Fracturing methods

Abstract

The present application discloses a fracturing method, comprising: obtaining target fracturing section information of a wellbore; injecting a temporary plugging agent combination into the wellbore to plug the perforation holes of the wellbore, wherein the temporary plugging agent combination includes temporary plugging balls and temporary plugging particles of multiple preset particle sizes; adding temporary plugging powder to the pre-fluid; injecting the pre-fluid into the wellbore; and adding proppant and / or temporary plugging powder to the sand-carrying fluid according to multiple preset stages, wherein the density of the proppant is 1g / cm 3 to 1.05g / cm 3 Sand-carrying fluid is sequentially injected into the wellbore in multiple preset stages. The fracturing fluid used in the sand-carrying fluid is produced water from the target formation with added surfactants. Displacement fluid is then sequentially injected into the wellbore at multiple preset displacement rates based on the target fracturing section. This provides a low-damage, high-intensity fracturing process that improves fracturing production while replacing conventional fracturing fluid with treated, qualified production wastewater, effectively reducing costs and mitigating damage to the formation.

Description

Technical Field

[0001] The present application relates to the technical field of oilfield fracturing operations, and in particular to a fracturing method. Background Art

[0002] In the related technologies, oil and gas well fracturing technology mainly refers to hydraulic fracturing technology, which is mainly used in the exploitation of low-permeability and low-yield oil and gas fields. Specifically, oil and gas well fracturing technology is a technology that, during the process of oil development, uses a high-pressure pump on the ground to squeeze a fracturing fluid with a certain viscosity into a low-permeability reservoir. However, the existing technology uses conventional fracturing fluid for reservoir fracturing, which has the following problems: First, during the fracturing process, the cracks start to crack along the direction of the maximum principal stress, and it is difficult to form a complex fracture network; second, the fracturing fluid enters the formation, causing great damage to the formation, affecting the fracturing effect; third, during the flowback process, the proppant is discharged from the crack along with the fracturing fluid, and the fracture support effect is further deteriorated; fourth, the conventional proppant has a fast settling speed and can only achieve support in the near-well area, affecting the fracturing effect. Due to the existence of the above problems, it is often impossible to achieve the expected fracturing effect during on-site construction. Summary of the Invention

[0003] In view of this, the present application provides a fracturing method.

[0004] According to one aspect of the present application, a fracturing method is provided, comprising:

[0005] Obtain target fracturing section information of the wellbore;

[0006] A temporary plugging agent combination is injected into the wellbore to plug the perforation holes of the wellbore, wherein the temporary plugging agent combination includes temporary plugging balls and temporary plugging particles of various preset particle sizes;

[0007] Add temporary plugging powder into the pre-fluid;

[0008] Injecting prepad fluid into the wellbore;

[0009] According to multiple preset stages, proppant and / or temporary plugging powder are added to the sand-carrying fluid, wherein the density of the proppant is 1g / cm 3 to 1.05g / cm 3 ;

[0010] Injecting sand-carrying fluid into the wellbore in sequence according to multiple preset stages, wherein the fracturing fluid used in the sand-carrying fluid is produced water from the target layer with added surfactant;

[0011] Based on the target fracturing section information, displacement fluid is injected into the wellbore in sequence according to multiple preset displacement rates.

[0012] Optionally, the target fracturing section information includes the number of perforation holes, and before injecting the temporary plugging agent combination into the wellbore to plug the perforation holes in the wellbore, it also includes:

[0013] Determining a first amount of temporary plugging balls according to the number of perforation holes, wherein the first amount is twice the number of perforation holes;

[0014] The second added amount of the temporary blocking particles is determined according to the first added amount and the preset particle size of the temporary blocking particles.

[0015] Optionally, the step of determining the second amount of temporary blocking particles based on the first amount and the preset particle size of the temporary blocking particles specifically includes:

[0016] If the preset particle size of the temporary blocking particles is equal to 3 mm, the second addition amount is: the first addition amount / 2×5.59;

[0017] If the preset particle size of the temporary blocking particles is less than 1 mm, the second addition amount is: the first addition amount / 2×7.35.

[0018] Optionally, the target fracturing section information includes reservoir permeability and, before adding temporary plugging powder to the flush fluid, also includes:

[0019] Determine the third amount of temporary plugging powder based on reservoir permeability;

[0020] If the reservoir permeability is greater than 50mD, the third addition amount is 1% of the pre-pad fluid amount;

[0021] If 10mD≤reservoir permeability≤50mD, the third addition amount is 0.5% of the pre-pad fluid dosage;

[0022] If 1mD≤reservoir permeability<10mD, the third addition amount is 0.1% of the pre-pad fluid amount.

[0023] Optionally, the steps of adding temporary plugging powder and / or proppant to the sand-carrying fluid respectively according to a plurality of preset stages specifically include:

[0024] According to the first preset stage, temporary plugging powder and proppant are added to the sand-carrying fluid;

[0025] According to the second preset stage, temporary plugging powder and 100 mesh proppant are added to the sand-carrying fluid;

[0026] According to the third preset stage, temporary plugging powder and mixed proppants of 40 / 70 mesh and 20 / 40 mesh are added to the sand-carrying fluid;

[0027] According to the fourth preset stage, 20 / 40 mesh proppant is added to the sand-carrying fluid.

[0028] Optionally, the target fracturing section information includes a fracture volume, and the steps of sequentially injecting displacement fluid into the wellbore according to the target fracturing section information and a plurality of preset displacement rates specifically include:

[0029] 3m 3 / min displacement fluid of 5 times the fracture volume is injected into the wellbore;

[0030] 2m 3 / min displacement fluid is injected into the wellbore at a volume three times the fracture volume;

[0031] 1m 3 The displacement fluid of one times the fracture volume is injected into the wellbore at a displacement rate of / min.

[0032] Optionally, the injection rate of the pre-pad fluid is 15m 3 / min to 20m 3 / min.

[0033] Optionally, the mass ratio of the proppant to the temporary plugging powder in the sand-carrying fluid corresponding to the first preset stage is 2:1.

[0034] Optionally, the density of the temporary blocking ball is 0.999 g / cm 3 ;

[0035] The density of temporary plugging particles is 1.02g / cm 3 .

[0036] Optionally, the content of surfactant in the fracturing fluid is 0.05%.

[0037] By means of the above technical solution, the present application provides a fracturing method that provides a low-damage, high-strength fracturing process for oil and gas well fracturing. During the real-time fracturing process, the fracturing system is used to treat the target layer production water that meets the standards by adding surfactants, and is combined with ultra-low density proppants. While ensuring the strength of the proppant, the proppant density is reduced, thereby reducing the proppant's requirements for pumping and fracturing fluid performance, thereby reducing costs. Furthermore, it is possible to form a complex fracture network in the reservoir and effectively support it, thereby improving the fracturing production increase effect. While adapting to the formation, it reduces the damage of the fracturing fluid to the formation, generating huge economic benefits for the oil field.

[0038] The above description is only an overview of the technical solution of the present application. In order to more clearly understand the technical means of the present application, it can be implemented in accordance with the contents of the specification. In order to make the above and other purposes, features and advantages of the present application more obvious and easy to understand, the specific implementation methods of the present application are listed below. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] The drawings described herein are used to provide a further understanding of the present application and constitute a part of the present application. The illustrative embodiments of the present application and their descriptions are used to explain the present application and do not constitute an improper limitation on the present application. In the drawings:

[0040] Figure 1 A schematic diagram of a fracturing method according to an embodiment of the present application is shown;

[0041] Figure 2 A schematic flow chart of another fracturing method provided in an embodiment of the present application is shown. DETAILED DESCRIPTION

[0042] The present application will be described in detail below with reference to the accompanying drawings and in combination with embodiments. It should be noted that, unless there is a conflict, the embodiments and features in the embodiments of the present application can be combined with each other.

[0043] In this embodiment, a fracturing method is provided, such as Figure 1 As shown, the method includes:

[0044] Step 101, obtaining target fracturing section information of the wellbore;

[0045] Step 102: injecting a temporary plugging agent combination into the wellbore to plug the perforation holes of the wellbore, wherein the temporary plugging agent combination includes temporary plugging balls and temporary plugging particles of various preset particle sizes;

[0046] Step 103, adding temporary plugging powder into the pre-fluid;

[0047] Step 104, injecting a pad fluid into the wellbore;

[0048] Step 105: Add proppant and / or temporary plugging powder to the sand-carrying fluid according to multiple preset stages, wherein the density of the proppant is 1g / cm 3 to 1.05g / cm 3 ;

[0049] Step 106: injecting a sand-carrying fluid into the wellbore in sequence according to a plurality of preset stages, wherein the fracturing fluid used in the sand-carrying fluid is produced water of the target layer with added surfactant;

[0050] Step 107 : Based on the target fracturing section information, displacement fluid is sequentially injected into the wellbore at multiple preset displacement rates.

[0051] The embodiment of the present application provides a fracturing method. Specifically, during the fracturing process, according to the target fracturing section information of the wellbore, a certain proportion of soluble temporary plugging balls and temporary plugging particles are added as a temporary plugging agent combination to plug the perforation holes of the fractured well section. Afterwards, soluble temporary plugging powder is added to the pre-fluid to reduce the fracturing fluid loss, and a large displacement of pre-fluid is used to create a three-dimensional fracture network in the near-wellbore area. Furthermore, according to different preset stages, ultra-low density proppants and / or temporary plugging powders are added to the sand-carrying fluid. By using the two in combination and injecting the sand-carrying fluid into the wellbore in sequence according to multiple preset stages, it is achieved that while supporting the fractures, the fracturing fluid loss is reduced, long fractures are created in the reservoir, and the tail ends of the fractures are supported.

[0052] It should be noted that conventional proppants used in the prior art have a high density. During use, they not only cause great wear on the fracturing equipment, but also require the use of high-viscosity sand-carrying fluids. Moreover, they settle quickly in the formation cracks, easily forming sand banks and shortening the effective support cracks. Based on the above problems, this application proposes the use of ultra-low density proppants. By selecting a density range of 1g / cm 3 to 1.05g / cm 3 Compared to conventional proppants, the ultra-low-density proppant is distributed in a single layer within the fracture, with a low sand concentration, enabling the fracture to maintain good long-term conductivity. Furthermore, the use of produced wastewater instead of conventional fracturing fluid reduces costs, formation damage, and equipment wear. Furthermore, because its density is close to that of water, its settling velocity is the lowest, effectively preventing proppant settling within the fracture, enhancing fracture conductivity and effectively improving conductivity.

[0053] Optionally, the target layer production water is the production wastewater after the produced fluid is treated to meet the standards. Specifically, the produced fluid is treated in accordance with the "Recommended Indicators and Analysis Methods for Water Quality in Clastic Oil Reservoirs" (SY / T5329-2012) standard so that the treated production wastewater meets the standards.

[0054] Furthermore, in the prior art, conventional fracturing fluids used in sand-carrying fluids are mainly composed of high-molecular compounds, such as guar gum slick water fracturing fluids, guar gum fracturing fluids, etc. This type of fracturing fluid requires the addition of a variety of additives, which makes its cost account for a very large proportion of the fracturing construction cost, and it causes great damage to the reservoir after entering the formation. Based on the above problems, the present application proposes to use the target layer production water that has been treated and met the standards by adding a small amount of surfactant as a fracturing fluid system. By using the production wastewater that has been treated and met the standards to replace the conventional fracturing fluid, there is no need to add a variety of additives, which effectively reduces the cost. At the same time, it will not cause damage to the reservoir after entering the formation, so that the fracturing fluid does not need to be backflowed, avoiding the proppant in the cracks from being backflowed out of the cracks with the fracturing fluid. Furthermore, the fracturing fluid uses the target layer production water that has been treated and met the standards by adding 0.05% of a small molecule drag reducing agent, which has good compatibility and low friction along the way. Moreover, under different temperature, salinity, and pressure conditions, the density of the target layer production water will be different. For example, under the conditions of 20℃-70℃, the density of the fracturing fluid is 1.06g / cm 3 -1.10g / cm 3 The density of the ultra-low density proppant used is usually 1.05g / cm 3 , making the proppant density slightly lower than the fracturing fluid density. Under flow conditions, the fracturing fluid can move the ultra-low density proppant to the deep of the fracture. After the flow rate is reduced, the proppant can complete the sedimentation and accumulation to support the fracture.

[0055] Furthermore, when injecting the displacement fluid, the amount of displacement fluid is controlled according to the target fracturing section information, and the injection speed is gradually reduced according to the preset displacement, so that the cracks opened by the fractures are slowly closed, the proppant in the cracks is fixed, the support effect of the proppant is ensured, and the fracturing effect is better guaranteed.

[0056] The embodiments of the present application provide a low-damage, high-strength fracturing process for oil and gas well fracturing. During the real-time fracturing process, the fracturing system uses surfactant-treated target layer production water to meet the standards, combined with ultra-low density proppants. This reduces the proppant density while ensuring the strength of the proppant, thereby reducing the proppant's requirements for pumping and fracturing fluid performance, and reducing construction costs. Furthermore, it is possible to form a complex fracture network in the reservoir and effectively support it, improving the fracturing and production increase effect. While adapting to the formation, it reduces the damage caused by the fracturing fluid to the formation, generating huge economic benefits for the oil field.

[0057] Furthermore, as a refinement and expansion of the specific implementation of the above embodiment, in order to fully illustrate the specific implementation process of this embodiment, another fracturing method is provided, such as Figure 2 As shown, the method includes:

[0058] Step 201: Acquire target fracturing section information of the wellbore.

[0059] During the construction process at the target fracturing location, the target fracturing section information in the wellbore is obtained, and then the reservoir material conditions are determined based on the target fracturing section information. Then, combined with the crack expansion and extension laws, multiple fracturing parameters such as fracturing fluid type, fracturing fluid volume, and pre-fluid ratio are determined, so that the entire fracture system can be expanded to a larger range to achieve sufficient fracture creation and ensure that the fracture creation volume covers the effective reservoir thickness to the maximum extent.

[0060] Step 202 : determining a first amount of temporary plugging balls according to the number of perforation holes, wherein the first amount is twice the number of perforation holes.

[0061] Step 203 : determining a second amount of temporary blocking particles based on the first amount and the preset particle size of the temporary blocking particles.

[0062] In steps 202-203, temporary plugging balls and temporary plugging particles of multiple preset sizes are used as a temporary plugging agent combination to plug the perforations. The first dosage of temporary plugging balls is twice the number of perforations to be temporarily plugged. After determining the number of temporary plugging balls to be used, the second dosage of temporary plugging particles for each preset particle size is determined based on the first dosage and the predetermined particle size of the temporary plugging particles to be used. Specifically, for temporary plugging particles with a preset particle size of 3 mm, the corresponding second dosage is the first dosage of temporary plugging balls / 2 × 5.59 g; for temporary plugging particles with a preset particle size of less than 1 mm, the corresponding second dosage is the first dosage of temporary plugging balls / 2 × 7.35 g. By combining temporary plugging balls, temporary plugging particles with a particle size of 3 mm, and temporary plugging particles with a particle size of less than 1 mm as a temporary plugging agent, a dense mud cake with extremely low fluid loss is formed, which effectively plugs irregular perforations of varying sizes in the reservoir and achieves a better plugging effect.

[0063] Optionally, the density of the temporary blocking ball is 0.999g / cm 3 The density of temporary plugging particles is 1.02g / cm 3 .

[0064] Step 204: Determine a third amount of temporary plugging powder to be added based on the reservoir permeability.

[0065] Step 205: Add temporary plugging powder into the forward fluid.

[0066] Step 206: injecting pad fluid into the wellbore.

[0067] Regarding steps 204-206, before injecting the pre-fluid into the wellbore, soluble temporary plugging powder is first added to the pre-fluid, and the amount of temporary plugging powder added is determined according to the reservoir properties to reduce the dynamic filtration rate of the fracturing fluid.

[0068] Specifically, the amount of temporary plugging powder corresponding to different reservoir permeabilities is different. If the reservoir permeability is greater than 50mD, the third amount of temporary plugging powder added is 1% of the pre-pad amount; if 10mD≤reservoir permeability≤50mD, the third amount of temporary plugging powder added is 0.5% of the pre-pad amount; if 1mD≤reservoir permeability<10mD, the third amount of temporary plugging powder added is 0.1% of the pre-pad amount.

[0069] Further, a pre-fluid containing temporary plugging powder is injected into the wellbore. Specifically, 15m 3 / min to 20m 3 The pre-fluid is injected at a large flow rate of 1 / min, which effectively improves the fracture-forming ability of the fracturing fluid and forms a three-dimensional fracture network within 3m of the near-wellbore area.

[0070] It should be noted that during the fracturing process, the maximum designed displacement of the fracturing fluid can be determined according to the scale of the fracturing, and this application does not make any specific limitation here.

[0071] Optionally, during the pre-fracture creation process, the amount of pre-fluid used is 20% of the maximum designed displacement during the fracturing process.

[0072] Step 207 : According to the first preset stage, temporary plugging powder and proppant are added into the sand-carrying fluid.

[0073] Step 208: According to the second preset stage, temporary plugging powder and 100 mesh proppant are added into the sand-carrying fluid.

[0074] Step 209 , according to the third preset stage, temporary plugging powder and mixed proppants of 40 / 70 mesh and 20 / 40 mesh are added into the sand-carrying fluid.

[0075] Step 210: According to the fourth preset stage, 20 / 40 mesh proppant is added into the sand-carrying fluid.

[0076] Step 211 : injecting sand-carrying fluid into the wellbore in sequence according to a plurality of preset stages.

[0077] In steps 207-211, during the sand-carrying fluid addition process, the sand-carrying fluid is sequentially injected into the wellbore in four predetermined stages to propel fractures in the formation and fracturing the formation. Furthermore, prior to injecting the sand-carrying fluid into the wellbore, temporary plugging powder and / or proppant are added to the sand-carrying fluid in each predetermined stage to improve fracture conductivity.

[0078] Optionally, the amount of sand-carrying fluid used is 70% of the maximum designed displacement during the fracturing process, wherein the amount of sand-carrying fluid used in the four preset stages can be evenly distributed.

[0079] Specifically, during the first pre-set stage of sand-carrying fluid addition, proppant and temporary plugging powder are added to reduce fracturing fluid loss, prop up, and temporarily plug the fracture network within 3 meters near the wellbore, preparing for the subsequent injection of sand-carrying fluid to create long fractures. Optionally, the combined amount of proppant and temporary plugging powder added in this first stage is 5% of the first-stage sand-carrying fluid volume, with a mass ratio of proppant to temporary plugging powder of 2:1.

[0080] Furthermore, proppant and temporary plugging powder are added to the sand-carrying fluid during the second preset stage of sand addition to reduce fracturing fluid filtration loss and improve the fracturing fluid's ability to create long fractures. It should be noted that the proppant added in the second preset stage has a particle size of 100 mesh, and the tail end of the fracture is supported by using 100 mesh small-diameter proppant. Optionally, the amount of proppant added in the second preset stage is 20% of the amount of sand-carrying fluid used in the second preset stage; the amount of temporary plugging powder added in the second preset stage is the same as that in the pre-pad fluid, that is, if the reservoir permeability is greater than 50mD, the amount of temporary plugging powder added is 1% of the amount of sand-carrying fluid used; if the reservoir permeability is 10mD≤reservoir permeability≤50mD, the amount of temporary plugging powder added is 0.5% of the amount of sand-carrying fluid used; and if the reservoir permeability is 1mD≤reservoir permeability<10mD, the amount of temporary plugging powder added is 0.1% of the amount of sand-carrying fluid used.

[0081] Furthermore, during the third preset stage of sand-adding, proppant and temporary plugging powder are added to the sand-carrying fluid to ensure that the fluid supports the central portion of the fracture while simultaneously creating long fractures. The proppant added to the sand-carrying fluid is a mixture of 40 / 70 mesh and 20 / 40 mesh proppant, with a mass ratio of 40 / 70 mesh to 20 / 40 mesh = 1:2. Optionally, the amount of mixed proppant added during the third preset stage is 25% of the sand-carrying fluid volume used during the third preset stage. The temporary plugging powder dosage during the third preset stage is similar to that used in the prepad fluid: if the reservoir permeability is greater than 50 mD, the temporary plugging powder dosage is 1% of the sand-carrying fluid dosage; if the reservoir permeability is 10 mD or less and less than 50 mD, the temporary plugging powder dosage is 0.5% of the sand-carrying fluid dosage; and if the reservoir permeability is 1 mD or less and less than 10 mD, the temporary plugging powder dosage is 0.1% of the sand-carrying fluid dosage.

[0082] Furthermore, proppant is added during the fourth preset stage of sand-carrying fluid addition to support the fracture root and ensure effective fracturing. It should be noted that the amount of proppant added during the fourth preset stage is 30% of the amount of sand-carrying fluid used during the fourth preset stage. Optionally, the proppant added during the fourth preset stage has a particle size of 20 / 40 mesh.

[0083] Through the above-mentioned method, after multiple stages of sand addition construction, the cracks are gradually and steadily expanded and supported, ultimately forming cracks with excellent conductivity. Furthermore, by using three different proppants of different particle sizes at different stages of sand addition in the sand-carrying fluid, the proppants are fully filled and supported in the near-wellbore fracture zone, thereby improving the conductivity of the fractures in the near-wellbore zone. In addition, by setting the volume ratio of the proppant in the sand-carrying fluid to gradually increase, a sharp increase in wellhead pressure caused by excessive proppant injection at the beginning, which completely blocks the fluid channels in the formation, is avoided, ensuring construction safety. At the same time, it also avoids the situation where newly formed cracks are re-closed due to insufficient proppant injection, thereby improving construction efficiency.

[0084] Optionally, the proppant has a density in the range of 1 g / cm 3 -1.05g / cm 3 , that is, the proppant is an ultra-low density (ULW) proppant, which has a crushing rate of 0% under 69MPa, an acid dissolution rate of 0.05%, a glass transition temperature of above 155℃, and a decomposition temperature of above 390℃. These conditions make the long-term conductivity of the proppant defined in this application about 6 times that of quartz sand proppant under the same conditions, thereby significantly increasing the output after fracturing. Furthermore, the density of the fracturing fluid is 1.06g / cm 3 to 1.10g / cm 3 Within this range, the proppant density is slightly lower than the fracturing fluid density. Under flow conditions, the fracturing fluid can move ULW to the deep part of the fracture. After the flow rate is reduced, the proppant can complete the sedimentation and accumulation to support the fracture.

[0085] Step 212, with 3m 3 The displacement fluid of 5 times the fracture volume is injected into the wellbore at a displacement rate of / min.

[0086] Step 213, with 2m 3 The displacement fluid of 3 times the fracture volume is injected into the wellbore at a displacement rate of / min.

[0087] Step 214, with 1m 3 The displacement fluid of one times the fracture volume is injected into the wellbore at a displacement rate of / min.

[0088] For steps 212-214, after the pre-pad fluid is used to create the cracks and the sand-carrying fluid is injected, first 3 After injecting 5 times the volume of the fracture displacement fluid at a rate of / min, the displacement fluid injection speed was reduced to 2m 3 / min, after injecting 3 times the volume of the fracture displacement fluid, the displacement fluid injection rate was reduced again to 1m / min of the original injection rate. 3 / min, and then inject 1 times the fracture volume of displacement fluid and stop injection.

[0089] By using the above method, during the displacement fluid injection process, the injection rate is continuously reduced, so that the formation cracks can be gradually closed, and the proppant in the cracks can be fixed in the cracks, thereby achieving the purpose of fixing the proppant and better ensuring the fracturing effect.

[0090] Optionally, the fracturing fluid contains 0.05% surfactant, such as OP-10 or a sulfonate. By using a fracturing fluid system that is treated with a small molecule drag-reducing agent (0.05%) to meet target formation production water standards, the fracturing fluid enters the formation without damaging the reservoir, eliminating the need for flowback. Using target formation production water as the fracturing fluid prevents proppant from migrating out of the fractures with the fracturing fluid. Furthermore, the readily available target production water eliminates the need for multiple additives, offers low cost, excellent compatibility, and low friction along the fracturing process, reducing fracturing costs.

[0091] Optionally, the fracturing fluids used in the pre-fluid and the displacement fluid are both produced water from the target formation.

[0092] Those skilled in the art will understand that the accompanying drawings are only schematic diagrams of a preferred implementation scenario, and the modules or processes in the accompanying drawings are not necessarily required to implement the present application. Those skilled in the art will understand that the modules in the devices in the implementation scenario can be distributed in the devices of the implementation scenario according to the implementation scenario description, or can be changed accordingly and located in one or more devices different from the implementation scenario. The modules of the above-mentioned implementation scenario can be combined into one module, or can be further split into multiple sub-modules.

[0093] The serial numbers of the above application are for descriptive purposes only and do not represent the advantages or disadvantages of the implementation scenarios. The above disclosure only discloses several specific implementation scenarios of the present application, but the present application is not limited thereto. Any changes that can be conceived by those skilled in the art should fall within the scope of protection of the present application.

Claims

1. A fracturing method, characterized in that: include: Obtain target fracturing section information of the wellbore; Adding a temporary plugging agent combination into the wellbore to plug the perforation holes of the wellbore, wherein the temporary plugging agent combination includes temporary plugging balls and temporary plugging particles of multiple preset particle sizes; Add temporary plugging powder into the pre-fluid; injecting the pad fluid into the wellbore; According to multiple preset stages, proppant and / or temporary plugging powder are added to the sand-carrying fluid respectively, wherein the density of the proppant is 1g / cm 3 to 1.05g / cm 3 ; Injecting the sand-carrying fluid into the wellbore in sequence according to the plurality of preset stages, wherein the fracturing fluid used in the sand-carrying fluid is produced water of the target layer with added surfactant; Injecting displacement fluid into the wellbore in sequence according to the target fracturing section information and a plurality of preset displacement rates; The target fracturing section information includes the number of the perforation holes. Before injecting the temporary plugging agent combination into the wellbore to plug the perforation holes in the wellbore, the method further includes: Determining a first amount of temporary plugging balls according to the number of the perforation holes, wherein the first amount is twice the number of the perforation holes; determining a second amount of the temporary blocking particles according to the first amount and a preset particle size of the temporary blocking particles; The step of adding the temporary plugging powder and / or proppant into the sand-carrying fluid respectively according to a plurality of preset stages specifically includes: According to the first preset stage, the temporary plugging powder and the proppant are added into the sand-carrying fluid; According to the second preset stage, the temporary plugging powder and 100 mesh proppant are added to the sand-carrying fluid; According to the third preset stage, the temporary plugging powder and the mixed proppant of 40 / 70 mesh and 20 / 40 mesh are added into the sand-carrying fluid; According to the fourth preset stage, 20 / 40 mesh proppant is added into the sand-carrying fluid.

2. The method according to claim 1, characterized in that The step of determining the second amount of the temporary blocking particles according to the first amount and the preset particle size of the temporary blocking particles specifically includes: If the preset particle size of the temporary plugging particles is equal to 3 mm, the second addition amount is: the first addition amount / 2×5.59; If the preset particle size of the temporary blocking particles is less than 1 mm, the second addition amount is: the first addition amount / 2×7.

35.

3. The method according to claim 1, characterized in that The target fracturing section information also includes reservoir permeability. Before adding temporary plugging powder into the flush fluid, the method further includes: determining a third amount of the temporary plugging powder according to the reservoir permeability; If the reservoir permeability is greater than 50 mD, the third addition amount is 1% of the pre-pad amount; If 10mD≤the reservoir permeability≤50mD, the third added amount is 0.5% of the prepad amount; If 1 mD≤the reservoir permeability<10 mD, the third added amount is 0.1% of the prepad amount.

4. The method according to claim 1, wherein The target fracturing section information also includes a fracture volume. The step of sequentially injecting displacement fluid into the wellbore according to a plurality of preset displacement rates based on the target fracturing section information specifically includes: 3m 3 Injecting the displacement fluid into the wellbore at a displacement rate of 5 times the fracture volume; 2m 3 Injecting the displacement fluid into the wellbore at a displacement rate of 3 times the fracture volume; 1m 3 The displacement fluid of one times the fracture volume is injected into the wellbore at a displacement rate of / min.

5. The method according to claim 1, wherein The injection volume of the pre-fluid is 15m 3 / min to 20m 3 / min.

6. The method according to claim 1, wherein The mass ratio of the proppant to the temporary plugging powder in the sand-carrying fluid corresponding to the first preset stage is 2:

1.

7. The method according to claim 1, characterized in that The density of the temporary blocking ball is 0.999g / cm 3 ; The density of temporary plugging particles is 1.02g / cm 3 .

8. The method according to claim 1, characterized in that The content of surfactant in the fracturing fluid is 0.05%.

Images