Shale oil and gas reservoir fracturing fluid and fracturing method

Abstract

The invention relates to shale oil and gas reservoir fracturing fluid and a fracturing method, and belongs to the technical field of oil and gas field development. According to the shale oil and gas reservoir fracturing fluid, through compounding of the resistance reducing agent, the anti-swelling agent and the imbibition agent, the wettability of the rock surface can be effectively improved, an oil film on the rock surface can be stripped, water imbibition driving is achieved, replacement of heavy oil components is improved, and then the oil displacement efficiency is improved. The acid liquor in the pre-posed agent can acidify the rock, and the liquid carbon dioxide can improve the brittleness of the rock, so that the fracture forming effect is improved. The shale oil and gas reservoir fracturing fluid can improve horizontal and vertical core imbibition effects at the same time. When the shale oil and gas reservoir fracturing fluid is used for shale oil and gas reservoirs with the horizontal stress difference coefficient not larger than 0.16 and the brittleness index not smaller than 0.4, shale can be fractured to form complex cracks, and the fracturing effect is improved.

Description

Technical Field

[0001] The invention relates to shale oil and gas reservoir fracturing fluid and a fracturing method, belonging to the technical field of oil and gas field development. Background Art

[0002] Shale oil and gas reservoirs are unconventional reservoirs with enormous reserves. Shale is a rock composed of clay minerals (such as kaolinite, montmorillonite, hydromica, and bayleite), detrital minerals (such as quartz, feldspar, and mica), and authigenic minerals (such as iron, aluminum, and manganese oxides and hydroxides). The detrital minerals in shale make it capable of storing oil and gas. Shale oil has no natural production capacity or commercial value under natural conditions, requiring specialized extraction methods such as fracking. Shale oil extraction relies primarily on capillary forces and gravity.

[0003] However, when the brittleness index of rocks in shale oil and gas reservoirs is too low, the rocks primarily fail plastically during fracturing, resulting in large horizontal stress differences and large vertical stress variations. This makes it difficult to form complex fractures during fracturing, resulting in poor fracturing results and low oil production. Therefore, there is an urgent need to develop a fracturing fluid suitable for shale oil and gas reservoirs with a low brittleness index. Summary of the Invention

[0004] The purpose of the present invention is to provide a shale oil and gas reservoir fracturing fluid, which can solve the problem of poor fracturing effect in shale oil and gas reservoirs with a small brittleness index.

[0005] Another object of the present invention is to provide a fracturing method for shale oil and gas reservoirs, which can solve the current problems of poor fracturing effect and low oil production during fracturing construction of shale oil and gas reservoirs with a small brittleness index.

[0006] In order to achieve the above objectives, the technical solution adopted by the shale oil and gas reservoir fracturing fluid of the present invention is:

[0007] A shale oil and gas reservoir fracturing fluid comprises a pre-flushing agent, an integrated fracturing oil-displacing fluid and a temporary plugging material; the temporary plugging material is a temporary plugging agent and / or a temporary plugging ball; the pre-flushing agent is an acid solution or liquid carbon dioxide; the integrated fracturing oil-displacing fluid mainly comprises a drag reducing agent, an anti-swelling agent, an imbibition agent, a gel breaker and water, wherein the mass fraction of the drag reducing agent is 0.1% to 1%, the mass fraction of the anti-swelling agent is 0.05% to 0.15%, the mass fraction of the imbibition agent is 0 to 0.3%, and the mass fraction of the gel breaker is 0.01 to 0.04%.

[0008] The shale oil and gas reservoir fracturing fluid of the present invention is a pioneering invention. The present invention can effectively improve the wettability of the rock surface, peel off the oil film on the rock surface, realize water imbibition drive, improve the replacement of heavy oil components, and thus improve the oil recovery efficiency by compounding a drag reducing agent, an anti-swelling agent and an imbibition agent. The acid in the pre-admixture can acidify the rock, and the liquid carbon dioxide can increase the brittleness of the rock, thereby improving the fracturing effect. The shale oil and gas reservoir fracturing fluid of the present invention can simultaneously improve the horizontal and vertical core imbibition effects. When the shale oil and gas reservoir fracturing fluid of the present invention is used for shale oil and gas reservoirs with a horizontal stress difference coefficient of not more than 0.16 and a brittleness index of not less than 0.4, the shale can be fractured to form complex cracks, thereby improving the fracturing effect.

[0009] Preferably, the acid solution mainly consists of HCl, an acidifying corrosion inhibitor, an iron ion stabilizer and water, the mass fraction of HCl is 10-12%, the mass fraction of the acidifying corrosion inhibitor is 2-3%, and the mass fraction of the iron ion stabilizer is 2-3%.

[0010] Preferably, the integrated fracturing oil displacement fluid comprises low-viscosity slick water, medium-viscosity slick water, high-viscosity slick water and glue; the mass fractions of the drag reducing agent in the low-viscosity slick water, medium-viscosity slick water, high-viscosity slick water and glue increase in sequence.

[0011] Preferably, the mass fraction of the drag reducing agent in the adhesive solution is 0.8% to 1.0%.

[0012] Preferably, the diameter of the temporary blocking balls is 16-18 mm, and the particle size of the temporary blocking agent is 40-80 mesh.

[0013] The technical solution adopted by the shale oil and gas reservoir fracturing method of the present invention is:

[0014] A shale oil and gas reservoir fracturing method comprises the following steps: firstly determining the segment cluster perforation positions of the target shale oil and gas reservoir, and then performing fracturing construction on each fracturing segment using the shale oil and gas reservoir fracturing fluid described above.

[0015] The shale oil and gas reservoir fracturing method of the present invention adopts shale oil and gas reservoir fracturing fluid to perform fracturing. The drag reducing agent, anti-swelling agent and imbibition agent in the fracturing fluid can effectively improve the wettability of the rock surface, peel off the oil film on the rock surface, realize water imbibition drive, improve the replacement of heavy oil components, and thus improve the oil displacement efficiency. The acid liquid in the pre-admixture can acidify the rock, and the liquid carbon dioxide can increase the brittleness of the rock, thereby improving the fracturing and fracture-forming effect. When the shale oil and gas reservoir fracturing method of the present invention is used for shale oil and gas reservoirs with a horizontal stress difference coefficient of not more than 0.16 and a brittleness index of not less than 0.4, the shale can be fractured to form complex fractures, thereby improving the fracturing effect.

[0016] Preferably, the fracturing construction method includes the following steps: injecting a pre-fluid into the fracturing section to form a pre-fluid plug, then sequentially injecting low-viscosity slick water, medium-viscosity slick water, and high-viscosity slick water in the shale oil and gas reservoir fracturing fluid as described above into the fracturing section to form combined slicks in different forms, and finally injecting a displacement fluid into the fracturing section for displacement; the pre-fluid is the pre-fluid in the shale oil and gas reservoir fracturing fluid as described above, and the displacement fluid includes the low-viscosity slick water and high-viscosity slick water in the shale oil and gas reservoir fracturing fluid as described above.

[0017] Preferably, the low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are respectively divided into multiple batches and injected into the fracturing stage to form combined slugs in different forms.

[0018] It can be understood that the combined slugs include a low-viscosity slug formed by low-viscosity slugs, a medium-viscosity slug formed by medium-viscosity slugs, and a high-viscosity slug formed by high-viscosity slugs.

[0019] Preferably, when low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are injected into the fracturing stage, the low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are used to carry proppants and temporary plugging materials in the shale oil and gas reservoir fracturing fluid as described above.

[0020] Preferably, the temporary blocking material carried by the low-viscosity slippery water is a temporary blocking agent, and the temporary blocking material carried by the high-viscosity slippery water is a temporary blocking ball.

[0021] Preferably, the proppant is ceramsite or quartz sand with a particle size of 40 to 140 meshes.

[0022] Preferably, the horizontal stress difference coefficient of the target shale oil and gas reservoir is not greater than 0.16, and the brittleness index is not less than 0.4. BRIEF DESCRIPTION OF THE DRAWINGS

[0023] Figure 1 This is a schematic cross-sectional view of the horizontal section of Well F in Experimental Example 2 of the present invention;

[0024] Figure 2 Schematic diagram of the relationship between the horizontal stress difference coefficient and the crack morphology in Experimental Example 2 of the present invention;

[0025] Figure 3 This is a construction curve diagram of the first fracturing stage during fracturing construction in Experimental Example 2 of the present invention;

[0026] Figure 4 This is a microseismic monitoring diagram when low-viscosity slick water is injected in batches during fracturing construction in Experimental Example 2 of the present invention;

[0027] Figure 5 This is a microseismic monitoring diagram when medium-viscosity slick water is injected in batches during fracturing construction in Experimental Example 2 of the present invention;

[0028] Figure 6 This is a microseismic monitoring diagram when highly viscous slick water is injected in batches during fracturing construction in Experimental Example 2 of the present invention;

[0029] Figure 7 This is a microseismic monitoring image during fracturing operation of the first fracturing stage in Experimental Example 2 of the present invention;

[0030] Figure 8 This is a construction curve diagram of the third fracturing stage during fracturing construction in Experimental Example 2 of the present invention;

[0031] Figure 9 This is a construction curve diagram when fracturing the sixth fracturing stage in Experimental Example 2 of the present invention;

[0032] Figure 10 This is a microseismic detection image during fracturing operation of the sixth fracturing stage in Experimental Example 2 of the present invention;

[0033] Figure 11 This is a schematic diagram of the production situation of Well F in Experimental Example 2 of the present invention;

[0034] Figure 12 Schematic diagram of interfacial tension test results of aqueous solutions of osmolytes with different concentrations in the experimental examples of the present invention;

[0035] Figure 13 Schematic diagram of the wetting angle test results of aqueous solutions containing different concentrations of imbibing agents on a quartz plate modified by immersion in silicone oil in an experimental example of the present invention;

[0036] Figure 14 Schematic diagram of the heat and shear resistance test results in the experimental example of the present invention;

[0037] Figure 15 Schematic diagram of the relationship between the injection rate of carbon dioxide and oil production in the experimental example of the present invention;

[0038] Figure 16 Schematic diagram of the relationship between the injection amount of carbon dioxide and the energy enhancement effect in the experimental example of the present invention. DETAILED DESCRIPTION

[0039] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0040] 1. Specific embodiments of the shale oil and gas reservoir fracturing fluid of the present invention are as follows:

[0041] Example 1

[0042] The shale oil and gas reservoir fracturing fluid of this embodiment includes a pre-adhesive, an integrated fracturing oil displacement fluid and a temporary plugging material; the temporary plugging material includes a temporary plugging agent and a temporary plugging ball;

[0043] The pre-adherent is acid or liquid carbon dioxide. The acid consists of the following components in percentage by weight: 10% HCl, 2% acidifying corrosion inhibitor, 2% iron ion stabilizer, and the balance is water. The acidifying corrosion inhibitor acts as a corrosion inhibitor to protect equipment and pipelines. The acidifying corrosion inhibitor used in this embodiment is BSA-62. The product information website is http: / / www.bjsdad.com / product / proShow.asp? id=51; The iron ion stabilizer is a commercially available product. Its function is to prevent iron ions from forming Fe(OH)3 precipitation after acidification. During the acidification process, due to the contact between the acid solution and the steel surface, some iron ions will enter the formation. As the acid-rock reaction proceeds, the acid solution activity gradually decreases and the pH value increases, causing free iron ions to precipitate in the form of Fe(OH)3, causing secondary pollution. Adding the iron ion stabilizer to the acid solution can effectively complex the free iron ions to form a stable iron ion complex, avoid the formation of secondary precipitation, and improve the acidification effect. The acidizing corrosion inhibitor used in this example is product model BSA-504, and the product information website is http: / / www.bjsdad.com / product / proShow.asp?id=50.

[0044] Integrated fracturing oil displacement fluid is mainly composed of resistance reducing agent, anti-swelling agent, imbibition agent, gel breaker and water. According to the concentration of each component, it is divided into low-viscosity slick water, medium-viscosity slick water, high-viscosity slick water and gel solution.

[0045] The low-viscosity slick water is composed of the following components in percentage by mass: 0.1% drag reducer, 0.15% anti-swelling agent, 0.2% imbibition agent, 0.01% gel breaker, and the balance is water;

[0046] Medium viscosity slippery water is composed of the following components in percentage by mass: 0.2% drag reducer, 0.05% anti-swelling agent, 0.1% imbibition agent, 0.01% gel breaker, and the balance is water;

[0047] High viscosity slick water is composed of the following components in percentage by mass: 0.4% drag reducer, 0.05% anti-swelling agent, 0.1% imbibition agent, 0.02% gel breaker, and the balance is water;

[0048] The glue solution consists of the following components in percentage by mass: 1.0% of a drag reducing agent, 0.05% of an anti-swelling agent, 0.04% of a gel breaker, and the balance being clean water.

[0049] The low-viscosity slickwater, medium-viscosity slickwater, high-viscosity slickwater, and drag reducer in the adhesive are commercially available and use the same drag reducer. Product information for this drag reducer is available at http: / / www.sxsrkj.com / cooperation.aspx?ID=381. By adjusting the concentration, the requirements for both slickwater and sand-carrying fluid can be met, enabling ready-to-use addition during construction. This also overcomes the poor salt tolerance of traditional emulsions, ensuring proper operation within a certain salinity range.

[0050] The anti-swelling agent in low-viscosity slippery water, medium-viscosity slippery water, high-viscosity slippery water and the glue is ammonium chloride.

[0051] The imbibition agent used in low-viscosity slickwater, medium-viscosity slickwater, and high-viscosity slickwater is a commercially available product. Its function is as follows: Low-permeability shale has fine pore throats and high resistance to liquid flow. Fluid flow within the shale requires high displacement pressure. The imbibition agent changes the wettability of the rock pore surface, promoting or enhancing the imbibition process, reducing capillary resistance, and improving injectivity and recovery. Product information for the imbibition agent is available at http: / / www.jielingkeji.cn / product / product-727186091.htm.

[0052] Ammonium persulfate is the gel breaker in low-viscosity slickwater, medium-viscosity slickwater, high-viscosity slickwater, and gel solutions. Its function is to act as an oxidant, breaking down macromolecules in the integrated fracturing fluid into small molecules, facilitating the return of the integrated fracturing fluid to the surface after fracturing.

[0053] The temporary plugging balls used in shale oil fracturing fluid are commercially available. Their function is to effectively seal casing perforations in high-permeability reservoirs, selectively plugging high-permeability perforations and mitigating fluid influx conflicts between perforation zones with different permeabilities. Product information for the temporary plugging balls is available at https: / / www.njsspeek.com / index.php / product / cpzs.html?ctype1=45. The diameter of the temporary plugging balls in this embodiment is 16-18 mm.

[0054] The temporary plugging agent used in shale oil fracturing fluid is a commercially available product. It is used to increase the net pressure within the reservoir fractures, facilitating the formation of multiple fractures during fracturing. Product information for the temporary plugging agent is available at http: / / www.sxsrkj.com / product_view.aspx?ID=338. The temporary plugging agent has a softening temperature of ≥50°C, a water solubility time of ≤200 minutes at 60°C, and a particle size of 40-80 mesh.

[0055] The shale oil fracturing fluid of this embodiment can increase the complexity of the fractures and increase the effective reconstruction volume. Under low-level stress difference, due to the influence of natural fractures, the fracture network is unevenly distributed. Temporary plugging within the fractures can make the fracture network distribution more uniform. Under high-level stress difference conditions, multiple temporary pluggings can form multiple nearly parallel fractures.

[0056] 2. Specific embodiments of the shale oil and gas reservoir fracturing method of the present invention are as follows:

[0057] Example 2

[0058] The fracturing method for a shale oil and gas reservoir in this embodiment, taking Well F in a shale oil and gas reservoir as an example, specifically includes the following steps:

[0059] Before fracturing Well F, the basic characteristics of the target layer of Well F are first introduced;

[0060] In this example, target well F is located in a shale reservoir. Its sidetrack depth is 2403 m, with target point A at 3039.68 m and target point B at 3182.70 m, resulting in a vertical depth difference of 362.49 m. Target point K is at 3906.60 m, and the completed depth is 5100 m. The horizontal section (target point A to bottomhole) is 2060.32 m long. The well was completed using lower reservoir casing (139.7 mm). The casing bottom depth is 5085.79 m, the choke annulus depth is 5036.52 m, and the artificial bottomhole depth is 5028 m. Basic data for Well F are shown in Table 1.

[0061] Table 1 Basic data of Well F

[0062]

[0063] The cross-sectional diagram of the horizontal section of Well F is as follows: Figure 1 As shown;

[0064] Core samples were obtained from the target layer of Well F at different depths through the pilot well. The triaxial mechanical parameters (vertical stress, horizontal maximum principal stress, and horizontal minimum principal stress of the rock) were obtained through rock mechanics parameter testing experiments. The horizontal stress difference (the difference between the horizontal maximum principal stress and the horizontal minimum principal stress) and the horizontal stress difference coefficient (the ratio of the horizontal maximum principal stress to the horizontal minimum principal stress) of the rock were further calculated based on the triaxial mechanical parameters of the rock. The rock mechanics parameter test results of the core samples at different depths in the target layer are shown in Table 2. The relationship between the horizontal stress difference coefficient and the fracture morphology is shown in Table 2. Figure 2 As shown in the figure, it can be seen that the larger the horizontal stress difference coefficient of shale, the easier it is to form unidirectional cracks, and the smaller the horizontal stress difference coefficient of shale, the easier it is to form multi-directional cracks.

[0065] Table 2 Rock mechanical parameter test results of core samples at different depths in the target layer

[0066]

[0067] Then, the rock brittleness index is calculated through rock mechanics experiments (when the brittleness index is less than 40%, the rock fractures plastically; when the brittleness index is between 40% and 60%, the rock fractures brittlely; when the brittleness index is greater than 60%, the rock fractures strongly brittle). The rock brittleness index reflects the difficulty of forming complex cracks after rock fracture. The greater the brittleness of the rock, the easier it is to crack. The greater the plasticity, the stronger the bond between rock particles, and the weaker the degree of fracture. The calculation formula of the brittleness index is as follows:

[0068]

[0069] Where E is the Young's modulus of rock, in units of 10 4 MPa; μ is Poisson's ratio, dimensionless.

[0070] The calculation formula of Young's modulus is E=σ / ε. Young's modulus is a physical quantity that describes the degree of deformation of a material when subjected to force, and is usually represented by the symbol E. It represents the ratio of the stress in the force direction of the material per unit area to the corresponding strain, that is: E=σ / ε, where E is Young's modulus, with units of Pascal (Pa) or Megapascal (MPa); σ is stress, with units of Pascal (Pa) or Megapascal (MPa); ε is strain, dimensionless. In the calculation of Young's modulus, the measurement of stress and strain needs to be obtained through experiments. In the experiment, a certain stress is usually applied, and then the corresponding strain is measured. Poisson's ratio refers to the ratio of the absolute value of the transverse normal strain to the axial normal strain when the material is subjected to unidirectional tension or pressure, also called the transverse deformation coefficient. It is an elastic constant that reflects the transverse deformation of the material.

[0071] The mechanical parameters of the core samples at different depths in the target interval are shown in Table 3;

[0072] Table 3 Mechanical parameters of core samples at different depths in the target layer

[0073]

[0074] Rock composition analysis then determined that the clay mineral types in the target shale layer of Well F are primarily illite and montmorillonite, with the mixed layer comprising 52% to 65% (average 60%). When montmorillonite absorbs water, the intercrystalline spacing between the silicon-oxygen tetrahedron and aluminum-oxygen octahedron increases due to hydration, causing the clay to expand. Illite, on the other hand, does not expand after absorbing water.

[0075] In summary, the target interval of Well F exhibits the following characteristics: brittle rock failure, large horizontal stress differences, and significant vertical stress variations, making complex fracture formation difficult. The rock contains a high clay mineral content, with the predominant clay mineral type being mixed layers of illite and montmorillonite, indicating some reservoir damage. The target interval of Well F is a normal-pressure formation with weak crude oil mobility, and the reservoir crude oil is primarily bound oil, resulting in poor fluidity. Furthermore, the target interval of Well F exhibits a well-developed pattern of thin interbedded layers and lamination.

[0076] After introducing the basic situation of the target layer of Well F, the following is an introduction to the fracturing method:

[0077] (1) Determine the fracturing sections and fracturing clusters of the target well (F well) target layer

[0078] The horizontal section of the target layer of Well F (3000-5028 m) was divided into 33 sections, and staged fracturing was carried out in 33 sections. The shale oil and gas reservoir fracturing fluid of Example 1 was used in all 33 fracturing sections for fracturing. The section number, fracturing section range (start and end depths of the fracturing section), sequence number of each perforation cluster, and upper and lower limit depths of perforating charges within each perforation cluster are shown in Table 4. A bridge plug was installed between any two adjacent fracturing sections, and the depth of each bridge plug is shown in Table 4.

[0079] Table 4: Segment number of each fracturing stage, fracturing stage range (start and end depth of the fracturing stage), sequence number of each perforation cluster, and upper and lower depths of perforating charges installed within each perforation cluster

[0080]

[0081]

[0082]

[0083]

[0084]

[0085]

[0086] (2) Staged fracturing construction

[0087] This step takes the first fracturing stage, the third fracturing stage and the sixth fracturing stage as examples to introduce the fracturing method of the shale oil and gas reservoir of the present invention;

[0088] ① The fracturing method of the first fracturing stage is as follows:

[0089] As shown in Table 4 , the first fracturing stage has the following profile: depth of 4996.00–5018.00 m, perforation length of 3.0 m, 3 clusters, and a total of 54 holes;

[0090] The method for fracturing the first fracturing stage is as follows: the acid solution in the shale oil fracturing fluid of Example 1 is added at 2m 3 / min is injected into the first fracturing stage, and the injection volume is 30m 3 Then, the low-viscosity slippery water in the shale oil fracturing fluid of Example 1 was discharged at a rate of 2 to 6 m3 / min (the discharge rate of the low-viscosity slippery water increased from low to high, respectively at 2m3 / min). 3 / min, injection 3min; 3m 3 / min, injection 4min; 4m 3 / min, injection 4min; 5m 3 / min, injection 2min; 6m 3 / min, the injection rate is injected into the first fracturing stage at a rate of 1min), and the injection rate is 50m 3 Then, the glue in the shale oil fracturing fluid of Example 1 is added at 12-14m 3 / min (the discharge volume of the glue solution increases from low to high, respectively, at 12m 3 / min, injection 4.5min; 13m 3 / min, injection 6.5min; 14m 3 / min, injection 4.395min) was injected into the first fracturing stage, and the injection volume was 200m 3 ;

[0091] Then, 20 batches of low-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the first fracturing stage, and the displacement of each batch of low-viscosity slippery water was 18m 3 / min, the volume of low-viscosity slickwater injected in the 1st, 2nd, 4th, 6th, 8th, 10th, 12th, 14th to 20th batches is 50m 3 The volume of low-viscosity slickwater injected in the 3rd, 5th, 7th, 9th, 11th and 13th batches is 40m 3 When low-viscosity slick water was injected in the 2nd, 4th, 6th, 8th, 10th, 12th, 14th, 16th, 18th and 20th batches, low-viscosity slick water was used to carry the proppant (the proppant was 70-140 mesh quartz sand), and the sand ratio carrying the proppant increased with the increase of the injection batch, which were 3%, 5%, 7%, 8%, 9%, 10%, 11%, 12%, 13% and 14% respectively;

[0092] After injecting low viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 18m 3 / min displacement is injected into the first fracturing stage for displacement, and the injection volume is 40m 3Then the low viscosity slick water in the shale oil fracturing fluid of Example 1 was added to 18m 3 / min is injected into the first fracturing stage, and the injection volume is 30m 3 ;

[0093] Then, 28 batches of medium-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the first fracturing stage, and the displacement of each batch of medium-viscosity slippery water was 18m 3 / min, the volume of medium-viscosity slick water injected in the 1st, 3rd, 5th, 12th, 14th, 19th, 20th and 21st batches is 50m 3 The volume of medium viscosity slick water injected in the 2nd, 4th, 6th, 8th, 10th and 25th batches is 40m 3 The volume of medium viscosity slick water injected in the 16th, 17th, 22nd and 27th batches is 30m 3 The volume of medium viscosity slick water injected in the 18th, 23rd and 28th batches is 20m 3 The volume of medium-viscosity slick water injected in the 24th and 26th batches was 55m 3 , when the medium-viscosity slippery water was injected in the 1st, 3rd, 5th, 7th, 9th, 11th, 13th, 15th, 17th, 18th, 20th, 22nd, 23rd, 25th, 27th and 28th batches, the medium-viscosity slippery water was used to carry the proppant. The proppant carried by the 1st and 3rd batches when injecting the medium-viscosity slippery water was 70-140 mesh quartz sand, and the proppant carried by the other batches when injecting the medium-viscosity slippery water was 40-70 mesh quartz sand; when the proppant was 70-140 mesh quartz sand, the sand ratio carrying the proppant increased with the increase of the injection batch, and the sand ratio of the proppant carried by the 1st and 3rd batches when injecting the medium-viscosity slippery water was 20-30 mesh. When the proppant is quartz sand of 40-70 mesh, the sand ratio of the proppant increases with the increase of the injection batch. The sand ratios of the proppant carried by the 5th, 7th, 9th, 11th, 13th, 15th, 17th, 18th, 20th, 22nd, 23rd, 25th, 27th and 28th batches of medium-viscosity slick water are 6%, 7%, 8%, 9%, 10%, 11%, 11%, 12%, 12%, 13%, 13%, 13% and 14% respectively. After the injection of the 15th batch of medium-viscosity slick water, the glue in the shale oil fracturing fluid of Example 1 is added at 18m 3 / min displacement is injected into the first fracturing stage for displacement, and the injection volume is 50m 3Then, the 15th batch of medium viscosity slick water is injected;

[0094] After injecting medium viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 18m 3 / min displacement is injected into the first fracturing stage for displacement, and the injection volume is 50m 3 Then, 8 batches of high-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the first fracturing stage. The displacement of the first batch of high-viscosity slippery water was 18m 3 / min, and the discharge rate of the other batches of high-viscosity slick water was 19m 3 / min, the volume of high viscosity slick water injected in the first and seventh batches was 40m 3 The volume of high viscosity slick water injected in the second, third and sixth batches is 50m 3 The volume of the fourth batch of highly viscous slick water injected was 30m 3 The volume of high viscosity slick water injected in the 5th and 8th batches is 20m 3 When highly viscous slick water was injected in the second, fourth, seventh, and eighth batches, the proppant was carried by highly viscous slick water (the proppant was 40-70 mesh ceramsite), and the sand ratio carrying the proppant increased with the increase of the injection batch. When highly viscous slick water was injected in the second, fourth, seventh, and eighth batches, the sand ratio carrying the proppant was 13%, 13%, 14%, 14%, and 15%, respectively.

[0095] After the high-viscosity slick water was injected in batches, the high-viscosity slick water and low-viscosity slick water in the shale oil fracturing fluid of Example 1 were respectively injected into the first fracturing stage for displacement to complete the fracturing operation. The injection rate of the high-viscosity slick water and the low-viscosity slick water was 19 m 3 / min, and the injection volume was 15m 3 and 52m 3 .

[0096] The pumping parameters for the first fracturing stage are shown in Table 5.

[0097] Table 5 Pumping parameters for the first fracturing stage during fracturing operation

[0098]

[0099]

[0100]

[0101] During the fracturing operation of the first fracturing stage, the net liquid volume injected was 2615.0m 3 , the total sand volume is 163.0m 3, the construction displacement is 18.0~19.0m 3 / min, the on-site construction curve is as follows Figure 3 As shown in the on-site construction curve, it can be seen that the integrated fracturing oil displacement fluid used in the embodiment can well adapt to the water quality of fracturing fluid, has stable liquid performance and good thickening performance, and can stably carry sand in the high sand ratio stage, ensuring the smooth completion of the construction; during the fracturing construction, a total of 52 effective events were monitored, and the fracturing affected body was 282m long, 49m wide, 42m high, and oriented at about 78°; the microseismic events in this section extended in an east-west direction near the wellbore, and the lengths of the seams on both wings were basically the same, with the east wing transformation volume being relatively larger. The microseismic monitoring diagram when injecting low-viscosity slick water in batches is shown in the figure below. Figure 4 As shown in the figure, the microseismic monitoring diagram when the medium viscosity slick water was injected in batches is as follows: Figure 5 As shown in the figure, the microseismic monitoring diagram when injecting high viscosity slick water in batches is as follows Figure 6 As shown in the figure, the overall microseismic monitoring diagram during the fracturing operation of the first fracturing stage is as follows: Figure 7 shown. Figures 4 to 7 The sphere in the figure represents the intensity of the sound emitted by rock fracture collected during the test. The larger the radius, the greater the intensity.

[0102] ②The fracturing method of the third fracturing stage is as follows:

[0103] As shown in Table 4, the profile of the third fracturing stage is as follows: depth is 4886.00-4930.00 m, perforation length is 3.8 m, there are 5 clusters and 60 holes in total;

[0104] The method for fracturing the third fracturing stage is as follows: the acid solution in the shale oil fracturing fluid of Example 1 is added at 2m 3 / min is injected into the third fracturing stage, and the injection volume is 25m 3 Then, the low viscosity slick water in the shale oil fracturing fluid of Example 1 is added to 2-6 m 3 / min (the discharge rate of low viscosity slippery water increases from low to high, respectively at 2m 3 / min, injection 3min; 3m 3 / min, injection 4min; 4m 3 / min, injection 4min; 5m 3 / min, injection 2min; 6m 3 / min, the displacement of 1min) is injected into the third fracturing stage, and the injection volume is 50m 3 Then, the glue in the shale oil fracturing fluid of Example 1 is added at 12-14m 3 / min displacement (the displacement of the glue liquid increases from low to high, respectively, at 12m 3 / min, injection 4.5min; 13m 3 / min, injection 6.5min; 14m 3 / min, injection 4.395min) was injected into the third fracturing stage, with an injection volume of 200m 3 ;

[0105] Then, 23 batches of low-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the third fracturing stage. The displacement of the 7th batch of low-viscosity slippery water was 14m 3 / min, and the discharge rate of low-viscosity slick water injected in other batches was 16m 3 / min, the volume of low-viscosity slickwater injected in the 1st, 6th, 9th, 11th, 13th, 15th, 17th, 19th, 21st and 23rd batches is 50m 3 The volume of the second batch of low-viscosity slick water injected is 60m 3 The volume of low-viscosity slickwater injected in the 3rd, 5th, 7th, 10th, 12th, 14th, 16th, 18th, 20th and 22nd batches is 30m 3 The volume of low-viscosity slick water injected in the fourth batch is 55m 3 The volume of low viscosity slick water injected in the eighth batch is 20m 3 When the 2nd, 4th, 6th, 9th, 11th, 13th, 15th, 17th, 19th, 21st and 23rd batches are injected with low-viscosity slick water, the low-viscosity slick water is used to carry the proppant. When the 2nd, 4th, 6th, 9th, 11th, 13th and 15th batches are injected with low-viscosity slick water, the proppant carried is 70-140 mesh quartz sand, and the proppant carried is 20-30 mesh quartz sand. The sand ratios with proppant were 3%, 5%, 7%, 9%, 11%, 13%, and 15%, respectively. The proppant carried by the 17th, 19th, 21st, and 23rd batches of low-viscosity slick water was quartz sand of 40-70 mesh, and the sand ratios with proppant were 4%, 6%, 8%, and 10%, respectively. When the 7th batch of low-viscosity slick water was injected, the temporary plugging agent was carried by the low-viscosity slick water, and the mass of the temporary plugging agent was 150 kg.

[0106] After injecting low viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 16m 3 / min displacement is injected into the third fracturing stage for displacement, and the injection volume is 40m 3 Then, the medium viscosity and slippery water in the shale oil fracturing fluid of Example 1 was mixed into 6 batches at 16m 3 The volume of the medium-viscosity slick water injected in 6 batches was 30m3 / min respectively. 3 , 20m3 、40m 3 、30m 3 , 20m 3 、40m 3 When the medium-viscosity slippery water was injected in the first, second, fourth and fifth batches, the medium-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 11%, 12%, 13% and 14% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected in 6 batches at 16m 3 The volume of the highly viscous slick water injected in 6 batches was 30m3 / min respectively. 3 , 20m 3 、40m 3 、30m 3 , 20m 3 50m 3 When the first, second, fourth and fifth batches of high-viscosity slippery water were injected, the high-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 14%, 15%, 15% and 16% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected at 14m 3 / min is injected into the third fracturing stage, and the injection volume is 30m 3 , add 25 temporary plugging balls into the highly viscous slippery water during injection;

[0107] Then, 22 batches of low-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the third fracturing stage. The displacement of the low-viscosity slippery water injected from the first batch to the fourth batch was 16m3. 3 / min, the discharge rate of low-viscosity slick water injected in the 5th, 7th to 9th batches is 17m 3 / min, the discharge rate of the 6th batch of low-viscosity slick water is 14m 3 / min, and the discharge rate of low-viscosity slick water injected in other batches is 18m 3 / min, the volume of low-viscosity slickwater injected in the 1st, 3rd, 16th, 18th, 20th and 22nd batches is 50m 3 The volume of low-viscosity slick water injected in the 2nd, 4th and 16th batches is 30m 3 The volume of low-viscosity slickwater injected in the 5th, 8th and 10th batches is 45m 3 The volume of low viscosity slick water injected in the 7th batch is 20m 3The volume of low-viscosity slickwater injected in the 9th, 11th, 12th, 13th, 14th, 15th, 17th, 19th and 21st batches is 40m 3 When low-viscosity slick water was injected in the 1st, 3rd, 5th, 8th, 10th, 12th and 14th batches, low-viscosity slick water was used to carry proppant (the proppant was 70-140 mesh quartz sand), and the sand ratio of the proppant was 3%, 5%, 7%, 9%, 11%, 13% and 15% respectively; when low-viscosity slick water was injected in the 16th, 18th, 20th and 22nd batches, low-viscosity slick water was used to carry proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 4%, 6%, 8% and 10% respectively; when low-viscosity slick water was injected in the 6th batch, low-viscosity slick water was used to carry temporary plugging agent, and the mass of the temporary plugging agent was 150 kg;

[0108] After injecting low viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 18m 3 / min displacement is injected into the third fracturing stage for displacement, and the injection volume is 40m 3 Then, 6 batches of medium-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the third fracturing stage. The displacement of the medium-viscosity slippery water injected in the first and second batches was 18m 3 / min, the displacement of medium-viscosity slick water injected from the 3rd to the 6th batches is 19m 3 / min, and the volume of the medium-viscosity slick water injected in 6 batches was 30m 3 、30m 3 、40m 3 、30m 3 、30m 3 、40m 3 When the medium-viscosity slippery water was injected in the first, second, fourth and fifth batches, the medium-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 11%, 12%, 13% and 14% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected into the shale oil fracturing fluid in 5 batches at 19m 3 The volume of the highly viscous slick water injected in five batches was 30m3 / min respectively. 3 、30m 3 、40m 3 、30m 3 、30m 3When the first, second, fourth and fifth batches of high-viscosity slippery water were injected, high-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 14%, 15%, 15% and 16% respectively; then the glue in the shale oil fracturing fluid of Example 1 was added at 19m 3 / min displacement is injected into the third fracturing stage for displacement, and the injection volume is 40m 3 ;

[0109] Then, 7 batches of high viscosity and slippery water in the shale oil fracturing fluid of Example 1 were mixed with 20m 3 The volume of the highly viscous slick water injected in 7 batches was 30m3 / min respectively. 3 , 20m 3 、40m 3 50m 3 50m 3 、40m 3 , 20m 3 When highly viscous slick water was injected in the first, second, fourth, sixth, and seventh batches, the proppant was carried by highly viscous slick water (the proppant was 40-70 mesh ceramsite), and the sand ratio carrying the proppant increased with the increase of the injection batch. When highly viscous slick water was injected in the first, second, fourth, sixth, and seventh batches, the sand ratio carrying the proppant was 15%, 16%, 16%, 16%, and 17%, respectively.

[0110] After the high-viscosity slick water was injected in batches, the high-viscosity slick water and low-viscosity slick water in the shale oil fracturing fluid of Example 1 were respectively injected into the third fracturing stage for displacement to complete the fracturing operation. The injection rate of the high-viscosity slick water and the low-viscosity slick water was 20 m 3 / min, and the injection volume was 15m 3 and 51m 3 .

[0111] The pumping parameters for the third fracturing stage are shown in Table 6.

[0112] Table 6 Pumping parameters for the third fracturing stage during fracturing operation

[0113]

[0114]

[0115]

[0116] During the fracturing operation of the third fracturing stage, the net liquid volume injected was 2528.9m 3 , the total sand volume is 220.5m 3, the maximum displacement is 19.0m 3 / min. 150.0kg of 40-80 mesh temporary plugging agent was added, and the pressure increased from 75.9MPa to 76.4MPa. 15 φ16mm temporary plugging balls and 10 φ18mm temporary plugging balls were added, and the pressure increased from 57.1MPa to 58.0MPa. The construction curve during the fracturing process is as follows: Figure 8 shown.

[0117] ③The fracturing method of the sixth fracturing stage is as follows:

[0118] As shown in Table 4, the profile of the sixth fracturing stage is as follows: depth is 4689.00-4736.00 m, perforation length is 2.6 m, there are 5 clusters, and a total of 42 holes;

[0119] The method for fracturing the sixth fracturing stage is as follows: the liquid carbon dioxide in the shale oil fracturing fluid of Example 1 is added at a temperature of 2 to 3 m 3 / min displacement into the sixth fracturing stage, the injection amount is 150t, and then the glue in the shale oil fracturing fluid of Example 1 is injected at a rate of 12-14m 3 / min displacement (the displacement of the glue liquid increases from low to high, respectively, at 12m 3 / min, injection 4.5min; 13m 3 / min, injection 6.5min; 14m 3 / min, injection 4.395min) was injected into the third fracturing stage, with an injection volume of 200m 3 ;

[0120] Then, 23 batches of low-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the sixth fracturing stage. The displacement of the eighth batch of low-viscosity slippery water was 14m 3 / min, and the discharge rate of low-viscosity slick water injected in other batches was 16m 3 / min, the volume of low-viscosity slickwater injected in the 1st, 6th, 9th, 11th, 13th, 15th, 17th, 19th, 21st and 23rd batches is 50m 3 The volume of the second batch of low-viscosity slick water injected is 60m 3 The volume of low-viscosity slickwater injected in the 3rd, 5th, 7th, 10th, 12th, 14th, 16th, 18th, 20th and 22nd batches is 30m 3 The volume of low-viscosity slick water injected in the fourth batch is 55m 3 The volume of low viscosity slick water injected in the eighth batch is 20m 3When the 3rd, 5th, 7th, 9th, 11th, 13th, 15th, 17th, 19th, 21st and 23rd batches of low-viscosity slick water are injected, the low-viscosity slick water is used to carry the proppant. When the 3rd, 5th, 7th, 9th, 11th, 13th and 15th batches of low-viscosity slick water are injected, the proppant carried is 70-140 mesh quartz sand, and the proppant carried is The proppant-to-sand ratios were 3%, 5%, 7%, 9%, 11%, 13%, and 15%, respectively. The proppant carried by the 17th, 19th, 21st, and 23rd batches of low-viscosity slickwater injections was quartz sand of 40-70 mesh, and the proppant-to-sand ratios were 6%, 8%, 10%, and 11%, respectively. When the 7th batch of low-viscosity slickwater was injected, the temporary plugging agent was carried by the low-viscosity slickwater, and the mass of the temporary plugging agent was 150 kg.

[0121] After injecting low viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 16m 3 / min displacement was injected into the sixth fracturing stage for displacement, and the injection volume was 40m 3 Then, the medium viscosity and slippery water in the shale oil fracturing fluid of Example 1 was mixed into 6 batches at 17m 3 The displacement of slick water was injected into the sixth fracturing stage at a rate of 30 m / min. The volume of the 6 batches of medium-viscosity slick water injected was 30 m 3 , 20m 3 、40m 3 、30m 3 , 20m 3 、40m 3 When the medium-viscosity slippery water was injected in the first, second, fourth and fifth batches, the medium-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 11%, 12%, 13% and 14% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected in 6 batches at 17m 3 The volume of the highly viscous slick water injected in six batches was 30m3 / min respectively. 3 , 20m 3 、40m 3 、30m 3 , 20m 3 50m 3 When the first, second, fourth and fifth batches of high-viscosity slippery water were injected, the high-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 14%, 15%, 15% and 16% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected at 17m 3 / min is injected into the sixth fracturing stage, and the injection volume is 30m 3 , add 25 temporary plugging balls into the highly viscous slippery water during injection;

[0122] Then, 22 batches of low-viscosity slippery water in the shale oil fracturing fluid of Example 1 were injected into the third fracturing stage. The displacement of the low-viscosity slippery water injected from the first batch to the fifth batch was 17m 3 / min, the discharge rate of the 6th batch of low-viscosity slick water is 14m 3 / min, the discharge rate of low-viscosity slick water injected from the 7th to the 22nd batches is 18m 3 / min, and the volume of low-viscosity slick water injected in each batch was 50m 3 、30m 3 50m 3 、30m 3 50m 3 、30m 3 , 20m 3 50m 3 、30m 3 、45m 3 、40m 3 、40m 3 、40m 3 、40m 3 、40m 3 50m 3 、40m 3 50m 3 、40m 3 50m 3 、40m 3 50m 3 When low-viscosity slick water was injected in the 1st, 3rd, 5th, 8th, 10th, 12th and 14th batches, low-viscosity slick water was used to carry proppant (the proppant was 70-140 mesh quartz sand), and the sand ratio of the proppant was 3%, 5%, 7%, 9%, 11%, 13% and 15% respectively; when low-viscosity slick water was injected in the 16th, 18th, 20th and 22nd batches, low-viscosity slick water was used to carry proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 6%, 8%, 10% and 11% respectively; when low-viscosity slick water was injected in the 6th batch, low-viscosity slick water was used to carry temporary plugging agent, and the mass of the temporary plugging agent was 150 kg;

[0123] After injecting low viscosity slick water in batches, the glue in the shale oil fracturing fluid of Example 1 was added at 18m 3 / min displacement was injected into the sixth fracturing stage for displacement, and the injection volume was 40m 3Then, the medium viscosity and slippery water in the shale oil fracturing fluid of Example 1 was mixed into 6 batches at 19m 3 The displacement of slick water was injected into the sixth fracturing stage at a rate of 30 m / min. The volume of the 6 batches of medium-viscosity slick water injected was 30 m 3 、30m 3 、40m 3 、30m 3 、30m 3 、40m 3 When the medium-viscosity slippery water was injected in the first, second, fourth and fifth batches, the medium-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 12%, 13%, 13% and 14% respectively; then the high-viscosity slippery water in the shale oil fracturing fluid of Example 1 was injected into the shale oil fracturing fluid in 5 batches at 19m 3 The displacement rate of / min was injected into the sixth fracturing stage. The volume of the high-viscosity slick water injected in five batches was 30m 3 、30m 3 、40m 3 、30m 3 、30m 3 When the first, second, fourth and fifth batches of high-viscosity slippery water were injected, high-viscosity slippery water was used to carry the proppant (the proppant was 40-70 mesh quartz sand), and the sand ratio of the proppant was 14%, 15%, 15% and 16% respectively; then the glue in the shale oil fracturing fluid of Example 1 was added at 19m 3 / min displacement was injected into the sixth fracturing stage for displacement, and the injection volume was 40m 3 ;

[0124] Then, 7 batches of high viscosity and slippery water in the shale oil fracturing fluid of Example 1 were mixed with 20m 3 The displacement rate was injected into the sixth fracturing stage at 100 / min. The volume of the highly viscous slick water injected in 7 batches was 30m3 / min respectively. 3 , 20m 3 、40m 3 50m 3 50m 3 、40m 3 , 20m 3 When highly viscous slick water was injected in the first, second, fourth, sixth, and seventh batches, the proppant was carried by highly viscous slick water (the proppant was 40-70 mesh ceramsite), and the sand ratio carrying the proppant increased with the increase of the injection batch. When highly viscous slick water was injected in the first, second, fourth, sixth, and seventh batches, the sand ratio carrying the proppant was 16%, 17%, 17%, 17%, and 18%, respectively.

[0125] The pumping parameters for the sixth fracturing stage during fracturing are shown in Table 7;

[0126] Table 7 Pumping parameters for the sixth fracturing stage during fracturing operation

[0127]

[0128]

[0129]

[0130] After the high-viscosity slick water was injected in batches, the high-viscosity slick water and low-viscosity slick water in the shale oil fracturing fluid of Example 1 were respectively injected into the sixth fracturing stage for displacement to complete the fracturing operation. The injection rate of the high-viscosity slick water and the low-viscosity slick water was 20 m 3 / min, and the injection volume was 15m 3 and 49m 3 .

[0131] During the fracturing operation of the sixth fracturing stage, the net liquid volume injected was 2862.3m 3 , the total sand volume is 240.6m 3 , the maximum displacement is 21.0m 3 / min. 2nd temporary plugging: The first time, 180.0kg of temporary plugging agent was added, and the pressure rose from 67.7MPa to 68.8MPa. The second time, 25 φ18.0mm temporary plugging balls were added, and the pressure rose from 71.8MPa to 72.1MPa. The construction curve during the fracturing process is as follows Figure 9 The microseismic detection diagram of the sixth fracturing stage during fracturing construction is shown in Figure 2. Figure 10 The monitoring and analysis data are shown in Tables 8-10. Figure 10 The sphere in the figure represents the intensity of the sound emitted by rock fracture collected during the test. The larger the radius, the greater the intensity.

[0132] Table 8 Microseismic event monitoring results at each temporary plugging stage

[0133]

[0134] Table 9 Microseismic event monitoring results at each temporary plugging stage

[0135]

[0136] Table 10 Microseismic event monitoring results at each temporary plugging stage

[0137]

[0138] (3) After the staged fracturing operation is completed, the post-fracturing drainage phase begins, and the measured wellhead fluid production is 41m 3 / d, with an oil production of 12.7m 3 / d, gas production is 141m 3 / d. After the integrated fracturing oil recovery fluid was returned to the surface, its pH value was tested to be 7. As of September 5, 2023, the cumulative discharge volume was 18527.92m 3 , the oil production is 1276.59m 3 , the water production is 17251.43m 3 , gas production is 18343m 3 , no flowback fracturing sand. The production situation diagram of Well F is as follows Figure 11 shown.

[0139] Before finalizing the formulation of the shale oil and gas reservoir fracturing fluid and the fracturing method of the present invention, the applicant also optimized the relevant parameters, as shown in the following experimental examples.

[0140] In other examples, the mass fraction of HCl in the acid solution was 10-12%, the mass fraction of the acidizing corrosion inhibitor was 2-3%, and the mass fraction of the iron ion stabilizer was 2-3%. When all other conditions except the acid solution were the same, the fracturing results of the other examples were similar to those of the example, indicating that the acid solution formulation had little effect on the fracturing effect.

[0141] Experimental Example 1

[0142] (1) Optimization of the dosage of resistance reducing agent

[0143] According to laboratory test results, when the drag reducer concentration is 0.1% to 1.0%, the fluid viscosity ranges from 3 to 102 mPa·s. Based on the experience of using integrated fracturing fluid systems in shale oil and gas wells and the fracturing process objectives of Well F, the drag reducer concentrations in fracturing fluids of different viscosities were determined as follows: 0.1% by mass for low-viscosity slickwater, 0.2% by mass for medium-viscosity slickwater, 0.4% by mass for high-viscosity slickwater, and 0.8% to 1.0% by mass for gel.

[0144] (2) Optimization of anti-swelling agent dosage

[0145] The use of water-based fracturing fluid can cause clay to swell, disperse, or migrate. During fracturing, the fracturing fluid filtrate enters the pores. Reservoir clay minerals, upon contact with water, have the potential to swell, disperse, and migrate, blocking oil and gas formations and leading to an irreversible decrease in reservoir permeability. Anti-swelling agents are chemical agents that inhibit the hydration and dispersion of clay. By exploiting the chemical ion exchange properties of clay surfaces, anti-swelling agents alter bound ions, modifying their physical and chemical properties, disrupting their ion exchange capacity, or disrupting the repulsion between ions in the double layer, thereby preventing clay hydration, swelling, dispersion, and migration, thereby reducing fracturing damage. Commonly used anti-swelling agents include inorganic salts, cationic surfactants, and organic polymers. In laboratory experiments, the permeability of cores rapidly decreased during initial flooding with simulated brine, primarily due to the migration of illite and illite-montmorillonite mixed-layer minerals. After the injection of a 0.3% anti-swelling agent-containing brine solution, the permeability decreased more slowly, demonstrating that the injection of the anti-swelling agent effectively inhibited clay migration and swelling.

[0146] This experiment optimized the dosage of the anti-swelling agent based on the methods of the petroleum and natural gas industry standard SY / T5971, "Performance Evaluation of Clay Stabilizers for Oilfield Water Injection." The specific method is as follows: 0.50g of bentonite was weighed to the nearest 0.01g and placed into a 10mL centrifuge tube. 10mL of a gel-breaking solution containing different concentrations of the anti-swelling agent (prepared with the anti-swelling agent, brine, and ammonium persulfate) was added to each tube. After thorough shaking, the tube was allowed to stand at room temperature for 2 hours. Centrifuged at 1500 rpm for 15 minutes, the volume of the expanded bentonite (V1) was recorded. The gel-breaking solution containing the anti-swelling agent was replaced with 10mL of water, and the expanded volume (V2) of the bentonite in water was measured. The gel-breaking solution containing the anti-swelling agent was replaced with 10mL of kerosene, and the expanded volume (V0) of the bentonite in kerosene was measured.

[0147] Calculate the anti-swelling rate according to the following formula:

[0148]

[0149] In the formula: B——anti-swelling rate;

[0150] V1——the expansion volume of bentonite in the solution containing anti-swelling agent, mL;

[0151] V2——expansion volume of bentonite in water, mL;

[0152] V0——expansion volume of bentonite in kerosene, mL.

[0153] The anti-swelling rates of the gel breaking solutions containing different mass fractions of anti-swelling agents obtained in the experiment are shown in Table 11;

[0154] Table 11 Anti-swelling ratio of gel breaking liquid containing different mass fractions of anti-swelling agent

[0155] Dosage / % Anti-swelling rate / % 0.05 61.1 0.1 68.6 0.15 71.3 0.2 77.4 0.3 82.2

[0156] The anti-swelling performance of different concentrations of anti-swelling agents in fracturing fluids was tested using a centrifugal anti-swelling test. The results showed that increasing the amount of anti-swelling agent increased the anti-swelling rate, reaching over 80% at a 0.3% addition. Balancing anti-swelling effectiveness and cost, the mass fraction of anti-swelling agent used in low-viscosity slippery water was 0.15%, while the mass fraction used in medium-viscosity, high-viscosity, and gel-liquid fracturing fluids was 0.05%.

[0157] (3) Optimization of imbibition agent dosage

[0158] The imbibition agent is used to enhance the imbibition capacity of the fracturing fluid, thereby improving the fracturing production increase effect. The imbibition agent used in the embodiment has low surface tension and ultra-low interfacial tension characteristics, which can change the wettability of the rock surface. It has the appearance of a light yellow transparent liquid, is temperature-resistant to 150°C, is acid-resistant and alkali-resistant, can be used in sandstone and limestone reservoirs, has low surface tension (<25mN / m) and ultra-low interfacial tension (<0.003mN / m), and has good wettability reversibility (<28°) and interface peeling ability. The drag reducing agent and water are prepared into a drag reducing agent solution, the initial viscosity is tested, and then the imbibition agent is added to obtain a test liquid. The concentration of the imbibition agent in the test liquid is 0.3%, and then the viscosity of the test liquid and the imbibition height at 10 minutes are tested. The results showed that when the concentration of the resistance reducer in the resistance reducer solution was 0.1%, the initial viscosity was 1.85 mPa·s, and after the addition of the imbibition agent, the viscosity was 1.99 mPa·s; when the concentration of the resistance reducer in the resistance reducer solution was 0.3%, the initial viscosity was 11.19 mPa·s, and after the addition of the imbibition agent, the viscosity was 11.24 mPa·s; when the concentration of the resistance reducer in the resistance reducer solution was 1.0%, the initial viscosity was 108 mPa·s, and after the addition of the imbibition agent, the viscosity was 110 mPa·s. After breaking the gel, the imbibition height was 42 mm at 10 minutes.

[0159] Interfacial tension tests (IFT) were conducted on aqueous solutions containing different concentrations of osmotic agents. The results showed that the osmotic agent has ultra-low interfacial tension. The osmotic agent solution with a mass fraction of 0.3% has a low surface tension of 24.7 mN / m. Figure 12 shown.

[0160] Then the wetting angle of the quartz plate modified by immersion in silicone oil was tested by aqueous solutions containing different concentrations of imbibing agents. The experimental results are as follows: Figure 13The results show that the wetting angle decreases significantly with increasing imbibition concentration. When the imbibition concentration is ≥0.3%, the wetting angle approaches equilibrium, indicating that imbibition can change the wettability of the rock surface, achieving a wetting reversal (the wettability of the quartz sheet changes from strong oil-wet to water-wet), stripping the oil film on the rock surface and achieving water imbibition drive. Therefore, imbibition can solubilize crude oil, have an excellent carrying effect on colloids and asphaltenes, and significantly improve the replacement of heavy oil components by fracturing solutions.

[0161] Next, we optimized the dosage of imbibition agents in the fracturing fluid system. Based on the results of capillary imbibition experiments and a comprehensive consideration of imbibition effectiveness and economic efficiency, we optimized the imbibition agent mass fraction to 0.2% for low-viscosity slickwater and 0.1% for medium- and high-viscosity slickwater. The results of the imbibition agent formulation optimization are shown in Table 12. The drag reducer, anti-swelling agent, and imbibition agent in Table 12 are the same as those used in Example 1, respectively.

[0162] Table 12 Optimization test results of imbibition agent formula

[0163]

[0164] Imbibition flooding tests showed that the kerosene saturated in the core was colorless, and that the displacing agent significantly increased the imbibition rate, with a significant effect also observed in vertical cores. The displacing agent displaced the colored immobile oil. The changes in the imbibition fluid indicated that the displacing agent and the immobile oil were mutually soluble, effectively displacing the immobile oil in small pores and improving oil recovery efficiency. The imbibition agent significantly enhanced the imbibition effect in both horizontal and vertical cores.

[0165] (4) Optimization of breaker dosage

[0166] Gel-breaking experiments were conducted on the integrated fracturing fluid at formation temperature, and the viscosity of the broken fluid was measured. The results showed that all breaking combinations achieved gel-breaking, with a final viscosity of approximately 2.0 mPa·s. The recommended breaker concentration for low-viscosity and medium-viscosity slickwater is 0.01%, for high-viscosity slickwater 0.02%, and for gel-liquid fracturing fluid 0.04%. The test results for the integrated fracturing fluid system are shown in Table 13.

[0167] Table 13 Gel breaking test of integrated fracturing fluid system

[0168]

[0169] Experimental Example 2

[0170] The water used for fluid preparation at the F well site was used to test the compounding performance of the integrated fracturing fluid and the field water.

[0171] (1) Compatibility evaluation

[0172] The salinity of the water used for fluid preparation on site in Well F (wellsite water) is 518.17 mg / L. Compatibility tests with fracturing fluid additives show that the wellsite water has good compatibility with the resistance reducer, anti-swelling agent, and imbibition agent.

[0173] (2) Viscosity performance evaluation

[0174] According to the formula requirements, the viscosity test of the water-mixed liquid was carried out on site. The test results are shown in Table 14.

[0175] Table 14 Viscosity test results of fracturing fluid formulation

[0176]

[0177] (3) Evaluation of heat and shear resistance

[0178] The adhesive solution was prepared with water, drag reducing agent and anti-swelling agent, with the drag reducing agent concentration of 0.8% and the anti-swelling agent concentration of 0.05%. -1 Under the same conditions, the continuous shearing lasted for 90 minutes and the tail viscosity was 42.5 mPa·s, indicating that the viscosity of the fracturing fluid can be maintained above 40 mPa·s after high temperature shearing, meeting the requirements of on-site construction. Figure 14 shown.

[0179] (4) Sand carrying performance evaluation

[0180] The sand-carrying performance of a fluid is primarily related to the viscosity of the fluid system. This experiment involved testing the sand-carrying performance of fracturing fluids of varying viscosities on 40-70 mesh proppants. Through two hours of observation and measurement, the proppant settling velocity in different fracturing fluid types was determined. The sand-carrying performance of low-viscosity slickwater, medium-viscosity slickwater, high-viscosity slickwater, and the glue used in Example 1 on 40-70 mesh quartz sand is shown in Table 15.

[0181] Table 15 Results of sand carrying experiments with different types of fracturing fluids

[0182] type Sedimentation velocity, mm / s Low viscosity slippery water 5.34 Medium viscosity slippery water 4.25 High viscosity slippery water 2.81 glue 0

[0183] (5) Injury experiment evaluation

[0184] Since the shale core is too dense and difficult to be displaced by fracturing fluid, the gel in Example 1 was used to conduct experiments on dense sandstone cores in the damage test evaluation. The results are shown in Table 16.

[0185] Table 16 Injury test results

[0186] Core number Original permeability / mD Permeability / mD Injury rate / % 1# 0.0168 0.0152 10.56 2# 0.01443 0.0128 12.78

[0187] (6) Evaluation of gel breaking performance

[0188] According to the formulation requirements, the viscosity of the gel-breaking solution prepared with water was tested on-site. At 90°C, the gel was broken for 2 hours. The viscosity of the gel-breaking solution met the standard requirements. The viscosity test results of the gel-breaking solutions with different formulations are shown in Table 17.

[0189] Table 17 Viscosity test results of different formulations of gel breaking liquid

[0190]

[0191] Experimental Example 3

[0192] Based on the drilling trajectory and well logging data, the stress near target B in the horizontal section exceeded the expected operating pressure, necessitating an acid-rock reaction to reduce the formation fracture pressure. Based on laboratory acid-rock reaction tests and the carbonate content in well logging, the optimal acid formulation was determined.

[0193] By conducting dissolution experiments on cuttings from the horizontal section of Well F using acid solutions of different concentrations, the experimental results are shown in Table 18. The preferred acid solution formula is: 12% HCl + 2% acidizing corrosion inhibitor + 2% iron ion stabilizer + 1% anti-swelling agent.

[0194] Table 18 Results of horizontal section rock chip dissolution test

[0195]

[0196] Experimental Example 4

[0197] Temporary plugging balls are primarily used to seal off blastholes that have become larger due to abrasion. By blocking these advantageous inlet holes, flow distribution is balanced across clusters, promoting balanced crack initiation and fracture formation within each cluster. Temporary plugging agents, on the other hand, temporarily block channels within the fractures to redirect cracks and increase fracture complexity. A dual temporary plugging approach of "temporary plugging balls + temporary plugging agent" is recommended. As long as the construction pressure allows, the number of temporary plugging cycles should be increased to maximize the balanced expansion and complexity of the fractures.

[0198] In order to better block the dominant liquid-inflow holes, temporary plugging balls with diameters of φ16mm and φ18mm are preferred, and soluble temporary plugging balls are preferred to increase the complexity of the fractures. The temporary plugging ball index requirements are shown in Table 19-20.

[0199] Table 19 Temporary blocking ball index requirements (solid ball)

[0200]

[0201]

[0202] Table 20 Performance requirements of soluble temporary plugging agents

[0203] Inspection items Index requirements Specifications, 40～80 <![CDATA[Density, g / cm 3 > 1.3～1.5 Plugging strength, MPa >40 Degradation time (120℃), h 60～90 Solubility Complete degradation Compatibility Good compatibility with formation fluids and fracturing fluids

[0204] Then, according to the provisions of standard Q / SH CG0152-2021, the temporary plugging ball pressure bearing and degradation performance test was carried out. The temporary plugging ball had a diameter of 16-18mm and was heated to 90℃. The temporary plugging ball pressure reached 74MPa and maintained for 3 hours, which exceeded the standard test requirements. In addition, by verifying the migration and plugging characteristics of temporary plugging balls of different specifications under different casing hole sizes and pumping parameters, when the pumping displacement was 4-6m 3 / min, the pumping medium is clean water, and the maximum pressure is 70MPa.

[0205] The temporary blocking balls were placed in a wide-mouth bottle for degradation performance testing. During the test, distilled water was added to the wide-mouth bottle, and then the temperature of the material in the wide-mouth bottle was controlled at 90°C in a water bath. The dissolved material was then dried and weighed every 24 hours, and its weight loss was calculated to form a degradation weight loss curve under the temperature environment. The test results showed that when the diameter of the temporary blocking balls was 16-18 mm, the degradation rate reached a maximum of 50.7% in 12 hours, and the degradation rate reached 99.6% in 4 days.

[0206] Then, using a high-temperature, high-pressure crack plugging instrument, experiments were conducted to optimize temporary crack plugging formulations. Simulating a downhole temperature of 90°C, three sets of temporary crack plugging formulations (medium-viscosity slickwater, high-viscosity slickwater, and glue, as described in Example 1) were optimized for three crack modules (fracture widths of 1-3 mm, 3-5 mm, and 5-8 mm, respectively) to achieve a maximum forward plugging pressure of 40 MPa and a reverse plugging pressure of ≤3 MPa. After the temporary plugging material was unplugged, the fracture permeability flowback recovery rate was ≥90%. The plugging test results for different crack modules tested using medium-viscosity slickwater (as described in Example 1) for cracks with a width of 1-3 mm are shown in Table 21. The plugging test results for different crack modules tested using glue (as described in Example 1) for cracks with a width of 5-8 mm are also shown in Table 21.

[0207] Table 21 Crack sealing test results

[0208]

[0209] The temporary plugging agent's degradation profile is as follows: in a 20% HCl solution at 90°C for 0.5 hours, the degradation rate is less than 10%, with complete degradation occurring in 20 hours. In a 5% HCl solution at 90°C for 15 hours, the degradation rate reaches 50%. In clean water or a 2% HCl solution at 150°C for 4 hours, the temporary plugging agent is completely degraded. The strength of the temporary plugging agent decreases with increasing immersion time. Experiments show that in a downhole solution environment, after dissolving 350g of granular temporary plugging agent in 350mL of distilled water, heating it to 150°C, and degrading it for 48 hours, the solution viscosity is 1.5mPa·s, demonstrating that the temporary plugging agent is completely degradable, causing zero damage to the reservoir.

[0210] The permeability recovery rate test experiment of the core was carried out using the degradation fluid of the temporary plugging agent. The results are shown in Table 22. The results show that after the temporary plugging agent is degraded in the formation water, the degradation fluid has little damage to the core, and the core permeability recovery rate is about 99%, indicating that the damage to the core is relatively small.

[0211] Table 22 Core permeability recovery test results

[0212]

[0213] Experimental Example 5

[0214] Increasing the amount of pre-fracturing CO2 can increase the energy-enhancing range, thereby increasing initial production. In this experimental example, before fracturing the sixth fracturing stage, the relationship between the injection rate of carbon dioxide and oil production, as well as the relationship between the injection rate of carbon dioxide and the energy-enhancing range and the average pressure coefficient after energy-enhancing were simulated. The results are as follows: Figures 15-16 As shown in the figure, the simulation results show that the optimal injection rate of carbon dioxide is 150 tons. After CO2 injection, three-phase seepage of gas, oil and water can be formed in the near-well reservoir, which is not conducive to the seepage of the other two phases (oil phase and water phase). When the injection rate is higher than 100 tons to 150 tons per section, the above unfavorable factors can be completely overcome.

Claims

1. A shale oil and gas reservoir fracturing fluid, characterized in that: It includes a pre-flushing agent, an integrated fracturing oil-displacing fluid and a temporary plugging material; the temporary plugging material is a temporary plugging agent and / or a temporary plugging ball; the pre-flushing agent is an acid solution or liquid carbon dioxide; the integrated fracturing oil-displacing fluid mainly consists of a drag reducing agent, an anti-swelling agent, an imbibing agent, a gel breaker and water, the mass fraction of the drag reducing agent is 0.1% to 1%, the mass fraction of the anti-swelling agent is 0.05% to 0.15%, the mass fraction of the imbibing agent is 0 to 0.3%, and the mass fraction of the gel breaker is 0.01 to 0.04%.

2. The shale oil and gas reservoir fracturing fluid according to claim 1, wherein: The acid solution mainly consists of HCl, acidifying corrosion inhibitor, iron ion stabilizer and water, the mass fraction of HCl is 10-12%, the mass fraction of the acidifying corrosion inhibitor is 2-3%, and the mass fraction of the iron ion stabilizer is 2-3%.

3. The shale oil and gas reservoir fracturing fluid according to claim 1, wherein: The integrated fracturing oil displacement fluid comprises low-viscosity slick water, medium-viscosity slick water, high-viscosity slick water and glue; the mass fractions of the drag reducing agent in the low-viscosity slick water, medium-viscosity slick water, high-viscosity slick water and glue increase in sequence.

4. The shale oil and gas reservoir fracturing fluid according to claim 3, wherein: The mass fraction of the resistance reducing agent in the adhesive solution is 0.8% to 1.0%.

5. The shale oil and gas reservoir fracturing fluid according to claim 1, wherein: The diameter of the temporary blocking ball is 16-18 mm, and the particle size of the temporary blocking agent is 40-80 mesh.

6. A fracturing method for shale oil and gas reservoirs, characterized in that: The following steps are involved: First, the segment cluster perforation positions of the target shale oil and gas reservoir are determined, and then the shale oil and gas reservoir fracturing fluid according to any one of claims 1 to 5 is used to perform fracturing construction on each fracturing segment.

7. The fracturing method for shale oil and gas reservoirs according to claim 6, wherein: The fracturing construction method comprises the following steps: injecting a pre-fluid into a fracturing section to form a pre-fluid plug; then sequentially injecting low-viscosity slick water, medium-viscosity slick water, and high-viscosity slick water in the shale oil and gas reservoir fracturing fluid according to any one of claims 1 to 5 into the fracturing section to form combined slicks in different forms; and finally injecting a displacement fluid into the fracturing section for displacement; the pre-fluid is the pre-fluid in the shale oil and gas reservoir fracturing fluid according to any one of claims 1 to 5, and the displacement fluid comprises the low-viscosity slick water and high-viscosity slick water in the shale oil and gas reservoir fracturing fluid according to any one of claims 1 to 5.

8. The fracturing method for shale oil and gas reservoirs according to claim 7, wherein: The low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are respectively divided into multiple batches and injected into the fracturing section to form combined slugs in different forms.

9. The fracturing method for shale oil and gas reservoirs according to claim 6, wherein: When low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are injected into the fracturing section, the low-viscosity slick water, medium-viscosity slick water and high-viscosity slick water are used to carry proppant and temporary plugging material in the shale oil and gas reservoir fracturing fluid according to any one of claims 1 to 5.

10. The shale oil and gas reservoir fracturing method according to claim 6, wherein: The horizontal stress difference coefficient of the target shale oil and gas reservoir shall not exceed 0.16, and the brittleness index shall not be less than 0.4.

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