Rock modifier as well as preparation method and application thereof

Abstract

The invention discloses a rock modifier as well as a preparation method and application thereof, and belongs to the technical field of oilfield development. The rock modifier comprises a compound A, sodium persulfate, a cosolvent, a solvent and organic acid, and an oxidizing agent can promote the surface of rock to expose more-OH groups, especially the surface of small-pore rock; si-OH formed after the compound A is hydrolyzed reacts with Si-OH on the rock surface to generate Si-O-Si, and hydrophobic groups are left on the rock surface, so that the hydrophilicity of the rock surface is converted into hydrophobicity, the contact angle is reversed, the capillary force is converted into flow driving force from flow resistance, and bound crude oil in a formation pore throat is activated and begins to flow; when the fracturing fluid is injected into the stratum along with the fracturing fluid, the fracturing fluid can be prevented from immersing into a matrix reservoir, the flowback starting pressure of the fracturing fluid can be reduced, the fracturing fluid retained in small pores is promoted to flow back smoothly, the flowback rate of the fracturing fluid is increased, and the pollution of the fracturing fluid to the stratum is remarkably reduced.

Description

Technical Field

[0001] The invention belongs to the technical field of oilfield development, and in particular relates to a rock modifier and a preparation method and application thereof. Background Art

[0002] Among the remaining proven oil and gas reserves in my country, low-permeability oil and gas resources have become the main target of domestic energy exploitation, and the rich low-permeability oil reservoir resource base provides huge potential for development. The reservoir of low-permeability oil reservoirs usually has the characteristics of low porosity, low permeability, and small pore radius; in addition, due to the poor physical properties of the reservoir, the fluid has a large seepage resistance in it, and a large production pressure is required to drive the fluid flow.

[0003] Water injection or gas injection into oil and gas reservoirs refers to injecting water or gas into the reservoir through special injection wells to maintain or restore the reservoir pressure. Water injection can also replenish formation energy to keep the reservoir with a strong driving force, thereby increasing the production rate and recovery rate of the reservoir. However, due to the low permeability, strong lipophilicity and high capillary resistance of low permeability reservoirs, water injection or gas injection is difficult and crude oil cannot flow and be produced.

[0004] Fracturing technology is mainly used for the development of low-permeability or ultra-low-permeability reservoirs. During the fracturing process, due to capillary resistance and water lock, a large amount of fracturing fluid penetrates into the pores and matrix of the formation, causing serious pollution to the formation and even stopping production. At the same time, the difficulty of fracturing fluid return will cause reservoir pollution, which is an important factor leading to production capacity not meeting expectations or even production failure; incomplete return of fracturing fluid will seriously inhibit the release of oil well production capacity. Therefore, improving the efficiency of water or gas injection and fracturing fluid return efficiency, reducing reservoir damage and improving crude oil fluidity are the technical keys to effectively improve the production capacity of low-permeability reservoirs.

[0005] The rock surface has hydrophilicity and lipophilicity, which will directly affect the wetting behavior of the liquid on the rock surface; the interface modifier can change the wettability of the rock surface, improve the microstructure of the rock surface, increase the connectivity and effective radius of the pores, and improve the permeability of the rock. During the long-term sedimentation process, the apex oxygen atoms of the rock Si-O tetrahedron are partially replaced by hydroxyl groups (-OH). The interface modifier in the prior art changes the rock interface properties by reacting with the -OH on the rock surface with -Si-O- covalent reaction, increases the wetting angle θ of water on the rock surface, reduces the capillary resistance, and thus achieves The technical effect of improving the return rate of fracturing fluid in low permeability reservoirs is achieved, but the -OH exposed on the rock surface is limited, especially on the rock surface with small pores. Due to space limitations, the flow and dissolution of groundwater are relatively weak, thereby reducing the chemical reaction of oxygen atoms in Si-O tetrahedron being replaced by -OH. In addition, the rock surface is rich in other minerals or impurities, which further reduces the possibility of oxygen atoms in Si-O tetrahedron being replaced by -OH. Therefore, the interface modifier has limited ability to react with -OH on the rock surface, resulting in weak interface modification ability, weak long-term stability and short service life of the interface modifier. Summary of the invention

[0006] In view of the above-mentioned prior art, the present invention discloses a rock modifier and a preparation method and application thereof, so as to solve the technical problems in the prior art that the rock modifier has weak modification ability on rock surface groups, poor stability after modification and short service life.

[0007] In order to solve the above technical problems, the technical solution adopted by the present invention is to provide a rock modifier, which includes the following raw materials in parts by weight: 0.05-0.15 parts of compound A, 0.08-0.12 parts of sodium persulfate, 0.08-0.12 parts of co-solvent, 8-12 parts of solvent and 0.01-0.012 parts of organic acid; the structure of compound A is shown below,

[0008]

[0009] Based on the above technical solution, the present invention can also be improved as follows.

[0010] Furthermore, the rock modifier comprises the following raw materials in parts by mass: 0.1 parts of compound A, 0.1 parts of sodium persulfate, 0.1 parts of co-solvent, 10 parts of solvent and 0.01 parts of organic acid.

[0011] Furthermore, the particle size of compound A is 50 to 75 nm.

[0012] Furthermore, the solvent is anhydrous ethanol; the co-solvent is polyvinyl alcohol; and the organic acid is glacial acetic acid, formic acid or propionic acid.

[0013] The beneficial effects of the technical solution adopted in the present invention are as follows: anhydrous ethanol has good solubility and permeability, and under the synergistic effect of polyvinyl alcohol, compound A can smoothly penetrate and infiltrate into the micro-pore structure of the low-permeability core, and after sodium persulfate interacts with the rock, more hydroxyl sites available for compound A to react are exposed on the surface of the small-pore rock, thereby increasing the reaction activity of the rock surface and enabling the rock surface to be fully modified. At the same time, organic acid can promote the hydrolysis of compound A, which is beneficial to the reaction of compound A with the hydroxyl groups on the rock surface. Under the synergistic effect of each component, compound A can efficiently and uniformly modify the rock surface, thereby avoiding potential blocking effects on the pore throat channels.

[0014] The invention also discloses a preparation method of the rock modifier, which comprises the following steps: accurately weighing various raw materials according to mass, mixing them uniformly, and obtaining the rock modifier.

[0015] The invention also discloses the application of adding the rock modifier into the formation along with the fracturing fluid to promote the return of the fracturing fluid.

[0016] Furthermore, the amount of the rock modifier added is 0.2 to 0.4 wt % of the total weight of the fracturing fluid.

[0017] The present invention has the following beneficial effects:

[0018] 1. The oxidant in the rock modifier can induce rapid dissolution or precipitation of minerals and impurities on the rock surface. This chemical reaction can significantly change the matrix and pore structure of the rock, thereby promoting the exposure of more -OH on the rock surface. Compound A in the rock modifier has two basic units, Si-OCH 2 CH 2 OCH 3 The group hydrolyzes to form Si-OH, which reacts with Si-OH on the rock surface, shedding H 2 O molecules, converting the highly polar -OH on the rock surface into a low polar ether bond (Si-O-Si), leaving a covalently bonded -CH 2 CF 2 CF 2 CF 3 Group, -CH 2 CF 2 CF 2 CF 3 The group has strong hydrophobic properties; the organic acid in the rock modifier can promote the Si-OCH 2 CH 2 OCH 3 The group is hydrolyzed to form Si-OH; the co-solvent and solvent can evenly disperse compound A.

[0019] 2. After the rock surface is modified by compound A, the rock surface changes from hydrophilic to hydrophobic, the contact angle is reversed, and the capillary force can be changed from flow resistance to flow driving force. The crude oil bound in the nano-scale pore throats in the formation is activated and begins to flow, realizing efficient development.

[0020] 3. The rock surface is uneven, crude oil is seriously adsorbed, and the pore structure has obvious filling characteristics. The rock modifier of the present invention is used to treat the formation rock. The rock surface presents a dense, fine and rough structure, the specific surface area is increased, and the contact of the solid-liquid interface is reduced, which is not conducive to the attachment of oil-water phase fluids. The hydrophobicity of the rock is enhanced, and there is no obvious filling of the pores. The rough characteristics reduce the contact area with the oil-water phase, which is conducive to the oil and water to break free from the constraints and hinder the infiltration of the rock.

[0021] 4. After rock modification, the volume of movable pores in the rock increases, which can drive the crude oil in the large pores or the fracturing fluid backflow, and can also effectively activate the bound crude oil or fracturing fluid backflow in the tiny pores.

[0022] 5. The rock modifier is injected into the formation together with the fracturing fluid, which can eliminate the water lock effect, reduce the penetration of the fracturing fluid into the matrix reservoir, greatly reduce the return start-up pressure of the fracturing fluid, and promote the smooth return of the fracturing fluid retained in the small pores. The return rate of the fracturing fluid is significantly improved, and the pollution of the fracturing fluid to the formation is significantly reduced.

[0023] 6. The reaction temperature of the rock modifier and the rock surface is low, the reaction time is short, and the cost is low. After the oxidant in the rock modifier acts on the rock, more -OH reaction sites are exposed on the rock surface, which prompts compound A to react with the rock surface to form more chemical bonds, increasing the adhesion and interaction between the modifier and the rock surface, so that the rock modifier can still firmly adhere to the rock surface when washed and is not easy to fall off, and can maintain the hydrophobicity of the rock surface for a long time in a high temperature environment, thereby extending the service life of the rock modifier. The rock modifier of this formula is in CO 2 It has high solubility in gas and water and can be dissolved in CO 2 , water or fracturing fluid is injected into the formation. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Figure 1 is the distribution diagram of fracturing fluid in the modified #1 and #2 cores;

[0025] Figure 2 This is the NMR T2 spectrum of #1 core before and after the flooding experiment;

[0026] Figure 3 This is the NMR T2 spectrum of #2 core before and after the flooding experiment;

[0027] Figure 4This is the 2D NMR imaging scan of the fracturing fluid distribution before and after the #1 and #2 core flooding experiments;

[0028] Figure 5 The relationship between permeability and flowback start-up pressure in the displacement and flowback test of the core before and after modification;

[0029] Figure 6 It is the relationship diagram between the rock modifier and the rock reaction time and contact angle;

[0030] Figure 7 This is a graph showing the relationship between the rock modifier and the rock reaction temperature and contact angle. DETAILED DESCRIPTION

[0031] The features and performance of the present invention are further described in detail below in conjunction with embodiments.

[0032] Example 1

[0033] A rock modifier comprises the following raw materials in parts by weight:

[0034] 0.05 parts of compound A, 0.12 parts of sodium persulfate, 0.08 parts of polyvinyl alcohol, 8 parts of anhydrous ethanol and 0.012 parts of propionic acid; the particle size of compound A is 50 nm, and the structure of compound A is as follows:

[0035]

[0036] The preparation method comprises the following steps: accurately weighing various raw materials, mixing them evenly, and stirring them to obtain the product.

[0037] Example 2

[0038] A rock modifier comprises the following raw materials in parts by weight:

[0039] 0.1 part of compound A, 0.1 part of sodium persulfate, 0.1 part of polyvinyl alcohol, 10 parts of anhydrous ethanol and 0.01 part of glacial acetic acid; the particle size of compound A is 75 nm, and the structure of compound A is as follows:

[0040]

[0041] The preparation method comprises the following steps: accurately weighing various raw materials, mixing them evenly, and stirring them to obtain the product.

[0042] Example 3

[0043] A rock modifier comprises the following raw materials in parts by weight:

[0044] 0.15 parts of compound A, 0.08 parts of sodium persulfate, 0.12 parts of polyvinyl alcohol, 12 parts of anhydrous ethanol and 0.01 parts of formic acid; the structure of compound A is shown below,

[0045]

[0046] The preparation method comprises the following steps: accurately weighing various raw materials, mixing them evenly, and stirring them to obtain the product.

[0047] Comparative Example 1

[0048] A rock modifier comprises the following raw materials in parts by weight:

[0049] 0.1 parts of compound A, 0.1 parts of polyvinyl alcohol, 10 parts of anhydrous ethanol and 0.01 parts of glacial acetic acid; the structure of compound A is shown below,

[0050]

[0051] The preparation method comprises the following steps: accurately weighing various raw materials, mixing them evenly, and stirring them to obtain the product.

[0052] Comparative Example 2

[0053] A rock modifier comprises the following raw materials in parts by weight:

[0054] 0.01 parts of compound A, 10 parts of anhydrous ethanol and 0.01 parts of glacial acetic acid; the structure of compound A is shown below,

[0055]

[0056] The preparation method comprises the following steps: accurately weighing various raw materials, mixing them evenly, and stirring them to obtain the product.

[0057] Experimental example

[0058] In the displacement experiment, the fracturing fluid was deionized water + 1‰ polyacrylamide and + 1‰ sodium chlorate, the displacement amount of the fracturing fluid was 0.5PV (the volume of the fracturing fluid driven was 50% of the total void volume of the core), and the displacement gas was nitrogen. When the rock modifier was added to the fracturing fluid, the amount of the rock modifier added was 0.2-0.4wt% of the total weight of the fracturing fluid.

[0059] 1. Fracturing fluid flowback experiment

[0060] The flowback volume of fracturing fluid is proportional to the permeability, flowback pressure difference, and average pore throat radius, and inversely proportional to fluid viscosity and migration distance. e -P wf , P e is the formation pressure, P wfThe bottom hole flow pressure is an important factor in determining the flowback effect. If the formation energy supply is insufficient, the formation pressure will be too low, which will lead to poor flowback effect. Especially in low permeability reservoirs, the capillary force phenomenon is prominent, which makes it easy for fluid to enter the reservoir, but the discharge process is extremely difficult. Therefore, in order to overcome the capillary force and successfully displace the invaded fluid, a sufficiently large pressure difference needs to be applied. In fact, when high-pressure fracturing is performed on the formation, the production pressure difference ΔP 1 (ΔP 1 =P 压裂流压 -P 地层压力 ) causes a large amount of fracturing fluid to enter the pore throats of the reservoir rock, especially the micropores with lower permeability. When the fracturing operation is completed, the backflow production pressure difference ΔP 2 (ΔP 2 =P 气藏压力 -P 返排流压 ), the return fluid gradually seeps or flows from the formation pore medium to the fracture, and then flows back out of the matrix formation. Obviously, due to ΔP 1 >ΔP 2 , the fracturing fluid immersed in the matrix formation under high pressure is extremely difficult to return due to the capillary resistance, or even impossible to return. Wettability is the decisive factor in changing the direction of capillary force. When the capillary force direction is reversed, it will be transformed from resistance to power, and the fracturing fluid will be returned under a smaller production pressure difference, and the fracturing fluid return rate will be greatly improved.

[0061] ① Select two permeability of 0.3×10 -3 μm 2 The low permeability cores were respectively driven forward with the fracturing fluids added with the rock modifiers in Example 2 and Comparative Example 1, wherein the #1 core was the core modified by the rock modifier in Comparative Example 1, and the #2 core was the core modified by the rock modifier in Example 2. Then, the low permeability cores were reversely driven with nitrogen. After the driving, the cores were analyzed with a MesoMR23-060H-I nuclear magnetic resonance imaging analyzer to obtain a T2 time distribution spectrum. The T2 spectrum is shown in FIG. Figures 1 to 3 As shown, from Figure 1 It can be seen that the fracturing fluid is mainly bound in the capillary tubes with pore sizes of 0.001 to 0.01 μm, making it difficult to flow back. The long T2 component corresponds to the movable or free fluid, and its T2 relaxation time is longer (>10ms), representing the fluid in the larger pores or the fluid that is less bound; the short T2 component corresponds to the fluid that is bound or immobile, and its T2 relaxation time is shorter (0.01 to 10ms); Figure 2 This is the T2 spectrum of the core modified by the rock modifier of Comparative Example 1, and the signal intensity is stronger in the relaxation time range of 0.1 to 10 ms; Figure 3This is the T2 spectrum of the core modified by the rock modifier in Example 2. In the figure, the signal intensity of the relaxation time > 10 ms is significantly enhanced, and the signal intensity within 0.01 to 10 ms after the gas drive is completed is significantly weakened, indicating that after the core is modified by the modifier, the constraints on oil and water are weakened and the fluidity is enhanced. It also shows that the surface of the rock with low pore size can also be modified by the rock modifier, which is beneficial to the return of residual oil or fracturing fluid retained in the low pore size.

[0062] ② Nuclear magnetic resonance imaging analyzer directly displays the distribution of fracturing fluid inside the core before and after. -3 μm 2 The low-permeability core was scanned by 2D NMR imaging, and the NMR imaging result was displayed with pseudo-color. The scanned image is shown in Figure 4 As shown, it can be seen from the results of nuclear magnetic phase formation that after the fracturing fluid was driven into the two cores, the core pores were filled with fracturing fluid (red part). After gas drive, the red area in the core became significantly less, that is, the fracturing fluid was reversely driven out of the core. Comparing the distribution of red area signals after the gas drive of the two cores, it can be seen that the red signal of the #1 core is more concentrated, the red signal of the #2 core is dispersed, and the area of ​​the red area of ​​the #1 core is significantly larger than that of the #2 core, indicating that the rock surface of the small pores of the core modified by the modifier in the embodiment is less likely to be replaced by hydroxyl groups due to space limitations. The rock modifier in the embodiment includes an oxidant, which, after interacting with the rock surface, exposes more hydroxyl sites that react with compound A on the rock surface, especially the rock surface of the small pores, so that the rock surface of the small pores can also be fully modified, so that it can not only displace the residual fracturing fluid in the large pores, but also efficiently displace the fracturing fluid retained in the small pores.

[0063] ③ The core with permeability of 0.43-98 mD was used for displacement and flowback experiment. The statistical results of flowback rate are shown in Table 1. It can be seen from Table 1 that the maximum flowback rate before modification is no more than 30%, and the maximum flowback rate after modification with the modifier in Example 1 can reach 61%.

[0064] Table 1

[0065]

[0066] Figure 5 This is a statistical diagram of the start-up pressure of the displacement and flowback test before and after the modification with two modifiers. Figure 5 It can be seen that after modification, the starting pressure drops to below 1MPa.

[0067] 2. Application evaluation

[0068] ① Test the reaction time between rock modifier and rock

[0069] The contact angle θ (0-180°) is used as an indicator to measure the wetting properties of liquid on the solid surface. When θ < 90°, it is called a wetting state, indicating that the liquid has a good spreading ability on the solid surface. When θ > 90°, it is a non-wetting state, that is, the spreading of the liquid on the solid surface is hindered.

[0070] The penetration rate is about 0.3×10 -3 μm 2 The rock modifier in Example 2 was reacted with the rock core, and the reaction time was 0min, 10min, 30min, 60min, 120min and 300min respectively. The experimental results are as follows Figure 6 The results show that when the fracturing fluid droplet contacts the untreated rock surface (0min), the droplet quickly penetrates into the rock, showing obvious hydrophilic properties, and the contact angle of the rock surface is 0°, that is, a completely wetted state; then the rock is modified with a rock modifier for 10min, and the wettability of the rock surface changes significantly, and the contact angle of the droplet on the rock surface increases to 98°, showing that the rock surface changes from hydrophilic to hydrophobic, showing a weak hydrophobicity; when the treatment time is extended to 30min, the contact angle of the rock surface is significantly increased to 135°, indicating that the rock surface has reached a strong hydrophobic state; when the reaction time continues to increase, the contact angle increase does not change much. The experimental results show that the reaction time of the rock modifier should be no less than 30min to change the properties of the rock, so that the rock reaches the best hydrophobic state, and further extension of the treatment time has no significant effect on the hydrophobicity of the rock surface.

[0071] ② Test the reaction temperature between rock modifier and rock

[0072] The penetration rate is about 0.3×10 -3 μm 2 The rock modifier in Example 2 was reacted with the rock core at 5°C, 40°C, 60°C, 80°C, 100°C and 120°C, and the reaction time was 30 min. The experimental results are as follows Figure 7As shown in the figure, the rock flakes and the rock modifiers can react in a wide temperature range of 25℃ to 120℃; when the reaction temperature is 25℃, the reaction efficiency is relatively low, the contact angle is 92°, and the rock flakes have a certain hydrophobicity, but the effect is not significant; as the reaction temperature increases, the hydrophobicity of the rock flake surface changes significantly; when the reaction temperature rises to 60℃ or higher, the contact angle of the treated rock flake surface reaches 130° and above, showing strong hydrophobicity, that is, the temperature above 60℃ can reach the best hydrophobic state. This result shows that high temperature conditions help to improve the reaction efficiency between the rock modifier and the rock flakes, thereby enhancing the hydrophobicity of the rock flakes; this is because the modification groups (carbon-fluorine bonds) contained in the rock modifiers are more likely to extend outward under high temperature conditions. When the number of modification groups extending outward increases, the rock hydrophobicity is enhanced, that is, the water phase contact angle increases significantly. When the reaction temperature is higher than 60°C, the temperature change no longer has a significant effect on the contact angle of the treated rock surface, which means that within the high temperature range of 60 to 120°C, the rock flakes can achieve a good hydrophobic state. In practical applications, rock modifiers can be successfully used in high-temperature reservoirs to achieve effective regulation of the hydrophobicity of the rock surface.

[0073] ③ The anti-scouring ability of the core after modification

[0074] The penetration rate is about 0.3×10 -3 μm 2 The core was subjected to interface modification treatment with the rock modifier in Example 2, and the initial wetting contact angle value was measured after drying. The core was placed in a core holder and flushed with fracturing fluid. The seepage linear velocities were 0.005m / d, 0.01m / d, 0.05m / d, 0.10m / d, 0.50m / d, 1.0m / d, 1.5m / d, 2.0m / d and 4.0m / d, respectively, and the flushing time was 14d. The core was taken out and dried at different time periods, and the wetting contact angle was measured multiple times at different positions, and the average value was calculated. The experimental results are shown in Table 2.

[0075] Table 2

[0076]

[0077] As can be seen from the table, the wetting contact angle of the rock drop fracturing fluid before flushing is between 133 and 145°. After continuous flushing of fracturing fluid at different linear speeds for 14 days, the wetting contact angle of each group of samples decreased to varying degrees, but the final contact angle range was between 130 and 137°, showing good hydrophobic performance, indicating that the rock modification has a strong binding force with the rock surface and will not be easily peeled off due to external force. Different from the adsorption and retention of ordinary surfactants, the chemical bonds produced by the reaction of rock modifiers with rocks are strong, and the covalent bonds formed increase the adhesion and interaction between the rock modifier and the rock surface, so that the rock modifier can still be firmly attached to the rock surface when flushed and is not easy to fall off; this characteristic gives the rock modifier the ability to continue to play a role in the entire process of fracturing fluid backflow construction. It can not only effectively maintain the hydrophobicity of the rock surface, but also have a positive impact on improving the fracturing effect and increasing the recovery rate of gas reservoirs.

[0078] ④ Anti-aging ability of core after treatment with rock modifier

[0079] The cores were modified with the rock modifiers in Examples 1 to 3 and Comparative Examples 1 to 2, and after drying, they were placed in an 80°C environment for aging times of 0 d, 30 d, 60 d, 90 d, 120 d, 150 d and 180 d. The contact angle variation characteristics of the cores were tested at different time points. The experimental results are shown in Table 3.

[0080] Table 3

[0081]

[0082] It can be seen from the table that with the extension of aging time, the contact angle shows a slow downward trend and finally tends to be stable; compared with the comparative example, the samples treated with the rock modifier in the embodiment can still maintain a wetting contact angle of more than 130° after half a year of aging treatment, showing good hydrophobic performance; the rock modifier in the embodiment contains an oxidant, and after the oxidant reacts with the rock, more hydroxyl groups on the rock surface are exposed, especially the surface of the rock with small pores, so that the rock modifier can form more stable covalent bonds with the rock surface, which enables it to maintain its performance without being destroyed in a long-term high-temperature environment, further enhancing its feasibility and reliability in field applications.

[0083] Although the specific implementation of the present invention is described in detail in conjunction with the embodiments, it should not be understood as limiting the scope of protection of this patent. Within the scope described in the claims, various modifications and variations that can be made by those skilled in the art without creative work still fall within the scope of protection of this patent.

Claims

1. A rock modifier, characterized in that: The method comprises the following raw materials in parts by weight: 0.05 to 0.15 parts of compound A, 0.08 to 0.12 parts of sodium persulfate, 0.08 to 0.12 parts of a cosolvent, 8 to 12 parts of a solvent and 0.01 to 0.012 parts of an organic acid; the structure of compound A is shown below:

2. The rock modifier according to claim 1, characterized in that: The method comprises the following raw materials in parts by weight: 0.1 part of compound A, 0.1 part of sodium persulfate, 0.1 part of a co-solvent, 10 parts of a solvent and 0.01 part of an organic acid.

3. The rock modifier according to any one of claims 1 to 2, characterized in that: The particle size of compound A is 50 to 75 nm.

4. The rock modifier according to any one of claims 1 to 2, characterized in that: The solvent is anhydrous ethanol; the co-solvent is polyvinyl alcohol; and the organic acid is glacial acetic acid, formic acid or propionic acid.

5. The method for preparing the rock modifier according to any one of claims 1 to 4, characterized in that: The following steps are involved: Accurately weigh each raw material by mass, mix them evenly, and stir them thoroughly to obtain the product.

6. Use of the rock modifier according to any one of claims 1 to 4 in promoting fracturing fluid flowback.

7. The use according to claim 6, characterized in that: The rock modifier is added into the formation along with the fracturing fluid.

8. The use according to claim 7, characterized in that: The added amount of the rock modifier is 0.2-0.4 wt% of the total weight of the fracturing fluid.

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