Method for distinguishing hydraulic fractures and natural fractures based on different dominant modes

Abstract

This invention discloses a method for distinguishing the interaction between hydraulic fractures and natural fractures based on different dominant modes, comprising the following steps: S1: Identifying the dominant mode of the target hydraulic fracture propagation, wherein the dominant mode is viscous or ductile, and determining the net pressure within the fracture under the dominant mode; S2: Determining the critical radius of the hydraulic fracture tip based on the conditions for the hydraulic fracture to pass through the natural fracture; S3: Calculating the stress field of the natural fracture based on the superposition principle; S4: Establishing a judgment criterion, and judging whether the hydraulic fracture continues to propagate through the natural fracture at an arbitrary angle under the stress field conditions obtained in step S3, and constructing an interaction diagram of hydraulic fractures and natural fractures. This invention can accurately determine whether hydraulic fractures continue to propagate through the natural fracture at an arbitrary angle under different dominant modes, providing technical support for the development of unconventional oil and gas reservoirs.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development technology, and in particular to a method for interactively identifying hydraulic fractures and natural fractures based on different dominant modes. Background Technology

[0002] With the continuous exploration and development of fossil resources, unconventional oil and gas has become one of the world's major energy sources. Due to the characteristics of unconventional oil and gas reservoirs, such as low porosity and low permeability, large-scale volumetric fracturing of unconventional reservoirs is currently mainly carried out through hydraulic fracturing technology. The extension behavior of hydraulic fractures is affected by a variety of factors, including geological factors, rock mechanical properties, reservoir interface properties, and fracturing operation parameters. Vertically, it is prone to insufficient or excessive fracture height extension, resulting in inadequate reservoir utilization, increased use of proppant and fracturing fluid, and environmental pollution.

[0003] To clarify the influence of formation discontinuities (faults, natural fractures, formation interfaces, etc.) on the propagation of hydraulic fractures, numerous scholars have studied the intersection behavior of hydraulic and natural fractures through theoretical analysis and laboratory experiments. However, current research on conventional hydraulic fracture propagation mainly focuses on the ductility-dominated mode, while the propagation of fractures under high-displacement, large-scale construction conditions and supercritical CO2 fracturing all belong to the viscosity-dominated mode. Therefore, a new method for distinguishing the interaction between hydraulic and natural fractures based on different dominant modes is urgently needed to accurately predict the intersection behavior of fractures and natural fractures under different dominant modes, providing technical support for optimizing the stimulation effect of unconventional oil and gas reservoirs. Summary of the Invention

[0004] To address the aforementioned problems, this invention aims to provide a method for interactively distinguishing between hydraulic fractures and natural fractures based on different dominant modes. By coupling fluid flow, stress shadowing, and porosity elasticity, it is possible to determine whether hydraulic fractures under different dominant modes penetrate the interface of natural fractures.

[0005] The technical solution of the present invention is as follows:

[0006] A method for interactively distinguishing hydraulic fractures and natural fractures based on different dominant modes includes the following steps:

[0007] S1: Identify the dominant mode of propagation of the target hydraulic fracture, which is either viscous or ductile, and determine the net intra-fracture pressure under the dominant mode.

[0008] S2: Determine the critical radius of the hydraulic fracture tip based on the conditions under which a hydraulic fracture passes through a natural fracture;

[0009] S3: Calculate the stress field of natural cracks based on the superposition principle;

[0010] S4: Establish judgment criteria, and determine whether the hydraulic crack will continue to expand through the natural crack at any angle under the stress field conditions obtained in step S3 based on the judgment criteria.

[0011] Preferably, in step S1, the dominant mode of propagation of the target hydraulic fracture is determined by the following formula:

[0012]

[0013]

[0014] In the formula: k is a characteristic parameter; K′, E′, and μ′ are all material parameters; Q0 is the injection rate; K IC ν represents rock fracture toughness; E represents elastic modulus; υ represents Poisson's ratio; μ represents fracturing fluid viscosity.

[0015] When the characteristic parameter k < 1, the dominant mode is viscosity-dominant; when the characteristic parameter k > 4, the dominant mode is toughness-dominant.

[0016] Preferably, in step S1, when the dominant mode is viscous, the net pressure within the joint is calculated using the following formula:

[0017]

[0018] When the dominant mode is toughness-dominant, the net intra-crack pressure is calculated using the following formula:

[0019]

[0020] In the formula: P net t represents the net pressure inside the fracture; t represents the fracturing fluid injection time.

[0021] Preferably, in step S2, the condition for the hydraulic fracture to penetrate the natural fracture is that the hydraulic fracture will penetrate the natural fracture when the maximum tensile stress reaches the tensile strength of the rock on the other side of the natural fracture interface.

[0022]

[0023]

[0024] In the formula: σ1 is the tensile stress at the opposite interface of the formation; σ x For the x-direction normal stress; σ y τ is the normal stress in the y-direction; xy T0 is the shear stress; T0 is the tensile strength of the rock on the opposite side of the formation; σ H σ is the maximum horizontal principal stress; h K represents the minimum principal stress in the horizontal direction. Ⅰθ is the stress intensity factor; r and θ are the polar coordinates of the hydraulic fracture tip, θ = β or θ = β - π, and β is the angle between the hydraulic fracture and the natural fracture.

[0025] Preferably, in step S3, the stress field is calculated using the following formula:

[0026] σ βy =σ γ,βy +σ Pnet,βy +σ por,βy (7)

[0027] τ βxy =τ γ,β +τ Pnet,β +τ por,β (8)

[0028] In the formula: σ βy σ is the normal stress acting on the interface of a natural crack; γ,βy For the far-field stress generated along β y Normal stress component in the axial direction; σ Pnet,βy The net pressure generated along β within the hydraulic fracture y Normal stress component in the axial direction; σ por,βy The variation in formation pore pressure along β y Normal stress component in the axial direction; τ βxy τ is the shear stress acting on the interface of a natural crack; γ,β τ represents the shear stress component generated in the far field. Pnet,β τ is the shear stress component generated by the net pressure within the hydraulic fracture; por,β This represents the shear stress component generated by changes in formation pore pressure.

[0029] Preferably, the far-field stress components at the natural fracture interface are calculated using the following formula:

[0030]

[0031] The induced stress components generated by fluid flow within hydraulic fractures at the interface of natural fractures are calculated using the following formula:

[0032]

[0033] The induced stress components caused by changes in formation pore pressure due to fracturing fluid injection at the natural fracture interface are calculated using the following formula:

[0034]

[0035] In the formula: σ γ,βx For the far-field stress generated along β x Normal stress component in the axial direction; σ Pnet,βxThe net pressure generated along β within the hydraulic fracture x Normal stress component in the axial direction; σ xx σ represents the normal stress component along the x-axis generated by the net pressure within the hydraulic fracture; yy τ represents the normal stress component along the y-axis generated by the net pressure within the hydraulic fracture. xy σ is the shear stress component generated by the net pressure within the hydraulic fracture; por,βx The variation along β caused by changes in formation pore pressure x Normal stress component in the axial direction; σ px σ represents the normal stress component along the x-axis caused by changes in formation pore pressure; py τ represents the normal stress component along the y-axis caused by changes in formation pore pressure. pxy This represents the shear stress component generated by changes in formation pore pressure.

[0036] Preferably, in the formula for calculating the induced stress components generated by fluid flow within the hydraulic fracture at the natural fracture interface, the stress shadow-induced stress field is calculated using the following formula:

[0037]

[0038]

[0039]

[0040] in:

[0041] -π≤{θ0,θ1,θ2,θ *}≤π (15)

[0042]

[0043]

[0044]

[0045]

[0046] In the formula: r0 is the distance from the midpoint of the hydraulic fracture to the plastic zone; r * θ is the length parameter. * θ0 is the angle between the midpoint of the hydraulic fracture and the plastic zone; θ1 is the angle between the tip of the hydraulic fracture near the natural fracture and the plastic zone; θ2 is the angle between the tip of the hydraulic fracture away from the natural fracture and the plastic zone; r1 is the distance between the tip of the hydraulic fracture near the natural fracture and the plastic zone; r2 is the distance between the tip of the hydraulic fracture away from the natural fracture and the plastic zone; x is the abscissa of the plastic zone radius; y is the ordinate of the plastic zone radius; l is the half-fracture length of the hydraulic fracture.

[0047] Preferably, in the formula for calculating the induced stress components caused by changes in formation pore pressure due to fracturing fluid injection at the natural fracture interface, the pore elastic induced stress field is calculated using the following formula:

[0048]

[0049] In the formula: α is Biot coefficient; υ is Poisson's ratio.

[0050] Preferably, in step S4, the judgment criterion is:

[0051] |τ βxy | <c-μ nf σ βy (twenty one)

[0052] In the formula: c and μ nf These represent the cohesion and coefficient of friction of the natural crack, respectively.

[0053] When the judgment criterion is met, the hydraulic crack will continue to expand through the natural crack; when the judgment criterion is not met, the hydraulic crack will not continue to expand through the natural crack at any angle.

[0054] The beneficial effects of this invention are:

[0055] This invention proposes a new criterion based on linear elastic fracture mechanics, by coupling fluid flow, stress shadowing, and porosity elasticity, to accurately determine whether a hydraulic fracture will continue to propagate through a natural fracture at an arbitrary angle before the hydraulic fracture intersects with it. This criterion can provide technical support for the study of hydraulic fracture propagation and is of great significance for the efficient development of unconventional oil and gas resources. Attached Figure Description

[0056] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0057] Figure 1 This is a schematic diagram showing the intersection of a hydraulic fracture and a natural fracture.

[0058] Figure 2 This is a schematic diagram showing the comparison between the new criteria of this invention and the Zhao and R&P criteria in a specific embodiment;

[0059] Figure 3 This is a schematic diagram showing the comparison between the new criteria of this invention and the Gu criterion in a specific embodiment. Detailed Implementation

[0060] The present invention will be further described below with reference to the accompanying drawings and embodiments. It should be noted that, unless otherwise specified, the embodiments and technical features described in this application can be combined with each other. It should also be pointed out that, unless otherwise indicated, all technical and scientific terms used in this application have the same meaning as commonly understood by one of ordinary skill in the art to which this application pertains. The terms "comprising" or "including" and similar words used in this invention refer to elements or objects preceding the word that encompass the elements or objects listed following the word and their equivalents, without excluding other elements or objects.

[0061] This invention provides a method for interactively distinguishing between hydraulic fractures and natural fractures based on different dominant modes, comprising the following steps:

[0062] S1: Identify the dominant mode of propagation of the target hydraulic fracture, which is either viscous or ductile, and determine the net intra-fracture pressure under the dominant mode.

[0063] Assume that hydraulic fractures propagate in uniformly linearly elastic and impermeable rock under far-field stress confinement conditions, with uniform fluid pressure applied to the fracture surface. The maximum and minimum principal stresses are parallel and perpendicular to the hydraulic fractures, respectively. The fracturing fluid is incompressible, and the hydraulic fracture propagation is continuous and quasi-static. The problem involved is limited to one-dimensional motion under two-dimensional plane strain (ignoring crack opening).

[0064] like Figure 1 As shown, the elliptical region represents hydraulic fractures, and the line segment represents natural fractures. In the global coordinate system (Oxy), fracturing fluid is injected from the origin O, and the hydraulic fractures extend along the positive x-axis, approaching the natural fractures. The far-field stresses are σ... H and σ h The angle between the hydraulic fracture and the natural fracture is β. For ease of calculation, a local coordinate system (O′β) is established at the natural fracture. x β y ), where β x Along the direction of the natural crack, β y Perpendicular to the natural crack, σ βx σ βy and τ βxy These are the local coordinate systems O′β x β y The stress state at a certain point.

[0065] In one specific embodiment, the dominant mode of propagation of the target hydraulic fracture is determined by the following formula:

[0066]

[0067]

[0068] In the formula: k is a characteristic parameter; K′, E′, and μ′ are all material parameters; Q0 is the injection rate; K IC ν represents rock fracture toughness; E represents elastic modulus; υ represents Poisson's ratio; μ represents fracturing fluid viscosity.

[0069] When the characteristic parameter k < 1, the dominant mode is viscosity-dominant; when the characteristic parameter k > 4, the dominant mode is toughness-dominant.

[0070] When the dominant mode is viscous, the net pressure within the joint is calculated using the following formula:

[0071]

[0072] When the dominant mode is toughness-dominant, the net intra-crack pressure is calculated using the following formula:

[0073]

[0074] In the formula: P net t represents the net pressure inside the fracture; t represents the fracturing fluid injection time.

[0075] S2: Determine the critical radius of the hydraulic fracture tip based on the conditions for a hydraulic fracture to pass through a natural fracture. The condition for a hydraulic fracture to pass through a natural fracture is that when the maximum tensile stress reaches the tensile strength of the rock on the other side of the natural fracture interface, the hydraulic fracture will pass through the natural fracture, that is:

[0076]

[0077]

[0078] In the formula: σ1 is the tensile stress at the opposite interface of the formation; σ x For the x-direction normal stress; σ y τ is the normal stress in the y-direction; xy T0 is the shear stress; T0 is the tensile strength of the rock on the opposite side of the formation; σ H σ is the maximum horizontal principal stress; h K represents the minimum principal stress in the horizontal direction. Ⅰ θ is the stress intensity factor; r and θ are the polar coordinates of the hydraulic fracture tip, θ = β or θ = β - π, and β is the angle between the hydraulic fracture and the natural fracture.

[0079] S3: Calculate the stress field of natural cracks based on the superposition principle.

[0080] In one specific embodiment, the stress field is calculated using the following formula:

[0081] σ βy =σγ,βy +σ Pnet,βy +σ por,βy (7)

[0082] τ βxy =τ γ,β +τ Pnet,β +τ por,β (8)

[0083] In the formula: σ βy σ is the normal stress acting on the interface of a natural crack; γ,βy For the far-field stress generated along β y Normal stress component in the axial direction; σ Pnet,βy The net pressure generated along β within the hydraulic fracture y Normal stress component in the axial direction; σ por,βy The variation in formation pore pressure along β y Normal stress component in the axial direction; τ βxy τ is the shear stress acting on the interface of a natural crack; γ,β τ represents the shear stress component generated in the far field. Pnet,β τ is the shear stress component generated by the net pressure within the hydraulic fracture; por,β This represents the shear stress component generated by changes in formation pore pressure.

[0084] The far-field stress components at the natural fracture interface are calculated using the following formula:

[0085]

[0086] The induced stress components generated by fluid flow within hydraulic fractures at the interface of natural fractures are calculated using the following formula:

[0087]

[0088] The induced stress components caused by changes in formation pore pressure due to fracturing fluid injection at the natural fracture interface are calculated using the following formula:

[0089]

[0090] In the formula: σ γ,βx For the far-field stress generated along β x Normal stress component in the axial direction; σ Pnet,βx The net pressure generated along β within the hydraulic fracture x Normal stress component in the axial direction; σ xx σ represents the normal stress component along the x-axis generated by the net pressure within the hydraulic fracture; yy τ represents the normal stress component along the y-axis generated by the net pressure within the hydraulic fracture. xy σ is the shear stress component generated by the net pressure within the hydraulic fracture;por,βx The variation along β caused by changes in formation pore pressure x Normal stress component in the axial direction; σ px σ represents the normal stress component along the x-axis caused by changes in formation pore pressure; py τ represents the normal stress component along the y-axis caused by changes in formation pore pressure. pxy This represents the shear stress component generated by changes in formation pore pressure.

[0091] In the formula for calculating the induced stress components generated by fluid flow within the hydraulic fracture at the natural fracture interface, the stress shadow-induced stress field is calculated using the following formula:

[0092]

[0093]

[0094]

[0095] in:

[0096] -π≤{θ0,θ1,θ2,θ *}≤π (15)

[0097]

[0098]

[0099]

[0100]

[0101] In the formula: r0 is the distance from the midpoint of the hydraulic fracture to the plastic zone; r * θ is the length parameter. * θ0 is the angle between the midpoint of the hydraulic fracture and the plastic zone; θ1 is the angle between the tip of the hydraulic fracture near the natural fracture and the plastic zone; θ2 is the angle between the tip of the hydraulic fracture away from the natural fracture and the plastic zone; r1 is the distance between the tip of the hydraulic fracture near the natural fracture and the plastic zone; r2 is the distance between the tip of the hydraulic fracture away from the natural fracture and the plastic zone; x is the abscissa of the plastic zone radius; y is the ordinate of the plastic zone radius; l is the half-fracture length of the hydraulic fracture.

[0102] In the formula for calculating the induced stress components caused by changes in formation pore pressure due to fracturing fluid injection at the natural fracture interface, the pore elastic induced stress field is calculated using the following formula:

[0103]

[0104] In the formula: α is Biot coefficient; υ is Poisson's ratio.

[0105] S4: Establish judgment criteria, and determine whether the hydraulic crack will continue to expand through the natural crack at any angle under the stress field conditions obtained in step S3 based on the judgment criteria.

[0106] In one specific embodiment, the judgment criterion is:

[0107] |τ βxy | <c-μ nf σ βy (twenty one)

[0108] In the formula: c and μ nf These represent the cohesion and coefficient of friction of the natural crack, respectively.

[0109] When the judgment criterion is met, the hydraulic crack will continue to expand through the natural crack; when the judgment criterion is not met, the hydraulic crack will not continue to expand through the natural crack at any angle.

[0110] In one specific embodiment, to verify the applicability of the new criteria of the present invention, the analytical results of the present invention were compared with the experimental results published by Zhou and Blanton. The basic experimental parameters are shown in Table 1:

[0111] Table 1. Experimental material parameters of Zhou and Blanton

[0112] experimental group E(GPa) <![CDATA[K IC (MPa.m 1 / 2 )]]> <![CDATA[T0(MPa)]]> c(MPa) <![CDATA[Q0(10 -9 m 3 / s)]]> v Zhou 8.402 0.59 3 3.2 4.2 0.23 Blanton 10 0.176 3.1 0 820 0.22

[0113] The results of the comparative experiments are shown in Tables 2 and 3:

[0114] Table 2 shows the comparison results with Zhou's experiment.

[0115]

[0116]

[0117] Table 3 shows the comparison results with the Blanton experiment.

[0118] Serial Number β(°) <![CDATA[σ H (MPa)]]> <![CDATA[σ h (MPa)]]> Δσ(MPa) <![CDATA[μ nf ]]> Experimental results Criterion Results B1 90 -14 -5 -9 0.75 Pass through Pass through B2 60 -12 -10 -2 0.75 Open Not worn B3 60 -20 -5 -15 0.75 Pass through Not worn B4 60 -14 -5 -9 0.75 abort Not worn B5 45 -20 -5 -15 0.75 abort Not worn B6 45 -18 -5 -13 0.75 abort Not worn B7 45 -16 -5 -11 0.75 abort Not worn B8 45 -14 -5 -9 0.75 abort Not worn B9 45 -10 -5 -5 0.75 Open Not worn B10 30 -20 -5 -15 0.75 abort Not worn B11 30 -19 -10 -9 0.75 abort Not worn

[0119] The comparison results in Tables 2 and 3 show that 22 out of the 25 experimental groups have results consistent with the calculated criteria, with only Z4, Z11, and B3 differing from the experimental results. The discrepancy may be related to the properties of the pre-fabricated crack materials used in the experiments. In his experiments, Zhou simulated the differences in the properties of natural cracks by filling different experimental materials. The influence of the critical crack tip and stress singularity may lead to critical radius failure, thus affecting the experimental results. Overall, the new criteria of this invention show good consistency with the indoor experimental results.

[0120] In another specific embodiment, the new criteria of the present invention are compared with the Zhao and R&P criteria and the Gu criterion to theoretically verify the new criteria of the present invention.

[0121] In this embodiment, when the propagation direction of the hydraulic fracture is orthogonal to the natural fracture, based on the shale parameters shown in Table 1, the tensile strength is taken as 5.67 MPa, the half-length of the hydraulic fracture is 0.03 m, and the fracture toughness is 1.74 MPa. 1 / 2 The results of comparing the new criteria of this invention with the published criteria are as follows: Figure 2 As shown.

[0122] from Figure 2 It can be seen that, under the same rock mechanics parameters, when hydraulic fractures approximate orthogonal natural fractures, the new criterion of this invention is slightly lower than that of the R&P and Zhao criteria. Under the condition of constant tensile strength, the critical friction coefficient of the natural fracture interface in the R&P criterion is only related to the horizontal stress ratio, and shows a negative correlation.

[0123] Because the angle between the hydraulic crack and the natural crack is 90°, it can be seen from formula (9) that, in the new criterion of this invention, the horizontal stress ratio (σ) H / σ h The change in stress ratio only affects the far-field stress component, and the change in stress ratio has no effect on the shear stress component acting on the natural crack interface. When the horizontal stress ratio is low, the R&P criterion only considers the influence of the far-field stress. As can be seen from the stress field model formula (7) of this invention, the compressive stress (σ) acting on the natural crack interface under the new criterion of this invention... βy The R&P criterion is larger, so when a hydraulic fracture extends into a natural fracture, it is easier to penetrate the natural fracture.

[0124] The novel criterion of this invention is further extended to the case where the propagation direction of hydraulic fractures is not orthogonal to that of natural fractures. The comparison results between the novel criterion of this invention and the Gu criterion are as follows: Figure 3 As shown. From Figure 3 It can be seen that when the intersection angle β between the hydraulic fracture and the natural fracture is less than 55°, the two criteria show good consistency, and the hydraulic fracture cannot penetrate the natural fracture. As the intersection angle increases, the horizontal stress difference gradually dominates the intersection behavior. When β > 59°, the new criterion makes it easier for the hydraulic fracture to penetrate the natural fracture compared to the Gu criterion. This is because the Gu criterion only considers the influence of far-field stress. When the horizontal stress difference is low, the compressive stress (σ) acting on the natural fracture interface in the new criterion... βy Compared to the Gu criterion, the natural fracture interface is less prone to slippage, and hydraulic fractures are more likely to extend through the natural fracture.

[0125] In summary, this invention can accurately determine whether a hydraulic fracture will continue to propagate through a natural fracture at any angle. Compared with existing technologies, this invention represents a significant advancement.

[0126] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for distinguishing hydraulic fractures from natural fractures based on different dominant modes, characterized in that, The method comprises the following steps: S1: determining a dominant mode of target hydraulic fracture propagation, the dominant mode being viscosity-dominated or toughness-dominated, and determining a net pressure in the fracture under the dominant mode; S2: determining a critical radius of a hydraulic fracture tip according to a condition of the hydraulic fracture penetrating a natural fracture; S3: calculating a stress field of the natural fracture according to a superposition principle by the following formula: （7） （8） In the formula: σ βy σ is the normal stress acting on the interface of a natural crack; γ,βy For the far-field stress generated along β y Normal stress component in the axial direction; σ Pnet,βy The net pressure generated along β within the hydraulic fracture y Normal stress component in the axial direction; σ por,βy The variation in formation pore pressure along β y Normal stress component in the axial direction; τ βxy τ is the shear stress acting on the interface of a natural crack; γ,β The shear stress component generated in the far field; τ Pnet,β τ is the shear stress component generated by the net pressure within the hydraulic fracture; por,β This refers to the shear stress component generated by changes in formation pore pressure. a far-field stress component on a natural fracture interface is calculated by the following formula: （9） an induced stress component on the natural fracture interface caused by fluid flow in the hydraulic fracture is calculated by the following formula: （10） an induced stress component on the natural fracture interface caused by a change in formation pore pressure due to fracturing fluid injection is calculated by the following formula: （11） where: σ γ,βx is the normal stress component along the β x axis direction due to far-field stresses; σ H is the horizontal maximum principal stress; σ h is the horizontal minimum principal stress; β is the angle between the hydraulic fracture and the natural fracture; σ Pnet,βx is the normal stress component along the β x axis direction due to the net pressure in the hydraulic fracture; σ xx is the normal stress component along the x-axis direction due to the net pressure in the hydraulic fracture; σ yy is the normal stress component along the y-axis direction due to the net pressure in the hydraulic fracture; τ xy is the shear stress component due to the net pressure in the hydraulic fracture; σ por,βx is the normal stress component along the β x axis direction due to the change in formation pore pressure; σ px is the normal stress component along the x-axis direction due to the change in formation pore pressure; σ py is the normal stress component along the y-axis direction resulting from the change in formation pore pressure; τ pxy is the shear stress component resulting from the change in formation pore pressure; in the formula for calculating the induced stress component on the natural fracture interface caused by fluid flow in the hydraulic fracture, a stress shadow induced stress field is calculated by the following formula: （12） （13） （14） wherein: （15） （16） （17） （18） （19） where: P net Pnet is the net pressure in the fracture; r0 is the distance from the midpoint of the hydraulic fracture to the plastic zone; r * l is the length parameter; θ * θ is the angle parameter; θ is the polar coordinate of the tip of the hydraulic fracture, θ = β or θ = β - π, β is the intersection angle of the hydraulic fracture and the natural fracture; θ0 is the angle between the midpoint of the hydraulic fracture and the plastic zone; θ1 is the angle between the tip of the hydraulic fracture near the end of the natural fracture and the plastic zone; θ2 is the angle between the tip of the hydraulic fracture far from the end of the natural fracture and the plastic zone; r1 is the distance from the tip of the hydraulic fracture near the end of the natural fracture to the plastic zone; r2 is the distance from the tip of the hydraulic fracture far from the end of the natural fracture to the plastic zone; x is the horizontal coordinate of the plastic zone radius; y is the vertical coordinate of the plastic zone radius; l is the half-length of the hydraulic fracture; S4: establishing a judgment criterion and judging, according to the judgment criterion, whether the hydraulic fracture will continue to propagate through an arbitrary-angle natural fracture under the stress field condition obtained in step S3.

2. The method of claim 1, wherein the method is characterized by, In step S1, the dominant mode of the target hydraulic fracture propagation is determined by the following formula: （1） （2） where: k is a characteristic parameter; K', E', μ' are material parameters; Q0 is the injection rate; K IC is the rock fracture toughness; E is the elastic modulus; υ is the Poisson's ratio; μ is the fracturing fluid viscosity; when the characteristic parameter k < 1, the dominant mode is viscosity-dominated; and when the characteristic parameter k > 4, the dominant mode is toughness-dominated.

3. The method of claim 2, wherein the different dominant mode based hydraulic fracture and natural fracture interaction discrimination method is characterized by, In step S1, when the dominant mode is viscosity-dominated, the net pressure in the fracture is calculated by the following formula: （3） when the dominant mode is toughness-dominated, the net pressure in the fracture is calculated by the following formula: （4） where: P net is the net pressure inside the fracture; t is the injection time of the fracturing fluid.

4. The method of claim 1, wherein the method is characterized by, In step S2, the condition of the hydraulic fracture penetrating the natural fracture is that when the maximum tensile stress reaches the tensile strength of the rock on the other side of the natural fracture interface, the hydraulic fracture will penetrate the natural fracture, i.e. （5） （6） where σ1is the tensile stress on the opposite interface of the formation; σ x is the x-direction normal stress; σ y is the y-direction normal stress; T0is the tensile strength of the rock on the opposite interface of the formation; K Ⅰ is the stress intensity factor; and r is the polar coordinate of the hydraulic fracture tip.

5. The method of claim 1, wherein the method is characterized by, in the formula for calculating the induced stress component on the natural fracture interface caused by the change in formation pore pressure due to fracturing fluid injection, a poroelastic induced stress field is calculated by the following formula: （20） where: P net is the net pressure inside the seam; a is the coefficient of Biot; and v is the Poisson's ratio.

6. The method of claim 1-5, wherein, In step S4, the judgment criterion is: （21） In the formula: τ βxy and σ βy These represent the shear stress and normal stress acting on the interface of the natural crack, respectively; c and μ nf These represent the cohesion and coefficient of friction of the natural crack, respectively. when the judgment criterion is satisfied, the hydraulic fracture will continue to propagate through the natural fracture; and when the judgment criterion is not satisfied, the hydraulic fracture will not continue to propagate through the arbitrary-angle natural fracture.

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