus (vacuum degree 0.08~0.09 MPa, distillation temperature 70℃) to remove anhydrous ethanol and unreacted acrylic acid monomers from the system, yielding a pale yellow viscous liquid, dodecylamine polyoxyethylene-polyoxypropylene ether acrylate (AEOP-AC), i.e., intermediate B.

[0025] (6) Add the prepared AEOP-AC and sodium 2-hydroxyethanesulfonate to a 250 mL three-necked flask, assemble a stirrer, thermometer, and reflux condenser, start stirring and heat to 90 °C, set the stirring rate to 250 r / min, and maintain the temperature for 4 h; the reaction is monitored in real time using Fourier transform infrared spectroscopy (FT-IR), and when the spectral density reaches 1190 cm⁻¹... - A sulfonic acid group (-SO3) appears at position ¹. - When the characteristic stretching vibration peak of ) is observed and its intensity is stable, the sulfonation reaction is considered complete. Heating is stopped, and when the system temperature drops to 50°C, an appropriate amount of deionized water is added. The mixture is stirred for 30 minutes to fully dissolve the product. A small amount of unreacted sodium 2-hydroxyethane sulfonate solid impurities are removed by vacuum filtration to obtain a brownish-red transparent liquid—dodecylamine polyoxyethylene-polyoxypropylene ether acrylate sulfonate (SCF-A).

[0026] Example 2: The implementation method of this embodiment is basically the same as that of Embodiment 1, except that the raw material ratio for preparing the treatment agent in this embodiment is as follows: By mass fraction, it contains 88% SCF-A, 5% isomeric deca-ol polyoxyethylene ether XP30, 3% vinyltrimethylsilane, and 2% deionized water.

[0027] The raw material ratio for preparing SCF-A is as follows: By mass fraction, the initiator is dodecylamine 9.53%, ethylene oxide 45.32%, propylene oxide 17.92%, esterification monomer acrylic acid 7.41%, sulfonation reagent sodium 2-hydroxyethanesulfonate 15.13%, alkaline catalyst potassium hydroxide 0.06%, acidic catalyst p-toluenesulfonic acid 0.09%, polymerization inhibitor hydroquinone 0.03%, dispersion medium anhydrous ethanol 2.03%, acid neutralizer 85% phosphoric acid solution 0.3%, and alkaline neutralizer 5% sodium carbonate solution 2.18%.

[0028] Example 3: The implementation method of this embodiment is basically the same as that of Embodiment 1, except that the raw material ratio for preparing the treatment agent in this embodiment is as follows: By mass fraction, it contains 92% SCF-A, 4% isomeric deca-ol polyoxyethylene ether XP30, 2% vinyltrimethylsilane, and 2% deionized water.

[0029] The raw material ratio for preparing SCF-A is as follows: By mass fraction, the initiator is dodecylamine 6.83%, ethylene oxide 48.72%, propylene oxide 21.41%, esterification monomer acrylic acid 5.84%, sulfonation reagent sodium 2-hydroxyethanesulfonate 12.13%, alkaline catalyst potassium hydroxide 0.06%, acidic catalyst p-toluenesulfonic acid 0.1%, polymerization inhibitor hydroquinone 0.03%, dispersion medium anhydrous ethanol 2.33%, acid neutralizer 85% phosphoric acid solution 0.21%, and alkaline neutralizer 5% sodium carbonate solution 2.34%.

[0030] Example 4: The implementation method of this embodiment is basically the same as that of Embodiment 1, except that the raw material ratio for preparing the treatment agent in this embodiment is as follows: By mass fraction, it contains 91% SCF-A, 5% isomeric deca-ol polyoxyethylene ether XP30, 3% vinyltrimethylsilane, and 1% deionized water.

[0031] The raw material ratio for preparing SCF-A is as follows: By mass fraction, the initiator is dodecylamine 7.79%, ethylene oxide 48.16%, propylene oxide 19.54%, esterification monomer acrylic acid 6.36%, sulfonation reagent sodium 2-hydroxyethanesulfonate 13.08%, alkaline catalyst potassium hydroxide 0.06%, acidic catalyst p-toluenesulfonic acid 0.09%, polymerization inhibitor hydroquinone 0.03%, dispersion medium anhydrous ethanol 2.32%, acid neutralizer 85% phosphoric acid solution 0.24%, and alkaline neutralizer 5% sodium carbonate solution 2.33%.

[0032] Comparative Example 1: By mass fraction, 90% dodecylmethyl (2-sulfonate sodium methyl hydroxypropyl) polyoxypropylene polyoxyethylene ether amine, 5% isomeric decaol polyoxyethylene ether, 3% vinyltrimethylsilane, and 2% deionized water were mixed and stirred for 30 minutes at 25°C and 200 r / min.

[0033] The raw materials and proportions for preparing dodecylmethyl (2-sulfonate sodium methyl hydroxypropyl) polyoxypropylene polyoxyethylene ether amine by mass fraction are shown below: N Dodecyl methylamine 5.88%, 3 chlorine 2 Sodium hydroxypropanesulfonate 4.64%, ethylene oxide 3.43%, propylene oxide 2.6%, ethanol 58.77%, xylene 23.51%, sodium hydroxide 1.17%.

[0034] The specific synthesis steps of dodecylmethyl (2-sulfonate sodium methyl hydroxypropyl) polyoxypropylene polyoxyethylene ether amine are as follows: (1) Add N to the four-necked flask Dodecyl methylamine, 3 chlorine 2 Sodium hydroxypropanesulfonate and ethanol were mixed, and the pH was adjusted to 8-9 with sodium hydroxide solution. The mixture was stirred and heated under reflux, and the pH was maintained at 8-9 during the reaction. After the reaction was completed, the mixture was distilled under reduced pressure to obtain a viscous solid. (2) Dissolve the above viscous solid by heating with xylene, transfer it to a high-pressure reactor, add the catalyst, and purge with nitrogen. Sweep the pipeline and reactor for 5 minutes, evacuate, add propylene oxide all at once, heat to 140°C, react, and cool the system to below 90°C with circulating cooling water. (3) Continue to introduce ethylene oxide at a rate of 2 ml / min. After the introduction is complete, raise the temperature to 140°C. After the reaction is complete, use circulating cooling water to cool the system to room temperature, filter, and adjust the pH to 8-9 with hydrochloric acid to obtain the xylene solution of the product. (4) The xylene solution of the above product was decolorized with activated carbon at 60°C and distilled under reduced pressure to obtain the product dodecylmethyl (2-sulfonate methyl hydroxypropyl) polyoxypropylene polyoxyethylene ether amine.

[0035] Performance testing I. Indoor Performance Evaluation The following performance tests were performed on each embodiment and comparative example, and the test methods are as follows: 1. Sand-gathering ability test Fracturing fluid containing 0.4% emulsion drag reducer and 0.03% APS was prepared, and 30 / 50 mesh quartz sand (sand ratio 30%) was added. Then, samples were prepared by adding different concentrations of the treatment agents from the examples and comparative examples. A blank sample without treatment agent was retained. The samples were heated at 70°C for 4 hours and then cooled. The fracturing fluid was poured out and inverted to observe the sand block aggregation state. The phenomenon of sand block scattering, collapse, or sand falling was recorded to qualitatively evaluate the sand aggregation stability. In Example 4, the treatment object was 200,000 mg / L brine.

[0036] 2. Particle migration inhibition rate test Mix 20 / 40 mesh quartz sand and silica powder at a mass ratio of 98:2, and fill the sand-filling tube in 5 portions. Compact the mixture by gently tapping until the porosity matches the target reservoir. Weigh the mixture using sieves at both ends. Connect the sand-filling tube to a core flow experiment apparatus and purge air using a 2% KCl solution at 3 mL / min for 30 minutes to achieve forward saturation. For the treatment group, inject twice the pore volume of 2% KCl solution containing the specified concentration of treatment agent from each example and comparative example (3 mL / min; Example 4 used 200,000 mg / L brine for testing). For the blank group, inject the same volume of 2% KCl solution without treatment agent. After the sand column is placed in a 70℃ oven and allowed to stand for 4 hours, flush it forward with a 2% KCl solution at 2 m³ / min for 2 hours (record the pressure; fluctuation ≤5% is considered stable). Collect the effluent through vacuum filtration, dry the filter membrane at 80℃ to constant weight, and record the mass as m² (the mass of the blank filter membrane is m0). The average of three parallel samples in each group was taken. The particle migration inhibition rate η = [(mass of solids collected in the blank group - mass of solids collected in the treatment group) / mass of solids collected in the blank group] × 100%; the mass of collected solids = m2 - m0 3. Contact Angle Test Coal and rock samples (taken from the target reservoir) were cut into 1cm × 1cm × 0.5cm thin slices, ultrasonically cleaned with anhydrous ethanol for 15 min to remove oil, rinsed three times with deionized water (5 min each time), vacuum dried at 80℃ for 2 h, and cooled for later use (the surface was dry, smooth, and free of impurities). Treatment agents for each example and comparative example were prepared using deionized water; the blank group used deionized water. The samples were fixed on a contact angle measuring instrument, and 5 μL of the prepared solution was vertically dropped into three different areas using a pipette. Immediately afterward, images were taken and calculated. Five points were measured for each group, and the average of the three values ​​after removing extreme values ​​was taken as the final contact angle.

[0037] 4. Core permeability recovery rate test Natural core samples from the target reservoir (φ25mm×50mm, matrix permeability 0.3~0.5mD) were cut and polished uniformly, dried at 80℃ for 2 hours, cooled, and weighed. A 2% KCl solution (200,000 mg / L brine was used in Example 4) was injected into a vacuum saturation device and saturated at 0.09 MPa for 24 hours. The samples were then dried, weighed, and the corresponding pore volume was calculated. The core sample was connected to a flow device, and the 2% KCl solution was forward-displaced at 0.1 mL / min for 30 minutes until the pressure stabilized. ΔP1 was recorded, and Darcy's law was used to calculate the basic permeability K1. A constant-pressure pump was used to inject 2% KCl solution containing a specified concentration of treatment agent at twice the pore volume. After standing for 24 hours, the sample was displaced at the same flow rate until the pressure stabilized. ΔP2 was recorded, and the post-treatment permeability K2 was calculated. .

[0038] 5. Maximum sand-free flow rate test 50μm fine sand was uniformly filled into the sand-filling tube and compacted until the porosity was consistent with the target reservoir. Screens were installed at both ends to prevent sand particles from overflowing. The blank group was directly saturated with tap water in the sand-filling tube. The treatment group was injected with the treatment agent solution, and after saturation, it was placed in a 70℃ constant temperature incubator for 16 hours to ensure that the treatment agent and fine sand fully interacted. The sand-filling tube was connected to the flow experiment device, and the high-pressure constant flow pump was started to inject tap water at an initial flow rate of 0.1mL / min. After stabilizing for 10 minutes, the pressure and permeability data were recorded. The injection flow rate was gradually increased in a gradient of 0.1mL / min, and each flow rate was stabilized for 10 minutes. At the same time, it was observed whether sand particles were produced at the outlet. When continuous sand production or pressure change (increase ≥50%) occurred at the outlet, the previous flow rate was recorded as the critical sand production flow rate, i.e., the maximum sand-free flow rate. The maximum sand-free flow rate and permeability changes of the blank group and the treatment group were compared to evaluate the sand stabilization effect of the treatment agent.

[0039] 6. Compatibility According to the actual proportion of fracturing construction, the treatment agent of the specified concentration of each example / comparative example was added to the viscous slick water. Three parallel samples were prepared for each group. 40 mL of the mixture was put into each colorimetric tube and the tube opening was sealed. The colorimetric tube was placed at room temperature of 25°C and allowed to stand for 24 h. The state of the mixture was observed at 0 h, 4 h, 8 h, 12 h and 24 h. Whether abnormal phenomena such as layering, precipitation, thickening, and gel breaking occurred were observed.

[0040] Table 1 Performance evaluation results of the treatment agent See Figures 1-3 Based on the performance evaluation results shown in Table 1 above, it can be seen that Example 1, using a 0.08% low-concentration formulation, balances sand-gathering capacity and fluidity, exhibits good compatibility with fracturing fluid, and achieves a maximum sand-free flow rate increase of 130%, meeting the process requirements for continuous addition throughout the fracturing process of new wells. It ensures sand stabilization without affecting the sand-carrying capacity of the fracturing fluid. In contrast, the branched sulfonate structure of Comparative Example 1 suffers from low adsorption strength, poor contact, and a tendency to cause pore blockage in the fracturing membrane.

[0041] In Example 2, m=10 and n=3, the chain segments are relatively short, and the treatment agent exhibits excellent flushing resistance at a high concentration of 3%. After heating at 70°C for 4 hours, it still showed no dispersion or collapse after rinsing with clean water 3 times, and the particle migration inhibition rate was 92.5%. It is suitable for the continuous water flow flushing scenario faced by medium-to-high water-cut production wells in long-term production.

[0042] The chain lengths of polyethylene oxide (m) and polypropylene oxide (n) significantly affect the overall performance of the treatment agent. In Example 3, m=15 and n=5, the polyethylene oxide chain segments are longer (stronger hydrophilicity) and the polypropylene oxide chain segments are longer (more significant steric hindrance effect), resulting in a particle migration inhibition rate of 95.7%, a core permeability recovery rate of 28.2%, and a maximum sand-free flow rate increase of 160%, demonstrating stronger particle control and permeability enhancement capabilities, and meeting the stringent requirements of repeated fracturing wells for fracture conductivity repair.

[0043] Example 4 is designed for high-salinity flowback fluid conditions. It still maintains a 90.8% particle migration inhibition rate and a core permeability recovery rate of 26% in 200,000 mg / L brine, and its sand-gathering ability does not decrease significantly. This fully verifies its excellent salt resistance and makes it suitable for oil and gas wells with a water salinity of 200,000 mg / L.

[0044] The product of Comparative Example 1 has a single-chain branched structure (non-Gemini), while the core components SCF-A in the examples are all tertiary amine Gemini double-chain structures. Comparative Example 1 contains only one polyether chain, with sulfonate groups connected by hydroxypropyl branches, lacking a synergistic effect of double chains. It can only achieve weak single-point adsorption and has no film-forming ability. Its particle mobility is only 42.1%, and the core permeability recovery rate is 12.4%, indicating poor sand-accumulating ability. This also shows that the "double-symmetric polyether-ester-sulfonate branch" is the core to achieving "strong adsorption, film-forming sand stabilization, and anti-clogging and permeability enhancement". Without this double-chain structure, even if similar amine raw materials and polyether segments are used, it is impossible to achieve both sand stabilization and permeability enhancement, resulting in a significant performance difference.

[0045] II. Field Application This application well is a vertical well with a vertical depth of 2565.4m and an elevation depth of 513.36m. The reservoir type is a typical coal-rock reservoir, characterized by low porosity and low permeability, with a matrix permeability of 0.45mD. The bottomhole stable temperature is 75℃, and the flowback fluid salinity reaches 170,000 mg / L, which is considered a high-salinity condition, placing stringent requirements on the salt resistance and compatibility of the fracturing fluid and treatment agent. The aim is to address the issues of coal powder production, proppant flowback, and decreased conductivity in coal-rock reservoirs by employing a sand-stabilizing and permeability-enhancing treatment agent. This well uses a variable viscosity slickwater system as the fracturing working fluid, with a formulation by mass fraction: 0.3% thickener + 0.1% flowback aid + 0.2% clay stabilizer + 0.05% breaker. This system possesses good proppant carrying capacity, drag reduction effect, and rapid breaker characteristics, making it suitable for high-salinity flowback fluid conditions and reducing formation damage.

[0046] The sand-stabilizing and permeability-enhancing agent prepared in Example 4 was selected, and a combination of "full-process addition + tail-end reinforcement" was adopted: 0.1% of the agent was added online throughout the fracturing operation to achieve comprehensive coverage of the entire stirred zone; after each fracturing operation, 0.4% of the agent was injected as a tail-end injection to focus on enhancing the sand stabilization and microstructure fixation effect in the perforated section and near-wellbore zone. The fracturing flow rate was controlled at 18~19 m³ / min, 20 / 40 mesh quartz sand was used as proppant, the proppant concentration was 40 kg / m³, and the cumulative proppant addition was 372 m³. During the operation, the pressure remained stable at 59.9~67 MPa, the fracturing curve was smooth, and no abnormal conditions such as sand blockage or pressure sudden changes occurred. The fracturing operation completion rate was 100%.

[0047] After fracturing operations, the well was shut in and left to stand for 24 hours as required by the process to ensure that the treatment agent fully interacts with the reservoir sand, coal dust, and proppant to form a stable adsorption film. After the stand was completed, the rupture fluid was flowed back using a conventional flowback process without any additional special procedures. The rupture fluid flowback rate reached 85%, and the flowback fluid was clear and transparent. Laboratory testing showed that no coal dust particles or proppant debris were detected in the flowback fluid, and the proppant backflow was zero. This demonstrates that the treatment agent has a significant effect on fixing the proppant and inhibiting coal dust aggregation, effectively avoiding particle migration problems during the flowback stage.

[0048] One month after production began, the daily gas production of a single well stabilized at 8.5 × 10⁻⁶. 4 m³, compared to the adjacent well that did not add this treatment agent (daily gas production of 5.2 × 10⁻⁶ m³ during the same period). 4 (m³), gas production increased by 63.5%; during 12 months of continuous production, gas production remained stable at 7.8×10 m³. 4 With a flow rate of over m³ / d, the maximum sand-free flow velocity during drainage is consistently maintained at 1.2 m / s. 3 With a flow rate exceeding [amount] / min, no production decline occurred due to sand production or fracture blockage, demonstrating outstanding production stability. This proves that the technology can effectively improve the permeability of coal and rock reservoirs, providing a stable guarantee for efficient oil and gas production.

[0049] In summary, this sand-stabilizing and permeability-enhancing treatment agent, through a scientific addition scheme, achieves the dual objectives of sand stabilization and microstructure fixation, as well as anti-blocking and permeability enhancement in fracturing operations of new oil and gas wells with high salinity. The construction process is simple and highly adaptable, providing a reliable technical reference for the efficient development of similar oil and gas reservoirs.

[0050] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be defined by the scope of the claims.

Claims

1. An oil and gas well sand stabilizing and permeability enhancing agent, characterized in that, By mass fraction, it includes the following components: SCF-A 85%~95% Dispersing agent 3%~8% Stabilizer 1%~5% The remaining amount is deionized water; The chemical structural formula of SCF-A is: R1-N-[(CH2CH2O)] m -(CH2CH(CH3)O) n -R2-SO3 - R3 + ]2, where R1 is a straight-chain aliphatic hydrocarbon, R2 is an ester-containing group, and R3 is a chain of ester groups. + It is a metal cation, and m = 10~15, n = 3~5.

2. The sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 1, characterized in that: The dispersing agent is isomeric decaol polyoxyethylene ether XP30, and the stabilizer is vinyltrimethylsilane.

3. The sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 1, characterized in that: The raw materials of SCF-A, by mass fraction, comprise the following components: Initiator 6.8%~9.5% Ethylene oxide 45%~49% Propylene oxide 17.9%~21.5% Esterified monomers: 5.8%–7.5% Sulfonating agent 12%~15.2% Alkaline catalyst 0.06%~0.08% Acidic catalyst 0.09%~0.1% Polymerization inhibitor 0.03%~0.04% Dispersion medium 2%~2.4% Acid neutralizer 0.2%~0.3% Alkaline neutralizer 2.1%~2.4%.

4. The sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 3, characterized in that: The preparation method of the SCF-A includes the following steps: Step S1: Nitrogen is purged through the initiator and alkaline catalyst under sealed conditions to remove oxygen. Then, the mixture is stirred at 300 r / min at 120℃~130℃, and ethylene oxide is added at a rate of 0.5 mol / h~1.0 mol / h. The reaction is maintained at 0.3 MPa~0.5 MPa for 2h~3h until the pressure drops below 0.1 MPa and stabilizes. Step S2: Keep the stirring rate constant, add propylene oxide at a rate of 0.3 mol / h to 0.5 mol / h at 110℃ to 120℃, and keep the reaction at 0.2 MPa to 0.4 MPa for 1.5 h to 2 h until the pressure drops below 0.1 MPa and stabilizes; Step S3: Cool to 80℃, add acidic neutralizing agent and stir for 30 minutes to adjust to neutral, filter under reduced pressure to remove salt impurities, and collect the pale yellow transparent liquid intermediate A; Step S4: Add esterification monomer, acid catalyst, polymerization inhibitor and dispersion medium to intermediate A, stir and reflux at 80℃~85℃ for 4h~6h, and continue to separate water until no obvious water is produced to complete the reaction; Step S5: After cooling to 40℃, slowly add an alkaline neutralizing agent to adjust the pH of the reaction solution to between 7.0 and 7.

3. After standing for 30 minutes to separate the layers, discard the lower aqueous phase and wash with deionized water at least twice. Each time, let the solution stand for 30 minutes to separate the layers and discard the aqueous phase. Collect the remaining organic phase and distill it under reduced pressure at a vacuum of 0.08MPa to 0.09MPa and a temperature of 70℃ to 80℃ to obtain a pale yellow viscous liquid intermediate B. Step S6: Intermediate B and sulfonating agent are reacted at 90℃~95℃ and stirred at 250r / min for 3h~4h. The mixture is then cooled to 50℃, dissolved in water and stirred for 30min. The brownish-red transparent liquid is collected by vacuum filtration.

5. The sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 3, characterized in that: The initiator is C. 10 ~C 14 One of the linear fatty primary amines; The esterifying monomer is either acrylic acid or methacrylic acid; The sulfonating agent is either sodium 2-hydroxyethanesulfonate or potassium 2-hydroxyethanesulfonate; The alkaline catalyst is either sodium hydroxide or potassium hydroxide; The acid catalyst is either p-toluenesulfonic acid or pyridine p-toluenesulfonate; The polymerization inhibitor is one of hydroquinone, tert-butylcatechol, or 2,6-di-tert-butyl-p-cresol; The dispersion medium is one of methanol, ethanol, and isopropanol; The acid neutralizer is either phosphoric acid or formic acid; One of the alkaline neutralizing agents: sodium carbonate solution or sodium hydroxide solution.

6. The application method of the sand-stabilizing and permeability-enhancing treatment agent for oil and gas wells as described in any one of claims 1 to 5, characterized in that: The treatment agent can be used for sand stabilization and permeability enhancement in production wells and sand stabilization and permeability enhancement in fractured wells. In production well remediation, the mass fraction of the treatment agent added is 2% to 5%, and in fractured well enhancement, the mass fraction added throughout the process is 0.05% to 0.1%, and the volume fraction added at the end is 0.2% to 0.5%.

7. The application method of the sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 6, characterized in that: The specific method for using the treatment agent to stabilize sand and improve permeability in production wells includes the following steps: Step 1: Well cleaning pretreatment; Step 2: Prepare a treatment solution containing 2%~5% by mass of treatment agent, and inject the treatment solution into the production layer within a 1-meter radius using a high-pressure pump. The injection rate is controlled at 0.5~1.0 m³ / min. The solvent of the treatment solution is a 2% KCl solution. Step 3: Inject 2% KCl solution to further flush the pipeline, pushing all the treatment fluid into the depth of the reservoir to ensure that the treatment fluid is in full contact with the reservoir; Step 4: Close the well and let it sit for 24-48 hours to allow the treatment agent to fully react with the sand, coal dust, and clay particles; Step 5: Slowly start production and gradually adjust output to the optimal production state.

8. The application method of the sand-stabilizing and permeability-enhancing agent for oil and gas wells according to claim 6, characterized in that: The specific method for using the treatment agent to stabilize sand and enhance permeability in fractured wells includes the following steps: Step 1: Prepare fracturing fluid and treatment agent according to the specified ratio; Step 2: Use a treatment agent accounting for 0.05% to 0.1% of the total mass of the fracturing fluid throughout the fracturing operation; Step 3: After each stage of fracturing is completed, inject fracturing fluid containing 0.2% to 0.5% of the treatment agent relative to the volume of the flushing fluid. Step 4: Routine flowback after fracturing is completed.

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