Method for quantifying inter-well interference intensity of shale oil horizontal well based on physical model

Abstract

The invention provides a shale oil horizontal well inter-well interference intensity quantification method based on a physical model. The shale oil horizontal well inter-well interference intensity quantification method comprises the steps that 1, a large-scale three-shaft physical model rock core and a standard-size rock core are prepared; 2, testing the initial permeability of the standard-size rock core; 3, adjusting experimental parameters, and carrying out multi-well three-dimensional fracturing physical model experiments in groups; 4, drilling a fractured physical model standard diameter rock core, and cutting a sample and manufacturing a standard sample; 5, testing the permeability of the core with the standard size after fracturing; step 6, forming a chart curve by taking the coring position and the permeability as variables, measuring the permeability after the pressure is measured, and analyzing the interference intensity; and 7, drawing a field scale inter-well interference area chart curve, analyzing a variable relationship and perfecting a fitting formula. According to the shale oil horizontal well inter-well interference intensity quantification method based on the physical model, shale oil horizontal well three-dimensional fracturing inter-well interference intensity quantification can be achieved, and the method has important significance on reasonable design and optimization of well pattern and well spacing.

Description

Technical Field

[0001] The invention relates to the technical field of continental shale horizontal well fracturing, and in particular to a method for quantifying the interference intensity between wells of shale oil horizontal wells based on physical modeling. Background Art

[0002] Since the application of horizontal well staged fracturing technology in North America in 2002, horizontal well multi-stage fracturing technology has developed rapidly. In order to cope with the problems of low development degree of single-layer development of multi-layer superimposed shale reservoirs and poor economic benefits under low oil prices, North America has proposed a new concept of three-dimensional development of horizontal wells in the entire reservoir. This concept mainly conducts a comprehensive evaluation of the reservoir properties, geomechanics, stress profiles and other characteristics of multi-layer distributed reservoirs to achieve a one-time three-dimensional development of oil and gas reservoirs.

[0003] China's shale oil geological resource potential and recoverable resource potential are huge, and it is a key area for future oil and gas exploration. The horizontal well segmented multi-cluster dense cutting volume fracture fracturing development technology can achieve a relatively ideal fracturing effect. In order to improve the development and utilization of reservoirs, make full use of the permeability channels between fractures, segments, wells and layers, improve the complexity of fractures and the control volume of fracture systems, and focus on the three-dimensional development technology of multi-well collaborative fracturing fracture networks. It plays an important role in improving the technical quality of shale oil development and ensuring the stability of shale oil production capacity. However, during the multi-well collaborative fracturing process, the stress field is complex due to the interference between the fractures of the well and the multiple superposition of stresses of adjacent wells; the elastic stress calculation model based on the assumption of straight fractures is difficult to reflect the actual complex fracture network stress field; the interference (action form / degree / range) of multiple superposition induced stresses on multi-well collaborative fracturing is not yet understood. Due to the influence of inter-well interference, a pressure drop funnel is formed around the adjacent well after production. When fracturing shale gas wells, it will cause interference in production and pressure to the adjacent wells that were put into production earlier, and strong inter-well interference will sharply inhibit the expansion of fractures, seriously reducing the fracturing effect.

[0004] Most of the multi-well fracturing fracture network models currently developed use digital modeling methods, and their accuracy still requires a large number of physical modeling experimental results to verify. Inter-well interference can promote the formation of fracture networks to a certain extent, thereby increasing fracturing production and efficiency. On the other hand, it will inhibit the diversion and expansion of fractures and the formation of fracture networks, seriously affecting the fracturing effect. Quantifying the intensity of inter-well interference in shale oil horizontal wells is an important basis for constructing key technologies for three-dimensional fracturing of multi-layer shale oil, and is of great significance to the technical system for efficient development of shale oil.

[0005] CN115358135A discloses a method, device and equipment for quantitatively evaluating the inter-well interference after hydraulic fracturing of shale oil, including: obtaining a request for quantitatively evaluating inter-well interference; establishing a physical model corresponding to a multi-fractured horizontal well to be evaluated; according to the request for quantitatively evaluating inter-well interference and the physical model, using a pre-configured well test model to obtain the interference bottom-hole pressure and the non-interference bottom-hole pressure; respectively performing dimensionless processing and derivative processing on the interference bottom-hole pressure and the non-interference bottom-hole pressure to obtain the interference pressure derivative value and the non-interference pressure derivative value; and obtaining the interference coefficient and the interference degree according to the interference pressure derivative value and the non-interference pressure derivative value. Sensitivity analysis is carried out on the relevant parameters affecting inter-well interference, and the inter-well interference coefficient and the inter-well interference degree are clearly defined. The physical model of this patent has strong limitations not only in calculation and processing, but also cannot be fully and effectively applied to actual engineering design; measuring inter-well interference through pressure monitoring and sensitivity analysis cannot directly quantify the influence degree of inter-well interference.

[0006] CN115310379A discloses a method and equipment for analyzing the production performance of a fractured horizontal well under inter-well interference conditions. The method includes: constructing a seepage mathematical model for analyzing the production performance of a fractured horizontal well under inter-well interference conditions; semi-analytically solving the seepage mathematical model for analyzing production performance to obtain the production rate solution of the fractured horizontal well under inter-well interference conditions; determining the pressure-normalized production rate curve under inter-well interference conditions according to the production rate solution; and performing curve fitting of the pressure-normalized production rate curve and the actual production data of the oilfield to determine the reservoir parameters. Although this patent constructs a seepage model under inter-well interference conditions, the production rate solution can be obtained through an analytical method and production performance analysis is carried out, but no further analysis is made on the interference degree and the influence of the interference degree on the production rate.

[0007] CN109209333A discloses a method for optimizing the spacing of efficient exploitation of a multi-well group of shale gas, belonging to the technical field of shale gas exploitation. This method first qualitatively judges the rationality of the well spacing for new area development by analogy with domestic and foreign engineering examples and construction parameters according to geological conditions; then establishes a steady-state production capacity evaluation mathematical model with shale gas wells as basic units to obtain the production rate expression; and finally improves the fracturing stimulation operation effect of the shale gas reservoir, increases the gas well production capacity and recovery rate through reasonable specific construction methods. This theoretical model enables efficient exploitation of multi-well fracturing of shale oil according to reasonable well spacing layout and specific construction methods, but does not specifically consider the influence of construction parameters on the inter-well interference degree and the quantification of the interference degree.

[0008] The above patent disclosure results show that current research on well - to - well interference in shale oil horizontal wells mainly focuses on theoretical models and numerical simulation methods. Through sensitivity analysis of relevant parameters, qualitative laws and well spacing optimization methods are studied. However, there is little research on quantifying the intensity of well - to - well interference in horizontal wells based on physical models through experimental means. Therefore, we have invented a new method for quantifying the intensity of well - to - well interference in shale oil horizontal wells based on physical models. Summary of the Invention

[0009] The object of the present invention is to provide a method for quantifying the intensity of well - to - well interference in three - dimensional fracturing of shale oil horizontal wells based on physical models, which is of great significance for the reasonable design and optimization of well patterns and well spacings.

[0010] The object of the present invention can be achieved by the following technical measures: A method for quantifying the intensity of well - to - well interference in shale oil horizontal wells based on physical models, which includes:

[0011] Step 1. Prepare large - scale three - wellbore physical model cores and standard - size cores.

[0012] Step 2. Test the initial permeability of the standard - size cores.

[0013] Step 3. Adjust the experimental parameters and conduct multi - well three - dimensional fracturing physical model experiments in groups.

[0014] Step 4. Drill the standard - diameter cores of the physical model after fracturing, and conduct sample cutting and standard sample production.

[0015] Step 5. Test the permeability of the standard - size cores after fracturing.

[0016] Step 6. Form a chart curve with the coring position and permeability as variables, measure the post - fracturing permeability and analyze the interference intensity.

[0017] Step 7. Draw a chart curve of the well - to - well interference area at the field scale, analyze the variable relationship and improve the fitting formula.

[0018] The object of the present invention can also be achieved by the following technical measures:

[0019] In Step 1, according to well logging data, core physical property parameters, and in combination with the similarity criteria of the target horizon and experimental conditions, prepare large - scale three - wellbore physical model cores and standard - size cores.

[0020] In Step 1, the well logging data and core physical property parameters are the distribution structure of the actual continental shale formation obtained from well logging interpretation and laboratory tests, as well as the rock mechanics and physics characteristics. The similarity criteria include material similarity, time similarity, boundary condition similarity, and geometric dimension similarity.

[0021] In Step 1, for materials similarity, fine sand, cement, and kaolin are selected through a certain ratio as the materials for making test samples to make the experimental materials as similar as possible to the physical properties of the target layer. For time similarity, the actual fracturing on site and the physical simulation test in the laboratory usually take several minutes to dozens of minutes. The injection fluid volume on the corresponding time scale is obtained through calculation and statistics with similar displacement and the volume of the similar wellbore. For boundary conditions similarity, the hydraulic fracturing simulation test requires simulating the real formation conditions. Applying three-dimensional stress boundary conditions by using a true triaxial loading method in the simulation test can better reflect the actual stress state of the formation. For geometric dimension similarity, considering the relationship between the driving force and deformation and the elimination of boundary effects, the geometric similarity coefficient is determined, and finally the geometric dimensions of the experimental model are determined.

[0022] In Step 1, for the physical model cores of three wellbores and standard-sized cores, the method of one-time molding pouring with pre-embedded packers is adopted. Cement, sand, and water are stirred evenly in a certain proportion, and then poured into a rigid plastic mold for molding. After the cement mortar begins to set and has a certain strength, demolding is carried out, and then specimen curing and subsequent hole sealing work are carried out. The three wellbore positions are evenly arranged and the perforation positions are staggered. Thus, the preparation process of artificial rock samples is completed. The standard-sized cores do not require pre-embedded packers and hole sealing.

[0023] In Step 2, according to the national standard for measuring the permeability of shale by the pulse decay method, the initial permeability of the standard-sized cores is tested. The permeability test method of the shale pulse decay method is transient measurement. The calculation formula for measuring the permeability by the pulse decay method is as follows:

[0024]

[0025] In the formula:

[0026] k—the permeability by the pulse decay method, unit: millidarcy (mD);

[0027] s1—the slope of the straight line;

[0028] μ g —the gas viscosity, unit: pascal-second (Pa·s);

[0029] L—the length of the rock sample, unit: centimeter (cm);

[0030] f z —the characteristic value of the actual gas deviating from the ideal gas (refer to Appendix C);

[0031] A—the cross-sectional area of the rock sample, unit: square centimeter (cm 2 );

[0032] p m —the average pressure between the upstream chamber and the downstream chamber, unit: pascal (Pa);

[0033] V1—the volume of the upstream chamber, in cubic centimeters (cm 3 );

[0034] V2—the volume of the downstream chamber, in cubic centimeters (cm 3 );

[0035] f1—the flow calibration factor, see the appendix standard.

[0036] In step 3, the experimental parameters include: stress conditions, servo pump protection pressure, displacement, fracturing fluid viscosity, and injection fluid volume.

[0037] In step 4, a water jet is used for drilling and cutting the standard diameter core of the physical model after fracturing; to ensure the accuracy of permeability testing, the upper and lower contact surfaces of the core are flattened using epoxy resin glue, and microbial constant temperature curing is carried out to make standard samples.

[0038] In step 6, combining the initial permeability of the standard-sized core, a chart curve is formed with the core-taking position and permeability as variables to measure the post-fracture permeability and analyze the interference intensity.

[0039] In step 6, the core-taking position adopts an equidistant and continuous core-taking method.

[0040] In step 7, combining the similarity criterion, a chart curve of the well-to-well interference area at the field scale is drawn with construction factors and stress interference range as variables to analyze the variable relationship and improve the fitting formula.

[0041] In step 7, the construction factors include displacement, fracturing fluid viscosity, and injection fluid volume.

[0042] The object of the present invention can also be achieved by the following technical measures: a physical model-based shale oil horizontal well well-to-well interference intensity quantification system, which uses a physical model-based shale oil horizontal well well-to-well interference intensity quantification method to quantify the well-to-well interference intensity of three-dimensional fracturing of shale oil horizontal wells.

[0043] The physical model-based shale oil horizontal well well-to-well interference intensity quantification method in the present invention prepares large-scale three-wellbore physical model cores and standard-sized cores according to logging data, core physical property parameters, and combining the similarity criterion of the target horizon and experimental conditions; uses the shale pulse attenuation method to test the initial permeability of the standard-sized core; conducts multi-well three-dimensional fracturing physical model experiments in groups to test the post-fracture permeability of the core; combines the initial permeability of the standard-sized core, and draws a chart curve with the core-taking position and permeability as variables. A chart curve of the well-to-well interference area at the field scale is drawn with construction factors and stress interference range as variables to measure the post-fracture permeability and the radius of the well-to-well interference area. The method described in the present invention can achieve the quantification of the well-to-well interference intensity of three-dimensional fracturing of shale oil horizontal wells, which is of great significance for the reasonable design and optimization of well pattern and well spacing.

[0044] The present invention effectively overcomes the limitations in parameter design, calculation processing, and practical application brought about by physical models and theoretical models, providing a new idea for the analysis and quantification method of well - to - well interference intensity. By conducting physical simulation experiments of three - dimensional multi - well fracturing, using an integrated testing machine for unconventional reservoir cores before and after fracturing to measure permeability, the experimental measurement is accurate, efficient, and the physical meaning of parameters is clear. Considering various factors related to horizontal well fracturing, such as rock mechanics, in - situ stress, construction displacement, fracturing fluid viscosity, and injection volume, the experimental analysis results have strong universality, accuracy, and comprehensiveness. The research results of the present invention have guiding significance for the optimization design of horizontal well fracturing transformation in deep shale reservoirs, the quantification analysis of well - to - well interference in three - dimensional multi - well collaborative fracturing, and oil and gas production increase. Brief Description of the Drawings

[0045] Figure 1 It is a flowchart of a specific embodiment of the method for quantifying well - to - well interference intensity of shale oil horizontal wells based on physical simulation of the present invention;

[0046] Figure 2 It is a schematic diagram of the stress - strain curve under the experimental test conditions of continental shale in Embodiment 2 of the present invention;

[0047] Figure 3 It is a schematic diagram of the layout position of three wellbores in Embodiment 2 of the present invention;

[0048] Figure 4 It is a schematic diagram of the layout of the coring positions of standard - diameter cores in Embodiment 2 of the present invention;

[0049] Figure 5 It is a graph of the permeability change of different coring positions under various displacement, viscosity, and injection volume in Embodiment 2 of the present invention;

[0050] Figure 6 It is a graph of the well - to - well interference zone at the field scale with displacement, viscosity, injection volume, and stress interference radius as variables in Embodiment 2 of the present invention. Detailed Description of the Invention

[0051] It should be noted that the following detailed description is exemplary and is intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those of ordinary skill in the technical field to which the present invention belongs.

[0052] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they specify the presence of features, steps, operations, and / or combinations thereof.

[0053] As Figure 1 shown, Figure 1 is a flowchart of the method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to the present invention. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models includes:

[0054] Step 1. Prepare large-scale three-wellbore physical model cores and standard-sized cores according to well logging data, core physical property parameters, and in combination with the similarity criteria of the target horizon and experimental conditions.

[0055] Step 2. Test the initial permeability of the standard-sized cores according to the national standard for measuring permeability by the shale pulse decay method.

[0056] Step 3. Adjust the experimental parameters and conduct multi-well three-dimensional fracturing physical model experiments in groups.

[0057] Step 4. Drill the standard-diameter cores of the physical model after fracturing, and conduct specimen cutting and standard sample production.

[0058] Step 5. Test the permeability of the standard-sized cores after fracturing according to the national standard for measuring permeability by the shale pulse decay method.

[0059] Step 6. Combine the initial permeability of the standard-sized cores, form a chart curve with the core-taking position and permeability as variables, measure the permeability after fracturing, and analyze the interference intensity.

[0060] Step 7. Combine the similarity criteria, draw a chart curve of the interference area between wells at the field scale with construction factors and stress interference range as variables, analyze the variable relationship, and improve the fitting formula.

[0061] As a preferred embodiment of the present invention, it quantifies the interference intensity between horizontal wells of shale oil in three-dimensional fracturing, provides ideas for reasonably designing and optimizing well patterns and well spacings, and improves the fracturing effect.

[0062] As a preferred embodiment of the present invention, the well logging data and core physical property parameters in Step 1 are the distribution structure of the actual continental shale formation obtained from well logging interpretation and laboratory tests, as well as the rock mechanics and physical characteristics.

[0063] As a preferred embodiment of the present invention, the similarity criteria in Step 1 include material similarity, time similarity, boundary condition similarity, and geometric dimension similarity.

[0064] As a preferred embodiment of the present invention, for materials that are similar, fine sand, cement, and kaolin are selected in the experiment and mixed in a certain proportion as the materials for making test samples to make the experimental materials as similar as possible to the physical properties of the target layer. For time similarity, the actual fracturing on site and the physical simulation test in the laboratory usually take several minutes to dozens of minutes. The injection liquid volume at the corresponding time scale is obtained through calculation and statistics with similar displacement and the volume of the similar wellbore. For boundary condition similarity, the hydraulic fracturing simulation test requires simulating the real formation conditions. Applying the three-dimensional stress boundary condition by the true triaxial loading method in the simulation test can better reflect the actual stress state of the formation. For geometric dimension similarity, considering the relationship between the driving force and deformation and the elimination of boundary effects, the geometric similarity coefficient is determined, and finally the geometric dimensions of the experimental model are determined.

[0065] As a preferred embodiment of the present invention, for the three-wellbore physical model core and the standard-size core in step 1, the pre-buried hole-sealing device is used for one-time molding and pouring. Cement, sand, and water are stirred evenly in a certain proportion, and poured into a hard plastic mold for molding. After the cement mortar begins to set and has a certain strength, demolding is carried out, and then sample curing and subsequent hole-sealing work are carried out. The three wellbore positions are evenly arranged and the perforation positions are staggered. Thus, the preparation process of the artificial rock sample is completed (the standard-size core does not require pre-burying the hole-sealing device and hole-sealing).

[0066] As a preferred embodiment of the present invention, the shale pulse decay method permeability test method in step 2 is transient measurement. The calculation formula for measuring permeability by the pulse decay method is as follows:

[0067]

[0068] In the formula:

[0069] k—the permeability by the pulse decay method, unit: millidarcy (mD);

[0070] s1—the slope of the straight line;

[0071] μ g —the gas viscosity, unit: pascal-second (Pa·s);

[0072] L—the length of the rock sample, unit: centimeter (cm);

[0073] f z —the characteristic value of the actual gas deviating from the ideal gas (refer to Appendix C);

[0074] A—the cross-sectional area of the rock sample, unit: square centimeter (cm 2 );

[0075] p m —the average pressure between the upstream chamber and the downstream chamber, unit: pascal (Pa);

[0076] V1—the volume of the upstream chamber, in cubic centimeters (cm 3 );

[0077] V2—the volume of the downstream chamber, in cubic centimeters (cm 3 );

[0078] f1—the flow calibration factor, see the appendix standard.

[0079] As a preferred embodiment of the present invention, the experimental parameters in step 3 include: stress conditions, servo pump protection pressure, displacement, fracturing fluid viscosity, and injection volume.

[0080] As a preferred embodiment of the present invention, in step 4, a water jet is used for both drilling and cutting the standard diameter core of the physical model after fracturing. To ensure the accuracy of permeability testing, the upper and lower contact surfaces of the core are flattened using epoxy resin adhesive solution, and microbial constant temperature curing is carried out to produce a standard sample.

[0081] As a preferred embodiment of the present invention, in step 6, the coring positions are taken at equal distances and in a continuous coring manner.

[0082] As a preferred embodiment of the present invention, the construction factors in step 7 include displacement, fracturing fluid viscosity, and injection volume.

[0083] The unit representations of the above specific parameters are as follows: initial (post-fracture) permeability, mD; experimental parameters: triaxial stress, MPa; protection pressure, MPa; displacement, ml / min; fracturing fluid viscosity, mPa·s; injection volume, ml; on-site construction parameters: displacement, m 3 / min; fracturing fluid viscosity, mPa·s; injection volume, m 3 .

[0084] The method of the present invention combines logging data, core physical property parameters, and similarity criteria to prepare large-scale three-wellbore physical model cores and standard-size cores, and then conducts tests on the initial permeability of the standard-size cores through the pulse decay method; by adjusting experimental parameters such as fracturing fluid viscosity and injection volume, multi-well three-dimensional fracturing physical model experiments are carried out in groups, and standard diameter cores are drilled, standard samples are cut and made, and then the permeability of the standard-size cores after fracturing is tested through the pulse decay method; from two aspects of the coring position and the change in permeability caused by construction factors, the post-fracture permeability is measured, the interference intensity is analyzed, and the fitting formula of the well-to-well interference at the field scale under different construction factors is obtained. The method of the present invention can measure the well-to-well interference intensity of the three-dimensional fracturing of shale oil horizontal wells, provide ideas for the reasonable design and optimization of well patterns and well spacings, and improve the fracturing effect.

[0085] The following are several specific embodiments of applying the present invention

[0086] Example 1

[0087] A method for quantifying the interference intensity between horizontal wells in shale oil based on physical models, the method comprising the following steps:

[0088] Step 1. According to the distribution structure of the actual continental shale formation obtained from well logging interpretation and laboratory tests, as well as the rock mechanics and physical characteristics, obtain well logging data and core physical property parameters, and prepare large-scale three-wellbore physical model cores and standard-size cores in combination with the similarity criteria of materials, time, boundary conditions, and geometric dimensions of the target layer and experimental conditions. For the experiment, fine sand, cement, kaolin, and clear water are selected and mixed in a certain ratio as the materials for making test samples to make the physical properties of the experimental materials similar to those of the target layer to the greatest extent; the actual fracturing in the field and the physical simulation tests in the laboratory usually take several minutes to dozens of minutes; the true triaxial loading method is used in the test to apply three-dimensional stress boundary conditions to better reflect the actual stress conditions of the formation; considering the relationship between the driving force and deformation and the elimination of boundary effects, determine the geometric dimensions of the experimental model. For the three-wellbore physical model cores and standard-size cores, the pre-embedded hole sealers are used for one-time molding and pouring. Cement, sand, and water are stirred evenly in a certain ratio, and poured into a rigid plastic mold for molding. After the cement mortar begins to set and has a certain strength, demold it, and carry out specimen curing and subsequent hole sealing work. The three wellbore positions are evenly arranged and the perforation positions are staggered. Thus, the preparation process of the artificial rock sample is completed.

[0089] Step 2. According to the national standard for measuring the initial permeability of standard-size cores by the shale pulse decay method, test the initial permeability of the standard-size cores. The shale pulse decay method for permeability testing is a transient method measurement, and its permeability calculation formula and experimental steps are as follows:

[0090]

[0091] In the formula:

[0092] k—Permeability by pulse decay method, unit is millidarcy (mD);

[0093] s1—Slope of the straight line;

[0094] μ g —Gas viscosity, unit is pascal-second (Pa·s);

[0095] L—Length of the rock sample, unit is centimeter (cm);

[0096] f z —Characteristic value of the actual gas deviating from the ideal gas (refer to Appendix C);

[0097] A—Cross-sectional area of the rock sample, unit is square centimeter (cm 2 );

[0098] p m — The average pressures of the upstream chamber and the downstream chamber, in pascals (Pa);

[0099] V1—the volume of the upstream chamber, in cubic centimeters (cm 3 );

[0100] V2—the volume of the downstream chamber, in cubic centimeters (cm 3 );

[0101] f1—the flow calibration factor, see the appendix standard.

[0102] Step 3. Adjust the experimental parameters and conduct physical simulation experiments of multi-well stereoscopic fracturing in groups;

[0103] The experimental parameters include stress conditions, servo pump protection pressure, displacement, fracturing fluid viscosity, and injection fluid volume.

[0104] Step 4. Drill a physical simulation standard diameter core after fracturing, and conduct sample cutting and standard sample production;

[0105] Both the drilling and cutting of the physical simulation standard diameter core after fracturing use a water jet. To ensure the accuracy of permeability testing, the upper and lower contact surfaces of the core are flattened using epoxy resin glue solution, and microbial constant temperature maintenance is carried out to produce standard samples.

[0106] Step 5. According to the national standard for measuring the permeability of shale by pulse decay method, test the permeability of the standard size core after fracturing;

[0107] Step 6. Combine the initial permeability of the standard size core, and form a chart curve with the core-taking position and permeability as variables to measure the post-fracture permeability and analyze the interference intensity;

[0108] The core-taking position adopts an equidistant and continuous core-taking method.

[0109] Step 7. Combine the similarity criterion, and draw a chart curve of the well-to-well interference area at the field scale with construction factors and stress interference range as variables, analyze the variable relationship and improve the fitting formula.

[0110] The construction factors include displacement, fracturing fluid viscosity, and injection fluid volume.

[0111] The overall implementation plan process is shown in the appendix Figure 1 。

[0112] Example 2

[0113] At present, multi-cluster closely spaced volume fracture fracturing development of horizontal wells has been achieved in Liye 1HF, Fengye 1HF, Fanye 2HF, etc. in the Jiyang Depression, and relatively ideal results have been obtained. To further improve the technical quality of Shengli shale oil development and ensure the stability of shale oil production capacity, it is urgent to carry out relevant research on three-dimensional multi-well collaborative fracturing. During the multi-well collaborative fracturing process, due to the multiple superposition effects of the stress between fractures in the well and the stress of adjacent wells, the stress field is complex, and well interference exacerbates the difficulty of oil and gas resource exploitation. Secondly, at present, for the well interference problem in three-dimensional multi-well fracturing at home and abroad, the main research focuses on qualitative laws and well spacing optimization methods, concentrating on theoretical analysis based on stress interference theory and numerical simulation research on fracturing fractures. This patent uses physical experimental methods to quantitatively analyze the well interference intensity between horizontal wells, avoiding the limitations of parameter design, calculation processing, and practical application brought by theoretical analysis and numerical simulation methods, and providing a new idea for the analysis and quantification of well interference intensity.

[0114] Taking the continental shale reservoir in Block X of Shengli Oilfield as an example, this patent adopts the method for quantifying the well interference intensity between shale oil horizontal wells based on physical models described in Example 1, which specifically includes the following steps:

[0115] The first step: According to the distribution structure of the actual continental shale formation in Block X obtained from well logging interpretation and laboratory tests, as well as the rock mechanics parameters of the core, combined with the similarity criteria of materials, time, boundary conditions, and geometric dimensions of the target layer and experimental conditions, large-scale three-wellbore physical model cores and standard-sized cores are prepared. The stress-strain curves of the cores measured in the experiment are as Figure 2 .

[0116] The oil layer studied in this example belongs to sandstone, mudstone, or sand-mud interbeds, and is buried relatively deep. In order to make the experimental materials as similar as possible to the physical properties of the target layer, fine sand and cement are selected as the materials for making test samples, and kaolin can be appropriately incorporated into the mudstone to reduce strength and porosity. This kind of test material not only makes the cement easy to consolidate and meets the strength requirements, but also can load various test conditions relatively easily, such as setting wellbores and directional perforations.

[0117] Compared with the actual geological model, the experimental model made is also carried out in three-dimensional space. Combining the direction and magnitude of the stress in the actual formation, the true triaxial loading method in the experiment can better reflect the actual stress condition of the formation. In the experiment, the vertical stress is set at 10 MPa, the maximum horizontal principal stress is 8 MPa, the minimum horizontal principal stress is 2 MPa, the horizontal stress difference is 6 MPa, and the servo pump protection pressure is 40 MPa.

[0118] In this example, a cube with dimensions of 300mm×300mm×300mm is selected. The pre-embedded hole sealer one-time molding pouring method is adopted. Cement, sand, and water are stirred evenly in a mass ratio of 1:2:0.5 and poured into a hard plastic mold for molding. When making test blocks, 32.5R composite Portland cement is used, and the sand is screened through a 6-mesh splitting sieve to remove large particles, making the formed cement mortar test blocks more homogeneous. To timely discharge the air inside the test blocks and avoid forming holes, layered pouring is adopted, and each layer of mortar is vibrated thoroughly using a portable concrete vibrator until no air bubbles escape. After the cement mortar begins to set and has a certain strength, demolding is carried out, and then sample curing and subsequent hole sealing work are carried out. Thus, the preparation process of artificial rock samples is completed. The three wellbores are evenly arranged, and the perforation positions are staggered, as shown in Figure 3 . From the top view, Well No. 1 is located 100mm below the lower edge of the sample and 150mm from the left and right edges; Well No. 2 is located 100mm above the upper edge of the sample, 50mm from the left edge, and 250mm from the right edge; Well No. 3 is located 100mm above the upper edge of the sample, 250mm from the left edge, and 50mm from the right edge; the straight-line distance between Well No. 2 and Well No. 3 is 200mm, and the vertical distance from Well No. 1 to Well No. 2 and Well No. 3 is 100mm (the horizontal well layer spacing is 100mm).

[0119] Step 2: According to the national standard for measuring the permeability of shale by the pulse decay method, the initial permeability of a standard-sized core (diameter 50mm×height 100mm) is tested. The permeability calculation formula is as follows:

[0120]

[0121] In the formula:

[0122] k—the permeability by the pulse decay method, unit is millidarcy (mD);

[0123] s1—the slope of the straight line;

[0124] μ g —the gas viscosity, unit is pascal-second (Pa·s);

[0125] L—the length of the rock sample, unit is centimeter (cm);

[0126] f z —the characteristic value of the actual gas deviating from the ideal gas (refer to Appendix C);

[0127] A—the cross-sectional area of the rock sample, unit is square centimeter (cm 2 );

[0128] p m —the average pressure between the upstream chamber and the downstream chamber, unit is pascal (Pa);

[0129] V1—the volume of the upstream chamber, in cubic centimeters (cm 3 );

[0130] V2—the volume of the downstream chamber, in cubic centimeters (cm 3 );

[0131] f1—the flow calibration factor, see the appendix standard.

[0132] Step 3: Set the vertical stress σ v = 10 MPa, the maximum horizontal principal stress σ H = 8 MPa, the minimum horizontal principal stress σ h = 2 MPa, the horizontal stress difference is 6 MPa, and the servo pump protection pressure is 40 MPa; the displacement is set to 50 ml / min, 60 ml / min, and 70 ml / min respectively; the viscosities of the fracturing fluid are set to 1 mPa·s, 10 mPa·s, and 50 mPa·s respectively; the injection volumes of the fluid are set to 150 ml, 300 ml, and 450 ml respectively. Conduct physical simulation experiments on multi-well three-dimensional fracturing in groups;

[0133] Step 4: Use the water drilling method to drill cores of the standard diameter of the physical model after fracturing, and adopt the method of taking cores continuously at equal distances. Viewed from the front view, the diameter of the core sampling standard sample is φ = 50 mm, the core sampling interval d = 8.3 mm, and the distance from the center of the standard sample at the core sampling position to the upper and lower edges of the sample is 150 mm; viewed from the top view, the core sampling positions of the standard samples No. ①, ②, ④, and ⑤ are 50 mm from the lower edge of the sample, the core sampling interval is 8.3 mm, the core sampling positions of the standard samples No. ① and ⑤ are 8.3 mm from the left and right edges, the core sampling position of the standard sample No. ③ is 50 mm from the upper edge of the sample, and the distances from the axis position of the standard sample to the left and right edges of the sample are 150 mm respectively, as Figure 4 . Subsequently, conduct sample cutting and standard sample production. Use epoxy resin adhesive to flatten the upper and lower contact surfaces of the core, and conduct microbial constant temperature curing to make standard samples to ensure the accuracy of permeability testing.

[0134] Step 5: According to the national standard for measuring the permeability of shale by the pulse decay method, test the permeability of the core with standard dimensions after fracturing. Combine the permeability calculation formula to calculate the post-fracture permeability k of the standard core, unit: millidarcy (mD).

[0135] Step 6: Combine the initial permeability of the core with standard dimensions. By adopting the method of taking cores continuously at equal distances, form a chart curve with the core sampling position and permeability as variables, measure the post-fracture permeability and analyze the interference intensity. Define k < 5k0 as weak interference, k ≥ 5k0 as weak interference, and k ≥ 10k0 as strong interference.

[0136] (1) Experimental parameter settings: The viscosity of the fracturing fluid is 10 mPa·s, the injection volume is 300 ml, and the displacement rates are 50 ml / min, 60 ml / min, and 70 ml / min respectively. The permeability change curves of different coring positions at each displacement rate are plotted, as shown in Figure 5 (a). The overall change in permeability shows a single-peak distribution, and the permeability at each coring position is higher than the initial permeability. Overall, the order of post-fracture permeability is ①, ⑤ < ②, ④ < ③. And at the same coring position, as the displacement rate increases, the permeability gradually increases and the interference degree gradually increases. This is because during the hydraulic fracturing process, a small displacement rate tends to create a single main fracture around the wellbore and activate a certain number of microfractures in the far-well region, while medium and high displacement rates tend to form complex fractures near the wellbore, communicate a large number of microfractures in the far-well region, and reopen hydraulic fractures in the matrix, thus increasing the complexity of the fracture network and causing the permeability to increase and the interference degree to increase. The coring positions ① and ⑤ are close to the outer edge of the specimen. When the displacement rate is 50 ml / min, the corresponding permeabilities are 3.5k0 and 3.6k0 respectively, belonging to micro-interference. When the displacement rate increases to 60 ml / min and 70 ml / min, the corresponding permeabilities are 5k0, 4.9k0, 6k0, and 6.1k0 respectively, and the interference degree increases, belonging to weak interference. The coring positions ② and ④ are close to the 1st, 2nd, 1st, and 3rd wellbores respectively. When the displacement rate is 50 ml / min, the corresponding permeabilities are 6k0 and 6.2k0 respectively, belonging to weak interference. When the displacement rate increases to 60 ml / min and 70 ml / min, the corresponding permeabilities are 8.3k0, 8.2k0, 9.6k0, and 9.8k0 respectively, and the interference degree increases, belonging to weak interference. The coring position ③ is located at the center of the 1st, 2nd, and 3rd wellbores. Each well generates a certain interference to the coring position ③ during the fracturing process, and the interference intensity here is the largest. When the displacement rate is 50 ml / min, the permeability is 9k0, belonging to weak interference. When the displacement rate increases to 60 ml / min and 70 ml / min, the corresponding permeabilities are 10.8k0 and 11.9k0 respectively, and the interference degree increases, belonging to strong interference.

[0137] (2) Experimental parameter settings: The displacement rate is 60 ml / min, the injection volume is 300 ml, and the viscosities of the fracturing fluid are 1 mPa·s, 10 mPa·s, and 50 mPa·s respectively. The permeability change curves of different coring positions at each viscosity are plotted, as shown in Figure 5(b). The overall change in permeability shows a single-peak distribution, and the permeability at each coring position is higher than the initial permeability. Overall, the order of permeability after fracturing is ①, ⑤ < ②, ④ < ③. And at the same coring position, as the viscosity increases, the permeability gradually decreases and the degree of interference gradually weakens. This is because the low-viscosity fracturing fluid will accelerate the penetration and diffusion from the perforation of the fracturing well to the near-well and even far-well compared with the high-viscosity fracturing fluid. Along with the initiation and propagation of microfractures, it greatly enriches the fracture complexity, is conducive to the formation of a complex fracture network, increases the permeability, and enhances the degree of interference. The coring positions of ① and ⑤ are close to the outer edge of the specimen. When the viscosity is 1 mPa·s, the corresponding permeabilities of the two are 7k0 and 6.9k0 respectively, belonging to weak interference. When the viscosity increases to 10 mPa·s and 50 mPa·s, the corresponding permeabilities of the two are 4.8k0, 4.9k0, 2k0, and 1.9k0 respectively, and the degree of interference weakens, belonging to micro-interference. The coring positions of ② and ④ are close to the 1st and 2nd, 1st and 3rd wellbores respectively. When the viscosity is 1 mPa·s, the corresponding permeabilities of the two are 10.3k0 and 10.2k0 respectively, belonging to strong interference. When the viscosity increases to 10 mPa·s and 50 mPa·s, the corresponding permeabilities of the two are 8.3k0, 8.2k0, 5.3k0, and 5.2k0 respectively, and the degree of interference weakens, belonging to weak interference. The coring position of ③ is located at the center of the 1st, 2nd, and 3rd wellbores. Each well produces a certain interference on the coring position of ③ during the fracturing process, and the interference intensity here is the largest. When the viscosity is 1 mPa·s, the permeability is 12.8k0, belonging to strong interference. When the viscosity increases to 10 mPa·s and 50 mPa·s, the corresponding permeabilities are 10.8k0 and 8.1k0 respectively, and the degree of interference weakens, belonging to strong interference and weak interference.

[0138] (3) Set the experimental parameters: the displacement is 60 ml / min, the viscosity of the fracturing fluid is 10 mP·s, and the injection fluid volumes are set to 150 ml, 300 ml, and 450 ml respectively. With a displacement of 60 ml / min, draw the permeability change curve of different coring positions at each injection fluid volume, as Figure 5(c). The overall change in permeability shows a single-peak distribution, and the permeability at each coring position is higher than the initial permeability. Overall, the order of permeability after fracturing is ①, ⑤ < ②, ④ < ③. And at the same coring position, as the injection fluid volume increases, the permeability gradually increases and the degree of interference gradually strengthens. This is because during the hydraulic fracturing process of the specimen, continuous injection of fracturing fluid is required from pressure accumulation to the formation of the main fracture, the formation of secondary branch fractures, and seepage channels. As the injection fluid volume increases, the rock around the main fracture is easily stressed and stress concentration occurs around brittle mineral particles, leading to the initiation and penetration of microfractures, and then the formation of secondary fractures, that is, branch fractures, which is conducive to the increase in permeability and the enhancement of the degree of interference. The coring positions of ① and ⑤ are close to the outer edge of the specimen. When the injection fluid volume is 150 ml, the corresponding permeabilities of the two are 2.8k0 and 2.7k0 respectively, belonging to micro-interference. When the injection fluid volume increases to 300 ml and 450 ml, the corresponding permeabilities of the two are 4.8k0, 4.9k0, 7.5k0, and 7.4k0 respectively, and the degree of interference strengthens, belonging to micro-interference and weak interference. The coring positions of ② and ④ are close to wellbores 1, 2 and 1, 3 respectively. When the injection fluid volume is 150 ml, the corresponding permeabilities of the two are 6.1k0 and 6k0 respectively, belonging to weak interference. When the injection fluid volume increases to 300 ml and 450 ml, the corresponding permeabilities of the two are 8.3k0, 8.2k0, 10.8k0, and 10.7k0 respectively, and the degree of interference strengthens, belonging to weak interference and strong interference. The coring position of ③ is located at the center of wellbores 1, 2, and 3. Each well produces a certain degree of interference to the coring position of ③ during the fracturing process, and the interference intensity here is the largest. When the injection fluid volume is 150 ml, the permeability is 8.6k0, belonging to weak interference. When the injection fluid volume increases to 300 ml and 450 ml, the corresponding permeabilities are 10.8k0 and 13.2k0 respectively, and the degree of interference strengthens, belonging to strong interference.

[0139] Step 7: Combining similarity criteria, taking construction factors (displacement, fracturing fluid viscosity, and injection fluid volume) and the stress interference range as variables, draw the cross-well interference zone chart curve on the field scale, analyze the variable relationship, and improve the fitting formula. Taking the geometric center of the specimen as the center of the circle and the area with permeability > k0 as the cross-well interference radius, quantify the degree of cross-well interference. Considering the similarity of physical phenomena between the field prototype and the experimental model, such as fracturing fluid flow rate, wellbore diameter, displacement, and geometric relationship of distances, etc., to establish similarity criteria and obtain the similarity ratio relationship between various physical quantities. The designed well spacing of the same layer in the laboratory model is 20 cm, and the similar field prototype scale is 160 m; the designed displacements of the laboratory model are 50 ml / min, 60 ml / min, and 70 ml / min, and the similar field prototype scales are 16 m 3 / min, 18 m 3 / min, 20 m 3 / min; The viscosities of the laboratory model are designed to be 1 mPa·s, 10 mPa·s, and 50 mPa·s, and the similar in-situ prototype scales are 1 mPa·s, 10 mPa·s, and 50 mPa·s; The injection fluid volumes of the laboratory model are designed to be 150 ml, 300 ml, and 450 ml, and the similar in-situ prototype scales are 1000 m 3 、2000 m 3 、3000 m 3 ;

[0140] (1) For the in-situ prototype scale parameters, the viscosity of the fracturing fluid is set to 10 mP·s, the injection fluid volume is 2000 m 3 , and the displacement rates are 16 m 3 / min, 18 m 3 / min, and 20 m 3 / min. Taking the displacement rate and the stress interference radius as variables, the cross-well interference zone chart curves of the in-situ scale are plotted, as shown in Figure 6 (a). It can be seen from the figure that as the displacement rate increases, the interference radius gradually increases, but the growth rate gradually decreases. A small displacement rate tends to create a single main fracture around the well, and the fracture-forming ability in the far-well area is poor, with a small stress interference radius; while medium and high displacement rates tend to form complex fractures near the well and communicate a large number of microfractures in the far-well area, with a large stress interference radius. When the displacement rate is 16 m 3 / min, the interference radius is 70 m; when the displacement rate increases to 18 m 3 / min, the interference radius is 98 m, with an increase of 40%; when the displacement rate increases to 20 m 3 / min, the interference radius is 112 m, with an increase of 14%.

[0141] (2) For the in-situ prototype scale parameters, the displacement rate is set to 18 m 3 / min, the injection fluid volume is 2000 m 3 , and the viscosities of the fracturing fluid are 1 mPa·s, 10 mPa·s, and 50 mPa·s respectively. Taking the viscosity of the fracturing fluid and the stress interference radius as variables, the cross-well interference zone chart curves of the in-situ scale are plotted, as shown in Figure 6 (b). It can be seen from the figure that as the viscosity increases, the interference radius gradually decreases. Since the low-viscosity fracturing fluid is more likely to penetrate and diffuse from the perforation of the fracturing well to the near-well and even far-well areas, the larger the interference radius, the stronger the interference. When the viscosity is 1 mPa·s, the interference radius is 107 m; when the viscosity increases to 10 mPa·s, the interference radius is 98 m, with a decrease of 8%; when the viscosity increases to 50 mPa·s, the interference radius is 72 m, with a decrease of 26%.

[0142] (3) For the in-situ prototype scale parameters, the displacement rate is set to 18 m 3 / min, the viscosity of the fracturing fluid is 10 mP·s, and the injection fluid volumes are set to 1000 m 3, 2000 m 3 , 3000 m 3 , taking the injection fluid volume and the stress interference radius as variables, draw the in-situ scale cross-well interference zone chart curve, as shown in Figure 6 (c). It can be seen from the figure that as the injection fluid volume increases, the interference radius gradually increases, but the growth rate gradually decreases. Under the condition of a higher injection fluid volume, while the main fracture is opened, the initiation and penetration of microfractures will be stimulated, and then secondary fractures will be formed, resulting in an increase in the interference radius. When the injection fluid volume is 1000 m 3 , the interference radius is 65 m; when the injection fluid volume increases to 2000 m 3 , the interference radius is 98 m, with an increase rate of 51%; when the injection fluid volume increases to 3000 m 3 , the interference radius is 115 m, with an increase rate of 17%.

[0143] Example 3

[0144] In the specific Example 3 of applying the present invention, taking the continental shale reservoir in Block Y of Shengli Oilfield as an example, the method for quantifying the cross-well interference intensity of shale oil horizontal wells based on physical models described in Example 1 is also adopted. First, according to the distribution structure of the actual continental shale formation in Block Y obtained from well logging interpretation and laboratory tests, as well as the rock mechanics parameters of the core, combined with the similarity criteria of materials, time, boundary conditions, and geometric dimensions of the target layer and the experimental working conditions, large-scale three-wellbore physical model cores and standard-size cores are prepared, and the initial permeability of the standard-size cores (diameter 50 mm × height 100 mm) is tested according to the national standard for measuring permeability by the shale pulse decay method. The three wellbores are evenly arranged and the perforation positions are staggered. Looking from the top view, Well No. 1 is located 80 mm below the lower edge of the specimen, 150 mm away from the left and right edges; Well No. 2 is located 80 mm above the upper edge of the specimen, 20 mm away from the left edge and 280 mm away from the right edge; Well No. 3 is located 80 mm above the upper edge of the specimen, 280 mm away from the left edge and 20 mm away from the right edge; the straight-line distance between Well Nos. 2 and 3 is 240 mm, and the vertical distance from Well No. 1 to Well Nos. 2 and 3 is 140 mm (the horizontal well spacing is 140 mm).

[0145] Secondly, conduct multi-well three-dimensional fracturing physical model experiments in groups. Use the water drilling method to drill the standard-diameter cores of the physical model after fracturing, and test the permeability of the standard-size cores after fracturing. Looking from the front view, the diameter of the core-taking standard sample is = 50 mm, the core-taking interval d = 7 mm, and the distance from the center of the standard sample at the core-taking position to the upper and lower edges of the specimen is 150 mm; looking from the top view, the core-taking positions of Standard Samples ①, ②, ④, and ⑤ are 50 mm away from the lower edge of the specimen, with a core-taking interval of 7 mm. The distances from the core-taking positions of Standard Samples ① and ⑤ to the left and right edges are 11 mm. The core-taking position of Standard Sample ③ is 50 mm away from the upper edge of the specimen, and the distances from the axis position of the standard sample to the left and right edges of the specimen are 150 mm respectively.

[0146] Finally, taking the coring position and permeability as variables, a chart curve is formed to measure the post-fracture permeability and analyze the interference intensity. When \(k < 4k_0\), it is defined as micro-interference; when \(k\geq4k_0\), it is weak interference; when \(k\geq8k_0\), it is strong interference.

[0147] The experimental setup has a vertical stress \(\sigma\) v = 10 MPa, the maximum horizontal principal stress \(\sigma\) H = 8 MPa, the minimum horizontal principal stress \(\sigma\) h = 2 MPa, a horizontal stress difference of 6 MPa, and a servo pump protection pressure of 40 MPa; the displacement is set to 60 ml / min, the viscosity of the fracturing fluid is set to 1 mPa·s, and the injection volume is set to 300 ml. A physical model experiment of multi-well three-dimensional fracturing is carried out, and the permeability change chart curve at different coring positions is plotted. Overall, the order of the post-fracture permeability magnitude is ①, ⑤ < ②, ④ < ③. The permeability change as a whole shows a single-peak distribution, and the permeability at each coring position is higher than the initial permeability. The coring positions of ① and ⑤ are close to the outer edge of the specimen, and the corresponding permeabilities are 5k0 and 4.8k0 respectively, belonging to weak interference. The coring positions of ② and ④ are close to the 1st and 2nd, 1st and 3rd wellbores respectively, and the corresponding permeabilities are 8.3k0 and 8.2k0 respectively, belonging to strong interference. The coring position of ③ is located at the center of the 1st, 2nd, and 3rd wellbores. Each well has a certain interference on the coring position of ③ during the fracturing process, and the interference intensity here is the largest, with a permeability of 10.8k0, belonging to strong interference.

[0148] Finally, combining with the similarity criterion, taking construction factors (displacement, viscosity of the fracturing fluid, and injection volume) and the stress interference range as variables, a chart curve of the well-to-well interference area at the field scale is plotted, the variable relationship is analyzed, and the fitting formula is improved. Taking the geometric center of the specimen as the center of the circle, the area with permeability > k0 is the well-to-well interference radius, and the degree of well-to-well interference is quantified. Considering the similarity of physical phenomena between the field prototype and the experimental model, such as the flow rate of the fracturing fluid, the wellbore diameter, the displacement, and the geometric relationship of the distance, etc., to establish the similarity criterion and obtain the similarity ratio relationship between various physical quantities. The well spacing of the same layer in the laboratory model is designed to be 24 cm, and the similar field prototype scale is 192 m; the displacements in the laboratory model are designed to be 50 ml / min, 60 ml / min, 70 ml / min, and the similar field prototype scales are 11 m 3 / min, 13 m 3 / min, 16 m 3 / min; the viscosities in the laboratory model are designed to be 1 mPa·s, 10 mPa·s, 50 mPa·s, and the similar field prototype scales are 1 mPa·s, 10 mPa·s, 50 mPa·s; the injection volumes in the laboratory model are designed to be 150 ml, 300 ml, 450 ml, and the similar field prototype scales are 1000 m 3 、2000 m 3 、3000 m 3;

[0149] (1) Set the fracturing fluid viscosity to 10 mPa·s, the injection fluid volume to 2000 m 3 , and the displacement rates to 11 m 3 / min, 13 m 3 / min, and 16 m 3 / min. Draw the cross-well interference zone chart curves at the field scale with displacement rate and stress interference radius as variables. The results show that as the displacement rate increases, the interference radius gradually increases, but the growth rate gradually decreases. Low displacement rates tend to create a single main fracture around the well, with poor fracture-forming ability in the far-well area and a small stress interference radius; while medium and high displacement rates tend to form complex fractures near the well and communicate a large number of microfractures in the far-well area, with a large stress interference radius. When the displacement rate is 11 m 3 / min, the interference radius is 32 m; when the displacement rate increases to 13 m 3 / min, the interference radius is 48 m, with an increase of 50%; when the displacement rate increases to 16 m 3 / min, the interference radius is 64 m, with an increase of 33%.

[0150] (2) Set the displacement rate to 13 m 3 / min, the injection fluid volume to 2000 m 3 , and the fracturing fluid viscosities to 1 mPa·s, 10 mPa·s, and 50 mPa·s. Draw the cross-well interference zone chart curves at the field scale with fracturing fluid viscosity and stress interference radius as variables. The results show that as the viscosity increases, the interference radius gradually decreases. Since low-viscosity fracturing fluid is more likely to penetrate and diffuse from the perforations of the fracturing well to the near-well and even far-well areas, the larger the interference radius, the stronger the interference. When the viscosity is 1 mPa·s, the interference radius is 59 m; when the viscosity increases to 10 mPa·s, the interference radius is 48 m, with a decrease of 19%; when the viscosity increases to 50 mPa·s, the interference radius is 30 m, with a decrease of 38%.

[0151] (3) Set the displacement rate to 13 m 3 / min, the fracturing fluid viscosity to 10 mPa·s, and the injection fluid volumes to 1000 m 3 , 2000 m 3 , and 3000 m 3 . Draw the cross-well interference zone chart curves at the field scale with injection fluid volume and stress interference radius as variables. The results show that as the injection fluid volume increases, the interference radius gradually increases, but the growth rate gradually decreases. Under the condition of a higher injection fluid volume, while opening the main fracture, it will stimulate the initiation and penetration of microfractures, and then form secondary fractures, resulting in an increase in the interference radius. When the injection fluid volume is 1000 m 3 , the interference radius is 26 m; when the injection fluid volume increases to 2000 m3 When the amount is [specific value], the interference radius is 48 m, with an increase rate of 46%; when the injection liquid volume increases to 3000 m 3 When the amount is [specific value], the interference radius is 62 m, with an increase rate of 29%.

[0152] Finally, it should be noted that the above are only the preferred embodiments of the present invention and are not used to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements for some of the technical features. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included within the protection scope of the present invention.

[0153] Except for the technical features described in the specification, the rest are known technologies to those skilled in the art.

Claims

1. A method for quantifying the interference intensity between horizontal wells of shale oil based on physical models, characterized in that The method for quantifying the interference intensity between horizontal wells in shale oil based on physical models includes: Step 1. Prepare large-scale three-wellbore physical model cores and standard-sized cores. Step 2. Test the initial permeability of the standard-sized cores. Step 3. Adjust the experimental parameters and conduct multi-well three-dimensional fracturing physical model experiments in groups. Step 4. Drill the standard-diameter cores of the physical model after fracturing, and perform sample cutting and standard sample production. Step 5. Test the permeability of the standard-sized cores after fracturing. Step 6. Form a chart curve with the coring position and permeability as variables, measure the post-fracture permeability and analyze the interference intensity. Step 7. Draw the chart curve of the interference area between wells at the field scale, analyze the variable relationship and improve the fitting formula.

2. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In Step 1, based on logging data and core physical property parameters, combined with the similarity criteria of the target horizon and experimental conditions, prepare large-scale three-wellbore physical model cores and standard-sized cores.

3. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 2, wherein In Step 1, the logging data and core physical property parameters are the distribution structure of the actual continental shale formation obtained from logging interpretation and laboratory tests, as well as the rock mechanics and physics characteristics. The similarity criteria include material similarity, time similarity, boundary condition similarity, and geometric dimension similarity.

4. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 3, wherein In Step 1, for material similarity, fine sand, cement, and kaolin are selected through a certain ratio as the materials for making test samples to make the experimental materials as similar as possible to the physical properties of the target horizon; for time similarity, the actual fracturing on site and the physical simulation test in the laboratory usually take several minutes to dozens of minutes; the injection liquid volume on the corresponding time scale is obtained through calculation and statistics with similar displacement and the volume of similar wellbores; for boundary condition similarity, the hydraulic fracturing simulation test requires simulating the real formation conditions, and applying triaxial stress boundary conditions by the true triaxial loading method in the simulation test can better reflect the actual stress state of the formation. For geometric dimension similarity, considering the relationship between driving force and deformation and the elimination of boundary effects, determine the geometric similarity coefficient, and finally determine the geometric dimensions of the experimental model.

5. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 2, wherein In Step 1, for the large-scale three-wellbore physical model cores and standard-sized cores, use the method of one-time forming and pouring with pre-embedded packers. Stir cement, sand, and water evenly in a certain proportion, and pour them into a hard plastic mold to form; after the cement mortar begins to set and has a certain strength, demold, and carry out sample curing and subsequent sealing work. The three wellbore positions are evenly arranged and the perforation positions are staggered. Thus, the preparation process of artificial rock samples is completed. The standard-sized cores do not require pre-embedded packers and sealing.

6. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In Step 2, according to the national standard for measuring the permeability of shale by the pulse decay method, test the initial permeability of the standard-sized cores. The permeability test method of the shale pulse decay method is transient measurement, and the calculation formula for measuring permeability by the pulse decay method is as follows: Where: k—the permeability by the pulse decay method, unit is millidarcy (mD); s1—the slope of the straight line; μ g — Gas viscosity, in pascal-seconds (Pa·s); L—the length of the rock sample, unit is centimeter (cm); f z —Characteristic value of the deviation of real gas from ideal gas (refer to Appendix C); A—the cross-sectional area of the rock sample, unit: square centimeter (cm 2 ); p m — The average pressures of the upstream chamber and the downstream chamber, in pascals (Pa); V1—the volume of the upstream chamber, in cubic centimeters (cm 3 ); V2—the volume of the downstream chamber, in cubic centimeters (cm 3 ); f1—the flow calibration factor, see the appendix standard.

7. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In Step 3, the experimental parameters include: stress conditions, servo pump protection pressure, displacement, fracturing fluid viscosity, and injection liquid volume.

8. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In step 4, a water jet is used for drilling and cutting the physical model standard diameter core after fracturing; to ensure the accuracy of permeability testing, the upper and lower contact surfaces of the core are flattened using epoxy resin glue, and microbial constant temperature curing is carried out to produce a standard sample.

9. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In step 6, combined with the initial permeability of the standard size core, a chart curve is formed with the core-taking position and permeability as variables to measure the post-fracture permeability and analyze the interference intensity.

10. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 9, wherein, In step 6, the core-taking position adopts an equidistant and continuous core-taking method.

11. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 1, wherein In step 7, combined with the similarity criterion, a chart curve of the well-to-well interference area at the field scale is drawn with construction factors and the stress interference range as variables, the variable relationship is analyzed, and the fitting formula is improved.

12. The method for quantifying the interference intensity between horizontal wells of shale oil based on physical models according to claim 11, wherein In step 7, the construction factors include displacement, fracturing fluid viscosity, and injection volume.

13. A physical model-based shale oil horizontal well inter-well interference intensity quantification system, characterized in that The physical model-based shale oil horizontal well well-to-well interference intensity quantification system uses the physical model-based shale oil horizontal well well-to-well interference intensity quantification method described in any one of claims 1-12 to quantify the well-to-well interference intensity of the stereoscopic fracturing of shale oil horizontal wells.

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