A device and experimental method for simulating the temporary plugging effect of hydraulic fractures

Abstract

This invention discloses a device and experimental method for simulating the temporary plugging effect of hydraulic fractures, belonging to the field of oil and gas field development technology. This invention proposes a method for simulating fracturing fluid loss under fracture permeability mode. Starting from simulating single-wing initiation of a hydraulic fracture at the wellbore, it designs a method considering the ratio of the initial fracture width to the proppant particle size and the influence of fracture permeability mode on fracturing fluid loss, achieving accurate simulation of the temporary plugging effect of hydraulic fractures and providing experimental means and design basis for optimizing fracture plugging parameters. The method simulates single-wing initiation of a hydraulic fracture at the wellbore, calculates the ratio of the initial fracture width to the proppant particle size as α, and simulates fracturing fluid loss under fracture permeability mode based on the pump injection rate Q. 实验 Experiments were conducted to simulate the effect of hydraulic fracture closure. The final simulation accurately demonstrated the effect of hydraulic fracture closure, providing guidance for the design of hydraulic fracture closure-to-fracturing in unconventional oil and gas development.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, and relates to a method for simulating the effect of hydraulic fracture temporary plugging, especially a device and experimental method for simulating the effect of hydraulic fracture temporary plugging. Background Technology

[0002] Unconventional tight oil and gas reservoirs generally exhibit poor physical properties, characterized by low porosity and permeability, strong planar heterogeneity, underdeveloped natural fractures, numerous vertically occurring layers, and a high proportion of thin interbedded layers. Effective reservoir modification is essential for economical and efficient development. Hydraulic fracture plugging and diversion fracturing technology is a crucial technique for the efficient development of unconventional oil and gas reservoirs.

[0003] Currently, the effectiveness of temporary plugging materials in stabilizing fractures under different hydraulic fracture conditions is unclear. The selection of particle size for temporary plugging materials is often arbitrary, with multiple trials being commonly used, resulting in waste of temporary plugging materials and even wellbore blockage after pumping in the materials. Therefore, simulating the effect of temporary plugging in hydraulic fractures and determining parameters such as the dosage and particle size of temporary plugging agents is of great significance for the efficient development of unconventional oil and gas reservoirs. Summary of the Invention

[0004] In order to overcome the shortcomings of the prior art, the present invention aims to provide a device and experimental method for simulating the temporary plugging effect of hydraulic cracks, so as to solve the technical problem that the temporary plugging effect of the plugging material on the crack cannot be clearly determined under different hydraulic crack conditions in the prior art.

[0005] To achieve the above objectives, the present invention employs the following technical solution:

[0006] An experimental method for simulating the effect of temporary plugging of hydraulic fractures includes the following steps:

[0007] Simulated hydraulic fracture initiation at the wellbore, dynamic changes in hydraulic fracture width, and fracturing fluid loss in an experimental fracture permeability model;

[0008] Determine the experimental pump injection rate and conduct a test on the effect of temporary plugging of hydraulic cracks under the experimental pump injection rate.

[0009] Preferably, the hydraulic fracture at the wellbore is simulated with a single-wing fracture initiation, and the relationship between the fracture length and the wellbore diameter is as follows:

[0010]

[0011] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length.

[0012] Preferably, the ratio of the initial width of the hydraulic fracture to the proppant particle size is:

[0013]

[0014] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size is given by the coefficient.

[0015] Preferably, the dynamic variation simulation method for hydraulic crack width is the control of elastic filler thickness.

[0016] Preferably, the method for calculating the thickness of the elastic filler is as follows:

[0017]

[0018] in, The thickness of the elastic filler; The unit of length is 1m; Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0019] Preferably, in the simulated experimental fracture permeability model, the fracturing fluid loss is measured by the initial permeability of the experimental fracture:

[0020]

[0021] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment.

[0022] Preferably, the method for determining the experimental pump flow rate is as follows:

[0023]

[0024] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid used in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0025] Preferably, the experiment on the effect of temporary plugging of hydraulic fractures under the experimental pump injection rate specifically includes:

[0026] S201: Based on the experimental pump discharge rate Inject a mixture of temporary plugging particles and carrier fluid with a mass fraction of W;

[0027] S202: Record the initial pumping pressure P_initial and the change of pumping pressure over time: P(t) ~ t;

[0028] S203: Change the mass concentration W of the temporary plugging particles, repeat the above steps, and record the cumulative injection time corresponding to different mass concentrations of temporary plugging particles.

[0029] Preferably, in step S202, when the experimental pump pressure At this time, the pressure is the temporary blocking steering pressure. Stop the experiment and record the temporary blockage time.

[0030] The present invention also discloses a device for simulating the effect of temporary plugging of hydraulic cracks, which is applied in the experimental method for simulating the effect of temporary plugging of hydraulic cracks. The device includes a steel plate with cracks inside, and elastic fillers for dynamic changes in crack width are provided at the cracks.

[0031] Compared with the prior art, the present invention has the following beneficial effects:

[0032] Currently, there are no published documents or patents regarding experimental devices and methods for simulating the temporary plugging effect of hydraulic fractures, especially in the field of experimental devices that couple the simulation of single-wing fracture initiation, dynamic changes in hydraulic fracture width, and fracturing fluid loss in a wellbore. This invention proposes a method for simulating fracturing fluid loss under fracture permeability mode. Starting from simulating single-wing fracture initiation in a wellbore, it designs a method that considers the ratio of initial fracture width to proppant particle size and the influence of fracture permeability mode on fracturing fluid loss, achieving accurate simulation of the temporary plugging effect of hydraulic fractures and providing experimental means and design basis for optimizing fracture plugging parameters. The method simulates single-wing fracture initiation in a wellbore and calculates the ratio of initial fracture width to proppant particle size as follows: By simulating fracture permeability model fracturing fluid loss, the pump injection rate was determined. Experiments were conducted to simulate the effect of hydraulic fracture closure. The final simulation accurately demonstrated the effect of hydraulic fracture closure, providing guidance for the design of hydraulic fracture closure-to-fracturing in unconventional oil and gas development. Attached Figure Description

[0033] Figure 1 This is a schematic diagram of the steps of the method of the present invention;

[0034] Figure 2 This is a simulation diagram of the device for simulating the temporary plugging effect of hydraulic cracks according to the present invention;

[0035] Figure 3This is a simulation diagram of the effect of temporary plugging of hydraulic cracks in Example 1 provided in this manual;

[0036] Figure 4 This is a simulation diagram of the effect of temporary plugging of hydraulic cracks in Example 2 provided in this manual;

[0037] Figure 5 This is a simulation diagram of the effect of temporary plugging of hydraulic cracks in Example 3 provided in this manual. Detailed Implementation

[0038] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0039] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0040] The present invention will now be described in further detail with reference to the accompanying drawings:

[0041] An experimental method for simulating the temporary plugging effect of hydraulic fractures involves simulating single-wing fracture initiation at the wellbore and calculating the ratio of the initial fracture width to the proppant particle size. By simulating fracture permeability model fracturing fluid loss, the pump injection rate was determined. Experiments were conducted to simulate the effect of hydraulic fracture closure. The final simulation accurately demonstrated the effect of hydraulic fracture closure, providing guidance for the design of hydraulic fracture closure-to-fracturing in unconventional oil and gas development.

[0042] See Figure 1 This invention discloses an experimental method for simulating the temporary plugging effect of hydraulic cracks, comprising the following steps:

[0043] S1: Simulated hydraulic fracture initiation at the wellbore, dynamic changes in hydraulic fracture width, and fracturing fluid loss in experimental fracture permeability mode.

[0044] S2: Determine the experimental pump flow rate and conduct a hydraulic crack temporary plugging effect experiment under the experimental pump flow rate.

[0045] This invention proposes a method for simulating fracturing fluid loss under fracture permeability mode. Starting from simulating single-wing initiation of a hydraulic fracture in the wellbore, it designs a method considering the ratio of the initial fracture width to the proppant particle size and the influence of fracture permeability mode on fracturing fluid loss, achieving accurate simulation of the hydraulic fracture temporary plugging effect. This provides experimental means and design basis for optimizing fracture temporary plugging parameters. The method simulates single-wing initiation of a hydraulic fracture in the wellbore and calculates the ratio of the initial fracture width to the proppant particle size. By simulating fracture permeability model fracturing fluid loss, the pump injection rate was determined. Experiments were conducted to simulate the effect of hydraulic fracture closure. The final simulation accurately demonstrated the effect of hydraulic fracture closure, providing guidance for the design of hydraulic fracture closure-to-fracturing in unconventional oil and gas development.

[0046] In some embodiments, a single-wing fracture initiation is simulated at the wellbore, and the relationship between the fracture length and the wellbore diameter is as follows:

[0047]

[0048] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length.

[0049] In some embodiments, the ratio of the initial width of the hydraulic fracture to the proppant particle size is:

[0050]

[0051] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size is given by the coefficient.

[0052] In some embodiments, the dynamic variation of hydraulic fracture width is simulated by controlling the thickness of the elastic filler.

[0053] In some embodiments, the method for calculating the thickness of the elastic filler is as follows:

[0054]

[0055] in, The thickness of the elastic filler; The unit of length is 1m; Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0056] In some embodiments, fracturing fluid loss is simulated in an experimental fracture permeability model, with the initial permeability of the experimental fracture being:

[0057]

[0058] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment.

[0059] In some embodiments, the experimental pump flow rate is determined using the following method:

[0060]

[0061] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0062] In some embodiments, the experiment on the effect of temporary plugging of hydraulic fractures under experimental pump injection rate specifically includes:

[0063] S201: Based on the experimental pump discharge rate Inject a mixture of temporary plugging particles and carrier fluid with a mass fraction of W;

[0064] S202: Record the initial pumping pressure P_initial and the change of pumping pressure over time: P(t) ~ t;

[0065] S203: Change the mass concentration W of the temporary plugging particles, repeat the above steps, and record the cumulative injection time corresponding to different mass concentrations of temporary plugging particles.

[0066] In some embodiments, during S202, when the experimental pump pressure At this time, the pressure is the temporary blocking steering pressure. Stop the experiment and record the temporary blockage time.

[0067] In some embodiments, an experimental method for simulating the effect of temporary plugging of hydraulic fractures includes the following steps:

[0068] Step 1: Simulate single-wing fracture initiation at the wellbore, with the fracture length to wellbore diameter ratio as follows:

[0069]

[0070] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length.

[0071] Step 2: The ratio of the initial fracture width to the proppant particle size is:

[0072]

[0073] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size is given by the coefficient.

[0074] Step 3: The simulation method for the dynamic change of hydraulic fracture width is based on the control of elastic filler thickness. The calculation method for the elastic filler thickness is as follows:

[0075]

[0076] in, The thickness of the elastic filler; The unit of length is 1m; Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0077] Step 4: The fracturing fluid was filtered out using a simulated fracture permeability model. The initial permeability of the experimental fracture was:

[0078]

[0079] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment.

[0080] Step 5: Determine the experimental pump flow rate, the specific method is as follows:

[0081]

[0082] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid used in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0083] Step Six: Using the experimental pump displacement Inject a mixture of temporary plugging particles and carrier fluid with a mass fraction of W; record the initial pumping pressure Pinitial and the change of pumping pressure over time: P(t) ~ t.

[0084] Step 7: When the experimental pump pressure At this time, the pressure is the temporary blocking steering pressure. Stop the experiment and record the temporary blocking time. .

[0085] Step 8: Change the concentration W of the temporary plugging particles, repeat steps 5 to 8, and record the results. , , …the corresponding cumulative injection time , , …

[0086] See Figure 2 This is a simulation diagram of a device for simulating the temporary plugging effect of hydraulic fractures in an embodiment of the present invention. The device includes a steel plate 1 with a fracture 2 inside the plate 1. An elastic filler 3 is placed at the fracture 2 to facilitate dynamic changes in the fracture width. The device simulates the initiation of a single hydraulic fracture at the wellbore. The dynamic change in the hydraulic fracture width is simulated by controlling the thickness of the elastic filler. The fracturing fluid is filtered out through a simulated fracture permeability model, and the temporary plugging effect of the hydraulic fracture is tested using a pump injection rate.

[0087] Example 1:

[0088] The example is based on the specific well parameters of a certain oilfield, and the design simulates the initiation of a single-wing fracture in the hydraulic fracture at the wellbore.

[0089] (1) Design the wellbore diameter for the experiment =2mm, proppant is made of 70 / 140 mesh quartz sand;

[0090] (2) Experimental simulation of crack length 2.56m

[0091]

[0092] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length;

[0093] Calculation determined =0.00078;

[0094]

[0095] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size;

[0096] Crack width 1.5mm, proppant is quartz sand, determined by calculation. =10;

[0097] (3) Elastic filling material

[0098] in, The thickness of the elastic filler; It is a unit of length. Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0099] =15MPa, =23GPa, =1mm, =1m;

[0100] =1.65mm;

[0101] (4) Based on the permeability of the rock matrix in a certain oilfield =1mD, on-site crack height 75m, laboratory crack height 0.2m,

[0102] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment;

[0103] Laboratory simulated permeability =26.4D;

[0104] (5) Determine the pump flow rate for the experiment. The specific method is as follows:

[0105]

[0106] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid used in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0107] Experimental displacement =50ml / min, experimental fracturing fluid viscosity =0.3 mPa·s, viscosity of fracturing fluid in the field =60 mPa·s, experimental fracturing fluid density =252g / cm 3 density of fracturing fluid at the site =1.68g / cm 3 Corresponding on-site pumping discharge rate =4m 3 / min.

[0108] (6) A mixture of temporary plugging particles and carrier liquid with a mass fraction of W was injected into the pump with a pump displacement of Q. The initial pump pressure P_initial and the change of pump pressure over time were recorded.

[0109] See Figure 3 The figure shows a simulation of the hydraulic crack temporary plugging effect in this embodiment. It can be seen from the figure that the temporary plugging agent concentration is 0.07, the temporary plugging time is 0.3 h, and the temporary plugging pressure is 12 MPa; the temporary plugging agent concentration is 0.09, the temporary plugging time is 0.29 h, and the temporary plugging pressure is 13 MPa; the temporary plugging agent concentration is 0.11, the temporary plugging time is 0.27 h, and the temporary plugging pressure is 14.5 MPa; the temporary plugging agent concentration is 0.13, the temporary plugging time is 0.25 h, and the temporary plugging pressure is 16 MPa; and the temporary plugging agent concentration is 0.15, the temporary plugging time is 0.25 h, and the temporary plugging pressure is 16 MPa.

[0110] Example 2:

[0111] (1) Design the wellbore diameter for the experiment =2mm, proppant is made of 70 / 140 mesh quartz sand;

[0112] (2) Experimental simulation of crack length 2.56m

[0113]

[0114] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length;

[0115] Calculation determined =0.00078;

[0116]

[0117] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size;

[0118] Crack width 1.25mm, proppant is quartz sand, determined by calculation. =8.3;

[0119] (3) Elastic filling material

[0120]

[0121] in, The thickness of the elastic filler; It is a unit of length. Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0122] =15MPa, =23GPa, =1mm, =1m;

[0123] =1.70mm;

[0124] (4) Based on the permeability of the rock matrix in a certain oilfield =1mD, on-site crack height 75m, laboratory crack height 0.2m,

[0125] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment;

[0126] Laboratory simulated permeability =26.4D;

[0127] (5) Determine the pump flow rate for the experiment. The specific method is as follows:

[0128]

[0129] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid used in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0130] Experimental displacement =62.5 ml / min, experimental fracturing fluid viscosity =0.3 mPa·s, viscosity of fracturing fluid in the field =60 mPa·s, experimental fracturing fluid density =252g / cm 3 density of fracturing fluid at the site =1.68g / cm 3 Corresponding on-site pumping discharge rate =5m 3 / min.

[0131] (6) A mixture of temporary plugging particles and carrier liquid with a mass fraction of W was injected into the pump with a pump displacement of Q. The initial pump pressure P_initial and the change of pump pressure over time were recorded.

[0132] See Figure 4 The figure shows a simulation of the hydraulic crack temporary plugging effect in this embodiment. It can be seen from the figure that the temporary plugging agent concentration is 0.07, the temporary plugging time is 0.29 h, and the temporary plugging pressure is 13 MPa; the temporary plugging agent concentration is 0.09, the temporary plugging time is 0.27 h, and the temporary plugging pressure is 14 MPa; the temporary plugging agent concentration is 0.11, the temporary plugging time is 0.25 h, and the temporary plugging pressure is 15 MPa; the temporary plugging agent concentration is 0.13, the temporary plugging time is 0.22 h, and the temporary plugging pressure is 16 MPa; and the temporary plugging agent concentration is 0.15, the temporary plugging time is 0.2 h, and the temporary plugging pressure is 16.5 MPa.

[0133] Example 3:

[0134] (1) Design the wellbore diameter for the experiment =2mm, proppant is made of 70 / 140 mesh quartz sand;

[0135] (2) Experimental simulation of crack length 2.56m

[0136]

[0137] in, The diameter of the wellbore. For the length of the seam, This is the ratio coefficient between the wellbore diameter and the hydraulic fracture length;

[0138] Calculation determined =0.00078;

[0139]

[0140] in, This represents the initial width of the hydraulic fracture. For proppant particle size; The ratio of the initial crack width to the proppant particle size;

[0141] Crack width 1.75mm, proppant is quartz sand, determined by calculation. =11.67;

[0142] (3) Elastic filling material

[0143]

[0144] in, The thickness of the elastic filler; It is a unit of length. Young's modulus of the reservoir rock; The thickness of the elastic filler after compaction.

[0145] =13MPa, =23GPa, =1.2mm, =1m. =1.76mm;

[0146] (4) Based on the permeability of the rock matrix in a certain oilfield =1mD, on-site crack height 75m, laboratory crack height 0.2m,

[0147] in, To simulate permeability in experiments; Permeability of the rock matrix; The length of the hydraulic crack; The height of the hydraulic crack; To simulate the crack length in the experiment; To simulate the crack height in the experiment;

[0148] Laboratory simulated permeability =26.4D;

[0149] (5) Determine the pump flow rate for the experiment. The specific method is as follows:

[0150]

[0151] in, The pump displacement was determined during the experiment. The viscosity of the experimental fracturing fluid; This refers to the density of the fracturing fluid used in the field. For on-site pumping discharge; This refers to the viscosity of the fracturing fluid used in the field. The density of the fracturing fluid was determined in the experiment.

[0152] Experimental displacement =43.75 ml / min, experimental fracturing fluid viscosity =0.3 mPa·s, viscosity of fracturing fluid in the field =60 mPa·s, experimental fracturing fluid density =252g / cm 3 density of fracturing fluid at the site =1.68g / cm 3 Corresponding on-site pumping discharge rate =5m 3 / min.

[0153] (6) A mixture of temporary plugging particles and carrier liquid with a mass fraction of W was injected into the pump with a pump displacement of Q. The initial pump pressure P_initial and the change of pump pressure over time were recorded.

[0154] See Figure 5 The figure shows a simulation of the hydraulic crack temporary plugging effect in this embodiment. It can be seen from the figure that the temporary plugging agent concentration is 0.07, the temporary plugging time is 0.32 h, and the temporary plugging pressure is 11.5 MPa; the temporary plugging agent concentration is 0.09, the temporary plugging time is 0.29 h, and the temporary plugging pressure is 12.5 MPa; the temporary plugging agent concentration is 0.11, the temporary plugging time is 0.26 h, and the temporary plugging pressure is 14 MPa; the temporary plugging agent concentration is 0.13, the temporary plugging time is 0.24 h, and the temporary plugging pressure is 15 MPa; and the temporary plugging agent concentration is 0.15, the temporary plugging time is 0.23 h, and the temporary plugging pressure is 15.5 MPa.

[0155] The above content is only for illustrating the technical concept of the present invention and should not be construed as limiting the scope of protection of the present invention. Any modifications made to the technical solution based on the technical concept proposed in this invention shall fall within the scope of protection of the claims of this invention.

Claims

1. An experimental method for simulating the temporary plugging effect of hydraulic fractures, characterized in that, Comprise the following steps: S1: simulate the hydraulic fracture single wing crack initiation at the wellbore; S2: simulate the dynamic change of the hydraulic fracture width; the dynamic change of the hydraulic fracture width is simulated by the elastic filler thickness control; the elastic filler thickness calculation method is: S3: simulate the experimental fracture permeability mode fracturing fluid loss; The initial permeability of the experimental fracture is: S4: determine the experimental pump displacement, and perform a hydraulic fracture temporary plugging effect experiment under the experimental pump displacement; the specific method for determining the experimental pump displacement is: wherein, is the elastic filler thickness; is the length unit dimension; is the reservoir rock Young's modulus; is the elastic filler thickness after compaction; is the experimental simulated permeability; is the rock matrix permeability; is the hydraulic fracture length; is the hydraulic fracture height; is the experimental simulated fracture length; is the experimental simulated fracture height; is the experimental pump rate; is the experimental fracturing fluid viscosity; is the field fracturing fluid density; is the field pump rate; is the field fracturing fluid viscosity; is the experimental fracturing fluid density.

2. The experimental method for simulating the effect of temporary plugging of hydraulic fractures according to claim 1, characterized in that, The relationship between the simulated hydraulic fracture single wing crack initiation at the wellbore and the wellbore diameter is: wherein, is the wellbore diameter, is the fracture length, is the wellbore diameter to hydraulic fracture length ratio factor.

3. The experimental method for simulating the effect of temporary plugging of hydraulic fractures according to claim 1, characterized in that, The ratio of the initial hydraulic fracture width to the proppant particle size is: wherein, is the initial fracture width of the hydraulic fracture; is the proppant particle size; is the ratio coefficient of the initial fracture width of the hydraulic fracture and the proppant particle size.

4. The experimental method for simulating the effect of temporary plugging of hydraulic fractures according to claim 1, characterized in that, The hydraulic fracture temporary plugging effect experiment under the experimental pump displacement specifically comprises: S401: with experimental pump injection displacement Inject the mixture of temporary plugging particles with a mass fraction of W and carrying fluid; S402: record the initial pump pressure Pinitial and the pump pressure change with time: P(t)~t; S403: change the temporary plugging particle mass concentration W, repeat the above steps, and record the cumulative injection time corresponding to different temporary plugging particle mass concentrations.

5. The experimental method for simulating the effect of temporary plugging of hydraulic fractures according to claim 4, characterized in that, S402, when the experimental pump injection pressure is the temporary plugging diversion pressure , stop the experiment, and record the temporary plugging time.

6. The experimental method for simulating the effect of temporary plugging of hydraulic fractures according to claim 1, characterized in that, A device for simulating the hydraulic fracture temporary plugging effect is adopted, the device comprises a steel plate (1), a crack (2) is formed in the steel plate (1), and an elastic filler (3) for the dynamic change of the crack (2) width is arranged at the crack (2).

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