Temporary plugging agent and preparation method, fracturing method and application thereof

Abstract

This invention discloses a temporary plugging agent, its preparation method, a fracturing method, and its application. Based on the total weight of the temporary plugging agent, the raw material composition is as follows: acrylamide 15wt%–20wt%; 2-acrylamide-2-methylpropanesulfonic acid 5wt%–10wt%; methyl acrylate 1wt%–2wt%; crosslinking agent 0.5wt%–1wt%; initiator 0.15wt%–0.8wt%; solvent 2wt%–5wt%; and the balance being water. The temporary plugging agent provided by this invention allows for control of different dissolution times at different temperatures by adjusting the amounts of initiator and crosslinking agent. Furthermore, by controlling different reaction rates and different preparation processes, the temporary plugging agent can be adjusted to have different densities, thereby obtaining temporary plugging agent product particles that are fully floating, partially floating, or fully sinking.

Description

Technical Field

[0001] This invention relates to the field of shale gas extraction, specifically to a temporary plugging agent and its preparation method, a fracturing method, and their applications. Background Technology

[0002] In my country, the potential of shale gas resources is enormous, with recoverable resources estimated at approximately 26 × 10⁻⁶. 12 m 3 The reserves are roughly equivalent to those in the United States. The Cambrian and Silurian shale formations in my country's Sichuan Basin alone contain 1.5 to 2.5 times the conventional natural gas resources of the basin. However, the low porosity and permeability of shale gas reservoirs necessitate hydraulic fracturing to create complex networks of natural fractures within the reservoirs to achieve commercial gas flow. Therefore, horizontal well segmented and clustered volumetric fracturing technology has become one of the main technologies for shale gas development.

[0003] Currently, the key trends in shale gas fracturing technology research are close-cutting, intensive proppant loading, and temporary plugging and redirection. Specifically, cluster spacing has increased from 15-25m to 5-10m, section length has shortened from 80-120m to 50-70m or even shorter, the number of perforation clusters per section has increased from 2-3 to 4-6, proppant loading intensity has increased from 1-1.5t / m to 2-3t / m, and the proppant loading rate per section has increased from 40-60m³. 3 Developed to the current 80-100m 3 These factors led to a decrease in the fracturing fluid volume per well from the initial 20,000–30,000 m³. 3 Develop to 30,000-40,000m 3 The total sand addition per well increased from the initial 1000m³ 3 Increase to 2000-3000m on the left and right sides. 3 Temporary plugging techniques have evolved from early single-stage inter-cluster plugging to multi-stage inter-cluster plugging, multi-stage intra-fracture plugging, and dual-plugging fracturing techniques that simultaneously perform inter-cluster and intra-fracture plugging. These measures have significantly improved fracturing efficiency and increased post-fracturing production by 1 to 2 times. However, they have also increased construction material costs and greatly increased the difficulty of economically developing shale gas.

[0004] Therefore, there is an urgent need to develop a more targeted, efficient, and economical fracturing technology. Summary of the Invention

[0005] To address the aforementioned problems in existing technologies, this invention provides a temporary plugging agent and its preparation method, a fracturing method using the temporary plugging agent, and its applications. The temporary plugging agent provided by this invention has a controllable dissolution time and can open and fill branch fractures through multiple sealing operations from near to far within the fracture, significantly increasing the distribution density and extension length of turning branch fractures. The overall fracture modification volume does not decrease and may even increase, resulting in a significant reduction in overall fracturing costs due to the reduced number of stages.

[0006] In a first aspect, the present invention provides a temporary plugging agent, the temporary plugging agent comprising acrylamide, 2-acrylamide-2-methylpropanesulfonic acid and methyl acrylate;

[0007] Based on the total mass of the temporary plugging agent, the acrylamide content is 15wt% to 20wt%; the 2-acrylamide-2-methylpropanesulfonic acid content is 5wt% to 10wt%, preferably 5wt% to 8wt%; and the methyl acrylate content is 1wt% to 2wt%.

[0008] The temporary plugging agent provided by this invention, by controlling the specific content of each specific component, results in a faster dissolution rate and a controllable dissolution time. This temporary plugging agent expands upon contact with water, significantly increasing its buoyancy in fracturing fluid and preventing it from settling to the bottom of the fracture.

[0009] For example, in the temporary plugging agent provided by the present invention, the acrylamide content, based on the total mass of the temporary plugging agent, can be 15wt%, 16wt%, 17wt%, 18wt%, 19wt%, 20wt%, and any value and any combination range thereof.

[0010] The content of 2-acrylamide-2-methylpropanesulfonic acid, based on the total weight of the temporary plugging agent, can be 5 wt%, 6 wt%, 7 wt%, 8 wt%, 9 wt%, 10 wt%, and any value and any combination thereof.

[0011] The content of methyl acrylate, based on the total weight of the temporary plugging agent, can be 1 wt%, 1.2 wt%, 1.4 wt%, 1.6 wt%, 1.8 wt%, 2 wt%, and any value and any combination thereof.

[0012] According to some embodiments of the temporary plugging agent of the present invention, the temporary plugging agent further includes a crosslinking agent, an initiator, and a mutual solvent; the crosslinking agent is selected from at least one of N,N-methylenebisacrylamide, N-vinylpyrrolidone, and neopentyl glycol diacrylate; the initiator is selected from at least one of potassium persulfate, sodium bisulfite, ammonium persulfate, and potassium bisulfite, preferably, the initiator is selected from a mixture of potassium persulfate and sodium bisulfite, more preferably, the weight ratio of potassium persulfate to sodium bisulfite is (2-3):1; the mutual solvent is selected from at least one of N,N-dimethylformamide, N,N-dimethylacetamide, and N,N-dimethylacrylamide.

[0013] According to some embodiments of the temporary plugging agent of the present invention, the crosslinking agent content is 0.5wt% to 1wt%; the initiator content is 0.15wt% to 0.8wt%; preferably, the content is 0.2wt% to 0.3wt%; the mutual solvent content is 2wt% to 5wt%; preferably, the content is 3wt% to 4wt%.

[0014] The content of the crosslinking agent, based on the total mass of the temporary plugging agent, can be 0.5wt%, 0.6wt%, 0.7wt%, 0.8wt%, 0.9wt%, 1wt%, and any value and any combination thereof.

[0015] The initiator content, based on the total mass of the temporary plugging agent, can be 0.15wt%, 0.2wt%, 0.25wt%, 0.3wt%, 0.35wt%, 0.4wt%, 0.45wt%, 0.5wt%, 0.55wt%, 0.6wt%, 0.65wt%, 0.7wt%, 0.75wt%, 0.8wt%, and any values ​​and combinations thereof.

[0016] The solvent content, based on the total mass of the temporary plugging agent, can be 2 wt%, 2.5 wt%, 3 wt%, 3.5 wt%, 4 wt%, 4.5 wt%, 5 wt%, and any value and any combination thereof.

[0017] According to some embodiments of the temporary plugging agent of the present invention, the dissolution time of the temporary plugging agent in water is 10 min to 120 min; the volume density of the temporary plugging agent is 0.95 to 1.2 mg / mL, preferably 1.05 to 1.1 mg / mL; and the temporary plugging agent withstands pressure of 40 MPa for more than 20 minutes.

[0018] According to some embodiments of the temporary plugging agent of the present invention, the density of the temporary plugging agent is 0.95 g / mL to 1.2 g / mL, which can meet different suspension requirements. For example, the temporary plugging agents of different densities provided by the present invention can meet different suspension states such as full floating, floating and sinking, and full sinking.

[0019] According to some embodiments of the temporary plugging agent of the present invention, the crosslinking agent is selected from at least one of N,N-methylenebisacrylamide, N-vinylpyrrolidone and neopentyl glycol diacrylate.

[0020] According to some embodiments of the temporary plugging agent of the present invention, the initiator is selected from at least one of potassium persulfate, sodium bisulfite, ammonium persulfate and potassium bisulfite.

[0021] According to a preferred embodiment of the temporary plugging agent of the present invention, the initiator is selected from a mixture of potassium persulfate and sodium bisulfite. In this invention, with a fixed composition of the temporary plugging agent, the higher the content of the oxidant component in the initiator, the shorter the dissolution time of the resulting temporary plugging agent.

[0022] According to a preferred embodiment of the temporary plugging agent of the present invention, the weight ratio of potassium persulfate and sodium bisulfite is (2-3):1.

[0023] According to some embodiments of the temporary plugging agent of the present invention, the mutual solvent is selected from at least one of N,N-dimethylformamide, N,N-dimethylacetamide and N,N-dimethylacrylamide.

[0024] Secondly, the present invention provides a method for preparing the above-mentioned temporary plugging agent, the method comprising the following steps:

[0025] Step A: Mix the acrylamide, 2-acrylamide-2-methylpropanesulfonic acid, methyl acrylate, crosslinking agent, miscible solvent and water to obtain a first solution;

[0026] Step B: After the first solution is deoxygenated, it is mixed with the initiator and then deoxygenated a second time.

[0027] According to some embodiments of the preparation method of the present invention, the conditions of the mixing process in step A include: a temperature of 15-25°C, a time of 10-20 min, and a stirring speed of 200-300 r / min. For example, in some embodiments of the present invention, the conditions for the mixing process in step A include: a temperature of 15°C, 16°C, 17°C, 18°C, 19°C, 20°C, 21°C, 22°C, 23°C, 24°C, 25°C, and any value and any combination thereof; a time of 10 min, 11 min, 12 min, 13 min, 14 min, 15 min, 16 min, 17 min, 18 min, 19 min, 20 min, and any value and any combination thereof; and a stirring speed of 200 r / min, 210 r / min, 220 r / min, 230 r / min, 240 r / min, 250 r / min, 260 r / min, 270 r / min, 280 r / min, 290 r / min, 300 r / min, and any value and any combination thereof.

[0028] According to some embodiments of the preparation method of the present invention, step A further includes: adjusting the pH value of the first solution to 6.95 to 7.05.

[0029] According to a specific embodiment of the preparation method of the present invention, step A further includes: adjusting the pH value of the first solution to 7.

[0030] According to some embodiments of the preparation method of the present invention, the conditions for the mixing process in step B include: a temperature of 15-25°C, a time of 30-40 min, and a stirring speed of 200-300 r / min. For example, in some embodiments of the present invention, the conditions for the mixing process in step B include: a temperature of 15°C, 16°C, 17°C, 18°C, 19°C, 20°C, 21°C, 22°C, 23°C, 24°C, 25°C, and any value and any combination thereof; a time of 30 min, 31 min, 32 min, 33 min, 34 min, 35 min, 36 min, 37 min, 38 min, 39 min, 40 min, and any value and any combination thereof; and a stirring speed of 200 r / min, 210 r / min, 220 r / min, 230 r / min, 240 r / min, 250 r / min, 260 r / min, 270 r / min, 280 r / min, 290 r / min, 300 r / min, and any value and any combination thereof.

[0031] According to some embodiments of the preparation method of the present invention, step B further includes: preparing the initiator into a solution with a mass concentration of 0.1 wt% to 1 wt%.

[0032] According to a preferred embodiment of the preparation method of the present invention, the potassium persulfate and the sodium bisulfite are dissolved in distilled water respectively to obtain an initiator solution.

[0033] According to some embodiments of the preparation method of the present invention, in step B, the deoxygenation process is carried out by bubbling nitrogen gas into the first solution for 30 min to 40 min. After the first solution and the initiator are mixed, nitrogen gas is bubbled into the solution for the second deoxygenation until it becomes viscous.

[0034] According to some embodiments of the preparation method of the present invention, the preparation method further includes: placing the solution obtained in step B in a water bath at 40-60°C for 6-9 hours to obtain a gel-like product. For example, in some embodiments of the present invention, the water bath temperature for the solution obtained in step B is 40°C, 45°C, 50°C, 55°C, 60°C, 65°C, 70°C, and any value or combination thereof.

[0035] According to a preferred embodiment of the preparation method of the present invention, the preparation method further includes: placing the solution obtained in step B in a water bath at 40-60°C for 6-8 hours to obtain a gel-like product.

[0036] According to some embodiments of the preparation method of the present invention, the preparation method further includes: cutting, drying and pulverizing the gelatinous product.

[0037] According to a preferred embodiment of the preparation method of the present invention, the drying temperature is 60-70°C.

[0038] In the preparation method of the temporary plugging agent provided by this invention, a gel block is prepared by initiating a polymerization reaction in an aqueous solution at a low temperature. The gel block is then subjected to granulation, drying, and pulverization to obtain temporary plugging agent particles of different sizes. In this method, by adjusting the amounts of initiator and crosslinking agent, the dissolution time of the temporary plugging agent at different temperatures can be controlled. Furthermore, by controlling different reaction rates and different preparation processes, the density of the temporary plugging agent can be adjusted, resulting in temporary plugging agent product particles that are fully floating, partially floating, or fully sinking.

[0039] Thirdly, the present invention provides a fracturing method, the method comprising the following steps:

[0040] S1 determines the operational parameters for the target well fracturing process;

[0041] S2 uses a temporary plugging agent to seal the ends of cracks of different lengths;

[0042] S3 preprocesses the target well formation;

[0043] S4 injects temporary plugging agent and first proppant into the target well formation in sequence to create fractures;

[0044] S5 injection of the second proppant;

[0045] S6 Insert a bridge plug into the target well formation and repeat steps S2 to S4;

[0046] The temporary plugging agent is selected from at least one of the temporary plugging agents described above or the temporary plugging agents prepared by the methods described above.

[0047] In the fracturing method of this invention, during temporary plugging, complete sealing is required in the fracture height direction to achieve the expected increase in temporary plugging pressure. After the branch fracture has fully extended and filled, the plugging agent needs to fully dissolve to ensure the main fracture continues to extend. Therefore, the fracturing method provided by this invention uses the aforementioned fast-dissolving, adjustable-dissolution suspension plugging agent to replace the conventional plugging agent with a long and unadjustable degradation time. The fracturing method of this invention can achieve complete sealing in the fracture height direction. The plugging agent of this invention can expand upon contact with water, significantly increasing buoyancy in the fracturing fluid. Using the suspension plugging agent provided by this invention avoids the problem of conventional plugging agents mostly settling to the bottom of the fracture.

[0048] According to some embodiments of the fracturing method of the present invention, step S1 includes: determining the number of temporary plugging times, the number of perforation clusters, and the cluster spacing during the fracturing process.

[0049] According to a preferred embodiment of the fracturing method of the present invention, when determining the number of temporary plugging operations, temporary plugging is performed once every 60m to 80m. In different embodiments of the present invention, the number of temporary plugging operations is optimized in conjunction with the total fracture length design. For ease of construction operation, temporary plugging is generally performed once every 60m to 80m. If the fracture length is 200m to 250m, three temporary plugging operations can be designed; if the fracture length is 150m to 200m, two temporary plugging operations can be performed; and if the fracture length is 100m to 150m, one temporary plugging operation is sufficient.

[0050] In a preferred embodiment of the fracturing method according to the present invention, the number of perforation clusters is 3 to 4. In this invention, controlling the number of perforation clusters to 3 to 4 clusters can increase the perforation rate per cluster and ensure sufficient fracture height extension.

[0051] According to a preferred embodiment of the fracturing method of the present invention, the cluster spacing is 1.5 to 2 times the fracture turning radius. Specifically, when determining the cluster spacing, the fracture turning radius can be calculated based on displacement discontinuity or the finite element method, taking into account factors such as geostress and fracturing fluid viscosity, and the cluster spacing is then determined to be 1.5 to 2 times the fracture turning radius.

[0052] In some embodiments of the present invention, the segment length can be determined based on the cluster spacing and the number of clusters.

[0053] According to some embodiments of the fracturing method of the present invention, step S1 further includes parameter evaluation of the target well formation, wherein the parameter evaluation includes pilot well logging data and / or the mechanical properties of core samples.

[0054] According to a preferred embodiment of the fracturing method of the present invention, the parameters of the target well formation are evaluated using at least one of X-ray diffraction analysis, dipole acoustic logging, FMI imaging logging, and core surface observation.

[0055] In different embodiments of the present invention, the brittleness of the target layer can be assessed based on pilot well logging data and mechanical experiments from core samples. The triaxial stress of the target layer can be assessed by combining pilot well logging data and acoustic emission mechanical experiments from core samples. Furthermore, the characteristics of natural fractures can be determined using various methods such as X-ray diffraction analysis, dipole acoustic logging, FMI imaging logging, and surface observation of core samples. Considering the high requirements for the overall reservoir filtration coefficient in temporary plugging fracturing, small-scale pre-fracturing tests can be conducted in this well or adjacent wells to obtain relevant parameters.

[0056] According to some embodiments of the fracturing method of the present invention, step S2 includes: the particle size of the temporary plugging agent is 1 / 3 to 1 / 6 of the fracture width; simulating the concentration profile of the temporary plugging agent at the fracture end; determining the support width of the temporary plugging agent; and determining the value of the support width and the dynamic fracture width by controlling at least one parameter among the particle size, concentration, addition time, carrier fluid viscosity and injection flow rate of the temporary plugging agent.

[0057] According to a preferred embodiment of the fracturing method of the present invention, the error between the support width and the dynamic fracture width is ≤2%, and the temporary plugging agent effectively seals the ends of fractures with different lengths.

[0058] According to a preferred embodiment of the fracturing method of the present invention, during effective plugging, the bottom hole pressure rise is >1 MPa / min.

[0059] In some embodiments of the present invention, step S2 includes: calculating the support length of the temporary plugging agent as 3m to 5m; using mature commercial fracturing optimization design software, including but not limited to STIMPLAN and MEYER; and using the temporary plugging agent particle size as 1 / 3 to 1 / 6 of the support fracture width, simulating the concentration profile of the temporary plugging agent at the fracture tip, thereby calculating the support width of the temporary plugging agent. By adjusting parameters such as the timing of the addition of the temporary plugging agent, the particle size, concentration, viscosity of the carrier fluid, and injection rate, if the support width is equal to the dynamic fracture width or the error is within 2%, it can be considered that effective sealing of the tip has been achieved, and the temporary plugging process parameters are the optimized results.

[0060] Furthermore, this step can be optimized using the aforementioned commercial software and dynamically adjusted based on the fracturing operation results. The dynamic adjustment method is as follows: observe the simulated bottom hole pressure operation curve. If the bottom hole pressure rises by 1 MPa / min, it indicates that the fracture end sealing has been truly achieved; otherwise, readjust parameters such as the timing of the temporary plugging agent addition, the particle size and concentration of the temporary plugging agent, the viscosity of the carrier fluid, and the injection rate until a satisfactory combination of temporary plugging process parameters is obtained.

[0061] According to some embodiments of the fracturing method of the present invention, in step S3, the pretreatment includes at least one of perforation, acid treatment, and fracture creation. Furthermore, the present invention does not limit the specific operation of the perforation process; a conventional perforation operation procedure can be used. In different embodiments of the present invention, the pretreatment process also includes a bridge plug insertion process, which can also be performed according to a conventional operation procedure.

[0062] According to a preferred embodiment of the fracturing method of the present invention, the injected fluid volume during the fracture creation process is 0.8 to 1.5 times the wellbore volume. In this invention, given the extremely low matrix filtration of unconventional oil and gas reservoirs such as shale gas and the relatively high critical pressure for natural fracture opening, the pre-injection fluid volume during the fracture creation process is relatively small, controlled to be 0.8 to 1.5 times the wellbore volume.

[0063] According to some embodiments of the fracturing method of the present invention, step S4 includes:

[0064] Step S41: Inject the first temporary plugging agent and the first proppant into the target well formation in sequence to create fractures;

[0065] Step S42: Sequentially inject the second temporary plugging agent and the first proppant into the target well formation to create fractures;

[0066] Step S43: Inject the third temporary plugging agent and the first proppant into the target well formation in sequence to create fractures.

[0067] According to some embodiments of the fracturing method of the present invention, the dissolution time of the second temporary plugging agent is greater than the dissolution time of the first temporary plugging agent, and the solvent time of the third temporary plugging agent is greater than the dissolution time of the second temporary plugging agent.

[0068] According to a preferred embodiment of the fracturing method of the present invention, the dissolution time of the first temporary plugging agent is 20 min to 40 min, the dissolution time of the second temporary plugging agent is 40 min to 60 min, and the dissolution time of the third temporary plugging agent is ≥120 min.

[0069] According to some embodiments of the fracturing method of the present invention, after the first temporary plugging agent, the second temporary plugging agent and the third temporary plugging agent are injected into the target well formation, the wellhead pressure rise rate is 0.95 to 1.05 MPa / min.

[0070] In some embodiments of the fracturing method according to the present invention, the particle size of the first proppant is 70 mesh to 200 mesh.

[0071] According to some embodiments of the fracturing method of the present invention, in step S41, after injecting the first proppant, the sand-liquid volume ratio is 3% to 8%, and the injected liquid volume is 0.8 to 1 times the wellbore volume.

[0072] According to some embodiments of the fracturing method of the present invention, in step S42, after injecting the first proppant, the sand-to-liquid volume ratio is 5% to 9%, and the injected fluid volume is 1 to 1.5 times the wellbore volume.

[0073] According to some embodiments of the fracturing method of the present invention, in step S43, after injecting the first proppant, the sand-liquid volume ratio is 6% to 10%, and the injected fluid volume is 1.5 to 2 times the wellbore volume.

[0074] In some embodiments of the fracturing method according to the present invention, the particle size of the second proppant is 30 mesh to 70 mesh.

[0075] According to some embodiments of the fracturing method of the present invention, in step S4, the temporary plugging agent and the first proppant are respectively injected into the target well formation by the first fracturing fluid.

[0076] According to a preferred embodiment of the fracturing method of the present invention, the first fracturing fluid is selected as low-viscosity slickwater with a viscosity of 3 to 5 mPa·s.

[0077] In the fracturing method provided by the present invention, step S4 specifically involves injecting a temporary plugging agent according to the optimized parameters obtained in steps S1 to S3. In step S41, the wellhead pressure after temporary plugging should be at a rate of 0.95 to 1.05 MPa / min. If the net pressure increase after temporary plugging exceeds the original horizontal stress difference, it proves that a swivel branch fracture has formed. Otherwise, under the condition that the wellhead construction pressure limit is not exceeded, the temporary plugging agent is continuously injected to promote the formation of a swivel branch fracture.

[0078] In step S41, a small-diameter first proppant is injected. When the vertical depth is less than 4000m, the particle size of the first proppant is selected to be 70-140 mesh; when the vertical depth is greater than 4000m, the particle size of the first proppant is selected to be 140-200 mesh. Furthermore, considering that only the branch fracture is extending, a low sand-to-liquid ratio continuous construction mode can be adopted, with a sand-to-liquid volume ratio of 3%-8% and an injection volume of 0.8-1.0 times the wellbore volume, thereby maximizing the filling degree of the first proppant in the branch fracture. In this step, the displacement volume is more than 1 times the wellbore volume. If other conditions remain unchanged, the wellhead pressure is reduced to the pressure level before the injection of the first temporary plugging agent for pressurization, and then the fracture construction stage begins; otherwise, the pump is stopped or displacement continues until the first temporary plugging agent dissolves.

[0079] During the joint creation process, first inject 5-10m... 3 Fracturing fluid is injected to allow the small-diameter first proppant at the leading edge of the main fracture to settle to the bottom of the main fracture. Fracturing fluid is then injected to create a fracture, with the injection volume being 0.8 to 1.5 times the wellbore volume.

[0080] In step S42 of the present invention, the second temporary plugging agent is injected according to the optimized parameters obtained in steps S1 to S3. The pressure rise rate at the wellhead after temporary plugging should be between 0.95 and 1.05 MPa / min. If the net pressure increase after temporary plugging exceeds the original horizontal stress difference, it proves that the swivel branch fracture has formed. Otherwise, the temporary plugging agent is continuously injected under the condition that it does not exceed the wellhead construction pressure limit, thereby promoting the formation of the swivel branch fracture.

[0081] In step S42, a small-diameter first proppant is injected. When the vertical depth is less than 4000m, the particle size of the first proppant is selected to be 70-140 mesh; when the vertical depth is greater than 4000m, the particle size of the first proppant is selected to be 140-200 mesh. Furthermore, considering that only the branch fracture is extending, a low sand-to-liquid ratio continuous construction mode can be adopted, with a sand-to-liquid volume ratio of 5%-9%, and the injected fluid volume being 1-1.5 times the wellbore volume, thereby maximizing the filling degree of the first proppant in the branch fracture. In this step, the displacement volume is more than 1 times the wellbore volume. If other conditions remain unchanged, the wellhead pressure is reduced to the pressure level before the second temporary plugging agent is injected for pressurization, and then the fracture construction stage begins; otherwise, the pump is stopped or displacement continues until the second temporary plugging agent dissolves.

[0082] During the joint creation process, first inject 5-10m... 3 Fracturing fluid is injected to allow the small-diameter first proppant at the leading edge of the main fracture to settle to the bottom of the main fracture. Fracturing fluid is then injected to create a fracture, with the injection volume being 0.8 to 1.5 times the wellbore volume.

[0083] In step S43 of the present invention, the third temporary plugging agent is injected according to the optimized parameters obtained in steps S1 to S3. The pressure rise rate at the wellhead after temporary plugging should be between 0.95 and 1.05 MPa / min. If the net pressure increase after temporary plugging exceeds the original horizontal stress difference, it indicates that a fracture has formed in the steering branch. Otherwise, the temporary plugging agent is continuously injected under the condition that the pressure limit at the wellhead is not exceeded, thereby promoting the formation of a fracture in the steering branch.

[0084] In step S43, a small-diameter first proppant is injected. When the vertical depth is less than 4000m, the particle size of the first proppant is selected to be 70-140 mesh; when the vertical depth is greater than 4000m, the particle size of the first proppant is selected to be 140-200 mesh. Furthermore, considering that only the branch fracture is extending, a low sand-to-liquid ratio continuous construction mode can be adopted, with a sand-to-liquid volume ratio of 6%-10% and an injection volume of 1.5-2 times the wellbore volume, thereby maximizing the filling degree of the first proppant in the branch fracture. In this step, the displacement volume is more than 1 times the wellbore volume. If other conditions remain unchanged, the wellhead pressure drops to the pressure level before the injection of the third temporary plugging agent for pressurization, and then proceeds to the next stage; otherwise, the pump is stopped or displacement continues until the third temporary plugging agent dissolves.

[0085] In different embodiments of the present invention, step S4 may include different numbers of multi-stage temporary plugging and crack-making processes depending on different production needs. However, in different temporary plugging processes, the extension of the branch crack becomes smaller from near to far, and the dissolution time of the temporary plugging agent increases accordingly. Especially in the last temporary plugging, considering as much extension as possible to the branch crack, the dissolution time of the temporary plugging agent can be appropriately extended.

[0086] According to some embodiments of the fracturing method of the present invention, in step S5, the second proppant is injected into the target well formation by being carried by the second fracturing fluid.

[0087] According to a preferred embodiment of the fracturing method of the present invention, the second fracturing fluid is selected as high-viscosity slickwater with a viscosity of 15-20 mPa·s.

[0088] In some embodiments of the present invention, in step S5, a second fracturing fluid carrying a second proppant with a particle size of 40-70 mesh is injected. Specifically, the second fracturing fluid carrying a second proppant with a particle size of 40-70 mesh is injected using a continuous proppant injection method with a long slug. Furthermore, the proppant-to-fluid ratio under each slug is 5-8, 8-10, 11-15, 11-15, 11-15, 11-15, 14-16, 14-16, 15-20, 15-20, 15-20, 15-20, 18-22, and 18-22, respectively, and the amount of proppant-carrying fluid under each proppant-to-fluid ratio condition is 40-50 m³. 3 The viscosity of the second fracturing fluid is 15–20 mPa·s, with 2–3 intermediate isolations, and the volume of the isolation fluid is 0.8–2 times the wellbore volume.

[0089] Furthermore, in step S5, if the vertical depth is less than 4000m, a second proppant with a particle size of 30-50 mesh can be added, and the weight of the added proppant accounts for 20-30wt% of the total weight of the second proppant added.

[0090] In step S6 of the present invention, the technical means of inserting bridge plugs into the target well formation are not limited, and conventional technical procedures and parameters can be used.

[0091] The fracturing method provided by this invention replaces the conventional densely packed parallel main fractures with densely branched fractures. Dense fracturing is primarily achieved through multi-cluster perforation within a segment. However, as the number of clusters increases, the per-cluster discharge rate becomes limited, increasing the difficulty of balancing the fracturing process and raising construction costs. Therefore, this invention employs a densely branched fracture method, that is, through multi-stage temporary plugging within the fractures, progressively plugging from near-wellbore to far-wellbore, with each stage plugging at different times at the fracture ends, thus achieving densely branched diversion fractures. This method reduces the number of clusters, increases the per-cluster discharge rate, and expands the longitudinal extension range of each fracture cluster. Simultaneously, it increases the cluster spacing and reduces the number of segments, thereby lowering fracturing construction costs.

[0092] Furthermore, the fracturing method provided by this invention replaces the conventional method with a multi-scale fracture proppant injection approach. Shale gas reservoirs naturally exhibit well-developed fractures, which easily lead to the formation of complex multi-scale fractures during fracturing. Therefore, proppant injection can result in a mixed distribution of proppant particles of different sizes within fractures at various levels, significantly reducing the conductivity of fractures at different scales. However, the proppant injection method provided by this invention achieves infinite flow resistance in the main fracture after temporary plugging, forcing the fracturing fluid to flow entirely into the branch fractures. This carries small-diameter proppant particles into the newly extended diversion fractures, ultimately achieving effective staged filling of the branch fractures. After proppant injection is completed in the diversion fractures near the wellbore, the temporary plugging agent at the end of the main fracture has completely dissolved. At this point, the main fracture is no longer obstructed by the temporary plugging agent, and the extension resistance becomes minimal. With subsequent injection of fracturing fluid, the main fracture can continue to extend. At this point, the near-wellbore turning support fracture has become a high-stress zone due to induced stress. Each fracture is essentially saturated with the previous fracturing fluid and proppant, making it difficult to absorb more. Even if absorption occurs, it is very weak and negligible. Furthermore, as the main fracture extends again, the extension pressure can return to the level before the temporary plugging pressure increases. After several cycles of this process, the main fracture can be continuously extended while the construction pressure remains essentially constant (except in cases where the temporary plugging pressure increases and extends the turning support fracture). As the number of temporary plugging stages increases, the turning support fractures not only advance further into the wellbore region, but the distribution pattern is also largely similar each time, maintaining sufficient extension capacity and length for each fracture.

[0093] Furthermore, the fracturing method provided by this invention replaces single-stage temporary plugging within the fracture with multi-stage temporary plugging within the fracture. In conventional single-stage temporary plugging fracturing processes, the number of plugging operations per stage is relatively small, generally occurring only in the middle and late stages of fracturing. At this point, the fracturing fluid has a large sweep area, resulting in a large amount of plugging agent required. Simultaneously, under a fixed flow rate, it is difficult to simultaneously initiate and extend multiple secondary fractures. Therefore, this invention, by progressively plugging fracture ends from near-wellbore to far-wellbore, reduces the number of activated branch fractures at each stage, thus lowering the difficulty of branch fracture formation.

[0094] A third aspect of this invention provides the application of the aforementioned temporary plugging agent, the preparation method of the aforementioned temporary plugging agent, or the aforementioned fracturing method in the stimulation of unconventional oil and gas reservoirs. However, it is not limited thereto.

[0095] The beneficial effects of this invention are:

[0096] 1. The temporary plugging agent provided by the present invention can control the different dissolution times of the temporary plugging agent at different temperatures by adjusting the amount of initiator and crosslinking agent therein. Furthermore, by controlling different reaction rates and different preparation processes, the temporary plugging agent can be adjusted to have different densities, thereby obtaining temporary plugging agent product particles that are fully floating, partially floating and partially sinking, or fully sinking.

[0097] 2. The fracturing method provided by this invention employs a multi-stage temporary plugging fracturing process within the fracture. By progressively plugging the fracture ends from near-wellbore to far-wellbore, branch fractures are opened and filled, significantly increasing the distribution density and extension length of diverting branch fractures. The number of activated diverting branch fractures at each stage is reduced, lowering the difficulty of branch fracture formation, significantly increasing cluster spacing, and reducing the number of fracturing stages. Compared to the previous fracturing mode of "dense cutting, strong sand addition, and temporary plugging diverting," the fracturing method provided by this invention does not reduce the overall fracture stimulation volume, and may even increase it, while the overall fracturing cost is significantly reduced due to the reduced number of stages, achieving the goal of low-cost and efficient stimulation of shale gas reservoirs. Attached Figure Description

[0098] Figure 1 A flow chart of the fracturing modification process provided in an embodiment of the present invention. Detailed Implementation

[0099] To make the present invention easier to understand, the present invention will be described in detail below with reference to embodiments and accompanying drawings. These embodiments are for illustrative purposes only and are not limited to the scope of application of the present invention.

[0100] The testing method and equipment used in this invention are as follows:

[0101] The test method for the bulk density of the temporary plugging agent is based on section 10.3, "Test Method for Performance of Proppants Used in Hydraulic Fracturing and Gravel Packing Operations," in the Petroleum and Natural Gas Industry Standard of the People's Republic of China SY / T5108-2014.

[0102] The test method for the plugging performance of the temporary plugging agent is based on the technical requirements and test methods for DCF-2 polyester particles used as a diverting agent for fracturing, as specified in the enterprise standard Q / HDKMG 0089-2017 of Beijing Kemaishi Oilfield Chemical Agent Technology Co., Ltd.

[0103] The reagents used in this embodiment of the invention are sourced from:

[0104] Acrylamide, industrial grade (polymerization grade), purchased from Shandong Baomo Co., Ltd.

[0105] 2-Acrylamide-2-methylpropanesulfonic acid, industrial grade (superior grade), purchased from Weifang Jinshi Environmental Protection Technology Co., Ltd.

[0106] Methyl acrylate: CAS# 96-33-3, purchased from Shanghai Aladdin Biotechnology Co., Ltd.;

[0107] N,N-Methylenebisacrylamide: CAS# 110-26-9, purchased from Shanghai Aladdin Biotechnology Co., Ltd.;

[0108] N,N-Dimethylformamide: CAS# 68-12-2, purchased from Shanghai Mairui Chemical Technology Co., Ltd.;

[0109] N,N-Dimethylacetamide: CAS# 127-19-5, purchased from Shanghai Mairui Chemical Technology Co., Ltd.;

[0110] N,N-Dimethylpropionamide: CAS# 758-96-3, purchased from Shanghai Mairui Chemical Technology Co., Ltd.;

[0111] Potassium persulfate: CAS# 7727-21-1, purchased from Beijing Bailingwei Technology Co., Ltd.;

[0112] Sodium bisulfite: CAS# 7631-90-5, purchased from Beijing Bailingwei Technology Co., Ltd.

[0113] Example 1

[0114] Taking the preparation of a 1kg reaction system as an example, the process of preparing the temporary plugging agent includes:

[0115] 1) Under the condition of continuous stirring at 200 rpm, add 200 g of acrylamide, 75 g of 2-acrylamido-2-methylpropanesulfonic acid (AMPS), 15 g of methyl acrylate, 5 g of N,N-methylenebisacrylamide and 20 g of N,N-dimethylformamide to 659 g of water, and add 14.5 g of sodium hydroxide to neutralize to pH 7.

[0116] 2) Dissolve 1g of potassium persulfate in 10g of distilled water and dissolve 0.5g of sodium bisulfite in 10g of water to obtain an initiator solution.

[0117] 3) Purge the reaction system obtained in step 1) with nitrogen for 30 minutes to remove oxygen. Then add the potassium persulfate solution and sodium bisulfite aqueous solution prepared in step 2) to it and continue purging with nitrogen until the solution becomes viscous and thick.

[0118] 4) Place the reaction vessel in a 45°C water bath and react for 8 hours.

[0119] 5) Chop the rubber block obtained from step 4) above, dry it at 65-70℃ to constant weight, and crush it with a pulverizer to obtain a temporary blockage agent.

[0120] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0121] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 40-50 minutes. A transparent solution is obtained after dissolution.

[0122] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0123] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0124] Example 2

[0125] Taking the preparation of a 1kg reaction system as an example, the process of preparing the temporary plugging agent includes:

[0126] 1) Under the condition of continuous stirring at 200 rpm, add 150 g of acrylamide, 100 g of 2-acrylamido-2-methylpropanesulfonic acid, 20 g of methyl acrylate, 10 g of N,N-methylenebisacrylamide and 30 g of N,N-dimethylformamide to 646.7 g of water, and add 19.3 g of sodium hydroxide to neutralize to pH 7.

[0127] 2) Dissolve 3g of potassium persulfate in 10g of distilled water, and dissolve 1g of sodium bisulfite in 10g of water to obtain an initiator solution.

[0128] 3) Purge the reaction system obtained in step 1) with nitrogen for 30 minutes to remove oxygen. Then add the potassium persulfate solution and sodium bisulfite aqueous solution prepared in step 2) to it and continue purging with nitrogen until the solution becomes viscous and thick.

[0129] 4) Place the reaction vessel in a 45°C water bath and react for 6 hours.

[0130] 5) Chop the rubber block obtained from step 4) above, dry it at 65°C to constant weight, and crush it with a pulverizer to obtain a temporary blockage agent.

[0131] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0132] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 30-40 minutes. A transparent solution can be obtained after dissolution.

[0133] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.10 mg / mL, and it can be suspended in water before dissolution.

[0134] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0135] Example 3

[0136] The preparation process is the same as in Example 1, except that:

[0137] Step 2) involves dissolving 2g of potassium persulfate in 10g of distilled water and dissolving 1g of sodium bisulfite in 10g of water to obtain an initiator solution. The amount of water used in step 1) is adjusted to maintain a reaction system volume of 1kg, ultimately yielding a temporary plugging agent.

[0138] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0139] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 30-40 minutes. A transparent solution can be obtained after dissolution.

[0140] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0141] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0142] Example 4

[0143] The preparation process is the same as in Example 1, except that:

[0144] Step 2) involves dissolving 4g of potassium persulfate in 12g of distilled water and dissolving 2g of sodium bisulfite in 10g of water to obtain an initiator solution. The amount of water used in step 1) is adjusted to maintain the reaction system at 1kg, ultimately yielding a temporary plugging agent.

[0145] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0146] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 20-30 minutes. A transparent solution is obtained after dissolution.

[0147] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0148] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0149] Example 5

[0150] The preparation process is the same as in Example 1, except that:

[0151] Step 2) involves dissolving 6g of potassium persulfate in 20g of distilled water and dissolving 2g of sodium bisulfite in 10g of water to obtain an initiator solution. The amount of water used in step 1) is adjusted to maintain the reaction system at 1kg, ultimately yielding a temporary plugging agent.

[0152] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0153] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 10-20 minutes. A transparent solution is obtained after dissolution.

[0154] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0155] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0156] Example 6

[0157] The preparation process is the same as in Example 1, except that 20g of N,N-dimethylformamide is replaced with 20g of N,N-dimethylacetamide to obtain the temporary plugging agent.

[0158] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0159] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 40-50 minutes. A semi-transparent solution is obtained after dissolution.

[0160] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.06 mg / mL, and it can be suspended in water before dissolution.

[0161] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 20 minutes under 40MPa conditions.

[0162] Example 7

[0163] The preparation process is the same as in Example 1, except that 20g of N,N-dimethylformamide is replaced with 20g of N,N-dimethylpropionamide to obtain the temporary plugging agent.

[0164] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0165] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 50-60 minutes.

[0166] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.08 mg / mL, and it can be suspended in water before dissolution.

[0167] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 30 minutes under 40MPa conditions.

[0168] Example 8

[0169] The preparation process is the same as in Example 1, except that the content of each substance in step 1) in a 1kg reaction system is: acrylamide 180g, 2-acrylamido-2-methylpropanesulfonic acid 50g, methyl acrylate 15g, N,N-methylenebisacrylamide 8g, and N,N-dimethylformamide 50g. The temporary plugging agent is then obtained.

[0170] The performance of the temporary plugging agent prepared in this embodiment was tested:

[0171] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 90-120 minutes.

[0172] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0173] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 40 minutes under 40MPa conditions.

[0174] Comparative Example 1

[0175] The preparation process is the same as in Example 1, except that 2-acrylamide-2-methylpropanesulfonic acid is not added in step 1). The amount of water in step 1) is adjusted to maintain the reaction system at 1 kg. The temporary plugging agent is then obtained.

[0176] The performance of the temporary plugging agent prepared in this comparative example was tested:

[0177] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. The dissolution time of this temporary plugging agent is 300-400 minutes, and the resulting solution is opaque.

[0178] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0179] 3) Sealing performance: This temporary plugging agent can withstand pressure for more than 200 minutes under 40MPa conditions.

[0180] Comparative Example 2

[0181] The preparation process is the same as in Example 1, except that N,N-dimethylformamide is not added in step 1). The amount of water in step 1) is adjusted to maintain the reaction system at 1 kg. The temporary plugging agent is then obtained.

[0182] The performance of the temporary plugging agent prepared in this comparative example was tested:

[0183] 1) Dissolution time: Add 2g of temporary plugging agent to 200g of tap water and observe the dissolution time of the temporary plugging agent in a 90℃ visual oven. This temporary plugging agent is not soluble in water.

[0184] 2) Bulk density and suspension: The bulk density of this temporary plugging agent is 1.05 mg / mL, and it can be suspended in water before dissolution.

[0185] 3) Sealing performance: This temporary plugging agent cannot withstand a pressure of 40MPa.

[0186] Application Examples

[0187] A shale gas well in southwestern Sichuan has a vertical depth of 3920m, a measured depth of 5980m, and a horizontal section length of 1560m.

[0188] like Figure 1 As shown, fracturing should be performed according to the following steps:

[0189] S1: The first perforation operation is completed using a coiled tubing-mounted perforating gun. The perforation length is 3m, the perforation density is 16 holes / m, and there are a total of 3 clusters.

[0190] S2: After the first perforation operation is completed, at a distance of 1m 3 A total of 15m³ of pretreated acid was injected at a discharge rate of / min. 3 Then, increase the displacement to 6m. 3 / min Inject 45m of low-viscosity slippery water 3 The acid was replaced, and the final displacement was reduced to 2m. 3 Inject 15m of low-viscosity slippery water per minute 3 The acid is replaced to ensure that the acid reacts fully with the rock.

[0191] S3: Uses adhesive to create the main seam, quickly increasing the flow rate to 16m. 3 The fracturing fluid velocity is 50 mPa·s, and the fracturing fluid flow rate is 60 m³ / min. 3 .

[0192] S4: Inject low-viscosity slippery water carrying the temporary plugging agent prepared in Example 4, continuously injecting it into a 10m solution at an agent-to-liquid ratio of 2%. 3 Then inject 75m of low-viscosity slickwater. 3 When the pressure increases by 3-5 MPa, it indicates that a branch joint has formed.

[0193] S5: Inject low-viscosity slippery water carrying 70-140 mesh low-density ceramsite, continuously injecting it at a sand-to-liquid volume ratio of 3%-4%-5%-7% over a depth of 6.65m. 3 The fracturing fluid volume under various sand-fluid volume ratio conditions is 40m³. 3 40m 3 35m 3 30m 3 Then inject 75m of low-viscosity slickwater. 3 .

[0194] S6: Inject low-viscosity slippery water carrying the temporary plugging agent prepared in Example 7, continuously injecting it into a 10m solution at an agent-to-liquid ratio of 2wt%. 3 Then inject 85m of low-viscosity slickwater. 3 When the pressure increases by 3-5 MPa, it indicates that a branch joint has formed.

[0195] S7: Inject low-viscosity slippery water carrying 70-140 mesh low-density ceramsite, continuously injecting it at a sand-to-liquid volume ratio of 5%-6%-7%-8% into a 9.25m... 3 The fracturing fluid volume under various sand-fluid volume ratio conditions is 40m³. 3 40m 3 35m 3 30m 3 Then inject 75m of low-viscosity slickwater. 3 .

[0196] S8: Inject low-viscosity slippery water carrying the temporary plugging agent prepared in Example 8, continuously injecting it into a 10m solution at an agent-to-liquid ratio of 2%. 3 Then inject 90m of low-viscosity slickwater. 3 When the pressure increases by 3-5 MPa, it indicates that a branch joint has formed.

[0197] S9: Inject low-viscosity slippery water carrying 70-140 mesh low-density ceramsite, continuously injecting it to a depth of 10.7m at a sand-to-liquid volume ratio of 6%-7%-8%-9%. 3 The fracturing fluid volume under various sand-fluid volume ratio conditions is 40m³. 3 40m 3 35m 3 30m 3 Then inject 60m of low-viscosity slickwater. 3 .

[0198] S10: Inject high-viscosity slippery water carrying 40-70 mesh low-density ceramsite, with a viscosity of 18 mPa·s. Inject continuously over a 31.35 m³ solution at a sand-to-liquid volume ratio of 8%-10%-11%-12%-13%-15%.3 The fracturing fluid volume under various sand-fluid volume ratio conditions is 60m³. 3 50m 3 45m 3 45m 3 40m 3 40m 3 Then inject 60m of high-viscosity slickwater. 3 .

[0199] S11: Inject high-viscosity slippery water carrying 40-70 mesh low-density ceramsite, with a viscosity of 18 mPa·s. Inject continuously over a depth of 36.55 m at a sand-to-liquid volume ratio of 14%-15%-16%-17%-18%. 3 The fracturing fluid volume under various sand-fluid volume ratio conditions is 50m³. 3 50m 3 45m 3 45m 3 40m 3 Then inject 60m of high-viscosity slickwater. 3 .

[0200] S12: Inject a high-viscosity slurry carrying 40-70 mesh low-density ceramsite, with a viscosity of 50 mPa·s. Inject the slurry continuously over a 7.7 m³ volume ratio of 17%-18%-20%-22%. 3 The fracturing fluid volume under each sand-fluid volume ratio condition is 10m³. 3 10m 3 10m 3 10m 3 .

[0201] The above description is merely a preferred embodiment of the present invention. It should be noted that, for those skilled in the art, based on the technical teachings provided by the present invention and as common knowledge in the field, other equivalent modifications and improvements can be made, and these should also be considered within the scope of protection of the present invention.

Claims

1. A temporary plugging agent, characterized in that, The temporary plugging agent includes acrylamide, 2-acrylamide-2-methylpropanesulfonic acid, and methyl acrylate; Based on the total mass of the raw materials of the temporary plugging agent, the acrylamide content is 15wt% to 20wt%; The content of 2-acrylamide-2-methylpropanesulfonic acid is 5wt% to 10wt%. The methyl acrylate content is 1wt% to 2wt%; The temporary plugging agent further includes a crosslinking agent, an initiator, and a cosolvent, wherein the cosolvent is selected from N,N-dimethylformamide, and the content of the cosolvent is 2wt% to 5wt%. The initiator is selected from a mixture of potassium persulfate and sodium bisulfite.

2. The temporary plugging agent according to claim 1, characterized in that, The content of 2-acrylamide-2-methylpropanesulfonic acid is 5wt% to 8wt%.

3. The temporary plugging agent according to claim 1, characterized in that, The crosslinking agent is selected from at least one of N,N-methylenebisacrylamide, N-vinylpyrrolidone, and neopentyl glycol diacrylate.

4. The temporary plugging agent according to claim 1, characterized in that, The weight ratio of potassium persulfate to sodium bisulfite is (2-3):

1.

5. The temporary plugging agent according to claim 1, characterized in that, The crosslinking agent content is 0.5wt% to 1wt%; and / or The initiator content is 0.15wt% to 0.8wt%; and / or The content of the mutual solvent is 3wt% to 4wt%.

6. The temporary plugging agent according to claim 5, characterized in that, The initiator content is 0.2wt% to 0.3wt%.

7. The temporary plugging agent according to any one of claims 1-6, characterized in that, The dissolution time of the temporary plugging agent in water is 10 min to 120 min; and / or The temporary plugging agent has a volume density of 0.95~1.2 mg / mL; and / or The temporary plugging agent can withstand pressure of 40 MPa for more than 20 minutes.

8. The temporary plugging agent according to claim 7, characterized in that, The bulk density of the temporary plugging agent is 1.05~1.1 mg / mL.

9. A method for preparing a temporary plugging agent according to any one of claims 1-8, characterized in that, The preparation method includes the following steps: Step A: Mix the acrylamide, 2-acrylamide-2-methylpropanesulfonic acid, methyl acrylate, crosslinking agent, miscible solvent and water to obtain a first solution; Step B: After the first solution is deoxygenated, it is mixed with the initiator and then deoxygenated a second time.

10. The preparation method according to claim 9, characterized in that, The mixing conditions in step A include: a temperature of 15–25°C, a time of 10–20 min, and a stirring speed of 200–300 r / min; and / or Step A further includes: adjusting the pH of the first solution to 6.95–7.05; and / or The mixing conditions in step B include: a temperature of 15–25°C, a time of 30–40 min, and a stirring speed of 200–300 r / min; and / or Step B further includes: preparing the initiator into a solution with a mass concentration of 0.1 wt% to 1 wt%; and / or In step B, the deoxygenation process is carried out by bubbling nitrogen gas into the first solution for 30-40 minutes. After the first solution and the initiator are mixed, nitrogen gas is bubbled into the solution for a second deoxygenation until it becomes viscous; and / or The preparation method further includes: placing the solution obtained in step B in a water bath at 40-60°C for 6-8 hours to obtain a gel-like product; The preparation method further includes cutting, drying and pulverizing the gel-like product.

11. The preparation method according to claim 10, characterized in that, In step B, the potassium persulfate and sodium bisulfite are dissolved separately in distilled water to obtain an initiator solution; and / or The drying temperature is 60–70°C.

12. A fracturing method, characterized in that, The method includes the following steps: S1: Determine the operational parameters for the target well fracturing process; S2: Use a temporary plugging agent to seal the ends of cracks of different lengths; S3: Preprocess the target well formation; S4: Inject temporary plugging agent and first proppant into the target well formation sequentially to create fractures; S5: Inject the second proppant; S6: Insert a bridge plug into the target well formation and repeat steps S2 to S4; The temporary plugging agent is selected from at least one of the temporary plugging agents according to any one of claims 1-8 or the temporary plugging agent prepared by any one of claims 9-11.

13. The fracturing method according to claim 12, characterized in that, Step S1 includes: determining the number of temporary plugging attempts, the number of perforation clusters, and the cluster spacing during the fracturing process; and / or Step S1 also includes parameter evaluation of the target well formation, wherein the parameter evaluation includes pilot well logging data and / or the mechanical properties of core samples; and / or Step S2 includes: the particle size of the temporary plugging agent is 1 / 3 to 1 / 6 of the crack width; simulating the concentration profile of the temporary plugging agent at the crack tip to determine the support width of the temporary plugging agent; and determining the value of the support width relative to the dynamic crack width by controlling at least one parameter among the particle size, concentration, addition time, carrier fluid viscosity, and injection rate of the temporary plugging agent; and / or In step S3, the pretreatment includes at least one of perforation, acid treatment, and slit creation.

14. The fracturing method according to claim 13, characterized in that, In step S1, when determining the number of temporary plugging operations, temporary plugging is performed once every 60m to 80m; the number of perforation clusters is 3 to 4 clusters; the cluster spacing is 1.5 to 2 times the crack turning radius; and / or In step S1, the parameters of the target well formation are evaluated using at least one of X-ray diffraction analysis, dipole acoustic logging, FMI imaging logging, and core surface observation. and / or In step S2: the error between the support width and the dynamic slot width is ≤2%; the temporary plugging agent effectively seals the ends of slots with different lengths; during effective sealing, the bottom hole pressure rise is >1 MPa / min; and / or In step S3, during the fracture creation process, the injected fluid volume is 0.8 to 1.5 times the wellbore volume.

15. The fracturing method according to any one of claims 12-14, characterized in that, Step S4 includes: Step S41: Inject the first temporary plugging agent and the first proppant into the target well formation in sequence to create fractures; Step S42: Sequentially inject the second temporary plugging agent and the first proppant into the target well formation to create fractures; Step S43: Inject the third temporary plugging agent and the first proppant into the target well formation in sequence to create fractures.

16. The fracturing method according to claim 15, characterized in that, The dissolution time of the second temporary plugging agent is greater than that of the first temporary plugging agent, and the solvent time of the third temporary plugging agent is greater than that of the second temporary plugging agent; and / or After the first, second, and third temporary plugging agents are injected into the target well formation, the wellhead pressure rise rate is 0.95–1.05 MPa / min; and / or The particle size of the first proppant is 70 mesh to 200 mesh; and / or In step S41, after injecting the first proppant, the sand-to-liquid ratio is 3wt%–8wt%, and the injected fluid volume is 0.8–1 times the wellbore volume; and / or, In step S42, after injecting the first proppant, the sand-to-liquid ratio is 5wt%–9wt%, and the injected fluid volume is 1–1.5 times the wellbore volume; and / or, In step S43, after injecting the first proppant, the sand-to-liquid ratio is 6wt% to 10wt%, and the injected fluid volume is 1.5 to 2 times the wellbore volume.

17. The fracturing method according to claim 16, characterized in that, The dissolution time of the first temporary plugging agent is 20 min to 40 min, the dissolution time of the second temporary plugging agent is 40 min to 60 min, and the dissolution time of the third temporary plugging agent is ≥120 min.

18. The fracturing method according to any one of claims 12-14, characterized in that, The particle size of the second proppant is 30 mesh to 70 mesh; and / or In step S4, the temporary plugging agent and the first proppant are respectively injected into the target well formation by being carried by the first fracturing fluid; and / or In step S5, the second proppant is injected into the target well formation by being carried by the second fracturing fluid.

19. The fracturing method according to claim 18, characterized in that, In step S4, the first fracturing fluid is selected as low-viscosity slickwater with a viscosity of 3-5 mPa·s; and / or In step S5, the second fracturing fluid is selected as high-viscosity slickwater with a viscosity of 15-20 mPa·s.

20. The application of a temporary plugging agent according to any one of claims 1-8, a method for preparing a temporary plugging agent according to any one of claims 9-11, or a fracturing method according to any one of claims 12-19 in the stimulation of unconventional oil and gas reservoirs.

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