Gas reservoir fracturing fluid rock modification system and preparation method and application thereof

Abstract

The invention discloses a gas reservoir fracturing fluid rock modification system as well as a preparation method and application thereof, and belongs to the technical field of oil and gas reservoir fracturing fluids. The gas reservoir fracturing fluid rock modification system provided by the invention is prepared from the following raw materials in percentage by volume: 0.001 to 0.2 percent of rock modifier, 0.1 percent of cosolvent, 10 percent of mutual solvent, 0.1 percent of glacial acetic acid, 2 percent of cross-linking agent and the balance of water. According to the gas reservoir fracturing fluid rock modification system, hydroxyl groups on the surface of rock can be replaced by strong hydrophobic groups, the wetting angle of a rock interface to water is increased, and the flow-back efficiency of the gas reservoir fracturing fluid is greatly improved.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas reservoir fracturing fluid, and in particular relates to a gas reservoir fracturing fluid rock modification system and a preparation method and application thereof. Background Art

[0002] Fracturing technology is an effective method to improve the productivity of low-permeability / tight gas reservoirs, but reservoir contamination caused by the difficulty of fracturing fluid return is an important factor that causes gas well productivity to fall short of expectations or even fail to be put into production. Take the Sulige gas field as an example. The gas field is characterized by low permeability, low pressure, low production and low abundance. The reservoir physical properties are poor and the capillary effect is significant. It mainly relies on fracturing transformation methods to achieve ideal productivity. However, the water lock effect caused by incomplete fracturing fluid return seriously inhibits the release of gas well productivity. Therefore, improving the efficiency of fracturing fluid return and reducing reservoir damage are the technical keys to effectively improve gas well productivity.

[0003] Research results and field data show that during the fracturing process, due to capillary resistance and water lock, a large amount of fracturing fluid will penetrate into the pores and matrix of the formation, causing serious damage to the formation and even shutting down production. Usually, the flowback rate of fracturing fluid in low permeability / tight gas reservoirs is less than 30%, or even zero flowback.

[0004] Aiming at the low return rate of fracturing fluid in Sulige gas field, a typical tight sandstone gas reservoir, a technical method for formation interface modification is proposed. The reservoir porosity of this gas field is generally less than 10%, and the gas permeability is 0.3×10 -3 μm 2 The permeability and porosity of the gas field are poor, the pores are narrow, and the capillary effect is very significant. Due to the low permeability, low pressure, low production and low abundance of the gas field, the natural production capacity cannot reach the industrial gas flow, and fracturing transformation has become a key way to increase production capacity. After fracturing construction, the reservoir is very susceptible to water lock damage, which directly affects the effect of single well transformation, severely suppresses the gas field production capacity, and causes irreversible damage to the overall development of the gas reservoir.

[0005] In order to reduce the damage of fracturing fluid to the formation, the main measures taken are to add surfactants or organic matter to reduce the surface tension of fracturing fluid and improve the wettability of formation rock. Studies have shown that the use of drainage chemicals can make the contact angle of the rock surface exceed 90°, converting capillary resistance into a driving force for favorable flowback, greatly improving the flowback rate. Summary of the invention

[0006] In view of the above-mentioned prior art, the present invention provides a gas reservoir fracturing fluid rock modification system and a preparation method and application thereof, which solves the problem of low fracturing fluid flowback efficiency in the prior art.

[0007] In order to achieve the above object, the technical solution adopted by the present invention is: to provide a gas reservoir fracturing fluid rock modification system, which includes the following raw materials by volume percentage:

[0008] 0.001-0.2% rock modifier, 0.1% cosolvent, 10% mutual solvent, 0.1% glacial acetic acid, and the rest is water;

[0009] The preparation steps of the modified interface modifier are as follows: weighing a siloxane polymer and a long-chain alkyl halide, adding them to toluene, stirring at a speed of 200 r / min for 20 to 30 minutes at 30 to 40° C., and obtaining the modified interface modifier; the mass ratio of the siloxane polymer to the long-chain alkyl halide is 10:1; the material-liquid ratio of the mixture of the siloxane polymer and the long-chain alkyl halide to toluene is 1 g:5 mL;

[0010] The cross-linking agent is a mixture of 20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 by volume percentage.

[0011] The beneficial effects of the present invention are as follows: the present invention provides a rock modification system similar to the rock surface structure, which reacts with the rock surface and, at the same time, connects hydrophobic groups to the rock surface and spreads as a hydrophobic modification layer on the rock surface, thereby changing the surface energy and wettability of the rock. Through the interface modification effect, the rock water phase contact angle is modified to a strong hydrophobic range of 120° to 150°, so that the capillary force is converted from flow resistance to driving force, and the return rate is increased by 10% or more; at the same time, by adding the above-mentioned proportion of cross-linking agent to the rock modification system to reduce the surface tension (or interfacial tension) to reduce the capillary resistance of the porous medium of the formation, the fracturing fluid can be returned faster and more thoroughly, thereby effectively reducing formation damage, and can also effectively improve the temperature resistance and shear resistance of the gas reservoir fracturing fluid rock modification system, wherein the CJ2-6 hydroxypropyl guar gum molecular structure contains hydroxyl and methyl groups, which can be quickly dissolved in water and form a high-viscosity colloidal solution, so that the fracturing fluid can effectively transmit pressure and Fill rock cracks to improve the fracturing effect. Hydroxypropyl guar gum has excellent temperature stability and salt-alkali tolerance, and can maintain stable performance under different geological conditions, ensuring the reliability and durability of the fracturing effect. CJSJ-3 fungicide ensures the performance and stability of the fracturing fluid by inhibiting the growth and reproduction of microorganisms and destroying the cell membrane and metabolic process of microorganisms. TGF-1 gas well high-efficiency drainage agent improves the rheological properties of the fracturing fluid, reduces capillary pressure, and improves the quality of fractures. COP-3 gas well clay stabilizer replaces the cations on the surface of the rock and adsorbs on the surface of the rock to form an oil-loving and water-repellent adsorption layer. It can also improve the compatibility of the fracturing fluid with the formation core and fluid, and reduce the chemical reactions and precipitation generated by incompatibility. The boric acid ester WD-JL-1 can undergo cross-linking reaction with high molecular polymers in the fracturing fluid system to form a three-dimensional cross-linked network structure. This network structure can significantly improve the viscosity and sand carrying capacity of the fracturing fluid.

[0012] Based on the above technical solution, the present invention can also be improved as follows.

[0013] Furthermore, the siloxane polymer is polydimethylsiloxane, polymethylsiloxane or alkyldimethylpolysiloxane.

[0014] Furthermore, the long-chain alkyl halide is dodecyl fluoride, hexadecyl fluoride or dodecyl chloride.

[0015] The beneficial effect of adopting a further technical solution is that a modified interface modifier having a strong hydrophobic group is obtained by reacting a siloxane polymer with a long-chain alkyl halide, which can replace the hydroxyl group on the rock surface and achieve hydrophobicization of the formation rock interface.

[0016] Furthermore, the co-solvent is a mixture of methanol and isopropanol, and the mass ratio of methanol to isopropanol is 1:10.

[0017] Furthermore, the mutual solvent is anhydrous ethanol.

[0018] The present invention also discloses a method for preparing a gas reservoir fracturing fluid rock modification system, comprising the following steps:

[0019] S1: Under normal temperature, add the co-solvent into water, stir at a speed of 500-700 r / min for 30 min, then heat to 60°C and continue stirring at a speed of 500-700 r / min for 30 min to obtain solution 1;

[0020] S2: adding the mutual solvent, glacial acetic acid and the cross-linking agent to the solution 1, stirring at a speed of 500-700 r / min for 30 min at room temperature to obtain the solution 2;

[0021] S3: Add the rock modifier to solution 2, and stir at a speed of 500-700 r / min for 1-2 hours at room temperature.

[0022] The beneficial effects of the present invention are as follows: the gas reservoir fracturing fluid rock modification system provided by the present invention has simple preparation steps, does not require a complex preparation environment, is easy to produce, and has excellent industrial prospects.

[0023] The invention also discloses the application of the gas reservoir fracturing fluid rock modification system as a gas reservoir fracturing fluid additive.

[0024] Furthermore, the amount of the rock modification system added to the gas reservoir fracturing fluid is 0.5 wt % of the mass of the gas reservoir fracturing fluid.

[0025] The beneficial effects of the present invention are as follows: the rock modification system for gas reservoir fracturing fluid provided by the present invention can effectively improve the flowback effect of the fracturing fluid when used as a gas reservoir fracturing fluid additive in gas reservoir fracturing fluid, and can effectively reduce reservoir damage and improve gas well productivity in gas fields characterized by low permeability, low pressure, low production and low abundance. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] Figure 1 The reaction mechanism between the rock modification system of gas reservoir fracturing fluid and the rock surface;

[0027] Figure 2 a is a 200-fold SEM image of an untreated natural core. Figure 2 b is a 3000-fold SEM image of an untreated natural core. Figure 2 c is the SEM image of the untreated natural core at 8000 times. Figure 2 d is a 12000x SEM image of the untreated natural core;

[0028] Figure 3 a is a 500-fold SEM image of a natural core treated with pure gas reservoir fracturing fluid. Figure 3b is a 1000-fold SEM image of a natural core treated with pure gas reservoir fracturing fluid. Figure 3 c is a 2000-fold SEM image of a natural core treated with pure gas reservoir fracturing fluid. Figure 3 d is a 5000x SEM image of the natural core treated with pure gas reservoir fracturing fluid;

[0029] Figure 4 a is a 500-fold SEM image of a natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1, Figure 4 b is a 2000-fold SEM image of a natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1, Figure 4 c is a 10,000-fold SEM image of a natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1, Figure 4 d is a 20,000-fold SEM image of a natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1;

[0030] Figure 5 a is a 500-fold SEM image of a natural core treated with a gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added, Figure 5 b is a 5000-fold SEM image of a natural core treated with a gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added, Figure 5 c is a 50,000-fold SEM image of a natural core treated with a gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added, Figure 5 d is a 100,000-fold SEM image of a natural core treated with a gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added;

[0031] Figure 6 This is the energy spectrum of the untreated natural core;

[0032] Figure 7 The energy spectrum of the natural core treated by the gas reservoir fracturing fluid rock modification system prepared in Example 1;

[0033] Figure 8 This is a statistical diagram showing the effect of the flushing velocity of the gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added on the contact angle;

[0034] Fig. 9 The statistical diagram of the influence of the contact angle of the natural core treated with the gas reservoir fracturing fluid added with the gas reservoir fracturing fluid rock modification system prepared in Examples 1 to 6 at different aging times;

[0035] Fig.10 It is a statistical diagram showing the influence of the injection amount of the gas reservoir fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Example 1 is added and the pure gas reservoir fracturing fluid on the flowback rate;

[0036] Fig.11 It is the relationship diagram between permeability, flowback start-up pressure gradient and flowback rate;

[0037] Fig.12 The flowback curves of experimental well 1 and comparison well 1 are shown;

[0038] Fig.13 The flowback curves of experimental well 2 and comparison well 2 are shown;

[0039] Fig.14 The flowback curves of experimental well 3 and comparison well 3 are shown;

[0040] Fig.15 The flowback curves of experimental well 4 and comparison well 4 are shown. DETAILED DESCRIPTION

[0041] The specific implementation modes of the present invention are described in detail below with reference to the embodiments.

[0042] Example 1

[0043] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.05% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0044] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0045] S1: Mix polydimethylsiloxane and dodecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 25 min at 35 ° C to obtain a modified interface modifier;

[0046] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0047] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 600 r / min for 30 min at room temperature to obtain solution 2;

[0048] S4: Add the rock modifier to solution 2, and stir at 600 r / min for 1.5 h at room temperature.

[0049] Example 2

[0050] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.001% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0051] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0052] S1: Mix polymethylsiloxane and hexadecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 30 min at 30° C. to obtain a modified interface modifier;

[0053] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at a speed of 500 r / min for 30 min, and then heated to 60°C and stirred at a speed of 500 r / min for 30 min to obtain solution 1;

[0054] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 500 r / min for 30 min at room temperature to obtain solution 2;

[0055] S4: Add the rock modifier to solution 2, and stir at 500 r / min for 2 h at room temperature to obtain the product.

[0056] Example 3

[0057] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.01% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0058] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0059] S1: Mix alkyl dimethyl polysiloxane and dodecyl chloride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 40°C and 200 r / min for 20 min to obtain a modified interface modifier;

[0060] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 700 r / min for 30 min, then heated to 60°C and stirred at 700 r / min for 30 min to obtain solution 1;

[0061] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 700 r / min for 30 min at room temperature to obtain solution 2;

[0062] S4: Add the rock modifier to solution 2, and stir at 700 r / min for 1 h at room temperature to obtain the product.

[0063] Example 4

[0064] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.1% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0065] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0066] S1: Mix polydimethylsiloxane and dodecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 25 min at 35 ° C to obtain a modified interface modifier;

[0067] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0068] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 600 r / min for 30 min at room temperature to obtain solution 2;

[0069] S4: Add the rock modifier to solution 2, and stir at 600 r / min for 1.5 h at room temperature.

[0070] Example 5

[0071] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.15% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0072] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0073] S1: Mix polydimethylsiloxane and dodecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 25 min at 35 ° C to obtain a modified interface modifier;

[0074] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0075] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 600 r / min for 30 min at room temperature to obtain solution 2;

[0076] S4: Add the rock modifier to solution 2, and stir at 600 r / min for 1.5 h at room temperature.

[0077] Example 6

[0078] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.2% rock modifier, 0.1% methanol and isopropanol mixed solution (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, 2% crosslinking agent (20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well high-efficiency drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 mixed), and the rest is water.

[0079] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0080] S1: Mix polydimethylsiloxane and dodecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 25 min at 35 ° C to obtain a modified interface modifier;

[0081] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0082] S3: adding anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, stirring at 600 r / min for 30 min at room temperature to obtain solution 2;

[0083] S4: Add the rock modifier to solution 2, and stir at 600 r / min for 1.5 h at room temperature.

[0084] Comparative Example 1

[0085] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.1% of a mixture of methanol and isopropanol (the mass ratio of methanol to isopropanol is 1:10), 10% of anhydrous ethanol, 0.1% of glacial acetic acid, 2% of a crosslinking agent (a mixture of 20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% of TGF-1 gas well high-efficiency drainage agent, 32% of COP-3 gas well clay stabilizer and 10% of boric acid ester WD-JL-1), and the rest is water.

[0086] The preparation method of the gas reservoir fracturing fluid rock modification system in this comparative example comprises the following steps:

[0087] S1: Under normal temperature, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0088] S2: Add anhydrous ethanol, glacial acetic acid and a cross-linking agent to solution 1, and stir at 600 r / min for 30 min at room temperature to obtain solution 2.

[0089] Comparative Example 2

[0090] A gas reservoir fracturing fluid rock modification system, the raw materials of which are calculated by volume percentage: 0.05% rock modifier, 0.1% methanol and isopropanol mixture (methanol and isopropanol mass ratio is 1:10), 10% anhydrous ethanol, 0.1% glacial acetic acid, and the rest is water.

[0091] The preparation method of the gas reservoir fracturing fluid rock modification system in this embodiment comprises the following steps:

[0092] S1: Mix polydimethylsiloxane and dodecyl fluoride (mass ratio is 10:1), then dissolve the mixture in toluene (the material-liquid ratio of the mixture to toluene is 1 g:5 mL), and stir at 200 r / min for 25 min at 35 ° C to obtain a modified interface modifier;

[0093] S2: Under normal temperature conditions, a mixture of methanol and isopropanol was added to water, stirred at 600 r / min for 30 min, then heated to 60°C and stirred at 600 r / min for 30 min to obtain solution 1;

[0094] S3: adding anhydrous ethanol and glacial acetic acid to solution 1, stirring at 600 r / min for 30 min at room temperature to obtain solution 2;

[0095] S4: Add the rock modifier to solution 2, and stir at 600 r / min for 1.5 h at room temperature.

[0096] Experimental Example 1: Scanning Electron Microscope Experiment

[0097] The natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1 and the natural core treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1 (the reaction mechanism is as follows) were Figure 1 ), natural cores treated with pure gas reservoir fracturing fluid and untreated core blocks were dried into fragments with a width of about 1 cm, ensuring that the bottom surface was flat and the top surface was a natural cross section, and the samples were photographed using SEM. The experimental results are shown in Figures 2 to 5 As shown, through Figure 2Observe the microstructural characteristics of untreated natural rocks. The rock is mainly composed of sharp rock flakes and rock debris of various shapes. The natural cross-section has a high degree of flatness, and the rock surface presents intricate and criss-crossed microcracks. These microcracks vary in length and depth and are randomly distributed on the surface of the rock. In addition, there are a certain number of pore structures scattered on the surface of the rock. These pores show obvious maturity. In addition to the presence of authigenic minerals, no other types of material filling phenomena are observed inside the pores. When the image is magnified to 12,000 times for observation, it can be seen that the rock surface is extremely smooth. This surface property is extremely beneficial for the spread of the liquid phase, allowing the liquid phase to easily penetrate into the rock. It is also clearly reflected in the water phase wetting contact angle on the rock surface, that is, the water phase wetting contact angle on the untreated rock surface is relatively small, much smaller than the wetting contact angle of the rock surface treated with the interface modifier. This phenomenon reveals that the original rock surface is highly hydrophilic, and the interface modifier can cause the rock surface properties to change, thereby affecting its interaction with the liquid phase.

[0098] By observation Figure 3 It can be seen that the fracturing fluid contamination has a significant impact on the rock surface. The fracturing fluid adsorption and retention phenomenon is serious on the contaminated rock surface, and the surface becomes uneven and covered with a layer of flocculent material. The accumulation of fracturing fluid leads to extremely obvious filling characteristics of the pore structure, and the pore space is filled in a large amount, so that the true morphology of the natural section is difficult to recognize.

[0099] pass Figure 4 It can be observed that after the interface modification, the pore space of the rock is not obviously filled. Further magnification to 10,000 times shows that there are many irregular nanostructures similar to "bamboo shoots" protrusions all over the rock surface, which give the rock surface a rough characteristic at the microscopic level.

[0100] pass Figure 5 It can be observed that when the interface modifier is added to the fracturing fluid to treat the rock sample, the characteristics of the rock surface have changed significantly. Specifically, the larger pores remain open and unfilled during the treatment process, while only a very small number of tiny pores are occupied by foreign media. This shows that by adding an interface modifier, the filling phenomenon of the overall pores on the rock surface by the fracturing fluid can be improved, the pore throats filled by the fracturing fluid can be unblocked, and only the local pore structure is affected by the fracturing fluid.

[0101] Energy spectrum analysis was then performed on natural cores treated with the gas reservoir fracturing fluid rock modification system prepared in Example 1 and untreated cores. Figure 6 The untreated cores showed that the weight percentage of C element was 33.9%, the weight percentage of O element was 31.4%, and the weight percentage of Si element was 21.8%. Figure 7 It shows that the weight percentage of C element in natural core treated by gas reservoir fracturing fluid rock modification system decreased slightly to 30.7%, while the weight percentage of O element increased significantly to 45.7%. In particular, the content of F element in the modified rock sample increased significantly, and its weight percentage reached 13.1%. At the same time, the content of Si element decreased to 10.5% by weight. By comparing the two sets of energy spectrum analysis results, the effect of interface modifier on the element content on the core surface is given. In particular, the significant increase in the content of F element clearly indicates that the fluoroalkyl group has been successfully connected to the core surface.

[0102] Experimental Example 3: Self-priming Experiment

[0103] The glass capillary was cleaned with anhydrous ethanol, washed with distilled water, and the residual liquid was blown dry with high-pressure nitrogen, and then dried for use; then the gas reservoir fracturing fluid rock modification system prepared in Examples 1 to 6 and the comparative example was sucked into the glass capillary, isolated from air and aged for 24 hours, the glass capillary was taken out, and the excess interface modifier solution was blown dry with high-pressure nitrogen. Finally, the untreated and treated glass capillary were inserted into the fracturing fluid, and the change in the height of the liquid column in the capillary was recorded. The experimental results are shown in Table 1.

[0104] Table 1 Capillary self-absorption experimental data table

[0105]

[0106] The experimental results show the influence of interface modifier concentration and capillary inner diameter on the height of liquid column. When the concentration of interface modifier is kept constant, it is observed that as the inner diameter of the capillary gradually decreases, the height of the self-imbibition liquid column of the glass capillary increases significantly, however, the descending height of the liquid column decreases accordingly. When the concentration of interface modifier exceeds 0.05%, the liquid level heights of the capillaries with three inner diameters (0.1mm, 0.3mm and 0.4mm) are all lower than the liquid level height of the fracturing fluid (35mm), indicating that the glass capillary after interface modification has reduced liquid adhesion and poor fracturing fluid infiltration ability. When the concentration is greater than 0.05%, the contact angle is greater than 90°, indicating that the wetting properties of the capillary surface are reversed, that is, from lyophilic to lyophobic.

[0107] Experimental Example 4: Wetting contact angle experiment

[0108] The natural core was cleaned and dried, and cut into 0.3-0.5 cm core slices with a core cutter. The core slices were then immersed in the fracturing fluid to which the gas reservoir fracturing fluid rock modification system prepared in Examples 1-6 and the comparative example was added, respectively, and placed in a vacuum filtration glass jar. Vaseline was applied to the closed part of the glass cover, the glass cover was covered, the connecting pipeline valve was opened, the vacuum pump was turned on, and the negative pressure was evacuated for 4 hours; after evacuation, the core slices were placed in an oven at 80° C. and dried for 2 hours. After the core slices were cooled, they were placed on the stage of a contact angle meter, and the wetting contact angle value of the fracturing fluid dripped on the surface of the rock slice was measured.

[0109] Taking the core slice immersed in the fracturing fluid of the gas reservoir fracturing fluid rock modification system prepared in Example 1 as an example, the contact angles of the immersion reaction times of 0min, 10min, 30min, 60min, 120min and 300min were measured. The experimental results are shown in Table 2. After the reaction time exceeds 30min, further extending the treatment time has no significant effect on the hydrophobicity of the rock slice surface. In general, in the process of the interface modifier changing the properties of the rock slice to make it reach a hydrophobic state, the shortest reaction time should be 10min to ensure that the surface of the rock slice begins to show hydrophobic characteristics. In order to make the rock slice reach the optimal hydrophobic state, the reaction time should be no less than 30min, and the extended treatment time no longer has a significant effect on the hydrophobicity of the rock slice surface.

[0110] Table 2 Relationship between contact angle and reaction time

[0111]

[0112] Taking the core slice immersed in the fracturing fluid of the gas reservoir fracturing fluid rock modification system prepared in Example 1 as an example, the immersion reaction time was 30min, but the contact angles of the temperature conditions were 25°C, 40°C, 60°C, 80°C, 100°C and 120°C respectively (ethanol boiling point 78.3°C, 80°C ~ 120°C three groups of experiments, the core slices were placed in a high pressure reactor for the experiment), the experimental results are shown in Table 3, in the wide temperature range of 25°C to 120°C, the rock slices and the interface modifier can react. When the reaction temperature is 25°C, the reaction efficiency is relatively low. Under this condition, the fracturing fluid is dripped on the surface of the treated rock slice, and the contact angle is 92°, showing a certain hydrophobicity, but the effect is not significant. As the reaction temperature increases, the hydrophobicity of the surface of the rock slice changes significantly. When the reaction temperature rises to 60°C or higher, the contact angle of the surface of the treated rock slice reaches 130° and above, showing a strong hydrophobicity, that is, the temperature is higher than 60°C to achieve the best hydrophobic state. This result indicates that high temperature conditions help to improve the reaction efficiency between the interface modifier and the rock flakes, thereby enhancing the hydrophobicity of the rock flakes.

[0113] Table 3 Relationship between contact angle and temperature

[0114]

[0115] Taking the core slice immersed in the fracturing fluid of the gas reservoir fracturing fluid rock modification system prepared in Example 1 as an example, the initial wetting contact angle value of the core slice after drying is measured first, and then the core slice is placed in a core holder, and the core is flushed with the fracturing fluid of the gas reservoir fracturing fluid rock modification system without the addition of the fracturing fluid, the seepage linear velocity is 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, the flushing time is 14d, after the flushing is completed, the core is taken out and dried, the wetting contact angle is measured multiple times at different positions, and the average value is calculated to explore the stability performance of the low permeability core after continuous fluid flushing and the change law of wettability. The experimental results are as follows Figure 8 As shown in the figure, the wetting contact angle of the rock dripping fracturing fluid before flushing was between 135° and 141°. After continuous flushing with fracturing fluid at different linear speeds for 14 days, the wetting contact angle of each group of samples decreased to varying degrees, but the change in the wetting contact angle did not exceed 10°. The final contact angle range was between 130° and 137°, showing good hydrophobic performance, indicating that the interface modifier has a strong bonding force with the rock surface and will not be easily peeled off due to external force.

[0116] The core pieces treated with the gas reservoir fracturing fluid rock modification system prepared in Examples 1 to 6 were dried and placed in an 80°C environment for aging time of 0d, 30d, 60d, 90d, 120d, 150d and 180d, and the contact angle change characteristics of the core pieces were tested at different time points. The experimental results are shown in Figure 2. Fig. 9 As shown in the figure, with the extension of aging time, the contact angle shows a slow downward trend and finally stabilizes. The final wetting contact angle reduction value of the 6 parallel experiments does not exceed 15°. For samples with an interface modifier concentration between 0.05% and 0.15%, after half a year of aging treatment, their wetting contact angles can still be maintained above 130°, showing good hydrophobic properties.

[0117] Experimental Example 5: Flowback Displacement Experiment

[0118] Experiment on the effect of interface modification system concentration on flowback rate: After cleaning, the natural core was dried at 80℃ for more than 10 hours, and the dry weight G1 was weighed. After saturation with water, the porosity was calculated. and pore volume Vpore, dry the core again for 10 hours, use the prepared fracturing fluid to displace the core forward, turn off the pump after the displacement, record the core wet weight G2, use gas to displace the core in the reverse direction, record the start and end time of the whole process, and accurately collect and weigh the volume of the returned liquid, calculate the average flow rate, and turn off the pump when there is no liquid flowing out of the outlet, and weigh the wet weight G3. The calculation formula for the return rate E is:

[0119]

[0120] The gas reservoir fracturing fluid rock modification system prepared in Examples 1 to 6 and the comparative example was added to the fracturing fluid (the addition amount was 0.5wt% of the mass of the fracturing fluid), and after forward displacement of 0.5PV fracturing fluid, the core wet weight was recorded, and the fracturing fluid was reversely displaced with nitrogen until no liquid was discharged from the outlet, and the second core wet weight was recorded. The flowback rate was calculated from the core mass difference, and the experimental results are shown in Table 4.

[0121] Table 4 Statistical table of the effect of interface modification system concentration on the backflow rate

[0122]

[0123] From the experimental results, we know that as the concentration of the added interface modifier (0% to 0.20%) increases, the flowback rate first rises sharply, and then the increase trend becomes slow. According to the curve results analysis, when the concentration is 0.05%, the flowback rate trend reaches a rapid growth inflection point, and the flowback rate reaches 64%. Thereafter, the flowback rate increases slowly. Since the interface modifier reacts with the -OH on the surface of the rock, when the concentration of the interface modifier increases, the interface modification groups contained in the fracturing fluid increase, and more -OH can be reacted to form a wider interface modification film, which promotes the change in the wettability of the rock surface. However, the number of -OH on the rock surface is limited, corresponding to the number of interface modifier molecules that react with it. When the interface modifier reaches the optimal concentration (0.05%), increasing the concentration will cause particle aggregation, and it will no longer have the effect of improving efficiency.

[0124] Experiment on the effect of cross-linking agent on the backflow rate: The experimental results are shown in Table 4. The backflow rate of the interface modification system prepared in Comparative Example 2 is only 29.12%, which is equivalent to the backflow rate of the interface modification system in Comparative Example 1 without adding the modified interface modifier, and is significantly different from the backflow rate of 64% in Example 1, indicating that under the temperature condition of 80°C, not adding a cross-linking agent will have a huge impact on the backflow capacity, temperature resistance and shear resistance of the interface modification system.

[0125] Experiment on the effect of fracturing fluid injection volume on flowback rate: 22 cores with gas permeability of about 0.3×10-3μm2, porosity less than 10%, length of about 5cm, diameter of about 2.5cm, and similar lithology were selected for the experiment. They were divided into two groups. Fracturing fluid with an interface modifier mass concentration of 0.05% (fracturing fluid with the interface modification system of Example 1 added) was injected into one group of cores, and pure fracturing fluid was injected into the other group of cores. The flowback rate was calculated when the injection volume was changed to 0.01PV, 0.05PV, 0.10PV, 0.15PV, 0.20PV, 0.25PV, 0.30PV, 0.35PV, 0.40PV, 0.45PV and 0.50PV respectively. The experimental results are as follows: Fig.10 As shown in the figure, with the increase of the injection volume of fracturing fluid, the overall flowback rate of the two groups of cores showed a trend of first rising and then stabilizing. In contrast, the flowback rate of the core injected with the interface modifier in the fracturing fluid was much higher than that of the other group under the same injection volume. Even after a small increase in the injection volume (0.01PV), a flowback rate of nearly 50% can be achieved, which shows that the interface modifier carried by the fracturing fluid can more fully travel in the low-permeability capillaries, and the modified rock surface covers a wider area, thereby displacing the fracturing fluid retained in the micro-pores to the greatest extent. However, continuously increasing the injection volume of the fracturing fluid containing the interface modifier will not have a sustained and effective effect on the flowback rate, because the number of hydroxyl groups on the rock surface is limited. Once the interface modifier reaches the optimal reaction equivalent, it will no longer promote the flowback process of the fracturing fluid. Therefore, for low-permeability rocks of the same permeability order of magnitude, the rock without interface modifiers will have a large capillary resistance and difficulty in fracturing fluid return due to its own low permeability and small pore throat radius. However, after adding interface modifiers, the return rate of fracturing fluid will be significantly improved. Since the return rate-injection volume curve reaches a 60% return rate at 0.05PV, and the return rate begins to stabilize at an injection volume of 0.10PV, the best return effect can be achieved by adding interface modifiers to 0.05-0.10PV fracturing fluid.

[0126] Experiment on the influence of permeability on flowback rate and flowback start pressure gradient: The flowback start pressure of fracturing fluid refers to the minimum pressure required to start the flowback of fracturing fluid from the formation fractures after the fracturing operation is completed. It reflects the degree of closure of the formation fractures and the difficulty of fracturing fluid flowback from the formation. The flowback start pressure of fracturing fluid indicates the minimum pressure at which the fracturing fluid starts to flow from the fractures under the action of pressure difference. When the applied pressure is greater than the flowback start pressure, the fracturing fluid can overcome the resistance of the formation and start to flow back from the fractures; if the applied pressure is lower than the flowback start pressure, the fracturing fluid may be retained in the fractures, resulting in obstruction or delay of the flowback of the fracturing fluid.

[0127] Take 12 gas test permeability 0.03×10-3μm 2 、0.3×10-3μm2 、1.0×10-3μm 2 、10×10-3μm 2 、20×10-3μm 2 and 50×10-3μm 2 The cores were divided into two groups, one group was injected with 0.05PV pure fracturing fluid, and the other group was injected with fracturing fluid with an interface modifier mass concentration of 0.05% (fracturing fluid with the interface modification system of Example 1 added), and the flowback rate and flowback start-up pressure were calculated. At the same time, the effective pore size values ​​of cores with different permeabilities were further estimated by the Kozeny-Carman equation as shown in Table 5

[0128] Table 5 Effective pore size of cores with different permeabilities

[0129] <![CDATA[Air permeability (×10-3μm 2 )]]> Effective pore size (μm) 0.03 3.69 0.3 7.83 1.0 14.30 10 24.90 20 27.76 50 35.52

[0130] The experimental results are as follows Fig.11 As shown, the gas permeability is 0.030×10-3μm 2 ~50×10-3μm 2 The effective pore size range is calculated to be between 3.69 and 35.52 μm. The flowback rate of the cores with 0.05% concentration of interface modifier is higher than 60%, with the highest reaching 75.17%. The flowback rate of the cores without interface modifier is only 45.33% when the effective pore size is 35.52 μm. This shows that the interface modifier can not only act on the rock surface with an effective pore size range of 3.69 to 35.52 μm, but also make the low-pore core have a high flowback rate, and the flowback rate of low-pore rock is not much different from that of high-pore rock. This phenomenon is consistent with the wetting contact angle experiment, indicating that after interface modification, the lower the pore size of the rock, the greater the resistance to capillary self-imbibition and the stronger the ability to inhibit capillary self-imbibition, which becomes the driving force for water phase flowback, which is beneficial to reduce the water saturation of the rock and improve the gas phase seepage capacity.

[0131] Experimental Example 6

[0132] Field experiment: In a low-permeability and tight gas reservoir area in the Sulige gas field, a process was adopted in which the interface modification system was sucked into the sand mixing tank by the on-board pump of the sand mixing truck and mixed with the gas reservoir fracturing fluid for injection. The construction was simple, with an average single-stage construction time of 90 minutes and an average single-stage addition of 625 kg. The construction well numbers were Su A1, Su A2, Su A3, Su A4, Su A5, Su A6, Su A7 and Su A8, with a total of 16 sections of perforations of 50 m.

[0133] The statistics of flowback effects of each construction well are shown in Table 6.

[0134] Table 6 Flowback effect statistics

[0135]

[0136]

[0137] The wells in the same layer are taken as the comparison wells and the construction wells are taken as the experimental wells. The difference is that the gas reservoir fracturing fluid rock modification system is not added to the gas reservoir fracturing fluid. The flowback effect is shown in Table 7.

[0138] Table 7 Comparison of flowback effects

[0139]

[0140] like Figures 12 to 15 As shown, the experimental results show that the construction process of the fracturing fluid with the addition of the interface modification system is simple, has no obvious effect on the fracturing construction process, and has no significant effect on the injection and sand carrying capacity of the fracturing fluid; after fracturing, the average return rate of the fracturing fluid in the experimental wells reached 61%, and the highest return rate of a single well reached 67%. The average return rate of the 8 fracturing experimental wells (61%) was 9% higher than that of the control wells (52%). The rock modification system of the gas reservoir fracturing fluid significantly improves the return effect of the fracturing fluid.

[0141] 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 gas reservoir fracturing fluid rock modification system, characterized in that: The following raw materials are included by volume percentage: 0.001-0.2% rock modifier, 0.1% cosolvent, 10% mutual solvent, 0.1% glacial acetic acid, 2% crosslinker, and the rest is water; The modified rock modifier is prepared by weighing a siloxane polymer and a long-chain alkyl halide, adding them to toluene, and stirring at a speed of 200 r / min for 20 to 30 minutes at 30 to 40° C.; the mass ratio of the siloxane polymer to the long-chain alkyl halide is 10:1; the material-liquid ratio of the mixture of the siloxane polymer and the long-chain alkyl halide to toluene is 1 g:5 mL; The crosslinking agent is a mixture of 20% CJ2-6 hydroxypropyl guar gum, 6% CJSJ-3 bactericide, 32% TGF-1 gas well efficient drainage agent, 32% COP-3 gas well clay stabilizer and 10% boric acid ester WD-JL-1 by volume percentage.

2. The gas reservoir fracturing fluid rock modification system according to claim 1, characterized in that: The silicone polymer is polydimethylsiloxane, polymethylsiloxane or alkyl dimethylpolysiloxane.

3. The gas reservoir fracturing fluid rock modification system according to claim 1, characterized in that: The long-chain alkyl halide is dodecyl fluoride, hexadecyl fluoride or dodecyl chloride.

4. The gas reservoir fracturing fluid rock modification system according to claim 1, characterized in that: The co-solvent is a mixture of methanol and isopropanol, and the mass ratio of methanol to isopropanol is 1:

10.

5. The gas reservoir fracturing fluid rock modification system according to claim 1, characterized in that: The mutual solvent is anhydrous ethanol.

6. The method for preparing the gas reservoir fracturing fluid rock modification system according to any one of claims 1 to 5, characterized in that: The following steps are involved: S1: Under normal temperature, add the co-solvent into water, stir at a speed of 500-700 r / min for 30 min, then heat to 60°C and continue stirring at a speed of 500-700 r / min for 30 min to obtain solution 1; S2: adding the mutual solvent, glacial acetic acid and the cross-linking agent to the solution 1, stirring at a speed of 500-700 r / min for 30 min at room temperature to obtain the solution 2; S3: Add the rock modifier to solution 2, and stir at a speed of 500-700 r / min for 1-2 hours at room temperature.

7. Use of the gas reservoir fracturing fluid rock modification system according to any one of claims 1 to 5 as a gas reservoir fracturing fluid additive.

8. The use according to claim 7, characterized in that: The added amount of the gas reservoir fracturing fluid rock modification system is 0.5% of the mass of the gas reservoir fracturing fluid.

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