Fracturing fracture network efficient regulation and evaluation method based on real-time liquid absorption profile

Abstract

The present application relates to the technical field of shale gas reservoir stimulation, and specifically discloses a high-efficiency regulation and evaluation method for fracture network based on real-time liquid absorption profile, which comprises the following steps: segmenting a target well based on the geological conditions and gas well parameters of a shale gas reservoir, and determining the number of fractures in the fractured well segment; detecting the liquid absorption profile of each fracture in real time during the fracturing process, and judging the fracture propagation condition according to the real-time liquid absorption profile; adjusting the threshold value of the dominant development fracture in real time according to the fracture propagation condition, and determining the number of dominant development fractures; determining the number of temporary blocking balls for staged balling in the temporary blocking and directional fracturing stage according to the number of dominant development fractures, and the number of temporary blocking balls used in each stage of balling, and evaluating the fracturing effect at each temporary blocking stage. The present application can realize real-time and accurate regulation and control of the underdeveloped fracture network.

Description

Technical Field

[0001] This invention relates to the field of shale gas reservoir production enhancement technology, and more specifically, to a method for efficient control and evaluation of fracture networks based on real-time liquid absorption profiles. Background Technology

[0002] The low porosity and low permeability of shale gas reservoirs necessitate reservoir stimulation measures to obtain industrial oil and gas flow. Hydraulic fracturing, as an efficient reservoir stimulation method, has been widely used in vertical well fracturing, horizontal well fracturing, highly deviated well fracturing, fracturing of extremely thick vertical wells, and repeated fracturing of various old wells, achieving good reservoir stimulation results.

[0003] Due to the heterogeneity of bedding and mineral distribution within shale gas reservoirs, as well as the influence of initial fractures at the wellhead, the mechanical properties of the target formation vary significantly in different directions. This significantly increases the complexity and difficulty of predicting the fracture propagation process in hydraulic fracturing. Consequently, the propagation length of fractures varies significantly in different layers and directions. Problems such as high degree of unstable fracture propagation, severe single fracture intrusion, low fracturing fluid efficiency, and small fracture network swept volume have become the focus of issues affecting the effectiveness of hydraulic fracturing.

[0004] Therefore, efficient control of the hydraulic fracture network in shale gas reservoirs is a key factor in improving the current unstable fracture propagation, improving the underground flow environment of shale gas, and ensuring gas well productivity. Currently, the main method for controlling the hydraulic fracture network both domestically and internationally is temporary plugging fracturing. Traditional temporary plugging methods involve placing a corresponding number of plugging balls or plugging agents based on the number of perforations or the volume of fractures to be plugged. This can improve the propagation of underdeveloped fractures to some extent and promote their further expansion. However, the control of the fracture network by traditional temporary plugging methods is general, imprecise, and lacks timeliness. Some "dominant fractures" become underdeveloped fractures after control. How to achieve real-time, efficient, and precise control of the hydraulic fracture network remains a major technical challenge in the oil and gas field development field. Summary of the Invention

[0005] The technical problem to be solved by the present invention is to provide a method for efficient control and evaluation of fracturing network based on real-time liquid absorption profile; and to achieve real-time and precise control of underdeveloped fracturing network.

[0006] The solution adopted by this invention to solve the technical problem is:

[0007] This invention discloses an efficient control and evaluation method for fracture networks based on real-time fluid absorption profiles. The method involves segmenting the target well based on shale gas reservoir geological conditions and well parameters to determine the number of fractures in the fractured section; real-time monitoring of the fluid absorption profile of each fracture during fracturing to determine fracture propagation; real-time adjustment of the dominant fracture threshold based on fracture propagation to determine the number of dominant fractures; and determination of the number of plugging balls used in each stage of the temporary plugging-to-fracturing phase, based on the number of dominant fractures. The method also evaluates the fracturing effect at each stage of temporary plugging.

[0008] In some possible implementations,

[0009] Specifically, the following steps are included:

[0010] Step S1: Obtain geological information of the shale gas reservoir. Obtain the reservoir stress profile distribution through Young's modulus, Poisson's ratio, well logging interpretation, and geostress interpretation of the fractured section; determine the number of fractures n and fracture propagation length within the target section. ;

[0011] Step S2: Physically seal the target layer and perform perforation according to the preset crack orientation and number of cracks in the designed layer;

[0012] Step S3: Initiate fracturing at the perforation location corresponding to the target layer, and open multiple fractures; monitor the fluid absorption profile of each fracture. Calculate the relative water absorption of a single crack. Determine the length of each crack. ;

[0013] Step S4: Based on the Lorentz curve and the relative water absorption of a single crack, determine the coefficient of variation of crack propagation length, and determine the curve expression corresponding to different coefficients of variation of crack propagation length;

[0014] Step S5: Determine the fracturing fracture propagation effect based on the real-time fluid absorption profile and the coefficient of variation of fracture propagation length. At the same time, determine the number of dominant propagating fractures s and the amount of temporary plugging balls Q, and carry out temporary plugging volume fracturing using a staged ball dropping method.

[0015] In some possible implementations,

[0016] In step S5, a tiered ball-throwing method is used to carry out temporary plugging volume fracturing, specifically a three-stage ball-throwing method.

[0017] In some possible implementations,

[0018] Temporary plugging volumetric fracturing using a three-stage ball-dropping method includes the following steps:

[0019] During the first-stage temporary plugging fracturing, a temporary plugging ball is inserted. After the fracture is opened, acid is pumped in to dissolve the temporary plugging ball in the fracturing fluid. Steps S3-S4 are repeated to evaluate the fracturing propagation effect.

[0020] During secondary temporary plugging fracturing, a temporary plug is put in. After the fracture is opened, acid is pumped in to dissolve the temporary plug ball in the fracturing fluid. Repeat steps S3-S4 above to evaluate the fracturing propagation effect.

[0021] During stage 3 temporary plugging fracturing, a temporary plugging ball is inserted. After the fracture is opened, acid is pumped in to unplug the ball. Repeat steps S3-S4 above to evaluate the fracturing propagation effect.

[0022] Fracturing completed.

[0023] In some possible implementations,

[0024] During primary temporary plugging fracturing, the number of plugging balls deployed is 1 / 4 s.

[0025] During secondary temporary plugging fracturing, 2 / 4 of a plugging ball is used;

[0026] During the third-stage temporary plugging fracturing, 3 / 4 of a plugging ball is inserted.

[0027] In some possible implementations,

[0028] In step S3, the relative water absorption of a single crack is calculated. Specifically, it refers to:

[0029] (1);

[0030] in This refers to the j-th fracturing fracture in the i-th target layer segment;

[0031] Let be the cumulative liquid absorption of the j-th crack.

[0032] In some possible implementations,

[0033] Step S4 specifically refers to:

[0034] Step S41: Define the Gini coefficient based on the Lorenz curve. :

[0035] (2),

[0036] Where y represents the cumulative relative water absorption of a single crack;

[0037] x represents the cumulative relative number of cracks;

[0038] Step S42: Obtain the cumulative liquid absorption of the fracture using the real-time monitored fracture liquid absorption profile. And calculate the amount of liquid absorbed. Ratio to total injected volume ;

[0039] Step S43: Arrange the ratios of aspirated volume to total injected volume in ascending order to obtain n sets of ratios of aspirated volume to total injected volume;

[0040] Step S44: Calculate the cumulative relative number of cracks and the cumulative relative water absorption of a single crack Lorentz curves were obtained to evaluate the heterogeneity of the propagation length of a single crack;

[0041] (3);

[0042] (4);

[0043] Step S45: Calculate the expression for the coefficient of variation of different crack propagation lengths;

[0044] (5);

[0045] in, is the coefficient of variation of crack propagation length.

[0046] In some possible implementations,

[0047] The physical sealing in step S2 specifically refers to: installing packers at both ends of the designed fracturing section to physically seal the target layer.

[0048] In some possible implementations,

[0049] In step S3, fracturing is initiated at the perforation location corresponding to the target layer, and multiple fractures are forced open. Specifically, this means:

[0050] After perforation, high-pressure fracturing fluid is pumped into the target layer by the ground fracturing truck team, and fracturing is initiated at the corresponding perforation position in the target layer, opening up multiple fractures.

[0051] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0052] This invention monitors the liquid absorption profile of cracks in real time and takes advantage of the large liquid absorption and high liquid flow velocity of the crack opening in the dominant expansion crack. After the ball is thrown, the temporary plugging ball will intelligently select the dominant expansion crack for plugging. The multi-stage ball throwing can adjust the crack to be plugged in a timely manner according to the liquid absorption profile of the crack, so that the optimal plugging can be formed after each ball throwing, fully expanding the underdeveloped crack and avoiding the formation of underdeveloped cracks after the dominant crack is plugged.

[0053] This invention presents a fracture propagation evaluation method based on the Lorentz curve. It can quantitatively characterize the heterogeneity of fracture length propagation based on the real-time fluid absorption profile of the fracture, evaluate the fracturing effect through the fracture propagation variation coefficient, and intelligently seal dominant propagating fractures by combining staged ball dropping technology. After adjustment, the method is used for evaluation. By comparing the Gini coefficient of fracture propagation at different stages, it provides a strong basis for evaluating hydraulic fracturing measures. Attached Figure Description

[0054] Figure 1 This is a flowchart of the process of the present invention;

[0055] Figure 2 A schematic diagram of the Lorentz curve;

[0056] Figure 3 The Lorentz curve before temporary closure using the traditional method;

[0057] Figure 4 The Lorentz curve after temporary closure using the traditional method;

[0058] Figure 5 The Lorentz curve before temporary clogging in this invention;

[0059] Figure 6 This is the Lorentz curve after the first-stage temporary plugging fracturing in this invention;

[0060] Figure 7 The Lorentz curve after secondary temporary plugging fracturing in this invention;

[0061] Figure 8 The Lorentz curve after three-stage temporary plugging fracturing in this invention; Detailed Implementation

[0062] The present invention will now be described in detail.

[0063] This invention discloses an efficient control and evaluation method for fracture networks based on real-time fluid absorption profiles. The method involves segmenting the target well based on shale gas reservoir geological conditions and well parameters to determine the number of fractures in the fractured section; real-time monitoring of the fluid absorption profile of each fracture during fracturing to determine fracture propagation; real-time adjustment of the dominant fracture threshold based on fracture propagation to determine the number of dominant fractures; and determination of the number of plugging balls used in each stage of the temporary plugging-to-fracturing phase, based on the number of dominant fractures. The method also evaluates the fracturing effect at each stage of temporary plugging.

[0064] In some possible implementations,

[0065] Specifically, the following steps are included:

[0066] Step S1: Obtain geological information of shale gas reservoirs. Obtain reservoir stress profile distribution by using Young's modulus, Poisson's ratio, well logging interpretation, and geostress interpretation of the fracturing section.

[0067] Based on geostress interpretation and well logging interpretation, the number of fractures n and fracture propagation length within the target formation are determined. ;

[0068] Step S2: Install packers at both ends of the designed fracturing section to physically seal the target section, and perform perforation according to the preset fracture orientation and number of fractures in the designed section.

[0069] Step S3: After perforation, high-pressure fracturing fluid is pumped into the target section by the surface fracturing truck team. Fracturing is initiated at the corresponding perforation location in the target section, creating multiple fractures; the fluid absorption profile of each fracture is monitored. Calculate the relative water absorption of a single crack. Determine the length of each crack. ;

[0070] In step S3, the relative water absorption of a single crack is calculated. Specifically, it refers to:

[0071] (1);

[0072] in This refers to the j-th fracturing fracture in the i-th target layer segment;

[0073] Let be the cumulative liquid absorption of the j-th crack.

[0074] Step S4: Based on the Lorentz curve and the relative water absorption of a single crack, determine the coefficient of variation of crack propagation length, and determine the curve expression corresponding to different coefficients of variation of crack propagation length;

[0075] In this invention, the Lorentz curve is used to evaluate the non-uniformity of reservoir fracture propagation, and the coefficient of variation of different fracture propagation lengths is used to evaluate the magnitude of the degree of non-uniform fracture propagation.

[0076] Step S4 specifically refers to:

[0077] Step S41: Based on the Lorenz curve, which was proposed by the American statistician Lorenz and initially used to study the distribution of national income among the population, if the distribution is uniform, the curve is a straight line with a slope of 45°. Figure 2 The diagonal AC is called a "perfectly uniform line"; when the distribution of all national income is concentrated at a single point, the curve is a broken line. Figure 2A broken-line ADC is called a "completely non-uniform line"; the Lorentz curve in general is between these two cases, and is in the form of an "upward convex" curve. Figure 2 The Gini coefficient is defined as the Gini curve (AEC). :

[0078] (2),

[0079] Where y represents the cumulative relative water absorption of a single crack;

[0080] x represents the cumulative relative number of cracks;

[0081] Step S42: Obtain the cumulative liquid absorption of the fracture using the real-time monitored fracture liquid absorption profile. And calculate the amount of liquid absorbed. Ratio to total injected volume ;

[0082] Step S43: Arrange the ratios of aspirated volume to total injected volume in ascending order to obtain n sets of ratios of aspirated volume to total injected volume;

[0083] Step S44: Calculate the cumulative relative number of cracks and the cumulative relative water absorption of a single crack Lorentz curves were obtained to evaluate the heterogeneity of the propagation length of a single crack;

[0084] (3);

[0085] (4);

[0086] Step S45: Calculate the coefficient of variation for different crack propagation lengths. The expression;

[0087] (5);

[0088] in, is the coefficient of variation of crack propagation length.

[0089] Step S5: Determine the fracturing fracture propagation effect based on the real-time fluid absorption profile and the coefficient of variation of fracture propagation length. At the same time, determine the number of dominant propagating fractures s and the amount of temporary plugging balls Q. Use a staged ball dropping method to carry out temporary plugging volume fracturing.

[0090] In step S5, a graded ball-dropping method is used to carry out temporary plugging volume fracturing, specifically a three-stage ball-dropping method is used to carry out temporary plugging volume fracturing.

[0091] The three-stage ball-throwing method for temporary plugging volumetric fracturing includes the following steps:

[0092] During the first-stage temporary plugging fracturing, 1 / 4 s of a plugging ball is inserted. After the fracture is opened, acid is pumped in to dissolve the plugging ball in the fracturing fluid. This restores the shale gas production channel and prevents formation damage. Steps S3-S4 are repeated to evaluate the fracturing propagation effect. Then, the second-stage temporary plugging fracturing is carried out.

[0093] During the second-stage temporary plugging fracturing, 2 / 4 of a plugging ball is inserted. After the fracture is opened, acid is pumped in to dissolve the plugging ball in the fracturing fluid. Steps S3-S4 are repeated to evaluate the fracturing propagation effect. Then, the third-stage temporary plugging fracturing is performed.

[0094] During the third-stage temporary plugging fracturing, 3 / 4s of temporary plugging balls are inserted. After the fracture is opened, acid is pumped in to unplug the plugging. Repeat steps S3-S4 above to evaluate the fracturing propagation effect.

[0095] Fracturing completed.

[0096] Compared with existing technologies, this invention achieves intelligent and efficient sealing of dominant propagating fractures through multi-stage ball-dropping temporary plugging fracturing, and realizes efficient control of the fracture network; by calculating and comparing the relative water absorption of a single fracture and the coefficient of variation of fracture propagation length, it achieves quantitative characterization of fracture propagation length and fracture propagation heterogeneity.

[0097] This invention monitors the liquid absorption profile of cracks in real time and takes advantage of the large liquid absorption and high liquid flow velocity of the crack opening in the dominant expansion crack. After the ball is thrown, the temporary plugging ball will intelligently select the dominant expansion crack for plugging. The multi-stage ball throwing can adjust the crack to be plugged in a timely manner according to the liquid absorption profile of the crack, so that the optimal plugging can be formed after each ball throwing, fully expanding the underdeveloped crack and avoiding the formation of underdeveloped cracks after the dominant crack is plugged.

[0098] This invention presents a fracture propagation evaluation method based on the Lorentz curve. This method can quantitatively characterize the heterogeneity of fracture length propagation based on the real-time fluid absorption profile of the fracture, evaluate the fracturing effect through the coefficient of variation of fracture propagation, and intelligently seal dominant propagating fractures by combining staged ball dropping technology. After adjustment, the method is used for evaluation. By comparing the Gini coefficient of fracture propagation at different stages, it provides a strong basis for evaluating hydraulic fracturing measures.

[0099] Example:

[0100] This embodiment includes two experimental zones. Experimental zone one serves as a comparative example, where conventional temporary plugging fracturing is used to modify the reservoir. Figure 3 For the traditional method of temporarily blocking the Lorentz curve, Figure 4 The image shows the Lorentz curve after temporary plugging using traditional methods; Experimental zone two, as an embodiment of this invention, utilizes the efficient control and evaluation method of the hydraulic fracturing network provided by this invention to modify the reservoir. Figure 5 To utilize the Lorentz curve before temporary clogging of this invention, Figure 6 To achieve the Lorentz curve after the first-stage temporary closure of this invention, Figure 7 To achieve the Lorentz curve after the second-stage temporary closure of this invention, Figure 8 To compare the fracturing effects of two experimental blocks using the Lorentz curve after the three-stage temporary plugging of this invention;

[0101] It should be noted that, Figures 3-8 The horizontal axis represents the cumulative relative number of cracks; the vertical axis represents the cumulative relative water absorption of a single crack.

[0102] Experimental Zone 1: The reservoir consists of black and grayish-black shale. The fractured well depth is 4887-4826m, with an effective fracture thickness of 61m. Based on logging, well logging interpretation, and sub-layer division results, sections with similar physical properties and minor stress differences are grouped together. For reservoirs with poor physical properties, the section length is appropriately reduced to increase stress interference. A total of 20 fracturing sections are designed, with a total of 42 wells per section and a designed flow rate of 14 m³ / min. Taking the 10th fracturing section as an example, the fluid absorption profile data of each fracture after the first fracturing operation are shown in Table 1.

[0103]

[0104] Table 1. Water absorption profile of fractures before temporary plugging fracturing using traditional methods.

[0105] The Gini coefficient for irregular propagation of a single fracture before temporary plugging fracturing using the traditional temporary plugging method is 0.5109.

[0106] like Figure 3 As shown, before the use of temporary plugging agent in experimental block 1, the Gini coefficient for uneven fracture propagation was 0.5109, which is relatively high, indicating a significant degree of uneven fracture propagation. Therefore, temporary plugging balls were deployed for temporary plugging and redirection fracturing to improve the uneven fracture propagation. Based on fracturing experience, half the number of temporary plugging balls were deployed, totaling 21 balls. Temporary plugging fracturing began after the balls were deployed. After fracturing, the well was opened for production after the temporary plugging balls had naturally dissolved in the fracturing fluid. The fracture water absorption profile data for this stage are shown in Table 2.

[0107]

[0108] Table 2 Water Absorption Profile of Fractures After Temporary Plugging Fracturing Using Traditional Methods

[0109] The Gini coefficient for irregular propagation of a single fracture after temporary plugging fracturing using the traditional method is 0.4659.

[0110] like Figure 3 , Figure 4As shown, comparing the area enclosed by the Lorentz curve and the standard line of the irregular propagation of a single fracture before and after temporary plugging fracturing, the reduction is not significant. However, the Gini coefficient decreases significantly after temporary plugging fracturing, indicating that the development of underdeveloped fractures has been improved to some extent. However, the degree of uneven fracture propagation is still strong. After temporary plugging fracturing, the relative fluid absorption of some relatively developed fractures decreases, becoming relatively underdeveloped fractures.

[0111] Experimental Zone 2: The reservoir consists of black and grayish-black shale. The fractured well depth is 4887-4826m, with an effective fracture thickness of 61m. Based on logging, well logging interpretation, and sub-layer division results, sections with similar physical properties and minor stress differences are grouped together. For reservoirs with poor physical properties, the section length is appropriately reduced to increase stress interference. A total of 20 fracturing sections are designed, with a total of 42 wells per section and a designed flow rate of 14m³ / min. Taking the 11th fracturing section as an example, Table 3 shows the fluid absorption profile data of each fracture after the first fracturing operation.

[0112]

[0113] Table 3 Water absorption profile of fractures before temporary plugging fracturing

[0114] like Figure 5 As shown, in Experimental Zone 2, before the use of temporary plugging agent, the Gini coefficient for uneven fracture propagation was 0.5068, which was relatively high, indicating a significant degree of uneven fracture propagation. Therefore, temporary plugging balls were deployed for temporary plugging and redirection fracturing to improve the uneven fracture propagation. Based on the multi-stage ball-dropping temporary plugging fracturing method provided by this invention, and based on real-time water absorption profiles and fracturing experience, the number of dominant propagating fractures was determined to be 27. Simultaneously, the number of balls deployed for the first-stage temporary plugging fracturing was determined to be 9, for the second-stage to be 18, and for the third-stage to be 27. After ball deployment, temporary plugging fracturing began. After each stage of temporary plugging fracturing was completed, a certain volume of unplugging agent was pumped in to rapidly dissolve the temporary plugging balls, allowing for the next stage of temporary plugging fracturing, until the third stage of temporary plugging fracturing was completed as planned. After dissolving the temporary plugging balls, normal production commenced. The fracture water absorption profile data after the first-stage temporary plugging fracturing based on the initial fluid absorption profile are shown in Table 4.

[0115]

[0116] Table 4 Water absorption profile of fractures after primary temporary plugging fracturing.

[0117] like Figure 6 As shown, the Gini coefficient for uneven fracture propagation after primary temporary plugging fracturing is 0.4188. Table 5 shows the fracture water absorption profile data after secondary temporary plugging fracturing, based on the fluid absorption profile of primary temporary plugging fracturing.

[0118]

[0119] Table 5 Water absorption profile of fractures after secondary temporary plugging fracturing.

[0120] like Figure 7 As shown, the Gini coefficient for uneven fracture propagation after secondary temporary plugging fracturing is 0.366. Table 6 shows the fracture water absorption profile data after tertiary temporary plugging fracturing, based on the fluid absorption profile of the secondary temporary plugging fracturing.

[0121]

[0122] Table 6 Water absorption profile of fractures after stage III temporary plugging fracturing.

[0123] like Figures 5-8 As shown, the Gini coefficient for uneven fracture propagation after three-stage temporary plugging fracturing is 0.2956. After staged ball-drop temporary plugging fracturing, the area enclosed by the Lorentz curve of the single fracture propagation length and the standard line is significantly reduced. After each stage of ball-drop temporary plugging fracturing, the Gini coefficients for uneven fracture propagation are 0.5068, 0.4188, 0.366, and 0.2956, respectively. The Gini coefficient is significantly reduced, the heterogeneity of each fracture extension length is reduced, and the probability of successfully fracturing a complex volumetric fracture network within the target layer is higher. The gas production after two-stage fracturing is as follows: the production of the fracturing stage using the method of this invention is twice that of the fracturing stage using the traditional method. Under the condition that the amount of fracturing fluid used is basically the same, the fracturing effect of multi-stage temporary plugging volume fracturing based on real-time fluid absorption profile is better. In addition, the fracture propagation evaluation method based on real-time fluid absorption profile in this invention can also intuitively, quantitatively and accurately evaluate the underground fracture propagation, which can better guide the adjustment of the fracture network of shale gas reservoirs and lay a good foundation for increasing the production and efficiency of shale gas reservoirs.

[0124] This invention is not limited to the specific embodiments described above. The invention extends to any new feature or combination disclosed in this specification, as well as any new method or process step or combination disclosed herein.

Claims

1. A method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles, characterized in that, Based on the geological conditions of the shale gas reservoir and the parameters of the gas well, the target well is segmented to determine the number of fractures in the fracturing section; during the fracturing process, the fluid absorption profile of each fracture is monitored in real time, and the fracture propagation is judged based on the real-time fluid absorption profile; the threshold of the dominant fracture is adjusted in real time according to the fracture propagation to determine the number of dominant fractures; based on the number of dominant fractures, the number of temporary plugging balls deployed in the stage of temporary plugging and diversion fracturing is determined, as well as the number of temporary plugging balls used in each stage, and the fracturing effect is evaluated at each stage of temporary plugging; Specifically, the following steps are included: Step S1: Obtain geological information of the shale gas reservoir. Obtain the reservoir stress profile distribution through Young's modulus, Poisson's ratio, well logging interpretation, and geostress interpretation of the fractured section; determine the number of fractures n and fracture propagation length within the target section. ; Step S2: Physically seal the target layer and perform perforation according to the preset crack orientation and number of cracks in the designed layer; Step S3: Initiate fracturing at the perforation location corresponding to the target layer, and open multiple fractures; monitor the fluid absorption profile of each fracture. Calculate the relative water absorption of a single crack. Determine the length of each crack. ; Calculate the relative water absorption of a single crack. Specifically, it refers to: （1）； in This refers to the j-th fracturing fracture in the i-th target layer segment; Let be the cumulative liquid absorption of the j-th crack; Step S4: Based on the Lorentz curve and the relative water absorption of a single crack, determine the coefficient of variation of crack propagation length, and determine the curve expression corresponding to different coefficients of variation of crack propagation length; specifically, this means: Step S41: Define the Gini coefficient based on the Lorenz curve. : （2）， Where y represents the cumulative relative water absorption of a single crack; x represents the cumulative relative number of cracks; Step S42: Obtain the cumulative liquid absorption of the fracture using the real-time monitored fracture liquid absorption profile. And calculate the amount of liquid absorbed. Ratio to total injected volume ; Step S43: Arrange the ratios of aspirated volume to total injected volume in ascending order to obtain n sets of ratios of aspirated volume to total injected volume; Step S44: Calculate the cumulative relative number of cracks and the cumulative relative water absorption of a single crack Lorentz curves were obtained to evaluate the heterogeneity of the propagation length of a single crack; （3）； （4）； Step S45: Calculate the expression for the coefficient of variation of different crack propagation lengths; （5）; in, The coefficient of variation for crack propagation length; Step S5: Determine the fracturing fracture propagation effect based on the real-time fluid absorption profile and the coefficient of variation of fracture propagation length. At the same time, determine the number of dominant propagating fractures s and the amount of temporary plugging balls Q, and carry out temporary plugging volume fracturing using a staged ball dropping method.

2. The method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles according to claim 1, characterized in that, In step S5, a tiered ball-throwing method is used to carry out temporary plugging volume fracturing, specifically a three-stage ball-throwing method.

3. The method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles according to claim 2, characterized in that, Temporary plugging volumetric fracturing using a three-stage ball-dropping method includes the following steps: During the first-stage temporary plugging fracturing, a temporary plugging ball is inserted. After the fracture is opened, acid is pumped in to dissolve the temporary plugging ball in the fracturing fluid. Steps S3-S4 are repeated to evaluate the fracturing propagation effect. During secondary temporary plugging fracturing, a temporary plug is put in. After the fracture is opened, acid is pumped in to dissolve the temporary plug ball in the fracturing fluid. Repeat steps S3-S4 above to evaluate the fracturing propagation effect. During stage 3 temporary plugging fracturing, a temporary plugging ball is inserted. After the fracture is opened, acid is pumped in to unplug the ball. Repeat steps S3-S4 above to evaluate the fracturing propagation effect. Fracturing completed.

4. The method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles according to claim 2, characterized in that, During primary temporary plugging fracturing, the number of plugging balls deployed is 1 / 4 s. During secondary temporary plugging fracturing, 2 / 4 of a plugging ball is used; During the third-stage temporary plugging fracturing, 3 / 4 of a plugging ball is inserted.

5. The method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles according to claim 1, characterized in that, The physical sealing in step S2 specifically refers to: installing packers at both ends of the designed fracturing section to physically seal the target layer.

6. The method for efficient control and evaluation of fracturing networks based on real-time liquid absorption profiles according to claim 1, characterized in that, In step S3, fracturing is initiated at the perforation location corresponding to the target layer, and multiple fractures are forced open. Specifically, this means: After perforation, high-pressure fracturing fluid is pumped into the target layer by the ground fracturing truck team, and fracturing is initiated at the corresponding perforation position in the target layer, opening up multiple fractures.

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