Nano-particles and method for evaluating adsorption characteristics of nano-particles on surface of gas reservoir sandstone

Abstract

The invention relates to the technical field of petroleum and natural gas exploration and development, in particular to nanoparticles and a method for evaluating adsorption characteristics of the nanoparticles on the surface of gas reservoir sandstone, and the method comprises the following steps: collecting a target gas reservoir sandstone core sample and preparing a fluorine-containing group functionalized SiO2 nanofluid; carrying out a static wetting contact angle determination experiment, and analyzing and determining the surface wettability of the rock slice soaked by the fluorine-containing group functionalized SiO2 nanofluid; a rock core displacement experiment is carried out, and the seepage capacity of the liquid in the saturated N2 rock core before and after the fluorine-containing group functionalized SiO2 nano-particle fluid is soaked is studied. The method solves the problem that the traditional adsorption characteristic experiment method of the polymer on the sandstone surface cannot systematically research the rock core imbibition characteristics and displacement characteristics before and after wettability reversal, and provides theoretical basis and technical support for relieving retrogression damage and improving the recovery ratio of condensate oil.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and natural gas exploration and development, and in particular to a nanoparticle and a method for evaluating the adsorption characteristics of the nanoparticle on the surface of gas reservoir sandstone. Background Art

[0002] During the depletion and depressurization process of condensate gas reservoirs, when the bottomhole reservoir pressure drops below the dew point pressure, condensate will precipitate from the gas phase. Before the condensate saturation reaches the critical flow saturation, the condensate will not only block the pore throats but also significantly reduce the gas phase permeability, resulting in a decrease in gas well productivity. To alleviate the damage caused by retrograde condensation to the reservoir, some scholars have proposed injecting organic solvents or liquid (or supercritical) CO2 into the near-wellbore area to dissolve the condensate or increase the fluidity of the oil phase to reduce the damage caused by retrograde condensation. However, these methods can only reduce the condensate content in the short term and cannot fundamentally solve the problem. Polymers or surfactants are used to change the wettability of the reservoir, converting liquid-wet to gas-wet, to achieve the goal of long-term relief of retrograde condensation damage. However, existing polymers for improving reservoir recovery and their evaluation methods have the following problems: 1. There are existing methods for improving oil recovery by using polymers to change reservoir wettability, but the polymers are difficult to prepare and are costly. 2. Existing research has mainly focused on changes in wettability and permeability, but has not yet systematically and in-depth studied the core imbibition and displacement characteristics before and after wettability reversal. 3. Insufficient technical integration. Existing research lacks multi-technical collaborative analysis such as contact angle experiments, rock surface nanoparticle adsorption characteristics measurement experiments, spontaneous imbibition experiments, and core displacement experiments, making it difficult to fully elucidate the specific mechanism of wettability reversal.

[0003] Therefore, a new, inexpensive polymer is urgently needed. Through wetting contact angle measurements, spontaneous imbibition experiments on cores, and displacement experiments, we systematically studied the changes in wetting contact angle, spontaneous oil-water imbibition, gas-liquid displacement pressure differential, and oil-water relative permeability before and after immersion of the new polymer particles. Combined with scanning electron microscopy, energy dispersive spectroscopy, and Fourier transform infrared spectroscopy, we revealed the adsorption characteristics of the new nanoparticles on sandstone surfaces, providing a theoretical basis and technical support for resolving retrograde condensate damage and improving condensate recovery. Summary of the Invention

[0004] In order to solve the above technical problems, the present invention provides a nanoparticle and a method for evaluating its adsorption characteristics on the surface of gas reservoir sandstone, providing a new solution for improving the recovery rate of condensate gas reservoirs. It systematically reveals the adsorption characteristics of new nanoparticles on the surface of sandstone, which is suitable for the exploration and development of condensate gas reservoirs, and provides a theoretical basis and technical support for eliminating retrograde condensation damage and improving the recovery rate of condensate oil.

[0005] The present invention provides a method for preparing nanoparticles, wherein the nanoparticles are fluorine-containing group functionalized SiO2 nanoparticles, and specifically comprises the following steps: (i) Preparing SiO2 nanoparticles; 4 parts ethanol, 4 parts deionized water, and 5 parts ethyl silicate were mixed by volume, stirred at room temperature for 20 minutes, and then 2 parts hydrochloric acid was added. The mixture was stirred for 5 minutes, and then 2 parts ammonia water was added. The mixture was stirred at 60°C for 2 hours to obtain a mixed solution; ethanol was added dropwise to the mixed solution at a molar ratio of 0.3 to the mixed solution, and the mixture was centrifuged at 2000 rpm to obtain SiO2 powder. The obtained powder was dried at 80°C for 24 hours and ground into a fine powder in an agate mortar to obtain SiO2 nanoparticles; (ii) Fluorination functionalization treatment: 34 parts of toluene and 22 parts of dichloromethane were mixed by volume in a round-bottom flask, followed by the addition of 4 parts of SiO2 nanoparticles to obtain a mixture. The mixture was stirred at room temperature for 15 minutes, and then 1 part of POTS solution was slowly added dropwise. The stirring was continued for 1 hour, and then the sample was centrifuged at 4000 r / min and dried at 60°C for 24 hours. The POTS-functionalized nanoparticles were recorded as NPOTS. NPOTS was evenly sprayed on a muffle furnace tray, heated to 500°C at a heating rate of 10°C / min and maintained for 1 hour. After the temperature dropped to room temperature, SiO2 nanoparticles functionalized with fluorine-containing groups were obtained.

[0006] A nanoparticle is a fluorine-containing group functionalized SiO2 nanoparticle prepared by a nanoparticle preparation method.

[0007] A method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone, wherein the nanoparticles are a nanoparticle; The evaluation method comprises the following steps: (a) Collecting target gas reservoir sandstone core samples and preparing fluorine-functionalized SiO2 nanofluids; (b) Conduct static wetting contact angle measurements, measuring the wetting contact angles of brine, air, and rock slices at formation temperature. Compare the changes in wetting angles before and after immersion in the fluorine-functionalized SiO2 nanofluid. Analyze and determine the surface wettability of the rock slices after immersion in the fluorine-functionalized SiO2 nanofluid. (c) Conducting experiments to determine the adsorption characteristics of nanoparticles on rock surfaces, analyzing and determining the adsorption characteristics of nanoparticles on the surface of sandstone powder after immersion in fluorine-functionalized SiO2 nanofluids; (d) Conduct spontaneous imbibition experiments to study the effect of brine imbibition on rock wettability reversal caused by fluorine-functionalized SiO2 nanoparticles. The degree of wettability reversal will be characterized by changes in the amount of brine imbibition. (e) Core flooding experiments were conducted to investigate the permeability of the fluid in N2-saturated cores before and after immersion of fluorine-functionalized SiO2 nanoparticles in fluid.

[0008] Preferably, the specific steps of the static wetting contact angle measurement experiment are as follows: A sandstone rock slice was immersed in nanofluids of different concentrations at 50°C for 24 hours, taken out and dried in an oven at 70-80°C for 24 hours, and then salt water was dropped on the sandstone rock slice. A digital microscope camera parallel to the horizontal viewing angle of the sandstone rock slice was used to continuously photograph the droplet shape. The droplet image was analyzed using LabVIEW software, and the average of the contact angles obtained at five different positions of the droplet was taken as the final contact angle.

[0009] Preferably, the specific steps of the rock surface nanoparticle adsorption characteristics determination experiment are as follows: The sandstone powder was immersed in nanofluid at 50°C for 24 hours, wrapped in gauze and blown dry with nitrogen, and dried at 70-80°C for 24 hours. The nanoparticle adsorption characteristics on the surface of the sandstone powder after nanofluid immersion were determined using field emission scanning electron microscopy FE-SEM, energy dispersive X-ray spectrometer EDX and Fourier transform infrared imager FTIR.

[0010] Preferably, the specific steps of the spontaneous imbibition experiment are as follows: The sandstone core was cleaned with petroleum ether and methanol, dried, and placed in a sealed container under vacuum. The core was then soaked in a nanofluid solution at an optimal concentration for 24 hours. The optimal concentration was the concentration used for soaking the sandstone rock slice when the wetting contact angle of the brine reached the maximum value in the static wetting contact angle measurement experiment. After being taken out, the core was blown dry with nitrogen and dried in a 70-80°C oven for 24 hours. The oven temperature was then raised to 50°C, the formation temperature. After the temperature stabilized, the sandstone core soaked in the nanofluid was tied with a plastic rope and completely immersed in the liquid. The change in the mass of the sandstone core with imbibition time was measured using an electronic balance, and the change in the mass of the absorbed liquid was recorded. The change in the mass of the liquid spontaneously absorbed by the core after nanofluid soaking with imbibition time was measured.

[0011] Preferably, the specific steps of the core flooding experiment are as follows: First, nitrogen was injected into the vacuumed sandstone core holder to test its sealing and saturate the sandstone core with nitrogen. Then, nanofluid was injected into the core at a low flow rate of 0.5 mL / min. The injection volume was 20 PV, which is 20 times the pore volume. The injection of nanofluid achieved effective adsorption of nanoparticles and reversed the wettability of the rock surface. Liquid was then injected into the sandstone core, and the changes in the pressure difference, liquid production, and gas production in the sandstone core during the displacement process were recorded in real time. When the liquid production rate at the outlet of the sandstone core remained stable, the core pressure difference during the liquid displacement of N2 after nanofluid immersion and the liquid flow rate after liquid production stabilized were measured three times in succession. The relative permeabilities of the liquid and N2 phases were calculated according to the JBN equation.

[0012] Preferably, the liquid is saline.

[0013] Preferably, the preparation method of SiO2 nanofluid functionalized with fluorine-containing groups is as follows: Polysorbate 80 dispersant was added to distilled water at a volume ratio of 1:100, and SiO2 nanoparticles functionalized with fluorine-containing groups were added as needed. The nanofluid was obtained by uniformly mixing using an ultrasonic homogenizer.

[0014] The beneficial effects of the present invention are: The fluorine-containing functionalized SiO2 nanoparticles of the present invention are low-cost and simple to synthesize, and can effectively change the wettability of reservoirs, reduce condensate damage, and improve the recovery rate of condensate gas reservoirs; The present invention solves the problem that traditional experimental methods for the adsorption characteristics of polymers on sandstone surfaces fail to systematically study the core imbibition and displacement characteristics before and after wettability reversal, and provides a theoretical basis and technical support for eliminating retrograde condensation damage and improving condensate oil recovery.

[0015] This paper systematically reveals the adsorption characteristics of new nanoparticles on sandstone surfaces through the collaboration of multiple experimental and observation methods. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] Figure 1 Schematic diagram of the experimental apparatus for static wetting contact angle measurement experiment.

[0017] Figure 2 Schematic diagram of the experimental apparatus for spontaneous imbibition experiment.

[0018] Figure 3 Schematic diagram of the experimental equipment for core flooding experiment.

[0019] Figure 4 Before nanofluid immersion ( Figure 4 a) After soaking ( Figure 4 b) Changes in the wetting contact angle of salt water on the surface of rock slices.

[0020] Figure 5 This is a graph showing the change in the wetting contact angle of brine on the rock surface with the concentration of nanofluid.

[0021] Figure 6 Before soaking the rock ( Figure 6 a) After soaking ( Figure 6 b. Figure 6 c) SEM images of the surface at different magnifications.

[0022] Figure 7 Before nanoparticles soaking ( Figure 7 a) After soaking ( Figure 7 b) EDX analysis of sandstone surface.

[0023] Figure 8 The XRD spectrum of the core after nanofluid immersion ( Figure 8 a) and FTIR spectra ( Figure 8 b).

[0024] Figure 9 The graph shows the change of the volume of spontaneously absorbed brine with time before and after core immersion.

[0025] Figure 10 This is a graph showing the change in core pressure difference during single-phase displacement of brine before and after nanofluid immersion.

[0026] Figure 11 This is a graph showing the changes in the relative permeability curves of liquid and N2 phases before and after nanofluid immersion. DETAILED DESCRIPTION

[0027] Taking the Chang 7 reservoir in the Ordos Basin as an example, the method of the present invention is described in detail.

[0028] The present invention provides a method for preparing nanoparticles, wherein the nanoparticles are fluorine-containing group functionalized SiO2 nanoparticles, and specifically comprises the following steps: (i) Preparation of SiO2 nanoparticles: 4 mL of ethanol, 4 mL of deionized water, and 5 mL of ethyl silicate were mixed, stirred at room temperature for 20 minutes, and then 2 mL of hydrochloric acid was added and stirred for 5 minutes. Subsequently, 2 mL of ammonia water was added and stirred at 60°C for 2 hours. Ethanol was then added dropwise to the mixture at a molar ratio of 0.3 to the mixture, and SiO2 powder was separated at a centrifugal speed of 2000 r / min. Finally, the obtained powder was dried at 80°C for 24 hours and ground into fine powder in an agate mortar. SiO2 nanoparticles were obtained; (ii) Fluorination functionalization: 34 mL of toluene and 22 mL of dichloromethane were mixed in a round-bottom flask, followed by the addition of 4 g of SiO2 nanoparticles. The mixture was stirred at room temperature for 15 minutes, and then 1 mL of POTS solution was slowly added dropwise, with stirring continuing for 1 hour. The sample was then centrifuged at 4000 rpm and dried at 60°C for 24 hours. The POTS-functionalized nanoparticles, designated NPOTS, were evenly sprayed onto a muffle furnace tray and heated at a rate of 10°C / min to 500°C and held there for 1 hour. After cooling to room temperature, SiO2 nanoparticles functionalized with fluorinated groups were obtained.

[0029] Polysorbate 80 dispersant was added to distilled water at a volume ratio of 1:100 to prevent nanoparticle aggregation. Subsequently, different masses of fluorinated group-functionalized SiO2 nanoparticles were added and uniformly mixed using an ultrasonic homogenizer to prepare nanofluids with concentrations of 0.2%, 0.4%, 0.6%, 0.8%, and 1.0%, respectively.

[0030] A method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone comprises the following steps: (a) Experimental materials and instruments The experimental core was taken from the outcrop sandstone of the Chang 7 reservoir in the Ordos Basin. It has a diameter of 2.5 cm and a length of 5-6 cm. According to the basic physical parameters and mineral composition analysis of the experimental core, its average porosity is 16.4% and the permeability is 89.5×10 -3 μm², the main mineral types include quartz, feldspar, calcite and clay minerals, with average mass contents of 41.3%, 24.2%, 16.8% and 12.6%, respectively.

[0031] In order to conduct wetting contact angle measurements and field emission scanning electron microscopy (FESEM) experiments, several core slices with a thickness of approximately 2 to 4 mm were cut from the experimental core. The debris powder generated during the cutting process was collected for energy dispersive X-ray spectroscopy (EDX), X-ray diffraction (XRD), and Fourier transform infrared spectroscopy (FTIR) analysis to evaluate the adsorption characteristics of nanoparticles on the pore surface.

[0032] In the experiment, a NaCl solution with a mass concentration of 2% was used as the injected mineralized water. According to the results of previous sensitivity evaluation experiments, this concentration of NaCl solution will not induce reservoir sensitivity damage. In the experiment, n-decane with a purity of 99.998% was used to simulate condensate oil, and nitrogen N2 with a purity of 99.99% was used to simulate condensate gas.

[0033] The instruments used in the experiment include an X'Pert PRO X-ray diffractometer produced by PANalytical in the Netherlands, with a diffraction accuracy of 0.001° / step, which is used to determine the mineral type and composition of the rock surface.

[0034] Zeiss G500 field emission scanning electron microscope, manufactured by Zeiss in Germany, with a maximum magnification of 200,000 times, was used to observe the morphological characteristics of the rock surface before and after the adsorption of nanoparticles.

[0035] Spotlight 400 / 400N Fourier transform infrared imager, manufactured by PerkinElmer, Australia, with a measurement wavelength range of 8000-300 cm -1 , used to analyze the adsorption characteristics of nanoparticles on rock surfaces.

[0036] The OCA200 fully automatic contact angle meter, manufactured by DataPhysics of Germany, has a measurement angle range of 0 to 180° and an accuracy of ±0.1°. It is used to measure the wetting contact angle in a salt water / air / rock system.

[0037] A Secura 224-1CN electronic balance, manufactured by Sartorius of Germany, with a measurement accuracy of 0.0001 g, was used to determine the mass change of the core in the spontaneous imbibition experiment.

[0038] An ultrasonic homogenizer with a vibration frequency of 20 kHz was used to disperse the nanoparticles uniformly and stably in water to prepare nanofluids.

[0039] (b) Wetting contact angle variation characteristics Schematic diagram of static wetting contact angle measurement experiment Figure 1 As shown, the wetting contact angles of the brine / air / rock system were measured at formation temperature.

[0040] The experimental steps are as follows: (1) 5 μL of salt water was dropped onto the rock slice before it was soaked in nanofluid. The droplet shape was continuously photographed using a digital microscope camera with a horizontal viewing angle parallel to the slice. The droplet image was analyzed using LabVIEW software, and the average of the contact angles obtained at five different positions of the droplet was taken as the final contact angle. (2) Sandstone rock slices were immersed in nanofluids of different concentrations at 50°C for 24 hours, taken out and dried in an oven at 70-80°C for 24 hours, and step (1) was repeated to measure the wetting contact angle of the rock slice surface after nanofluid immersion.

[0041] Based on the contact angle measurement experiment, the wetting contact angle of the rock slice surface after being soaked in nanofluid was analyzed. Figure 4The figure shows the change in the contact angle between air and brine on the surface of the rock slice before and after nanofluid immersion. As can be seen from the figure, before nanofluid immersion, the contact angle of brine is 64.6°. Figure 4 a, indicating that the wettability of the rock before immersion is liquid wet, belonging to strong oil wet and moderate water wet. When the nanofluid with a mass concentration of 0.4% is used for immersion, the contact angle of the brine increases to 133.7°. Figure 4 b, indicating that the wettability of the rock after nanofluid immersion changes from liquid wetting to moderate gas wetting, that is, hydrophobic and weakly oleophilic.

[0042] By comparing the changes in rock wetting contact angle after immersion in nanofluids with different mass concentrations, such as Figure 5 , it can be seen that the wetting contact angle of salt water on the rock surface changes in the following pattern: as the concentration of nanofluid increases, the wetting contact angle first increases and then decreases. When the nanofluid concentration is 0.4%, the wetting contact angle of salt water reaches its maximum value, indicating that the degree of rock wettability reversal is the greatest at this concentration. This is mainly because increasing the concentration of nanofluid can increase the adsorption of nanoparticles on the rock surface, thereby enhancing the hydrophobicity of the rock surface. However, when the concentration exceeds 0.4%, the nanoparticles will form a self-association effect in the solvent, resulting in a decrease in their adsorption on the rock surface. Therefore, the optimal concentration of nanofluid is 0.4% to achieve the effect of maximizing the change in rock wettability.

[0043] (c) Chemical adsorption characteristics of nanoparticles The experimental steps for determining the adsorption characteristics of nanoparticles on rock surfaces are as follows: (1) The sandstone powder collected during core cutting was washed with toluene and methanol in sequence, and then dried in an oven at 70-80 °C for 24 h. The surface elemental composition of the sandstone powder before nanofluid immersion was determined using energy dispersive X-ray spectrometry (EDX). (2) The sandstone powder was then immersed in the nanofluid at 50°C for 24 hours, wrapped in gauze and blown dry with nitrogen, and dried at 70-80°C for 24 hours. The nanoparticle adsorption characteristics on the surface of the sandstone powder after nanofluid immersion were determined using field emission scanning electron microscopy (FE-SEM), energy dispersive X-ray spectrometer (EDX), and Fourier transform infrared imager (FTIR).

[0044] The experiment on the adsorption characteristics of nanoparticles on the rock surface was carried out using FESEM analysis, EDX analysis, XRD analysis and FTIR spectroscopy analysis to analyze the chemical adsorption characteristics of nanoparticles.

[0045] (i) FESEM analysis By comparing the FESEM images at different magnifications before and after nanofluid immersion, we can see Figure 6It can be found that before the nanofluid immersion, the sandstone surface is relatively smooth and no obvious granular material is seen. Figure 6 However, after being soaked in nanofluid, multiple layers of granular materials of different sizes were adsorbed on the surface of the sandstone, as shown in Figure 2. Figure 6 b, forming an uneven surface. Further enlarge the image and see Figure 6 c shows that these particles adsorbed on the sandstone surface are nearly spherical SiO2 nanoparticles.

[0046] Due to the strong interaction between the nanoparticles, they self-associate to form a granular structure that adsorbs on the sandstone surface, significantly increasing the surface roughness of the sandstone. This is because the SiO2 nanoparticles functionalized with fluorine groups have low surface free energy and can form a rough structure, which helps to create a superhydrophobic surface, thereby changing the wettability of the rock.

[0047] (ii) EDX analysis Energy dispersive X-ray spectroscopy (EDX) analysis, as a surface characterization technique, can be used to verify the adsorption of nanoparticles on the sandstone surface and determine the elemental composition of the adsorption layer on the sandstone surface after the wettability transition. Figure 7 EDX spectra before and after nanofluid immersion are shown. As can be seen, the elements F and Si were detected on the sandstone surface after immersion compared to before, confirming that the adsorption layer on the sandstone surface is composed of SiO2 nanoparticles functionalized with fluorine groups. Combined with the results of quantitative EDX elemental analysis, the mass fractions of F and Si reached 27.68% and 22.15%, respectively, with a slight decrease in the mass fractions of the original elements C, O, and Al. This indicates that the primary cause of the wettability reversal is the extensive adsorption of fluorine-functionalized SiO2 nanoparticles on the sandstone surface.

[0048] (iii) XRD and FTIR spectroscopy analysis According to the XRD spectrum of SiO2 nanoparticles functionalized with fluorine groups, Figure 8 It can be seen from a that an obvious broad diffraction peak is observed at 2θ = 22.28°, which is basically consistent with the diffraction peak of pure SiO2 nanoparticles reported by Mahmoudi et al., indicating that the SiO2 functionalized with fluorine groups still retains the structural characteristics of the original SiO2. Figure 8 b It can be seen that compared with the FTIR spectrum of pure SiO2, the absorption peaks of SiO2 functionalized with fluorine groups at 3139, 2989, 2898, 1404, 1078, 955, 801 and 452 cm-1 remain unchanged.

[0049] It is worth noting that the corresponding -1The Si-O-Si group signal at 1200 cm-1 showed a more obvious shoulder peak, which may be due to the -1 The new vibration mode at 3139 cm -1 The intensity of the hydroxyl-OH functional group decreases, which may be due to the functionalization of the functional group by the reaction between SiO2 and POTS molecules. In summary, the SiO2 functionalized with fluorine groups not only retains the basic particle structure characteristics of the original SiO2, but also introduces polycrystalline structure characteristics.

[0050] (d) Spontaneous imbibition characteristics The spontaneous imbibition experiment is used to study the imbibition effect of liquid after rock wettability reversal. The liquid is brine, and the degree of wettability reversal is characterized by the change in liquid imbibition amount. Figure 2 This is a schematic diagram of the spontaneous imbibition experimental setup. The experimental steps are as follows: (1) The oven temperature was raised to 50°C, the formation temperature. After the temperature stabilized, the core that had not been soaked in nanofluid was tied with a plastic rope and completely immersed in the liquid, which was brine. The change in the core mass with the imbibition time was measured using an electronic balance, and the change in the mass of the imbibed liquid was recorded. (2) After step (1), the core was washed with petroleum ether and methanol, dried, and placed in a sealed container under vacuum. The core was soaked in the nanofluid solution of optimal concentration for 24 hours. After being taken out, it was blown dry with nitrogen and dried in an oven at 70-80°C for 24 hours. Step (1) was repeated to measure the change in the mass of liquid spontaneously absorbed by the core after nanofluid soaking as a function of the imbibition time.

[0051] Figure 9 The temporal variation of brine imbibition during spontaneous imbibition of the core before and after nanofluid immersion is shown.

[0052] As can be seen from the figure, before nanofluid immersion, the volume of brine absorbed by the core under capillary pressure accounts for 0.637 of the total pore volume of the core. This shows that the amount of liquid absorption is mainly determined by the capillary pressure of different types of liquids, and the capillary pressure depends on wettability and pore radius.

[0053] After the core was soaked in nanofluid, the volume of brine absorbed dropped significantly to 0.068, a reduction of 89%. This indicates that the core's absorption of brine was significantly reduced after nanofluid immersion. This is primarily due to the fact that when the rock's wettability shifts from liquid-wet to moderate gas-wet, the capillary pressure on the liquid shifts from a driving force to a resistance. This not only reduces the amount of liquid absorbed, but also inhibits the amount of liquid adsorbed on the pore surface, effectively changing the gas-liquid seepage state.

[0054] (e) Liquid-gas two-phase flow characteristics By injecting liquid into the core to displace N2, the liquid is brine, and the seepage capacity of the liquid in the N2 saturated core before and after nanofluid immersion is studied. Figure 3 This is a schematic diagram of the core flooding experiment. The experimental steps are as follows: (1) First, N2 was injected into the core holder after vacuuming to test the sealing and saturate the core with N2. Then, brine was injected into the core at a flow rate of 1 mL / min. The changes in the core pressure difference, liquid production, and gas production during the displacement process were recorded in real time. When the liquid production rate at the core outlet remained stable, the liquid flow rate was measured three times in succession, and the relative permeability of the liquid and N2 phases was calculated according to the JBN equation. (2) The nanofluid was injected into the core at a low flow rate of 0.5 mL / min and an injection volume of 20 PV. By injecting a large amount of nanofluid, the nanoparticles were effectively adsorbed and the wettability of the rock surface was reversed. (3) Dry the core with nitrogen, and repeat step (1) after vacuuming. Measure the core pressure difference during the liquid displacement of N2 after nanofluid immersion and the liquid flow rate after the liquid production stabilizes. Calculate the relative permeability of the liquid and N2 phases according to the JBN equation.

[0055] (i) Liquid-gas displacement characteristics By comparing the changes in core pressure difference during liquid displacement before and after nanofluid immersion, we can see Figure 10 It can be found that before nanofluid immersion, the core pressure difference during brine displacement continues to increase with the increase of injected liquid volume. When the injected brine volume reaches 1.4 PV, the core pressure difference reaches a maximum value of 0.24 MPa and tends to be stable. Figure 10 shown.

[0056] After nanofluid immersion, the core pressure differential significantly decreased during brine injection, reaching a maximum of 0.07 MPa. This is because the polar groups of the fluorinated nanoparticles interact with polar sites on the rock surface, adsorbing to the rock surface through van der Waals forces and electrostatic interactions, and stripping the liquid from the pore surfaces. Therefore, after the rock wettability changes, the seepage resistance of the brine in the core is significantly reduced, which helps alleviate pore throat blockage caused by liquid precipitation.

[0057] In a liquid-wetting system, liquid primarily adheres to pore walls, requiring significant force to remove them. Even at very low liquid saturation in the core, liquid can remain as a continuous phase within the pores, severely impacting gas flow. However, when wettability reverses to moderate gas wetting, the brine becomes a neutral-wetting and non-wetting phase. Liquid is unable to adhere to pore walls, making it difficult to form a continuous phase in the pore throats. The precipitated liquid can be driven with relatively low force and does not significantly impact gas flow.

[0058] (ii) Two-phase relative permeability curve Figure 11 The changes in the relative permeability curves of brine and nitrogen (N₂) before and after nanofluid immersion are shown. The figure shows that after nanofluid immersion, the residual saturation of brine decreases from 0.35 to 0.31, and the liquid-gas isotonic point shifts to the left. This indicates that when rock wettability shifts from liquid-wet to intermediate gas-wet, the residual liquid saturation decreases, and at relatively low liquid saturations, the relative permeabilities of the liquid and gas phases become equal.

[0059] Furthermore, at the same liquid saturation, the nanofluid treatment significantly increased both gas and liquid relative permeabilities. The maximum brine relative permeability increased 1.9-fold, from 0.38 to 0.75. This suggests that after rock wettability inversion occurs, liquids can flow more easily at lower saturations. The increase in liquid relative permeability not only did not reduce gas relative permeability, but actually significantly increased it, thereby achieving the desired effect of unblocking and increasing production.

Claims

1. A method for preparing nanoparticles, characterized in that: The nanoparticles are fluorine-containing group functionalized SiO2 nanoparticles, and specifically include the following steps: (i) Preparing SiO2 nanoparticles; 4 parts ethanol, 4 parts deionized water, and 5 parts ethyl silicate were mixed by volume, stirred at room temperature for 20 minutes, and then 2 parts hydrochloric acid was added. The mixture was stirred for 5 minutes, and then 2 parts ammonia water was added. The mixture was stirred at 60°C for 2 hours to obtain a mixed solution; ethanol was added dropwise to the mixed solution at a molar ratio of 0.3 to the mixed solution, and the mixture was centrifuged at 2000 rpm to obtain SiO2 powder. The obtained powder was dried at 80°C for 24 hours and ground into a fine powder in an agate mortar to obtain SiO2 nanoparticles; (ii) Fluorination functionalization treatment: 34 parts of toluene and 22 parts of dichloromethane were mixed by volume in a round-bottom flask, followed by the addition of 4 parts of SiO2 nanoparticles to obtain a mixture. The mixture was stirred at room temperature for 15 minutes, and then 1 part of POTS solution was slowly added dropwise. The stirring was continued for 1 hour, and then the sample was centrifuged at 4000 r / min and dried at 60°C for 24 hours. The POTS-functionalized nanoparticles were recorded as NPOTS. NPOTS was evenly sprayed on a muffle furnace tray, heated to 500°C at a heating rate of 10°C / min and maintained for 1 hour. After the temperature dropped to room temperature, SiO2 nanoparticles functionalized with fluorine-containing groups were obtained.

2. A nanoparticle, characterized in that: Fluorine-containing group-functionalized SiO2 nanoparticles prepared by the nanoparticle preparation method as claimed in claim 1.

3. A method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone, characterized in that: The nanoparticles are the nanoparticles according to claim 2; The evaluation method comprises the following steps: (a) Collecting target gas reservoir sandstone core samples and preparing fluorine-functionalized SiO2 nanofluids; (b) Conduct static wetting contact angle measurements, measuring the wetting contact angles of brine, air, and rock slices at formation temperature. Compare the changes in wetting angles before and after immersion in the fluorine-functionalized SiO2 nanofluid. Analyze and determine the surface wettability of the rock slices after immersion in the fluorine-functionalized SiO2 nanofluid. (c) Conducting experiments to determine the adsorption characteristics of nanoparticles on rock surfaces, analyzing and determining the adsorption characteristics of nanoparticles on the surface of sandstone powder after immersion in fluorine-functionalized SiO2 nanofluids; (d) Conduct spontaneous imbibition experiments to study the effect of brine imbibition on rock wettability reversal caused by fluorine-functionalized SiO2 nanoparticles. The degree of wettability reversal will be characterized by changes in the amount of brine imbibition. (e) Core flooding experiments were conducted to investigate the permeability of the fluid in N2-saturated cores before and after immersion of fluorine-functionalized SiO2 nanoparticles in fluid.

4. The method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 3, wherein: The specific steps of the static wetting contact angle measurement experiment are as follows: A sandstone rock slice was immersed in nanofluids of different concentrations at 50°C for 24 hours, taken out and dried in an oven at 70-80°C for 24 hours, and then salt water was dropped on the sandstone rock slice. A digital microscope camera parallel to the horizontal viewing angle of the sandstone rock slice was used to continuously photograph the droplet shape. The droplet image was analyzed using LabVIEW software, and the average of the contact angles obtained at five different positions of the droplet was taken as the final contact angle.

5. The method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 3, wherein: The specific steps of the rock surface nanoparticle adsorption characteristic determination experiment are as follows: The sandstone powder was immersed in nanofluid at 50°C for 24 hours, wrapped in gauze and blown dry with nitrogen, and dried at 70-80°C for 24 hours. The nanoparticle adsorption characteristics on the surface of the sandstone powder after nanofluid immersion were determined using field emission scanning electron microscopy FE-SEM, energy dispersive X-ray spectrometer EDX and Fourier transform infrared imager FTIR.

6. The method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 3, wherein: The specific steps of the spontaneous imbibition experiment are as follows: The sandstone core was cleaned with petroleum ether and methanol, dried, and placed in a sealed container under vacuum. The core was then soaked in a nanofluid solution of optimal concentration for 24 hours. After being taken out, it was blown dry with nitrogen and dried in an oven at 70-80°C for 24 hours. The oven temperature was then raised to 50°C, the formation temperature. After the temperature stabilized, the sandstone core soaked in nanofluid was tied with a plastic rope and completely immersed in the liquid. An electronic balance was used to measure the change in the mass of the sandstone core with imbibition time, and the change in the mass of the absorbed liquid was recorded. The change in the mass of the liquid spontaneously absorbed by the core after nanofluid soaking was measured with imbibition time.

7. The method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 3, wherein: The specific steps of the core flooding experiment are as follows: First, N2 was injected into the vacuumed sandstone core holder to test the sealing and saturate the sandstone core with N2. Then, nanofluid was injected into the core at a low flow rate of 0.5 mL / min and an injection volume of 20PV. The injection of nanofluid achieved effective adsorption of nanoparticles and achieved wettability reversal on the rock surface. Liquid was then injected into the sandstone core, and the changes in the pressure difference, liquid production, and gas production in the sandstone core during the displacement process were recorded in real time. When the liquid production rate at the outlet of the sandstone core remained stable, the core pressure difference during the liquid displacement of N2 after nanofluid immersion and the liquid flow rate after liquid production stabilized were measured three times in succession. The relative permeabilities of the liquid and N2 phases were calculated according to the JBN equation.

8. A method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 6 or 7, characterized in that: The liquid is saline.

9. The method for evaluating the adsorption characteristics of nanoparticles on the surface of gas reservoir sandstone according to claim 3, wherein: The preparation method of SiO2 nanofluid functionalized with fluorine-containing groups is as follows: Polysorbate 80 dispersant was added to distilled water at a volume ratio of 1:100, and SiO2 nanoparticles functionalized with fluorine-containing groups were added as needed. The nanofluid was obtained by uniformly mixing using an ultrasonic homogenizer.

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