Method for improving recovery efficiency of low-permeability oil reservoir based on CTAB modified nano silicon dioxide

Abstract

The invention discloses a method for improving the recovery efficiency of a low-permeability reservoir based on CTAB (Cetyltrimethyl Ammonium Bromide) modified nano silicon dioxide. The method comprises the following steps: S1, preparing nano SiO2 dispersion liquid; s2, adding CTAB (Cetyltrimethyl Ammonium Bromide) into the dispersion liquid, and performing ultrasonic treatment, freeze drying and dispersion to obtain a modified nano silicon dioxide system; s3, pretreating the low-permeability rock core, and measuring the pore volume and the oil saturation; s4, performing primary water drive on the pretreated rock core until the water content reaches a preset value; s5, after the modification system is injected, secondary water drive is conducted till the water content reaches a preset value; s6, the volume of produced oil is counted, and the recovery efficiency is calculated and compared to determine the lifting effect. The dispersion stability of the nanoparticles is improved through CTAB modification, the rock wettability is improved, the oil-water interfacial tension is reduced, pore residual oil can be effectively stripped, the recovery rate of the low-permeability oil reservoir is remarkably improved, and practical technical support is provided for related oil reservoir development.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil exploitation, in particular to a method for improving the recovery ratio of low-permeability oil reservoirs based on CTAB-modified nano-silica. BACKGROUND

[0002] Low-permeability oil reservoirs account for more than 40% of global oil and gas resources, but their permeability is usually less than 1 mD, the pore structure is complex, and the content of clay minerals is high, resulting in a traditional water flooding recovery ratio generally less than 30%. In China, the proportion of low-permeability oil reservoirs is more than 60%, and the recovery ratio of some oilfields is even less than 20%, so the potential of remaining oil resources is huge but the exploitation is extremely difficult.

[0003] Traditional low-permeability oil reservoir development mainly relies on water injection development and chemical oil displacement technology. Water injection development drives the flow of crude oil by injecting high-pressure water into the reservoir, but due to the small pore throat and large capillary resistance of low-permeability oil reservoirs, the water flooding efficiency is low, and water channeling and fingering phenomena are easily caused, which limits the recovery ratio. Although chemical oil displacement technology (such as polymer flooding and surfactant flooding) can improve the oil displacement efficiency by improving the mobility ratio or reducing the interfacial tension, it has problems such as high cost of reagents, large adsorption loss in the formation, poor temperature resistance and salt tolerance, and the application effect is significantly reduced in high-temperature high-salt low-permeability oil reservoirs. For example, the recovery ratio of an oilfield is only increased by 8% to 12% after polymer flooding, and the polymer solution has poor injectivity in low-permeability formations, which easily causes formation plugging.

[0004] In recent years, nano materials have attracted widespread attention in the field of improving recovery ratio due to their unique surface effect and small size effect. Existing researches mainly focus on using unmodified nano-silica particle dispersion, but there are the following problems: ① The nano particles are easy to agglomerate, have poor stability, and are easy to plug the pore throat after being injected into the formation; ② The interaction with the surface of the reservoir rock is weak, and it is difficult to effectively change the wettability of the rock; ③ The adaptability to the complex pore structure of low-permeability oil reservoirs is insufficient, and the oil displacement efficiency is limited. For example, a study using unmodified nano-silica dispersion for oil displacement only increased the recovery ratio by 5% to 8%, and the migration distance of nano particles in the formation was short, which could not sweep the remaining oil in the far well zone. SUMMARY

[0005] Based on the above technical problems, the present application discloses a method for improving the recovery ratio of low-permeability oil reservoirs based on CTAB-modified nano-silica, which specifically comprises:

[0006] S1, dispersing nano-SiO2 particles in water and performing ultrasonic treatment to prepare a nano-SiO2 dispersion;

[0007] S2, constructing a modified nano-silica system;

[0008] S3, pretreating a low-permeability oil reservoir core;

[0009] S4. Perform a water drive on the pretreated core until the water content reaches the preset value.

[0010] S5. Inject the modified nano-silica system prepared by S2 into the core that has undergone one water flooding, and then carry out a second water flooding until the water content reaches the preset value.

[0011] S6. Calculate the oil production volume of primary and secondary waterflooding, and combine the pore volume and oil saturation to determine the recovery rate and the enhancement effect.

[0012] Preferably, the preparation of the nano-silica dispersion in S1 specifically involves: dispersing nano-SiO2 particles with a particle size of 10-15 nm in distilled water, and using an ultrasonic disperser to perform ultrasonic treatment on them for 1-1.5 h to make the nano-SiO2 particles uniformly dispersed in the distilled water, thereby obtaining a nano-SiO2 dispersion solution.

[0013] Preferably, the modified nano-silica system constructed in S2 is specifically as follows: CTAB is added to the nano-silica dispersion obtained in S1, wherein the mass ratio of nano-SiO2 to CTAB is 1:0.5, 1:1, 1:2, and 1:3, respectively. The mixture is ultrasonically treated at 60-70°C for 1-1.5 hours to ensure uniform mixing. After freeze-drying, modified nano-silica solid particles are obtained. The modified nano-silica solid particles are then dispersed in water to obtain the modified nano-silica system.

[0014] Preferably, the modified nano-silica solid particles are dispersed in water to obtain the modified nano-silica system, specifically as follows: the modified nano-silica solid particles obtained after freeze-drying are added to distilled water at a mass concentration of 0.1%, and the mixture is ultrasonically treated for 20 to 30 minutes using an ultrasonic disperser with a power of 300 to 500W, during which the ultrasonic temperature is controlled at 25 to 30°C, so that the modified nano-silica solid particles are uniformly dispersed in the water to obtain modified nano-silica.

[0015] Preferably, the pretreatment of low-permeability reservoir cores in step S3 includes:

[0016] S3.1 Select outcrop cores with permeability of 1 to 100 mD and measure the gas permeability, length, radius and porosity parameters of the cores;

[0017] S3.2. Vacuum the core until all the air inside is removed, then inject water into the core to achieve saturation, and calculate the pore volume of the core based on the volume of water injected.

[0018] S3.3 Inject shale oil into the core after it has been saturated with water until the core can no longer absorb shale oil, thus completing the saturation oil operation;

[0019] S3.4, place the core saturated with oil in the experimental environment for aging for 7 days, so that the shale oil and the core fully act, and calculate the oil saturation of the core through the core pore volume and the volume of injected shale oil.

[0020] Preferably, the process of calculating the pore volume of the core in S3.2 is: the pore volume V p The calculation formula is: Wherein V w,s is the total volume of injected water after the core is saturated with water, V w,u is the volume of injected water corresponding to the part of the core not saturated with water after the core is vacuumed, is the filling coefficient of water in the core pores, and the pore volume of the core is calculated.

[0021] Preferably, the process of calculating the oil saturation of the core through the core pore volume and the volume of injected shale oil in S3.4 is: the oil saturation S o The calculation formula is: Wherein V o is the volume of injected shale oil, V p is the pore volume of the core, and the oil saturation of the core is obtained.

[0022] Preferably, in S4, the pretreated core is subjected to a water drive until the water cut reaches a preset value, specifically: the core after S3 pretreatment is injected with water into the core at a constant speed of 0.1-0.15 mL / min, and the produced liquid is collected in real time through the connected separatory funnel. By using the density difference and the immiscibility of oil and water phases, after the produced liquid is layered in the separatory funnel, the oil phase volume V o and the water phase volume V w are read to measure the real-time water cut, and the formula is The end point of the first water drive is determined by monitoring f w , and the first water drive is stopped when f w reaches a preset threshold value.

[0023] Preferably, in S5, the modified nanosilica system prepared in S2 is injected into the core after the first water drive, and then a second water drive is performed until the water cut reaches a preset value, specifically: after the first water drive is stopped, the experimental environment of the core is maintained and the injection speed is kept constant at 0.1-0.15 mL / min, 0.5 PV of the modified nanosilica system is injected into the core, and after the injection is completed, water is continuously injected into the core at the same speed for the second water drive. The produced liquid is collected in real time through the separatory funnel connected to the outlet end of the core, and the oil phase volume V' o and the water phase volume V'w The real-time secondary water content is calculated, and the formula is: Continuously inject water until f' w Stop the secondary water flooding when the secondary preset threshold is reached.

[0024] Preferably, the S6 determines the recovery effect, specifically: the total volume V o1 And the total volume V o2 Of the oil produced in the secondary water flooding process is calculated, combined with the obtained oil saturation S o And the core pore volume V p The primary water flooding recovery rate is calculated, and the formula is: And the total recovery rate E is calculated by the formula To obtain the recovery rate improvement value ΔE, and the formula is: ΔE = E - E1.

[0025] Compared with the prior art, the technical scheme of the present application has the following technical effects:

[0026] The present application modifies the nano-silicon dioxide by CTAB, significantly improves the dispersion stability of the nano-particles in water, avoids the problems of easy agglomeration of unmodified nano-materials and plugging of the formation pore throat after injection, ensures that the modified system can smoothly enter the small pores of the low-permeability core, enhances the sweep range of the deep part of the oil reservoir, lays a foundation for the full play of the subsequent oil displacement effect, and solves the technical problem of poor injectability of traditional nano-materials in low-permeability oil reservoirs.

[0027] The present application combines the primary water flooding with the secondary water flooding after the injection of the modified nano-silicon dioxide system, and by means of the regulation of the wettability of the rock surface by the modified nano-particles and the reduction of the oil-water interfacial tension, the residual oil attached in the core pores can be effectively stripped, the carrying capacity of the displacement fluid for the remaining oil can be improved, the oil production can be greatly increased compared with single water flooding, the development effect of the low-permeability oil reservoir can be significantly improved, and the bottleneck of limited recovery rate improvement of conventional water flooding in low-permeability oil reservoirs is broken through.

[0028] The present application has clear operation specifications for the whole process from the preparation of the modified nano-silicon dioxide system, the core pretreatment to the displacement experiment, the recovery rate improvement effect can be clearly quantified through the accurate calculation of parameters such as pore volume, oil saturation and water content, the experimental conditions are easy to control and have good repeatability, which provides reliable experimental basis and operation guidance for the industrial application of the low-permeability oil reservoir enhanced recovery technology, and has strong practicality and popularization value.

[0029] The above description is only a summary of the technical solutions of the present application. In order to make the technical means of the present application more clearly understood, and thus can be implemented according to the content of the description, and in order to make the above and other purposes, characteristics and advantages of the present application more obvious and easy to understand, the following will be described in detail with the preferred embodiments of the present application and with the help of the accompanying drawings as follows.

[0030] The above and other purposes, advantages and characteristics of the present application will be more apparent to those skilled in the art from the following detailed description of specific embodiments of the present application in conjunction with the accompanying drawings. BRIEF DESCRIPTION OF DRAWINGS

[0031] In order to more clearly illustrate the technical solutions in the embodiments of the present application or the prior art, the following will briefly introduce the drawings needed to be used in the embodiment or prior art description. Obviously, the drawings described below are some embodiments of the present application, and those skilled in the art can also obtain other drawings according to these drawings without any creative labor. In all the drawings, similar elements or parts are generally identified by similar reference numerals. In the drawings, each element or part is not necessarily drawn according to the actual proportion.

[0032] According to the description of the drawings in the document and the corresponding technical content, the titles of the drawings are as follows:

[0033] Figure 1 Flow chart for low permeability reservoir recovery enhancement method based on CTAB modified nano-silica;

[0034] Figure 2 Flow chart for low permeability reservoir core pretreatment;

[0035] Figure 3 Schematic diagram of visual chip model;

[0036] Figure 4 XRD spectrum of nano-SiO2 before and after modification;

[0037] Figure 5 FTIR spectrum of nano-SiO2 before and after modification;

[0038] Figure 6 Particle size and morphology of nano-silica particles before and after modification;

[0039] Figure 7 Transmission spectrum of nano-SiO2 before modification;

[0040] Figure 8 Transmission spectrum of nano-SiO2 after modification;

[0041] Figure 9 Microscopic oil and water displacement distribution map;

[0042] Figure 10 is a microcosmic displacement process diagram;

[0043] Figure 11 is an oil displacement effect diagram of a modified nanofluid system under different permeabilities. DETAILED DESCRIPTION

[0044] In order to make the objects, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be described clearly and completely below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are only some but not all of the embodiments of the present application. In the following description, specific details such as specific configurations and components are provided only to help a comprehensive understanding of the embodiments of the present application. Therefore, it should be apparent to those skilled in the art that various changes and modifications can be made to the embodiments described herein without departing from the scope and spirit of the present application. In addition, in order to be clear and concise, the description of known functions and structures is omitted in the embodiments.

[0045] It should be understood that the "one embodiment" or "the embodiment" mentioned throughout the specification means that the specific features, structures or characteristics related to the embodiment are included in at least one embodiment of the present application. Therefore, "one embodiment" or "the embodiment" appearing throughout the specification does not necessarily mean the same embodiment. In addition, these specific features, structures or characteristics can be combined in one or more embodiments in any suitable manner.

[0046] In addition, reference numerals and / or letters can be repeated in different examples in the present application. Such repetition is for the purpose of simplification and clarity, and does not in itself indicate a relationship between the various embodiments and / or arrangements discussed.

[0047] The term "and / or" herein is only a description of the association relationship of the associated objects, which means that there can be three relationships, for example, A and / or B can mean that A exists alone, B exists alone, and A and B exist simultaneously. The term "and" herein is a description of another association relationship of the associated objects, which means that there can be two relationships, for example, A and B can mean that A exists alone and A and B exist simultaneously. In addition, the character " / " herein generally means that the associated objects before and after are in an "or" relationship.

[0048] The term "at least one" herein is only a description of the association relationship of the associated objects, which means that there can be three relationships, for example, at least one of A and B can mean that A exists alone, A and B exist simultaneously, and B exists alone.

[0049] It is also need to make clear that, in this article, the relationship terms such as first and second are only used to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any such actual relationship or order between the entities or operations. Moreover, the term "include", "contain" or any other variant thereof is intended to cover non-exclusive inclusion.

[0050] Embodiment 1

[0051] This embodiment describes a low permeability reservoir recovery enhancement method based on CTAB modified nanosilica, as shown in the following specific steps: Figure 1 The specific steps are as follows:

[0052] S1, dispersing nanosilica particles in water and performing ultrasonic treatment to prepare a nanosilica dispersion solution;

[0053] S2, constructing a modified nanosilica system;

[0054] S3, pretreating a low permeability reservoir core;

[0055] S4, performing a primary water flooding on the pretreated core until the water cut reaches a preset value;

[0056] S5, injecting the modified nanosilica system prepared in S2 into the core subjected to the primary water flooding, and then performing a secondary water flooding until the water cut reaches a preset value;

[0057] S6, counting the oil volume produced by the primary and secondary water flooding, and calculating the recovery rate in combination with the pore volume and oil saturation to determine the enhancement effect.

[0058] Further, the nanosilica dispersion solution prepared in S1 is prepared by dispersing nanosilica particles with a particle size of 10-15 nm in distilled water, and using an ultrasonic disperser to perform ultrasonic treatment for 1-1.5 h to make the nanosilica particles uniformly dispersed in the distilled water, thereby obtaining a nanosilica dispersion solution.

[0059] Further, the modified nanosilica system in S2 is constructed by adding CTAB to the nanosilica dispersion solution obtained in S1, wherein the mass ratio of nanosilica to CTAB is 1:0.5, 1:1, 1:2 or 1:3, and the mixture is uniformly treated by using an ultrasonic disperser at 60-70°C for 1-1.5 h, and then freeze-dried to obtain modified nanosilica solid particles, which are then dispersed in water to obtain a modified nanosilica system.

[0060] Further, the modified nano-silica solid particles are dispersed in water to obtain a modified nano-silica system, specifically, the modified nano-silica solid particles obtained after freeze-drying are added into distilled water at a mass concentration of 0.1%, and the mixture is subjected to ultrasonic treatment for 20-30 min using an ultrasonic disperser with a power of 300-500 W, during which the ultrasonic temperature is controlled at 25-30°C, so that the modified nano-silica solid particles are uniformly dispersed in water to obtain the modified nano-silica.

[0061] Further, as shown in S3, the pretreatment of the low-permeability oil reservoir core in S3 includes: Figure 2

[0062] S3.1, selecting an outcrop core with a permeability of 1-100 mD, and measuring the gas-measured permeability, length, radius and porosity parameters of the core;

[0063] S3.2, vacuumizing the core until the air inside the core is completely discharged, and then injecting water into the core to achieve water saturation, and calculating the pore volume of the core according to the volume of the injected water;

[0064] S3.3, injecting shale oil into the water-saturated core until the core can no longer absorb shale oil, and completing the oil saturation operation;

[0065] S3.4, placing the oil-saturated core in an experimental environment for aging for 7 days, so that the shale oil fully acts on the core, and calculating the oil saturation of the core through the pore volume of the core and the volume of the injected shale oil.

[0066] Further, the process of calculating the pore volume of the core in S3.2 is as follows: the pore volume V p The calculation formula is: wherein V w,s is the total volume of the injected water after the water saturation treatment of the core, V w,u is the volume of the injected water corresponding to the unsaturated part of the core after the vacuum treatment of the core, and is the filling coefficient of water in the pores of the core, and the pore volume of the core is calculated.

[0067] Further, the process of calculating the oil saturation of the core through the pore volume of the core and the volume of the injected shale oil in S3.4 is as follows: the oil saturation S o The calculation formula is: wherein V o is the volume of the injected shale oil, and V p is the pore volume of the core, and the oil saturation of the core is obtained.

[0068] ​Furthermore, in S4, the pretreated core is subjected to water flooding until the water cut reaches the preset value. Specifically, water is injected into the core after the S3 pretreatment at a constant rate of 0.1-0.15 mL / min. The produced liquid is collected in real time through a connected separatory funnel. Taking advantage of the density difference and immiscibility of the oil and water phases, after the produced liquid has settled and separated into layers in the separatory funnel, the volume V of the oil phase is measured by reading the scale of the separatory funnel. o and water phase volume f w The formula for calculating the real-time primary moisture content is as follows: By monitoring f w Determine the endpoint of a water drive operation when f w The water drive will stop once a preset threshold is reached.

[0069] Furthermore, in S5, the modified nano-silica system prepared in S2 was injected into the core after one waterflooding, followed by a second waterflooding until the water cut reached the preset value. Specifically, after the first waterflooding was stopped, the experimental environment of the core and the injection rate of 0.1-0.15 mL / min were maintained, and 0.5 PV of the modified nano-silica system was injected into the core. After the injection was completed, water was injected into the core at the same rate for a second waterflooding. The produced liquid was collected in real time through a separatory funnel connected to the core outlet. After the produced liquid was allowed to settle and separate into layers, the oil phase volume V' was read. o and the volume of the aqueous phase V' w The formula for calculating the real-time secondary moisture content is: Continue injecting water until f' w The secondary water drive will stop when the preset threshold is reached.

[0070] Furthermore, in S6, the enhanced oil recovery effect was determined, specifically by calculating the total volume V of oil produced during a single waterflooding operation. o1 The total volume V of oil produced during the secondary water drive process o2 Combined with the obtained oil saturation S o and core pore volume V p The formula for calculating the recovery rate of a single waterflood is: And through the formula Calculate the total recovery rate E to obtain the recovery rate enhancement value ΔE, the formula is: ΔE=E-E1.

[0071] This embodiment describes in detail how CTAB is used to modify the surface of nano-silica, which significantly improves the dispersion stability of nanoparticles in water and their adsorption capacity on oil reservoir rocks. The modified nanoparticles can effectively reduce the oil-water interfacial tension, change the wettability of the rock surface, and improve the displacement efficiency of residual oil in the micropore throat.

[0072] Based on Example 1, this example is based on the micro and macro oil displacement experiments of CTAB modified nanosilica system, specifically:

[0073] The micro oil displacement experiment uses a visual chip model to simulate the pore structure of a low permeability reservoir, and the chip throat size is 30-110 pm. The model schematic is shown in Figure 3 Before the experiment, the surface of the chip model was first treated with a hydrophobic agent, and the chip surface was allowed to stand for 1 h to ensure that the chip surface showed oil-wet properties, simulating the original wettability of the reservoir rock. The deionized water was dyed with water-soluble dyeing material, and the deionized water was filtered through a 0.2 pm micrometer filter to remove impurities and avoid clogging the chip microchannel. The chip was saturated with dyed oil, and the oil phase was allowed to fully fill the chip pores for one day to simulate the original oil-bearing state of the reservoir. During the experiment, dyed water was first injected into the chip at a flow rate of 20 pL / min for a first water flooding, and the outlet end was continuously observed until no oil phase flowed out of the outlet end. Then, the CTAB modified nanosilica system was injected at the same flow rate to ensure that the system fully contacted the residual oil in the chip pores. Finally, a second water flooding was performed at a flow rate of 20 pL / min, and the migration, stripping and displacement of the oil phase in the chip pores were observed and recorded in real time by microscope, directly reflecting the effect of the modified system on micro residual oil.

[0074] The macro oil displacement experiment uses a natural outcrop core to simulate actual reservoir conditions. First, the basic parameters of the core were measured, including gas permeability (1-100 mD), length, radius and porosity, to provide basic data for subsequent calculations. The core was placed in a vacuum device and vacuumed to completely remove the internal air, then deionized water was injected to saturate the water, and the pore volume of the core was calculated according to the injected water volume and related formula. Shale oil was injected into the water-saturated core until the core could no longer absorb oil, and the oil-saturated operation was completed. The core was aged in the experimental environment for 7 days to allow the shale oil to fully interact with the core, and the oil saturation was calculated by injecting the oil volume and the pore volume. The experiment was carried out at a constant temperature of 45°C. First, a first water flooding was performed at a constant speed of 0.1 mL / min, and the produced liquid was collected and separated into oil and water phases in real time, and the water cut was calculated until the water cut reached 98%. Then, 0.5 PV of CTAB modified nanosilica system was injected, and a second water flooding was performed at the same speed until the water cut reached 98%. The displacement pressure change was recorded throughout the experiment, and the first water flooding recovery, total recovery and recovery enhancement value were calculated by combining the produced oil volume, to quantify the oil displacement effect of the modified system at the macro scale.

[0075] The embodiment details that the modified system can effectively strip residual oil in the chip pores in the micro oil displacement experiment, and the macro oil displacement experiment shows that it can significantly improve the core recovery rate, and there is no plugging phenomenon throughout, which shows that the technology can improve the oil displacement effect of low permeability reservoirs at micro and macro levels, and verifies its effectiveness and practicality.

[0076] Based on embodiment 1, the embodiment details the structure and stability characterization experiments of CTAB modified nano-SiO2, specifically:

[0077] Take 0.1wt% nano-SiO2 dispersion liquid and 0.1wt% nano-SiO2+0.05wt% CTAB mixed liquid, freeze-dry and grind into powder respectively, and use Bruker D8 Advance X-ray diffractometer for structure characterization, scanning range is 10°-80°, scanning speed is 2° / min, as shown in Figure 4 The results show that the two samples all have characteristic broadening diffuse scattering peaks of amorphous silicon dioxide in the range of 2θ=20°-25°, indicating that nano-SiO2 before and after modification maintains amorphous structure. Among them, the diffraction intensity of nano-SiO2 modified by CTAB in this peak area is slightly enhanced, and the peak width is slightly reduced. This is because CTAB molecules are coated on the surface of SiO2 through electrostatic adsorption, changing the electron cloud distribution of the particle surface, slightly improving the short-range order of nano-SiO2. This change confirms that CTAB has interacted with the surface of SiO2, and is not simply physically mixed, providing a structural basis for the improvement of system stability and interfacial properties.

[0078] Perform Fourier transform infrared spectroscopy (FT-IR) analysis, mix and grind the above two dry powders with potassium bromide at a mass ratio of 1:100, and press into transparent sheets, and use Bruker-Tensor II type Fourier transform infrared spectrometer for testing, wave number range is 400-4000cm -1 As shown in Figure 5 , the nano-SiO2 before modification has Si-O-Si bending vibration peak at 464.76cm -1 , O-Si-O bending vibration peak at 799.35cm -1 , Si-O-Si anti-symmetrical stretching vibration peak at 1101.15cm -1 , Si-OH stretching vibration peak at 951.70cm -1 , and structure water-OH anti-symmetrical stretching vibration peak at 3438.46cm -1 , water molecule H-O-H bending vibration peak at 1631.48cm -1 . After modification, 1101.15cm -1The Si-O-Si peak intensity at 1086.48 cm -1 and 1631.48 cm -1 was significantly weakened, indicating that the CTAB coating reduced the adsorption capacity of nano-SiO2 to water molecules, further confirming the success of surface modification.

[0079] Further, particle size and morphology analysis was performed, and Nanotrac Flex type nanoparticle size analyzer and JEM-2100F type high-resolution transmission electron microscope (TEM) were used to characterize the particle size distribution and micro-morphology of nano-SiO2 before and after modification; when testing the particle size, the two samples were diluted to 0.01wt%, the refractive index was set to 1.46, and the average value was taken by repeating the measurement 3 times, as shown in a, b of Figure 6 , the results showed that the D50 of nano-SiO2 before modification was 12.16 nm, and obvious agglomeration was observed in the TEM image, and irregular aggregates were formed between the particles; as shown in c, d of Figure 6 , the D50 after modification was reduced to 11.25 nm, and the particle size distribution was more concentrated, the TEM image showed that the particles were in a monodisperse state, and a uniform organic film (CTAB adsorption layer) was wrapped on the surface, and there was no obvious agglomeration. This is because the double electric layer formed by CTAB molecules on the surface of SiO2 increases the electrostatic repulsion between particles, effectively inhibiting the agglomeration caused by van der Waals force, and significantly improving the dispersibility.

[0080] Further, for the dispersion stability analysis, Turbiscan Lab stability analyzer and Malvern Zetasizer Nano ZS90 type Zeta potential analyzer were used to evaluate the system stability; Turbiscan test was carried out at 45°C, the scanning time was 180 min, and the transmission intensity change at different heights was recorded; when testing the Zeta potential, the sample concentration was 0.1wt%, and the average value was taken by repeating the measurement 5 times, as shown in Figure 7 , the transmission intensity of nano-SiO2 before modification fluctuated greatly with time, the particle concentration at 0.5mm height increased by 25%, and the Zeta potential was-25.37mV; as shown in Figure 8 , the transmission intensity distribution after modification was uniform, and the concentration increased by only 8%, and the Zeta potential decreased to-42.31mV. The increase in the absolute value of the negative value indicates that the surface charge density of the particles increases, and the electrostatic repulsion increases, combined with the stability of the transmission light in the Turbiscan data, it is confirmed that the CTAB modification significantly improves the dispersion stability of nano-SiO2 in water by forming a surface protective layer and enhancing the electrostatic repulsion, laying a foundation for its smooth migration in the pores of low permeability reservoirs.

[0081] The present embodiment describes in detail the modification of nano-SiO2 by CTAB through X-ray diffraction, Fourier transform infrared spectroscopy, particle size and morphology analysis, and dispersion stability analysis. The results show that CTAB successfully interacts with the surface of nano-SiO2, not only significantly improving the dispersibility of nano-particles and reducing the aggregation phenomenon, but also greatly improving the dispersion stability of the system by enhancing the electrostatic repulsion. This provides a solid structure and performance support for the effective application of modified nano-SiO2 in low permeability reservoirs.

[0082] Based on Example 1, the present embodiment describes the interfacial properties and oil displacement effect of the CTAB modified nano-SiO2 system in detail. Specifically:

[0083] Macroscopic and microscopic oil displacement experiments were conducted using a modified nano-SiO2 system with a nanoparticle concentration of 0.1wt% and a CTAB concentration of 0.05wt%. By observing the flow characteristics of the nanofluid in the chip, the mechanism of starting micro residual oil was explored in depth, as shown in Figure 9 The oil-water distribution under saturated oil state, primary water flooding state and secondary water flooding state is shown. The observation results show that after primary water flooding, there is a large amount of residual oil in the pore structure, especially in the corners of the pores, the throat and the rock wall. After nanofluid displacement, the distribution of residual oil has changed significantly, and the residual oil originally trapped in the channel is carried away, indicating that the injection of nanofluid reduces the oil-water mobility and expands the swept volume. Through binary processing for quantitative analysis of residual oil, the oil saturation after primary water flooding is calculated to be 52.70%, and the oil saturation after secondary water flooding is calculated to be 38.42%, indicating that the system can significantly improve the displacement efficiency of residual oil after water flooding.

[0084] From the micrograph, it can be seen that there is a large amount of irregular residual oil droplets and oil films in the reservoir pores after water flooding. These residual oils mainly adhere to the pore wall and the throat. By capturing the images of the micro-displacement process, it is found that the nanofluid displacement system forms a relatively stable emulsion system after injection, which reduces the tendency of oil droplets to coalesce. The reduction of oil droplet size makes it easier to be carried and migrated, as shown in Figure 10 At the same time, the wetting reversal ability of the nanofluid displacement system changes the surface properties of the rock, making the originally oil-wet surface gradually change to hydrophilic state. This change breaks the balance of adhesion between oil droplets and rock, prompting the oil droplets to fall off from the pore wall and enter the flowing phase, as shown in Figure 10 The thick oil film formed after nanofluid displacement is unstable and forms an oil ring. Under the action of structural separation pressure, the oil ring and the solid surface form a spherical oil droplet, thereby stripping the residual oil from the rock surface, as shown in Figure 10The results show that the nano oil displacement system mainly carries out the oil droplets and oil film remaining in the channel after water flooding through emulsification, wetting reversal and structural separation pressure effect. This process effectively removes the blockage of residual oil in the channel, and achieves the effect of improving the recovery rate.

[0085] Further, under the condition of 45 DEG C, the oil displacement experiment of the system in the permeability range of the target oil reservoir is carried out, and the oil displacement effect under different permeabilities is as shown in the following table. Figure 11 The specific technical effect is intuitively reflected by the following table.

[0086]

[0087] For the core with a permeability of 1 mD, the recovery rate in the first water flooding stage is 24.72%. After injecting 0.5 PV of the modified nano SiO2 system, the water content of the subsequent water flooding oil decreases by about 15%, the recovery rate is increased by 12.51%, and the final recovery rate is 37.23%, which shows that the modified nano SiO2 system has good water reduction and oil increase effect under the condition of the permeability. For the cores with a permeability of 50 mD and 100 mD, the final recovery rate is increased by 17.37% and 16.56% respectively. The greater the core permeability, the easier the nano particles enter the small pore throat, thereby improving the sweep efficiency and the effect of improving the recovery rate. However, when the permeability increases to a certain extent, the modified nano SiO2 system will flow to the dominant channel preferentially, and cannot fully displace the crude oil in the non-dominant channel, resulting in a slight decrease in the sweep efficiency and a weakening of the effect of improving the recovery rate.

[0088] The embodiment details that the CTAB modified nano SiO2 system can greatly reduce the oil-water interfacial tension, and the reduction amplitude is 95.3% at the best concentration; the core surface can be converted from weak lipophilic to medium to strong hydrophilic, and the oil stripping capacity is enhanced; in the 50 mD sand filling pipe model, the recovery rate is increased by 17.2 percentage points compared with the blank water flooding, and is better than the unmodified system, and the oil displacement effect of the low permeability reservoir is effectively improved through the synergistic effect of multiple mechanisms.

[0089] The above is only a preferred embodiment of the present application, and does not limit the protection scope of the present application. For those skilled in the art, the present application can have various changes and variations; any change, modification, replacement, integration and parameter change of the embodiments within the spirit and principles of the present application, which can realize the same function without departing from the principles and spirit of the present application, falls within the protection scope of the present application.

Claims

1. A method for enhanced oil recovery in low permeability reservoirs based on CTAB modified nanosilica, characterized in that, The application relates to a method for improving the oil recovery of low-permeability oil reservoirs. The method comprises the following steps: S1, dispersing nano-SiO2 particles in water and performing ultrasonic treatment to prepare a nano-SiO2 dispersion solution; S2, constructing a modified nano-SiO2 system; S3, pretreating a low-permeability oil reservoir core; S4, performing primary water flooding on the pretreated core until the water content reaches a preset value; S5, injecting the modified nano-SiO2 system prepared in S2 into the core subjected to the primary water flooding, and then performing secondary water flooding until the water content reaches a preset value; 2. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, S6, counting the oil production volume of the primary and secondary water flooding, combining the pore volume and the oil saturation to calculate the recovery rate, and determining the improvement effect.

3. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, In the step S1, the nano-SiO2 particles with a particle size of 10-15 nm are dispersed in distilled water, and the nano-SiO2 particles are uniformly dispersed in the distilled water by using an ultrasonic disperser for 1-1.5 h to obtain a nano-SiO2 dispersion solution.

4. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica according to claim 3, characterized in that, In the step S2, the modified nano-SiO2 system is constructed by adding CTAB into the nano-SiO2 dispersion solution obtained in S1, wherein the mass ratio of the nano-SiO2 to the CTAB is 1:0.5, and the mixture is uniformly mixed by using an ultrasonic disperser for 1-1.5 h at 60-70 DEG C, and then the modified nano-SiO2 solid particles are obtained by freeze-drying, and the modified nano-SiO2 solid particles are dispersed in water to obtain the modified nano-SiO2 system.

5. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, In the step of dispersing the modified nano-SiO2 solid particles in water to obtain the modified nano-SiO2 system, the modified nano-SiO2 solid particles obtained by freeze-drying are added into distilled water at a mass concentration of 0.1%, and the mixture is ultrasonically treated for 20-30 min by using an ultrasonic disperser with a power of 300-500 W, wherein the ultrasonic temperature is controlled to be 25-30 DEG C, so that the modified nano-SiO2 solid particles are uniformly dispersed in water to obtain the modified nano-SiO2. In the step S3, the low-permeability oil reservoir core is pretreated by the following steps: S3.1, selecting an outcrop core with a permeability of 1-100 mD, and measuring the gas-measured permeability, length, radius and porosity parameters of the core; S3.2, performing vacuum extraction on the core until the air in the core is completely discharged, and then injecting water into the core to realize water saturation, and calculating the pore volume of the core according to the water injection volume; S3.3, injecting shale oil into the water-saturated core until the core cannot absorb shale oil any more, and completing the oil saturation operation; S3.4, placing the oil-saturated core in an experimental environment to age, so that the shale oil and the core fully act on each other, and the oil saturation of the core is calculated according to the pore volume of the core and the shale oil injection volume.

6. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 5, wherein, The process for calculating the pore volume of the core in S3.2 is: pore volume V p The calculation formula is: Wherein V w,s is the total volume of the injected water after the core is saturated with water, V w,u is the volume of the injected water corresponding to the part of the core that is not saturated with water after the core is vacuumed, is the filling coefficient of the water in the core pores, and the pore volume of the core is calculated.

7. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica according to claim 1 or 6, characterized in that, The process for calculating the oil saturation of the core in S3.4 by the core pore volume and the volume of injected shale oil is as follows: the oil saturation S of the core is calculated by the following formula: o The calculation formula is: Wherein V o is the volume of shale oil injected into the core, V p is the core pore volume, and the oil saturation of the core is obtained.

8. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, The core after pretreatment in S4 is subjected to one water drive until the water cut reaches a preset value, specifically: the core after completing S3 pretreatment is injected with water into the core at a constant speed of 0.1-0.15 mL / min, the produced fluid is collected in real time through the connected separatory funnel, the oil and water two-phase density difference and the mutually insoluble characteristics are utilized, after the produced fluid is stratified after standing in the separatory funnel, the oil phase volume V o and the water phase volume V w are read and measured respectively according to the separatory funnel scale, the real-time one-time water cut is calculated, and the formula is The end point of one-time water drive is judged by monitoring f w , and one-time water drive is stopped when f w reaches a preset threshold value.

9. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, In step S5, the modified nano-silica system prepared in step S2 is injected into the core after one waterflooding, followed by a second waterflooding until the water content reaches a preset value. Specifically, after the first waterflooding is stopped, the experimental environment of the core and the injection rate of 0.1-0.15 mL / min are maintained, and 0.5 PV of the modified nano-silica system is injected into the core. After the injection is completed, water is injected into the core at the same rate for a second waterflooding. The produced liquid is collected in real time through a separatory funnel connected to the core outlet. After the produced liquid is allowed to settle and separate into layers, the oil phase volume V' is read. o and the volume of the aqueous phase V' w The formula for calculating the real-time secondary moisture content is: Continue injecting water until f' w The secondary water drive will stop when the preset threshold is reached.

10. The method for enhancing oil recovery in low permeability reservoirs based on CTAB modified nanosilica as claimed in claim 1, wherein, The S6 determines the recovery ratio improvement effect, specifically: the total volume V of the produced oil in the first water flooding process is counted o1 and the total volume V of the produced oil in the second water flooding process is counted o2 , the obtained oil saturation S o and the core pore volume V p are combined, the first water flooding recovery ratio is calculated, and the formula is: the total recovery ratio E is calculated through the formula , the recovery ratio improvement value ΔE is obtained, and the formula is: ΔE=E-E1.

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