Multistage temporary plugging fracturing method and device based on stress cage effect and storage medium

Abstract

The present application relates to a multistage temporary plugging fracturing method and device based on stress cage effect and a storage medium, applied to the technical field of oil and gas exploitation, comprising: determining a plugging point by obtaining a stress weak position on a main fracture, determining the amount of temporary plugging diverting fluid by calculating the additional net pressure in the fracture required to generate a branch diverting fracture at the position with the minimum principal stress, plugging the position with the weakest stress in the main fracture to form an artificial barrier layer to prevent subsequent fluid pressure from being transmitted forward, thereby changing the ground stress field near the position to form an additional induced stress field, generating a stress cage effect, and realizing the formation of multistage temporary plugging branch fractures in a straight well; and overcoming the problem that it is difficult to form complex fractures by simply increasing the amount of liquid and the construction displacement to expand the liquid sweep range.

Description

Multi-stage temporary plugging fracturing method, device, and storage medium based on stress cage effect Technical Field

[0001] This invention relates to the field of oil and gas engineering and extraction technology, specifically to multi-stage temporary plugging fracturing based on the stress cage effect, equipment, and storage medium. Background Technology

[0002] Tight oil refers to oil accumulations formed in tight reservoirs sandwiched or adjacent to high-quality source oil formations without large-scale, long-distance migration. It is an unconventional oil resource characterized by low porosity and low permeability. Due to the lack of natural fractures in tight oil reservoirs, it is difficult to form complex fracture networks. Current technologies typically employ large-scale, high-volume formation fracture network stimulation methods. This involves increasing the stimulation volume by enhancing the strength of proppant-carrying fluids and fracturing fluids used during fracture network formation. However, this approach leads to a gradual deterioration of reservoir properties in tight oil test blocks, resulting in unsatisfactory formation of formation fracture networks and incurring high costs. Summary of the Invention

[0003] In view of this, the purpose of the present invention is to provide a multi-stage temporary plugging fracturing device and storage medium based on the stress cage effect, so as to solve the problem in the prior art that by increasing the amount of sand-carrying fluid and fracturing fluid used in the formation of the fracture network to increase the stimulation volume, the reservoir properties of tight oil test blocks deteriorate year by year, the formation effect of the formation fracture network is not ideal, and it has a high cost.

[0004] According to a first aspect of the present invention, a multi-stage temporary plugging fracturing method based on the stress cage effect is provided, the method comprising:

[0005] A preset amount of acid is injected into the wellbore at a preset injection rate to reduce the rock fracturing pressure around the wellbore.

[0006] A preset amount of fracturing fluid is injected into the wellbore at a preset injection rate and into the formation, forming the first main fracture with the injection point in the formation as the starting point.

[0007] The location of minimum principal stress within the first main crack is determined, and the magnitude of the principal stress at this location is denoted as σ. min ;

[0008] According to the minimum principal stress σ min Obtain the increase in net pressure within the crack, Δp, required to generate a branching crack at the location of minimum principal stress;

[0009] The volume of temporary plugging diversion fluid required to generate a branch diversion crack at the location of minimum principal stress is obtained based on the increase value Δp of the net pressure inside the crack.

[0010] The obtained temporary plugging and diversion fluid volume is injected into the first main crack to seal the position of minimum principal stress in the first main crack;

[0011] Fracturing fluid is injected into the first main fracture at a preset first injection rate until a diverting branch fracture is generated at the position where the principal stress of the first main fracture is minimal.

[0012] Repeat the above steps to form multiple diversion branch fractures within the first main fracture until the distance between the location of the minimum principal stress within the first main fracture and the location of the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging diversion fracturing of the first main fracture.

[0013] Preferably, it further includes:

[0014] After completing the multi-stage temporary plugging and diversion fracturing of the first main fracture, the temporary plugging and diversion fluid is injected between the position of minimum principal stress in the first main fracture and the position of the injection point.

[0015] Then, inject the preset amount of fracturing fluid into the injection point at the preset injection rate, so that a second main fracture with a different direction from the first main fracture is generated starting from the injection point.

[0016] Then, following the steps described above, complete the multi-stage temporary plugging and diversion fracturing of the second main fracture;

[0017] Multiple main fractures are generated and multi-stage temporary plugging and directional fracturing of multiple main fractures is completed until the angle between two adjacent main fractures is less than a preset angle threshold.

[0018] Preferably, it further includes:

[0019] After completing the multi-stage temporary plugging and diversion fracturing of the first main fracture or multiple main fractures, sand-carrying fluid is injected into the formation through the wellbore to support the formed multi-stage temporary plugging and diversion branch fractures.

[0020] Then, a displacement fluid of one wellbore volume is injected into the formation through the wellbore to displace the sand-carrying fluid in the wellbore into the formation.

[0021] Preferably,

[0022] The method of obtaining the location of minimum principal stress within the first main crack includes:

[0023] The shear stress, x-direction normal stress, and y-direction normal stress at different locations within the first main crack are obtained. The principal stress at different locations is obtained by comparing the shear stress, x-direction normal stress, and y-direction normal stress at different locations, and the location with the minimum principal stress is obtained.

[0024] Preferably,

[0025] The minimum principal stress σ min Obtaining the increase in net intracrack pressure Δp required to generate a branching crack at the location of minimum principal stress includes:

[0026] Obtain the angle between the direction of the first main crack and the initiation direction of the branch turning crack. The initiation direction of the branch turning crack is the direction of the principal stress at the position of minimum principal stress. Obtain the normal stress of the branch turning crack of the first main crack by means of the shear stress, the normal stress in the x-direction, the normal stress in the y-direction at the position of minimum principal stress, and the angle between the direction of the first main crack and the initiation direction of the branch turning crack.

[0027] The normal stress and minimum principal stress σ of the branch-oriented crack min The net pressure increase Δp required to generate a branching crack at the location of minimum principal stress is obtained.

[0028] Preferably,

[0029] The step of injecting fracturing fluid into the first main fracture at a preset first injection rate until a diversion branch fracture is generated at the location of minimum principal stress in the first main fracture includes:

[0030] Fracturing fluid is injected into the first main fracture at a preset first injection rate, when the bottom pressure p of the wellbore... w When the preset pressure condition is met, a second preset amount of fracturing fluid is injected into the first main fracture to generate a branch fracture at the position of minimum principal stress in the first main fracture.

[0031] According to a second aspect of the present invention, a multi-stage temporary plugging fracturing apparatus based on the stress cage effect is provided, the apparatus comprising:

[0032] Pre-injection module: used to inject a preset amount of acid into the formation at a preset injection rate to reduce the rock fracturing pressure around the wellbore;

[0033] Main fracture fracturing module: used to inject a preset amount of fracturing fluid into the formation at a preset injection rate, forming the first main fracture starting from the injection point in the formation;

[0034] Principal stress acquisition module: used to obtain the location of minimum principal stress within the first main crack, and denot the magnitude of the principal stress at this location as σ. min ;

[0035] Net pressure acquisition module within the joint: used to obtain the minimum principal stress σ min Obtain the increase in net pressure within the crack, Δp, required to generate a branching crack at the location of minimum principal stress;

[0036] Temporary plugging diversion fluid usage acquisition module: used to obtain the volume of temporary plugging diversion fluid required to generate a branch diversion crack at the position of minimum principal stress based on the increase value Δp of the net pressure inside the crack.

[0037] The sealing module is used to inject the obtained temporary sealing diversion fluid volume into the first main fracture to seal the position of minimum principal stress in the first main fracture.

[0038] Branch fracture fracturing module: used to inject fracturing fluid into the first main fracture at a preset first injection rate until a branch fracture is generated at the position where the principal stress of the first main fracture is minimal;

[0039] Multi-stage temporary plugging and diversion fracturing module: used to repeat the above steps to form multiple diversion branch fractures in the first main fracture until the distance between the position of minimum principal stress in the first main fracture and the position of the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging and diversion fracturing of the first main fracture.

[0040] According to a third aspect of the present invention, a storage medium is provided, the storage medium storing a computer program, which, when executed by a host controller, implements the steps of the above-described method.

[0041] The technical solutions provided by the embodiments of the present invention may include the following beneficial effects:

[0042] This application determines the plugging point by identifying the weakest stress location on the main fracture, and determines the amount of temporary plugging and diversion fluid needed by calculating the increased net pressure within the fracture required to generate a branch diversion fracture at the location of minimum main stress. By plugging the weakest stress location in the main fracture, an artificial shielding layer is formed, preventing the subsequent fluid pressure from being transmitted forward. This alters the geostress field near this location, thereby creating an additional induced stress field near the weakest location, generating a stress cage effect, and realizing multi-stage temporary plugging and diversion fracturing in vertical wells. This overcomes the problem of traditional methods that simply increase the fluid volume and discharge rate to expand the fluid sweep range, making it difficult to form complex fractures.

[0043] It should be understood that the above general description and the following detailed description are exemplary and explanatory only, and are not intended to limit the invention. Attached Figure Description

[0044] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0045] Figure 1 is a schematic flowchart of a multi-stage temporary plugging fracturing method based on the stress cage effect according to an exemplary embodiment;

[0046] Figure 2 is a schematic diagram illustrating the relationship between the net pressure increase and the amount of temporary plugging steering fluid used, according to another exemplary embodiment.

[0047] Figure 3 is a schematic diagram of a multi-stage temporary plugging fracturing device based on the stress cage effect according to an exemplary embodiment;

[0048] In the attached diagram: 1-Pre-injection module, 2-Main fracture fracturing module, 3-Main stress acquisition module, 4-Net pressure acquisition module within the fracture, 5-Temporary plugging diversion fluid dosage acquisition module, 6-Pluging module, 7-Branch fracture fracturing module, 8-Multi-stage temporary plugging diversion fracturing module. Detailed Implementation

[0049] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numerals in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present invention. Rather, they are merely examples of apparatuses and methods consistent with some aspects of the invention as detailed in the appended claims.

[0050] Example 1

[0051] Figure 1 is a flowchart illustrating a multi-stage temporary plugging fracturing method based on the stress cage effect according to an exemplary embodiment. As shown in Figure 1, the method includes:

[0052] S1, inject a preset amount of acid into the formation at a preset injection rate to reduce the rock fracture pressure around the well.

[0053] S2, inject a preset amount of fracturing fluid into the wellbore at a preset injection rate to the formation, and form the first main fracture with the injection point in the formation as the starting point;

[0054] S3, Obtain the location of minimum principal stress within the first main crack, and denote the magnitude of the principal stress at this location as σ. min ;

[0055] S4, based on the minimum principal stress σ min Obtain the increase in net pressure within the crack, Δp, required to generate a branching crack at the location of minimum principal stress;

[0056] S5, based on the increase value Δp of the net pressure inside the crack, obtain the volume of temporary plugging diversion fluid required to generate a branch diversion crack at the position of minimum principal stress;

[0057] S6, inject the obtained temporary plugging diversion fluid volume into the first main crack to seal the position of minimum principal stress in the first main crack;

[0058] S7, inject fracturing fluid into the first main fracture at a preset first injection rate until a diverting branch fracture is generated at the position where the principal stress of the first main fracture is minimal;

[0059] S8. Repeat steps S2-S6 to form multiple diversion branch fractures in the first main fracture until the distance between the position of minimum principal stress in the first main fracture and the position of the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging diversion fracturing of the first main fracture.

[0060] Understandably, this application is approved with a resolution of 5.0-10.0m. 3 / min of construction flow rate, injecting 100~500m³ into the wellbore of a vertical well in a tight reservoir. 3 Fracturing fluid is injected into the formation to form the first main fracture. The location of the minimum principal stress within the first main fracture is determined, and the magnitude of the principal stress at this location is denoted as σ. min According to the minimum principal stress σ min The increase in net pressure within the crack, Δp, required to generate a branching crack at the location of minimum principal stress is obtained. Based on the relationship curve between the increase in net pressure and the amount of temporary plugging diverting fluid used, the volume of temporary plugging diverting fluid corresponding to the increase in net pressure Δp is determined. The relationship curve between the increase in net pressure and the amount of temporary plugging diverting fluid used is shown in Figure 2, with a range of 1.0-5.0 m. 3The injection rate is determined by the volume of temporary plugging and diverting fluid injected into the formation at a rate of / min. This volume is used to seal the weakest point in the first main fracture, forming an artificial barrier layer to prevent the forward transmission of subsequent fluid pressure. This alters the geostress field near the location, creating an additional induced stress field and generating a stress cage effect. Fracturing fluid is injected into the first main fracture at a preset first injection rate until a diverting branch fracture occurs at the location of minimum principal stress in the first main fracture. It is worth emphasizing that the location of minimum principal stress in the first main fracture changes with the occurrence of branch fractures, gradually moving from the end of the first main fracture towards the starting point, i.e., the injection point. When the principal stress in the first main fracture reaches its minimum... The distance between the location of minimum stress and the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging and diversion fracturing of the first main fracture. This application determines the plugging point by obtaining the stress-weak location on the main fracture, and determines the amount of temporary plugging and diversion fluid by calculating the net pressure increase required to generate a branch diversion fracture at the location of minimum main stress. By plugging the weakest stress location in the main fracture, an artificial shielding layer is formed to prevent the subsequent fluid pressure from being transmitted forward, thereby changing the geostress field near this location, thus forming an additional induced stress field near the weak location, generating a stress cage effect, and realizing multi-stage temporary plugging and diversion in vertical wells. This overcomes the problem that the traditional method of simply increasing the fluid volume and construction discharge to expand the fluid sweep range is difficult to form complex fractures.

[0061] Preferably, it further includes:

[0062] After completing the multi-stage temporary plugging and diversion fracturing of the first main fracture, the temporary plugging and diversion fluid is injected between the position of minimum principal stress in the first main fracture and the position of the injection point.

[0063] Then, inject the preset amount of fracturing fluid into the injection point at the preset injection rate, so that a second main fracture with a different direction from the first main fracture is generated starting from the injection point.

[0064] Then, following the steps described above, complete the multi-stage temporary plugging and diversion fracturing of the second main fracture;

[0065] Multiple main fractures are generated and multi-stage temporary plugging and diversion fracturing of multiple main fractures is completed until the angle between two adjacent main fractures is less than a preset angle threshold.

[0066] Understandably, after completing the multi-stage temporary plugging and diversion fracturing of the first main fracture, temporary plugging and diversion fluid is injected between the location of minimum principal stress within the first main fracture and the injection point. This prevents subsequent injections of fracturing fluid from generating branch fractures on the first main fracture, preparing for the formation of new main fractures. Then, at a depth of 5.0-10.0m... 3A flow rate of / min is used to inject 100~500m³ of water into the injection point at the bottom of a vertical wellbore in a tight reservoir. 3 The fracturing fluid is used to generate a second main fracture with a different direction from the first main fracture, starting from the injection point. The above steps are repeated until the multi-stage temporary plugging and turning fracturing of the second main fracture is completed. New main fractures are generated and multi-stage temporary plugging and turning fracturing is completed. Finally, a main fracture and branch fractures are formed that spread outward from the injection point, generating a fracture network, until the angle between two adjacent main fractures is less than a preset angle threshold, so as to avoid the branch fractures of two main fractures that are too close to the injection point from penetrating each other.

[0067] Preferably, it further includes:

[0068] After completing the multi-stage temporary plugging and diversion fracturing of the first main fracture or multiple main fractures, sand-carrying fluid is injected into the formation through the wellbore to support the formed multi-stage temporary plugging and diversion fractures.

[0069] Then, a displacement fluid of one wellbore volume is injected into the formation through the wellbore to displace the sand-carrying fluid in the wellbore into the formation;

[0070] It is understandable that, with a sand concentration of 5%-30%, 1000-3000m³ of sand could be injected into the formation. 3 The sand-carrying liquid has a discharge rate of 5-10m³ during construction. 3 / min, to effectively support the multi-stage temporary plugging and turning cracks formed, creating a crack mesh system with high flow conductivity, and then with a construction discharge rate of 1-3m 3 / min, injecting a displacement fluid of one wellbore volume into the formation to displace the sand-carrying fluid in the wellbore into the formation.

[0071] Preferably,

[0072] The method of obtaining the location of minimum principal stress within the first main crack includes:

[0073] The shear stress, x-direction normal stress, and y-direction normal stress at different locations within the first main crack are obtained. The principal stress at different locations is obtained by comparing the shear stress, x-direction normal stress, and y-direction normal stress at different locations, and the location with the minimum principal stress is obtained.

[0074] It is understandable that the shear stress, x-direction normal stress, and y-direction normal stress are different at each location within the first main crack. The specific formulas for obtaining the shear stress, x-direction normal stress, and y-direction normal stress at different locations are shown below:

[0075]

[0076]

[0077]

[0078] The stress components in the cylindrical coordinate system in the above formula , and By converting them to a rectangular coordinate system, we can obtain... , and ,in (y, x) are the coordinates of a certain position within the first main crack in a rectangular coordinate system, and r w p is the wellbore radius. w The bottom hole pressure is σ. The specific calculation formula is given in the following examples. h The original minimum horizontal principal stress of the stratum is a constant value, σ. H The original maximum horizontal principal stress of the stratum is a constant value.

[0079] After obtaining the shear stress, x-direction normal stress, and y-direction normal stress at different locations, the principal stresses at these locations are obtained using the principal stress calculation formula, which is shown below:

[0080]

[0081] In the formula, τ xy σ represents shear stress. x σ represents the normal stress in the x-direction. y σ represents the normal stress in the y-direction. p This represents the maximum principal stress. By analyzing the principal stresses at different locations, we can determine the location of the minimum principal stress within the first principal crack. The principal stress at the location of the minimum principal stress is σ. min .

[0082] Preferably,

[0083] The minimum principal stress σ min The increase in net intracrack pressure Δp required to generate a branching crack at the location of minimum principal stress includes:

[0084] Obtain the angle between the direction of the first main crack and the initiation direction of the branch turning crack. The initiation direction of the branch turning crack is the direction of the principal stress at the position of minimum principal stress. Obtain the normal stress of the branch turning crack of the first main crack by means of the shear stress, the normal stress in the x-direction, the normal stress in the y-direction at the position of minimum principal stress, and the angle between the direction of the first main crack and the initiation direction of the branch turning crack.

[0085] The normal stress and minimum principal stress σ of the branch-oriented crack min To obtain the increase in net pressure Δp required to generate a branching crack at the location of minimum principal stress;

[0086] It is understandable that the principal stress σ at the location of minimum principal stress within the first main crack is obtained. min Then, the angle between the direction of the first main crack and the direction of the branch crack initiation is obtained. The direction of the branch crack initiation is the direction of the principal stress at the position of minimum principal stress. The formula for calculating the direction of the principal stress at the position of minimum principal stress is:

[0087] The normal stress of the branch-direction crack of the first main fracture is obtained by using the shear stress at the location of minimum principal stress, the normal stress in the x-direction, the normal stress in the y-direction, and the angle between the direction of the first main fracture and the initiation direction of the branch-direction crack. The formula for calculating the normal stress of the branch-direction crack is as follows:

[0088]

[0089] In the formula, σ n The normal stress of the branch crack is represented by θ, which is the angle between the direction of the first main crack and the direction of the branch crack initiation. The normal stress and minimum principal stress σ at the location of the minimum principal stress of the first main crack are obtained. min Then, the increase value Δp of the net pressure inside the seam is obtained through the calculation formula for the increase value Δp of the net pressure inside the seam, which is as follows:

[0090]

[0091] Preferably,

[0092] The step of injecting fracturing fluid into the first main fracture at a preset first injection rate until a diversion branch fracture is generated at the location of minimum principal stress in the first main fracture includes:

[0093] Fracturing fluid is injected into the first main fracture at a preset first injection rate, when the bottom pressure p of the wellbore... w When the preset pressure condition is met, continue to inject a second preset amount of fracturing fluid into the first main fracture to generate a diversion branch fracture at the position of minimum principal stress of the first main fracture.

[0094] Understandably, with a range of 1.0-5.0m 3The construction flow rate is determined by the volume of temporary plugging fluid injected into the formation at a rate of / min. This volume is used to seal the weakest point of principal stress in the first main fracture, forming an artificial barrier layer to prevent subsequent fluid pressure from propagating forward. This alters the geostress field near this location, creating an additional induced stress field and generating a stress cage effect, with a depth of 5.0-10.0m. 3 / min of construction flow rate, injecting a certain amount of fracturing fluid into the first main fracture, forming a branching fracture at the position of minimum principal stress in the first main fracture, when the bottom pressure p of the wellbore... w When the preset pressure conditions are met, it indicates that a branching fracture has occurred, and fracturing fluid injection should continue for another 100-500m. 3 To ensure that the branch turning crack continues to extend forward a certain distance, the pressure p w The preset pressure conditions are as follows:

[0095]

[0096] In the formula,

[0097]

[0098]

[0099]

[0100]

[0101]

[0102]

[0103] In the above formula, p f σ is the intra-crack pressure of the first main crack; ΔL is the length from the position of minimum stress in the first main crack to the end of the first main crack; H The original maximum horizontal principal stress of the stratum is a constant value; σ h The original minimum horizontal principal stress of the stratum is a constant value; π is pi; r w k is the radius of the wellbore; c For fracture toughness;

[0104] It is worth emphasizing that during the formation of the branch fractures of the first main fracture, the bottom pressure p of the wellbore... wIf the above conditions are met, and during the subsequent formation of branch fractures in the main fracture, the bottom pressure p in the wellbore... w The conditions for meeting the criteria are not the same as those for meeting the criteria during the formation of the branch cracks of the first main crack, as detailed below:

[0105]

[0106] In the formula,

[0107]

[0108]

[0109]

[0110]

[0111]

[0112] In the above formula, w c The width of the main crack; The apparent fracture toughness of the main fracture; E is the rock elastic modulus; ν is Poisson's ratio; σ h The original minimum horizontal principal stress of the stratum is a constant value; π is pi; p f1 The intracranial pressure of the main crack; h is the crack height of the main crack; k c For fracture toughness; c o This is the ratio of the bulk modulus of the rock skeleton to that of the saturated fluid rock. This refers to the expansion stress caused by water absorption by the well wall rock. The coefficient of thermal expansion; The magnitude of the temperature difference caused by water absorption on the well wall; Tensile strength of rock; The pressure difference between the flowing pressure within the main fracture and the formation pore pressure; This refers to the formation pore pressure.

[0113] To facilitate understanding of this application, this embodiment also discloses a specific example to verify the above scheme, as shown below:

[0114] Well A is a vertical well in the PuX tight oil block. Natural fractures are not well-developed. The total perforated sandstone thickness is 20.8m, with an effective thickness of 14.2m. The reservoir GR difference is 40-50 API, indicating strong lithological obstruction. The target fracturing interval is 1748.0-1745.0m. The geothermal gradient in this area is 5.15℃ / 100m, classifying it as a high geothermal gradient reservoir. The pressure coefficient is 1.13-1.281MPa / 100m, the original formation pressure is 18.18MPa, and the surface crude oil viscosity is 38.9mPa·s. To increase the well's production, a multi-stage temporary plugging and diversion fracturing operation based on the stress cage effect was performed. The specific pumping procedure is as follows: starting at 5.0m... 3 / min of construction flow rate, injecting 200m³ into the wellbore of a vertical well in a tight reservoir. 3 The fracturing fluid was introduced into the formation, forming the first main fracture;

[0115] Input horizontal biaxial ground stress 31.5MPa / 30.5MPa, vertical ground stress 76.3MPa, elastic modulus 25.7GPa, Poisson's ratio 0.25, injection volume 200m³ 3 Construction discharge volume 5.0m 3 Parameters such as / min, stress components σ at various locations after the completion of the first main crack. x σ y τ xy This allows us to pinpoint the location of the weakest point with the greatest principal stress, where the magnitude of the stress is denoted as σ. min =34.6MPa;

[0116] According to the formula The normal stress was calculated to be 36.5 MPa;

[0117] The increase in net pressure within the slit, Δp, required to inject temporary plugging diverting fluid is determined using the following formula:

[0118]

[0119] Based on the relationship curve between the net pressure increase and the amount of temporary plugging diverter fluid shown in Figure 2, it is determined that when Δp is 1.9 MPa, the corresponding volume of temporary plugging diverter fluid is 25 m³. 3 ;

[0120] At 1.5m 3 / min construction discharge rate, injecting 25m³ into the formation. 3 Temporarily plugging diverting fluid is used to seal the weakest stress point in the first main fracture, forming an artificial shielding layer to prevent subsequent fluid pressure from being transmitted forward. This alters the geostress field near the location, thereby creating an additional induced stress field near the weak point and generating a stress cage effect.

[0121] With 5.0m 3 At a drilling flow rate of / min, a certain amount of fracturing fluid is injected into the first main fracture, forming a branching fracture at the weakest point of principal stress. When the bottom hole pressure p w When the pressure exceeds 69.8 MPa, it indicates that a branching and turning crack has occurred, and further injection of 200 m is recommended. 3 Fracturing fluid is used to ensure that the branching fracture continues to extend forward a certain distance.

[0122] Repeat steps 2 to 7 a total of 5 times to form 6 branching cracks in the first main joint, that is, a total of six levels of inter-joint temporary plugging and directional fracturing operations are carried out.

[0123] A temporary plugging and diversion fluid is injected between the location of minimum principal stress within the first main fracture and the injection point to prevent the formation of new branch fractures on the first main fracture. Then, the fluid is directed 5.0m towards the injection point. 3 / min of construction flow rate, injecting 200m³ into the wellbore of a vertical well in a tight reservoir. 3 The fracturing fluid reached the formation, forming a second main fracture;

[0124] Calculate σ of the second main crack min2 =38.8MPa;

[0125] Calculate the normal stress σ at the location of minimum principal stress of the second principal crack. n2 :

[0126] ;

[0127] Determine the magnitude of the increase in net pressure within the slit required by injecting the temporary plugging diverting fluid, Δp2.

[0128] ;

[0129] Based on the relationship curve between the net pressure increase and the amount of temporary plugging diverter fluid shown in Figure 2, the volume of temporary plugging diverter fluid corresponding to Δp2 of 2 MPa is determined to be 30 m³. 3 ;

[0130] At 1.5m 3 / min construction discharge rate, injecting 30m³ into the formation. 3 Temporarily plugging diverting fluid is used to seal the fracture opening at the weakest stress point in the second main fracture at the wellbore, forming an artificial shielding layer to prevent subsequent fluid pressure from being transmitted forward. This alters the geostress field near this location, thereby creating an additional induced stress field near the weak point and generating a stress cage effect near the wellbore.

[0131] With 5.0m 3At a drilling flow rate of / min, a certain amount of fracturing fluid is injected into the second main fracture, forming a fracture-turning fracture at the weakest point of the principal stress in the second main fracture. When the bottom hole pressure p w2 When the pressure is greater than 71.8 MPa, the p w2 The calculation formula is:

[0132] This indicates that a fracture turning at the opening has occurred, and 500m of fracturing fluid continues to be injected. 3 To ensure that the fracture continues to extend forward for a certain distance, the fracture temporary plugging and fracturing operation was completed to form the first branch fracture of the second main fracture. The above steps were repeated until the formation of the six branch fractures of the second main fracture was completed, and then the third main fracture was generated. Finally, six main fractures were formed around the wellbore, each of which included six intra-fracture branch fracturing fractures.

[0133] Inject 1000m of the mixture into the formation at a sand concentration of 15%. 3 The sand-carrying liquid has a construction discharge volume of 5m³. 3 / min, to effectively support the multi-stage temporary plugging turning cracks formed, forming a crack network system with high flow conductivity;

[0134] Construction displacement is 2m 3 / min, injecting a displacement fluid of one wellbore volume into the formation to displace the sand-carrying fluid in the wellbore into the formation.

[0135] Example 2

[0136] Figure 3 is a schematic diagram of a multi-stage temporary plugging fracturing device based on the stress cage effect according to an exemplary embodiment, including:

[0137] Pre-injection module 1: Used to inject a preset amount of acid into the formation at a preset injection rate to reduce the rock fracture pressure around the well.

[0138] Main fracture fracturing module 2: Used to inject a preset amount of fracturing fluid into the wellbore at a preset injection rate to the formation, forming the first main fracture with the injection point in the formation as the starting point;

[0139] Principal stress acquisition module 3: Used to obtain the location of the minimum principal stress within the first main crack, and denot the magnitude of the principal stress at this location as σ. min ;

[0140] Module 4 for obtaining net pressure within the seam: used to determine the minimum principal stress σ min Obtain the increase in net intracrack pressure Δp required to generate a branching crack at the location of minimum principal stress;

[0141] Temporary plugging diversion fluid usage acquisition module 5: used to obtain the volume of temporary plugging diversion fluid required to generate a branch diversion crack at the position of minimum principal stress based on the increase value Δp of the net pressure inside the crack;

[0142] Module 6: Used to inject the obtained temporary plugging diversion fluid volume into the first main crack to plug the position of minimum principal stress in the first main crack;

[0143] Branch fracture fracturing module 7: used to inject fracturing fluid into the first main fracture at a preset first injection rate until a branch fracture is generated at the position where the principal stress of the first main fracture is minimal;

[0144] Multi-stage temporary plugging and diversion fracturing module 8: used to repeat the above steps to form multiple diversion branch fractures in the first main fracture until the distance between the position of minimum principal stress in the first main fracture and the position of the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging and diversion fracturing of the first main fracture.

[0145] Understandably, the pre-injection module 1 is used to inject a preset amount of acid into the formation at a preset injection rate to reduce the rock fracturing pressure around the wellbore; the main fracture fracturing module 2 is used to inject a preset amount of fracturing fluid into the formation at a preset injection rate, forming the first main fracture starting from the injection point in the formation; the principal stress acquisition module 3 is used to acquire the location of the minimum principal stress within the first main fracture, and the magnitude of the principal stress at this location is denoted as σ. min The net pressure acquisition module 4 is used to obtain the minimum principal stress σ based on the net pressure within the seam. minThe system obtains the increase in net pressure within the fracture, Δp, required to generate a branching fracture at the location of minimum principal stress. The temporary plugging fluid volume acquisition module 5 uses Δp to determine the required volume of temporary plugging fluid needed to generate the branching fracture at the location of minimum principal stress. The sealing module 6 injects the determined volume of temporary plugging fluid into the first main fracture to seal the location of minimum principal stress. The branching fracture fracturing module 7 injects fracturing fluid into the first main fracture at a preset first injection rate until a branching fracture is generated at the location of minimum principal stress. The multi-stage temporary plugging fracturing module 8 repeats the above steps to form multiple branching fractures within the first main fracture. The distance between the location of the minimum principal stress within the first main fracture and the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging and diversion fracturing of the first main fracture. This application determines the plugging point by identifying the stress-weak location on the main fracture, and determines the amount of temporary plugging and diversion fluid by calculating the net pressure increase required to generate a branch diversion fracture at the location of minimum principal stress. By plugging the weakest stress location in the main fracture, an artificial shielding layer is formed, preventing the subsequent fluid pressure from being transmitted forward. This changes the geostress field near this location, thereby forming an additional induced stress field near the weak location, generating a stress cage effect, and realizing multi-stage temporary plugging and diversion in vertical wells. This overcomes the problem that traditional methods of simply increasing the fluid volume and construction discharge to expand the fluid sweep range are difficult to form complex fractures.

[0146] Example 3:

[0147] This embodiment provides a storage medium storing a computer program, which, when executed by a host controller, implements the various steps in the above method.

[0148] It is understood that the storage medium mentioned above can be a read-only memory, a hard disk, or an optical disk, etc.

[0149] It is understood that the same or similar parts in the above embodiments can be referred to each other, and the contents not described in detail in some embodiments can be referred to the same or similar contents in other embodiments.

[0150] It should be noted that in the description of this invention, the terms "first," "second," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance. Furthermore, in the description of this invention, unless otherwise stated, "a plurality of" means at least two.

[0151] Any process or method description in the flowchart or otherwise herein can be understood as representing a module, segment, or portion of code comprising one or more executable instructions for implementing a particular logical function or process, and the scope of the preferred embodiments of the invention includes additional implementations in which functions may be performed not in the order shown or discussed, including substantially simultaneously or in reverse order depending on the functions involved, as will be understood by those skilled in the art to which embodiments of the invention pertain.

[0152] It should be understood that various parts of the present invention can be implemented in hardware, software, firmware, or a combination thereof. In the above embodiments, multiple steps or methods can be implemented in software or firmware stored in memory and executed by a suitable instruction execution system. For example, if implemented in hardware, as in another embodiment, it can be implemented using any one or a combination of the following techniques known in the art: discrete logic circuits having logic gates for implementing logical functions on data signals, application-specific integrated circuits (ASICs) having suitable combinational logic gates, programmable gate arrays (PGAs), field-programmable gate arrays (FPGAs), etc.

[0153] Those skilled in the art will understand that all or part of the steps of the methods in the above embodiments can be implemented by a program instructing related hardware. The program can be stored in a computer-readable storage medium, and when executed, the program includes one or a combination of the steps of the method embodiments.

[0154] Furthermore, the functional units in the various embodiments of the present invention can be integrated into a processing module, or each unit can exist physically separately, or two or more units can be integrated into a module. The integrated module can be implemented in hardware or as a software functional module. If the integrated module is implemented as a software functional module and sold or used as an independent product, it can also be stored in a computer-readable storage medium.

[0155] The storage media mentioned above can be read-only memory, disk, or optical disk, etc.

[0156] In the description of this specification, references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., indicate that a specific feature, structure, material, or characteristic described in connection with that embodiment or example is included in at least one embodiment or example of the invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples.

[0157] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of the present invention.

Claims

1. A multi-stage temporary plugging fracturing method based on the stress cage effect, characterized in that, The method includes the following steps: injecting a preset amount of acid into the formation at a preset injection rate to reduce the rock fracturing pressure around the wellbore; injecting a preset amount of fracturing fluid into the formation at a preset injection rate to form a first main fracture starting from the injection point in the formation; obtaining the location of the minimum principal stress within the first main fracture, and denoting the magnitude of the principal stress at this location as σ. min ; The step of obtaining the location with the minimum principal stress within the first main crack includes: obtaining the shear stress, x-direction normal stress, and y-direction normal stress at different locations within the first main crack; obtaining the principal stress at different locations using the shear stress, x-direction normal stress, and y-direction normal stress; comparing the principal stresses at different locations to obtain the location with the minimum principal stress; and then determining the location with the minimum principal stress σ. min Obtain the increase in net intra-crack pressure Δp required to generate a branching crack at the location of minimum principal stress; the step is based on the minimum principal stress σ. min Obtaining the increase in net intra-crack pressure Δp required to generate a branching crack at the location of minimum principal stress includes: obtaining the angle between the direction of the first main crack and the initiation direction of the branching crack, wherein the initiation direction of the branching crack is the principal stress direction at the location of minimum principal stress; obtaining the normal stress of the branching crack of the first main crack using the shear stress, normal stress in the x-direction, normal stress in the y-direction at the location of minimum principal stress, and the angle between the direction of the first main crack and the initiation direction of the branching crack; and obtaining the normal stress of the branching crack and the minimum principal stress σ. min The process involves: obtaining the net pressure increase Δp required to generate a branching fracture at the location of minimum principal stress; obtaining the temporary plugging fluid volume required to generate a branching fracture at the location of minimum principal stress based on the net pressure increase Δp; injecting the obtained temporary plugging fluid volume into the first main fracture to seal the location of minimum principal stress in the first main fracture; injecting fracturing fluid into the first main fracture at a preset first injection rate until a branching fracture is generated at the location of minimum principal stress in the first main fracture; the step of injecting fracturing fluid into the first main fracture at a preset first injection rate until a branching fracture is generated at the location of minimum principal stress in the first main fracture includes: injecting fracturing fluid into the first main fracture at a preset first injection rate, when the bottom pressure p of the wellbore... w When the preset pressure condition is met, continue injecting a second preset amount of fracturing fluid into the first main fracture to generate a branching fracture at the position of minimum principal stress in the first main fracture; repeat the above steps to form multiple branching fractures in the first main fracture until the distance between the position of minimum principal stress in the first main fracture and the injection point is less than a preset distance threshold, completing the multi-stage temporary plugging and turning fracturing of the first main fracture; after completing the multi-stage temporary plugging and turning fracturing of the first main fracture, inject temporary plugging and turning fluid between the position of minimum principal stress in the first main fracture and the injection point; then inject the preset amount of fracturing fluid into the injection point at the preset injection rate, so that a second main fracture with a different direction from the first main fracture is generated starting from the injection point; then complete the multi-stage temporary plugging and turning fracturing of the second main fracture according to the above steps; generate multiple main fractures and complete the multi-stage temporary plugging and turning fracturing of multiple main fractures until the angle between two adjacent main fractures is less than a preset angle threshold.

2. The method according to claim 1, characterized in that, Also includes: After completing the multi-stage temporary plugging and directional fracturing of the first main fracture or multiple main fractures, a proppant-carrying fluid is injected into the formation through the wellbore to support the formed multi-stage temporary plugging branch fractures; then, a displacement fluid of one wellbore volume is injected into the formation through the wellbore to displace the proppant-carrying fluid in the wellbore into the formation.

3. A multi-stage temporary plugging fracturing device based on the stress cage effect, characterized in that, The device includes: a pre-injection module for injecting a preset amount of acid into the formation at a preset injection rate to reduce the rock fracturing pressure around the wellbore; a main fracture fracturing module for injecting a preset amount of fracturing fluid into the formation at a preset injection rate to form the first main fracture starting from the injection point in the formation; and a principal stress acquisition module for acquiring the location of the minimum principal stress within the first main fracture, and denoting the magnitude of the principal stress at that location as σ. min The step of obtaining the location of minimum principal stress within the first main crack includes: obtaining shear stress, normal stress in the x-direction, and normal stress in the y-direction at different locations within the first main crack; obtaining the principal stress at different locations using the shear stress, normal stress in the x-direction, and normal stress in the y-direction; comparing the principal stresses at different locations; and obtaining the location of minimum principal stress. The net pressure acquisition module within the crack is used to obtain the minimum principal stress σ. min Obtain the increase in net intra-crack pressure Δp required to generate a branching crack at the location of minimum principal stress; the step is based on the minimum principal stress σ. min Obtaining the increase in net intra-crack pressure Δp required to generate a branching crack at the location of minimum principal stress includes: obtaining the angle between the direction of the first main crack and the initiation direction of the branching crack, wherein the initiation direction of the branching crack is the principal stress direction at the location of minimum principal stress; obtaining the normal stress of the branching crack of the first main crack using the shear stress, normal stress in the x-direction, normal stress in the y-direction at the location of minimum principal stress, and the angle between the direction of the first main crack and the initiation direction of the branching crack; and obtaining the normal stress of the branching crack and the minimum principal stress σ. min The system comprises the following modules: a 1) obtaining the net pressure increase Δp required to generate a branching fracture at the location of minimum principal stress; a 2) temporarily plugging fluid volume acquisition module, used to obtain the volume of temporarily plugging fluid required to generate a branching fracture at the location of minimum principal stress based on the net pressure increase Δp; a 3) sealing module, used to inject the obtained volume of temporarily plugging fluid into the first main fracture to seal the location of minimum principal stress in the first main fracture; and a branching fracture fracturing module, used to inject fracturing fluid into the first main fracture at a preset first injection rate until a branching fracture is generated at the location of minimum principal stress in the first main fracture. The step of injecting fracturing fluid into the first main fracture at a preset first injection rate until a branching fracture is generated at the location of minimum principal stress in the first main fracture includes: injecting fracturing fluid into the first main fracture at a preset first injection rate, when the bottom pressure p of the wellbore... w When the preset pressure condition is met, a second preset amount of fracturing fluid is injected into the first main fracture to generate a branching fracture at the position of minimum principal stress in the first main fracture. The multi-stage temporary plugging and redirection fracturing module is used to repeat the above steps, forming multiple branching fractures within the first main fracture until the distance between the position of minimum principal stress in the first main fracture and the injection point is less than a preset distance threshold, thus completing the multi-stage temporary plugging and redirection fracturing of the first main fracture. After completing the multi-stage temporary plugging and redirection fracturing of the first main fracture, temporary plugging and redirection fluid is injected between the position of minimum principal stress in the first main fracture and the injection point. Then, the preset amount of fracturing fluid is injected into the injection point at the preset injection rate, generating a second main fracture with a direction different from the first main fracture, starting from the injection point. The multi-stage temporary plugging and redirection fracturing of the second main fracture is then completed according to the above steps. Multiple main fractures are generated and multi-stage temporary plugging and redirection fracturing of multiple main fractures is completed until the angle between two adjacent main fractures is less than a preset angle threshold.

4. A storage medium, characterized in that, The storage medium stores a computer program, which, when executed by the main controller, implements the multi-stage temporary plugging fracturing method based on the stress cage effect as described in any one of claims 1-2.

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