A shale gas formation drilling risk assessment method, device and equipment

Abstract

This article relates to the field of oil industry drilling engineering technology, and in particular to a shale gas formation drilling risk assessment method, device, and equipment. The method includes establishing a rock mechanics parameter calculation model and a geostress parameter calculation model for the target formation; selecting a rock failure criterion based on the rock mechanics parameter calculation model, the geostress parameter calculation model, the degree of collapse of the wellbore already drilled in the target formation, and the density of the drilling fluid already drilled; determining the construction risk level corresponding to the degree of collapse of the wellbore already drilled based on the construction conditions of the already drilled well; and determining the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation based on the construction risk level and the rock failure criterion. Through the embodiments of this article, a quantitative assessment of the construction risk of the drilling fluid density of the well to be drilled during on-site construction of a shale gas formation is achieved, and at the same time, it can accurately guide on-site construction to select a reasonable drilling fluid density, ensuring safe drilling underground.

Description

Technical Field

[0001] This article relates to the field of oil industry drilling engineering technology, and in particular to a shale gas formation drilling risk assessment method, device and equipment. Background Art

[0002] With the rapid development of shale gas exploration and development, the number of three-dimensional horizontal wells with large offsets and long horizontal sections is increasing. At present, the length of domestic shale gas horizontal sections has reached more than 3,000 meters. Due to the dense rocks, low permeability, developed bedding and micro-fractures in shale gas reservoirs, and poor wellbore stability, drill sticking accidents occur frequently, which greatly increases drilling costs and seriously restricts the efficient development of shale gas.

[0003] Shale reservoirs have unique rock mechanical properties that vary significantly with changes in geological structure and burial depth. Traditionally, the degree of rock damage in wellbores has been assessed based on the subjective experience of workers, selecting a single Mohr-Coulomb rock failure criterion and an empirical value for the allowable wellbore collapse width. However, the calculated collapse pressure exhibits significant errors compared to actual drilling conditions, making it impossible to quantitatively assess the construction risk of drilling fluid density during on-site construction, nor accurately guide the selection of a reasonable drilling fluid density during on-site construction, thereby failing to ensure safe drilling in the wellbore.

[0004] There is an urgent need for a shale gas formation drilling risk assessment method to solve the problem that the existing technology cannot quantitatively assess the construction risk of drilling fluid density in shale gas formation on-site construction. Summary of the Invention

[0005] To address the problem in the prior art that the construction risk of drilling fluid density during on-site construction in shale gas formations cannot be quantitatively assessed, the embodiments of this article provide a shale gas formation drilling risk assessment method, device, and equipment, which achieve the quantitative assessment of the construction risk of drilling fluid density during on-site construction in shale gas formations and ensure safe drilling underground.

[0006] In order to solve the above technical problems, the specific technical solutions of this article are as follows:

[0007] On the one hand, the embodiments herein provide a method for assessing the degree of damage to a shale gas formation wellbore, comprising:

[0008] Establish rock mechanics parameter calculation model and ground stress parameter calculation model of target formation;

[0009] Selecting a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled;

[0010] Determining a construction risk level corresponding to a degree of wellbore collapse of the drilled well according to the construction status of the drilled well;

[0011] The drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation is determined according to the construction risk level and the rock failure criterion.

[0012] Furthermore, the wellbore collapse degree includes the wellbore collapse width and well diameter at all wellbore depths.

[0013] Furthermore, the rock failure criterion selected based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse in the target formation and the drilling fluid density of the drilled well further includes:

[0014] Based on each candidate rock failure criterion, a curve of formation collapse pressure versus wellbore depth for each candidate rock failure criterion is calculated according to the wellbore collapse width at each wellbore depth, the rock mechanics parameter calculation model, and the in-situ stress parameter calculation model;

[0015] The rock failure criterion is selected from the candidate rock failure criteria according to the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and a curve showing that the formation collapse pressure varies with wellbore depth.

[0016] Furthermore, before selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and the curve of the formation collapse pressure varying with wellbore depth, the method further includes:

[0017] The depth of the wellbore at which the wellbore has collapsed is removed.

[0018] Furthermore, selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the wellbore diameter at each wellbore depth, and the curve of the formation collapse pressure varying with wellbore depth further includes:

[0019] Based on the curve of the formation collapse pressure varying with the wellbore depth, calculating the difference between the formation collapse pressure of each candidate rock failure criterion and the density of the drilling fluid in the wellbore, the formation collapse pressure and the density of the drilling fluid in the wellbore being at the same wellbore depth;

[0020] Determine whether the difference at the same wellbore depth is consistent with the wellbore diameter at the wellbore depth; if so, record the number of consistent values;

[0021] The rock failure criterion with the largest number of compliances is selected from the candidate rock failure criterions.

[0022] Furthermore, the construction conditions include the actual lifting weight, theoretical lifting weight, actual lowering weight, theoretical lowering weight and reaming speed of the drilling tool.

[0023] Furthermore, determining the construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction status of the drilled well further includes:

[0024] Calculating the difference between the actual lifting weight and the theoretical lifting weight at each wellbore depth, and the difference between the actual lowering weight and the theoretical lowering weight, and determining the reaming speed at each wellbore depth;

[0025] The construction risk level corresponding to the wellbore collapse width of the drilled well is determined according to the lifting hanging weight difference, the lowering hanging weight difference, the eye-removing speed and the predetermined threshold value.

[0026] Furthermore, the construction risk levels sorted in descending order of construction risk include level one risk, level two risk, and level three risk;

[0027] Determining the construction risk level corresponding to the wellbore collapse width of the drilled well based on the lifting hanging weight difference, the lowering hanging weight difference, the reaming speed and the predetermined threshold value further includes:

[0028] If the difference between the lifting and hanging weights is less than the first preset threshold value, the difference between the lowering and hanging weights is greater than the second preset threshold value, and the reaming speed is 0, the construction risk level is the third level risk;

[0029] If the difference between the lifting and hanging weights is greater than or equal to the first preset threshold value, the difference between the lowering and hanging weights is less than or equal to the second preset threshold value, and the reaming speed is greater than the third preset threshold value, then the construction risk level is the second level risk;

[0030] If the difference in the lifting hanging weight is greater than or equal to the first preset threshold value, the difference in the lowering hanging weight is less than or equal to the second preset threshold value, and the eye-marking speed is less than or equal to the third preset threshold value, the construction risk level is the first-level risk.

[0031] Furthermore, determining the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion further includes:

[0032] Based on the rock failure criterion, and according to the wellbore collapse width corresponding to each construction risk level, respectively calculating the formation collapse pressure of each construction risk level;

[0033] If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the third-level risk, the drilling risk is the third-level risk;

[0034] If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the second-level risk and greater than the formation collapse pressure corresponding to the third-level risk, then the drilling risk is the second-level risk;

[0035] If the density of the drilling fluid to be drilled is greater than the formation collapse pressure corresponding to the second-level risk, the drilling risk is the first-level risk.

[0036] On the other hand, the embodiment of this invention also provides a shale gas formation drilling risk assessment device, comprising:

[0037] A mechanical parameter calculation model establishment unit is used to establish a rock mechanical parameter calculation model and a ground stress parameter calculation model for the target formation;

[0038] a rock failure criterion selection unit, configured to select a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled;

[0039] a construction risk level determining unit, configured to determine a construction risk level corresponding to a degree of wellbore collapse of the drilled well according to the construction status of the drilled well;

[0040] A drilling risk assessment unit is used to determine the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion.

[0041] On the other hand, an embodiment of the present invention further provides a computer device, including a memory, a processor, and a computer program stored in the memory, wherein the processor implements the above method when executing the computer program.

[0042] Finally, the embodiments of this document further provide a computer storage medium on which a computer program is stored. When the computer program is executed by a processor of a computer device, the above method is executed.

[0043] By using the embodiments of this article, a rock failure criterion suitable for the target formation is preferably selected based on the rock mechanics parameter calculation model of the target formation, the ground stress parameter calculation model, the degree of wellbore collapse of the drilled wells in the target formation, and the drilling fluid density, thereby improving the accuracy of drilling risk assessment. The construction risk level corresponding to the wellbore collapse degree of the drilled well is determined according to the construction situation of the drilled well, and a corresponding relationship between the wellbore collapse degree and the construction risk level is established. Finally, the drilling risk corresponding to the drilling fluid density of the well to be drilled in the target formation is determined according to the determined construction risk level and the preferred rock failure criterion, thereby achieving a quantitative assessment of the construction risk of the drilling fluid density of the well to be drilled in the on-site construction of shale gas formations. At the same time, it can also accurately guide the on-site construction to select a reasonable drilling fluid density according to the determined construction risk level and the preferred rock failure criterion, thereby ensuring safe drilling underground. BRIEF DESCRIPTION OF THE DRAWINGS

[0044] In order to more clearly illustrate the technical solutions in the embodiments of this article or the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are only some embodiments of this article. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0045] Figure 1 FIG2 is a schematic diagram of a system for implementing a shale gas formation drilling risk assessment method according to an embodiment of this invention;

[0046] Figure 2 Shown is a flow chart of a shale gas formation drilling risk assessment method according to an embodiment of this invention;

[0047] Figure 3 The figure shows the process of selecting rock failure criteria in the embodiment of this article;

[0048] Figure 4 The figure shows the process of selecting the optimal rock failure criterion in the embodiment of this article;

[0049] Figure 5 The figure shows the process of determining the construction risk level corresponding to the degree of wellbore collapse of the drilled well in the embodiment of this article;

[0050] Figure 6 The figure shows the process of determining the optimal construction risk level corresponding to the wellbore collapse width of the drilled well in the embodiment of this article;

[0051] Figure 7 FIG2 is a schematic structural diagram of a shale gas formation drilling risk assessment device according to an embodiment of the present invention;

[0052] Figure 8Shown are the curves of formation collapse pressure changing with wellbore depth, the actual drilling fluid density, and the actual wellbore diameter corresponding to the various rock failure criteria implemented in this paper;

[0053] Figure 9 Schematic diagram of the process of assessing the drilling risk of shale gas formations according to the embodiment of this invention;

[0054] Figure 10 Shown is a schematic structural diagram of a computer device according to an embodiment of this invention.

[0055]

Description of the accompanying drawings

[0056] 101. Terminal;

[0057] 102. Processor;

[0058] 701. Mechanical parameter calculation model establishment unit;

[0059] 702. Rock failure criterion selection unit;

[0060] 703. Construction risk level determination unit;

[0061] 704. Drilling Risk Assessment Unit;

[0062] 1002. Computer equipment;

[0063] 1004. Processing equipment;

[0064] 1006. Storage resources;

[0065] 1008, driving mechanism;

[0066] 1010, input / output module;

[0067] 1012. Input device;

[0068] 1014. Output device;

[0069] 1016. Presentation equipment;

[0070] 1018. Graphical user interface;

[0071] 1020, network interface;

[0072] 1022, communication link;

[0073] 1024. Communication bus. DETAILED DESCRIPTION

[0074] The following will be combined with the accompanying drawings to clearly and completely describe the technical solutions in the embodiments of this document. Obviously, the embodiments described are only part of the embodiments of this document, not all of the embodiments. Based on the embodiments of this document, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of this document.

[0075] It should be noted that the terms "first," "second," and the like in the specification and claims herein and in the accompanying drawings are used to distinguish similar objects and are not necessarily used to describe a particular order or precedence. It should be understood that the terms used in this manner are interchangeable where appropriate so that the embodiments of the present invention described herein can be implemented in an order other than those illustrated or described herein. In addition, the terms "including" and "having," as well as any variations thereof, are intended to cover non-exclusive inclusions. For example, a process, method, apparatus, product, or device comprising a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units that are not explicitly listed or that are inherent to these processes, methods, products, or devices.

[0076] It should be noted that the steps shown in the flowcharts of the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions, and that, although a logical order is shown in the flowcharts, in some cases, the steps shown or described can be executed in an order different from that shown here.

[0077] like Figure 1 FIG. 1 is a schematic diagram of a system for implementing a shale gas formation drilling risk assessment method according to an embodiment of the present invention, which may include a terminal 101 and a processor 102. A communication connection is established between the terminal 101 and the processor 102, enabling data exchange. The terminal 101 may input relevant information required for the shale gas formation drilling risk assessment method, such as a rock mechanics parameter calculation model and a geostress parameter calculation model for a target formation, as well as relevant data on wells already drilled in the target formation and relevant data on wells to be drilled in the target formation, into the processor 102. The processor 102 calculates the relevant information input by the terminal 101 and assesses the drilling risk of the wells to be drilled in the target formation.

[0078] In the embodiments of this specification, the processor 102 can be an independent physical computer, a processor cluster or distributed system composed of multiple physical computers, or a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, content delivery networks (CDNs), and big data and artificial intelligence platforms.

[0079] In some optional embodiments, terminal 101 can be combined with processor 102 to assess drilling risk in shale gas formations. Specifically, terminal 101 may include, but is not limited to, electronic devices such as smartphones, desktop computers, tablet computers, laptop computers, smart speakers, digital assistants, augmented reality (AR) / virtual reality (VR) devices, and smart wearable devices. Optionally, the operating system running on the electronic device may include, but is not limited to, Android, iOS, Linux, and Windows.

[0080] In addition, it should be noted that Figure 1 What is shown is only one application environment provided by the present disclosure. In actual applications, other application environments may also be included, such as guiding on-site construction operations based on assessed drilling risks, which may also be implemented on the terminal 101 and the processor 102.

[0081] Specifically, the embodiments of this article provide a shale gas formation drilling risk assessment method, which quantitatively assesses the construction risk of drilling fluid density during on-site construction of shale gas formations. At the same time, it can also accurately guide on-site construction to select a reasonable drilling fluid density, ensuring safe drilling underground. Figure 2 The flowchart of a shale gas formation drilling risk assessment method according to an embodiment of the present invention is shown. This figure describes the process of assessing the risk of shale gas formation drilling fluid, but it may include more or fewer operating steps based on conventional or non-creative work. The order of steps listed in the embodiment is only one way of executing the steps among many, and does not represent the only execution order. When the system or device product is actually executed, it can be executed in the order shown in the embodiment or the accompanying drawings or in parallel. Specifically, Figure 2 As shown, the method may include:

[0082] Step 201: establishing a rock mechanics parameter calculation model and a ground stress parameter calculation model for the target formation;

[0083] Step 202: selecting a rock failure criterion based on the rock mechanics parameter calculation model, the in-situ stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled;

[0084] Step 203: determining a construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction status of the drilled well;

[0085] Step 204: Determine the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion.

[0086] Through the method of the embodiments of this article, a rock failure criterion suitable for the target formation is preferably selected based on the rock mechanics parameter calculation model of the target formation, the ground stress parameter calculation model, the degree of wellbore collapse of the drilled wells in the target formation, and the drilling fluid density, thereby improving the accuracy of assessing drilling risks, and determining the construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction conditions of the drilled well, establishing a corresponding relationship between the degree of wellbore collapse and the construction risk level, and finally determining the drilling risk corresponding to the drilling fluid density of the well to be drilled in the target formation according to the determined construction risk level and the preferred rock failure criterion, thereby achieving a quantitative assessment of the construction risk of the drilling fluid density of the well to be drilled in the on-site construction of shale gas formations, and also accurately guiding the on-site construction to select a reasonable drilling fluid density according to the determined construction risk level and the preferred rock failure criterion, thereby ensuring safe drilling underground.

[0087] In the embodiments of this article, rock mechanics parameters may include Poisson's ratio, Young's modulus, uniaxial compressive strength and rock internal friction angle, and ground stress parameters may include maximum horizontal principal stress, minimum horizontal principal stress and vertical stress.

[0088] Furthermore, establishing the rock mechanics parameter calculation model of the target formation in step 201 may include the following steps:

[0089] Step 1: Establishing an initial calculation model of the rock mechanical parameters based on the logging data of the wells drilled in the target formation;

[0090] Step 2: Correcting the initial calculation model of the rock mechanics parameters according to the core test data of the drilled well to obtain the rock mechanics parameter calculation model.

[0091] In the embodiment of this invention, the well logging data of the drilled well may include well depth, longitudinal wave velocity, shear wave velocity and rock bulk density. The core test data is obtained by testing a core sample in the target formation. The core sample can be taken out of the target formation by a special drilling machine. The core test data has the same composition as the rock mechanical parameters. Specifically, the initial calculation model of the rock mechanical parameters can be established by formulas (1) to (4):

[0092]

[0093]

[0094]

[0095]

[0096] Where, μ represents Poisson's ratio, E represents Young's modulus, U represents uniaxial compressive strength, δ represents the internal friction angle of rock, V pIndicates the longitudinal wave velocity in m / h, V s represents the shear wave velocity in m / h, and ρ represents the rock bulk density in g / cm 3 , A, B, C, and D are correction coefficients.

[0097] Then, the core test data (Poisson's ratio, Young's modulus, uniaxial compressive strength and rock internal friction angle) are used to correct the initial calculation model of the rock mechanical parameters described in Formulas (1) to (4), that is, the specific values ​​of the correction coefficients A, B, C, and D are solved to obtain the rock mechanical parameter calculation model.

[0098] Furthermore, establishing the geostress parameter calculation model in step 201 may include the following steps:

[0099] Step 1: establishing an initial calculation model for the in-situ stress parameters based on the wellbore parameters of the drilled well, the pore pressure of the target formation, and the calculation model for the rock mechanics parameters;

[0100] Step 2: Correcting the initial calculation model of the in-situ stress parameters according to the core test data of the drilled well to obtain the calculation model of the in-situ stress parameters.

[0101] In the embodiments of this invention, the wellbore parameters of the drilled well may include well depth, well inclination, and azimuth, and the core test data may also include maximum horizontal principal stress, minimum horizontal principal stress, and vertical stress. Specifically, the initial calculation model of the in-situ stress parameters may be established using formulas (5) to (7):

[0102]

[0103]

[0104]

[0105] Among them, σ v represents the vertical stress, σ min represents the minimum horizontal principal stress, σ max represents the maximum horizontal principal stress, H represents the depth of the drilled well, and ρ represents the rock bulk density in g / cm 3 , g represents the acceleration of gravity, μ represents the Poisson's ratio, E represents the Young's modulus, α represents the effective stress coefficient. In the embodiment of this article, the effective stress coefficient α ranges from 0.6 to 0.8, P p represents the pore pressure, ε x represents the minimum horizontal stress azimuth structural coefficient, ε y Represents the structural coefficient of the maximum horizontal stress orientation.

[0106] Then, the core test data (maximum horizontal principal stress, minimum horizontal principal stress and vertical stress) are used to correct the initial calculation model of the ground stress parameters established by formulas (5) to (7), that is, the minimum horizontal stress azimuth structural coefficient ε is obtained. x , maximum horizontal stress orientation structural coefficient ε y The specific value of is used to obtain the calculation model of the ground stress parameter.

[0107] According to one embodiment of the present invention, the wellbore collapse degree includes the wellbore collapse width and wellbore diameter at all wellbore depths, that is, the wellbore collapse width and wellbore diameter at each wellbore depth position of the drilled well.

[0108] In the embodiments of this invention, the depth position of each wellbore of the drilled well can be measured by formation microresistivity scanning imaging (FMI, Formation MicroScanner Image) technology to obtain the wellbore collapse width at each wellbore depth position. The depth position of each wellbore of the drilled well can be measured by multi-arm caliper logging technology to obtain the wellbore diameter at each wellbore depth position. FMI technology and multi-arm caliper logging technology are commonly used technical means in the field for measuring wellbore collapse width and wellbore diameter, and are not described in detail in the embodiments of this invention.

[0109] According to one embodiment of this invention, Figure 3 As shown, step 202 further includes selecting a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the drilled well in the target formation, and the drilling fluid density of the drilled well.

[0110] Step 301: Based on each candidate rock failure criterion, a curve of formation collapse pressure versus wellbore depth for each candidate rock failure criterion is calculated according to the wellbore collapse width at each wellbore depth, the rock mechanics parameter calculation model, and the in-situ stress parameter calculation model;

[0111] Step 302: Select the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the wellbore diameter at each wellbore depth, and the curve of the formation collapse pressure varying with wellbore depth.

[0112] In the embodiment of this article, the candidate rock failure criteria may include the Mohr-Coulomb rock failure criterion and the modified Lade rock failure criterion.

[0113] Specifically, step 301 first calculates the curve of formation collapse pressure varying with wellbore depth based on the Mohr-Coulomb rock failure criterion and the modified Lade rock failure criterion, according to the wellbore collapse width at each wellbore depth, the rock mechanics parameter calculation model, and the ground stress parameter calculation model:

[0114] The process of calculating the formation collapse pressure using the Mohr-Coulomb rock failure criterion can include the following steps:

[0115] Step 1: The model of the component of ground stress along the wellbore for directional wells is shown in formula (8):

[0116]

[0117] Among them, σ 11 , σ 22 , σ 33 , σ 12 , σ 13 , σ 23 represents the ground stress component, γ represents the well inclination, β represents the azimuth, σ v represents the vertical stress, σ min represents the minimum horizontal principal stress, σ max represents the maximum horizontal principal stress.

[0118] Step 2: The stress component calculation model of the wellbore at the critical failure position is shown in formula (9):

[0119]

[0120] Among them, σ zz represents the axial stress component of the wellbore, ε θθ represents the tangential stress component of the wellbore, τ θz represents the shear stress component of the wellbore, σ rr represents the radial stress component of the wellbore wall, represents the initial collapse position angle of the wellbore, σ 11 , σ 22 , σ 33 , σ 12 , σ 13 , σ 23 represents the ground stress component calculated by formula (8), ω represents the wellbore collapse width, P c Indicates the formation collapse pressure, P p Represents the pore pressure.

[0121] Step 3: According to the Mohr-Coulomb rock failure criterion model as shown in formula (10):

[0122]

[0123] Among them, σ zz represents the axial stress component of the wellbore calculated by formula (9), σ θθ represents the wellbore tangential stress component calculated by formula (9), τ θzrepresents the shear stress component of the wellbore calculated by formula (9), U represents the uniaxial compressive strength, δ represents the internal friction angle of the rock, and P c Indicates the formation collapse pressure, P p Represents the pore pressure.

[0124] The formation collapse pressure at a certain well depth corresponding to the Mohr-Coulomb rock failure criterion is calculated by formula (8) to formula (10), and then the σ corresponding to each well depth is calculated. v represents the vertical stress, σ min represents the minimum horizontal principal stress, σ max Substituting the maximum horizontal principal stress into the above formula, we can obtain the curve of the formation collapse pressure corresponding to the Mohr-Coulomb rock failure criterion as a function of wellbore depth.

[0125] The process of calculating formation collapse pressure by modifying the Lade rock failure criterion may include the following steps:

[0126] Step 1: Calculate the axial stress component σ of the wellbore using formulas (8) and (9) in this manual: zz , wellbore tangential stress component σ θθ and the wellbore shear stress component τ θz .

[0127] Step 2: The effective principal stress calculation model for any wellbore angle on the wellbore wall is shown in formula (11):

[0128]

[0129] Among them, σ tmax represents the maximum effective principal stress on the tangent plane of the wellbore, σ tmin represents the minimum effective principal stress on the tangent plane of the wellbore, σ rr represents the radial stress component of the wellbore, σ θθ represents the wellbore tangential stress component calculated by formula (9), P c Indicates the formation collapse pressure, P p Represents the pore pressure.

[0130] Step 3: According to the modified Lade rock failure criterion model as shown in formula (12):

[0131]

[0132] Among them, σ1, σ2, and σ3 represent the principal stresses in the three directions of the wellbore wall, and s and k represent the characteristic parameters of the rock material, which can be calculated by the following formulas (13) and (14):

[0133]

[0134]

[0135] Among them, U represents the uniaxial compressive strength, δ represents the internal friction angle of the rock, and when the wellbore wall is damaged, then:

[0136]

[0137] Substituting formula (15) into formula (12) can obtain the formation collapse pressure at a certain well depth corresponding to the modified Lade rock failure criterion, and then the σ corresponding to each well depth is v represents the vertical stress, σ min represents the minimum horizontal principal stress, σ max Substituting the maximum horizontal principal stress into the above formula, we can obtain the curve of formation collapse pressure changing with wellbore depth corresponding to the modified Lade rock failure criterion.

[0138] Then, the rock failure criterion is selected from the candidate rock failure criteria according to the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and the curve of the formation collapse pressure varying with the wellbore depth.

[0139] According to one embodiment of this invention, Figure 4 As shown, selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the wellbore diameter at each wellbore depth, and the curve of the formation collapse pressure varying with the wellbore depth further includes:

[0140] Step 401: Based on the curve of formation collapse pressure varying with wellbore depth, calculating the difference between the formation collapse pressure of each candidate rock failure criterion and the density of the drilling fluid in the wellbore, the formation collapse pressure and the density of the drilling fluid in the wellbore being at the same wellbore depth;

[0141] Step 402: Determine whether the difference at the same wellbore depth is consistent with the wellbore diameter at the wellbore depth. If so, record the number of consistent values.

[0142] Step 403: Select the rock failure criterion that meets the largest number of criteria from the candidate rock failure criteria.

[0143] For example, the curve of formation collapse pressure corresponding to the modified Lade rock failure criterion and the curve of formation collapse pressure corresponding to the Mohr-Coulomb rock failure criterion and the curve of formation collapse pressure corresponding to the wellbore depth obtained by the above method of the embodiment of this invention, the actual drilling fluid density of the drilled well and the actual well diameter of the drilled well can be as follows: Figure 8 As shown, Figure 8The vertical axis represents the wellbore depth, the left half of the horizontal axis represents the stress value, and the right half represents the actual wellbore diameter value. In the embodiment of this article, when the formation collapse pressure is greater than the actual drilling fluid density, the wellbore will not collapse, that is, the wellbore diameter expansion is not obvious; when the formation collapse pressure is less than or equal to the actual drilling fluid density, the wellbore will collapse, that is, the wellbore diameter expansion is obvious. Therefore, Figure 8 It can be seen that at the wellbore depth of 2800m to 3100m, the wellbore diameter has not expanded significantly. The formation collapse pressure corresponding to the modified Lade rock failure criterion is less than the actual drilling fluid density, and the formation collapse pressure corresponding to the Mohr-Coulomb rock failure criterion is greater than the actual drilling fluid density. According to the above relationship, the modified Lade rock failure criterion is the preferred rock failure criterion.

[0144] like Figure 8 As shown, after the wellbore depth exceeds 3500m, the actual wellbore diameter fluctuates greatly, indicating that the wellbore has collapsed after the wellbore depth exceeds 3500m. Therefore, in order to improve the accuracy of selecting the rock failure criterion, according to an embodiment of this invention, before selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the wellbore diameter at each wellbore depth, and the curve of the formation collapse pressure changing with the wellbore depth, it also includes removing the wellbore depth where the wellbore has collapsed.

[0145] According to an embodiment of the present invention, the construction conditions include the actual lifting weight, theoretical lifting weight, actual lowering weight, theoretical lowering weight and reaming speed of the drilling tool.

[0146] In the embodiments of this article, the theoretical lifting weight and theoretical lowering weight of the drill tool at each wellbore depth position of the drilled well can be obtained based on the design plan of the drilled well. During the actual construction process, the actual lifting weight, actual lowering weight and eye-marking speed of the drill tool at each wellbore depth position can be recorded.

[0147] According to one embodiment of this invention, Figure 5 As shown, determining the construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction status of the drilled well further includes:

[0148] Step 501: Calculating the difference between the actual lifting weight and the theoretical lifting weight, and the difference between the actual lowering weight and the theoretical lowering weight at each wellbore depth, and determining the reamer speed at each wellbore depth;

[0149] Step 502: Determine the construction risk level corresponding to the wellbore collapse width of the drilled well based on the difference in the lifting and lowering weights, the difference in the lowering and lowering weights, the reaming speed, and a predetermined threshold value.

[0150] According to one embodiment of the present invention, the construction risk levels sorted in descending order of construction risk include level one risk, level two risk and level three risk, wherein the risk level of level one risk is greater than the risk level of level two risk, and the risk level of level two risk is greater than the risk level of level three risk. Figure 6 As shown, determining the construction risk level corresponding to the wellbore collapse width of the drilled well based on the lifting hanging weight difference, the lowering hanging weight difference, the reaming speed and the predetermined threshold value further includes:

[0151] Step 601: If the difference between the lifting and lowering weights is less than a first preset threshold value, the difference between the lowering and upper hanging weights is greater than a second preset threshold value, and the reaming speed is 0, then the construction risk level is the third risk level;

[0152] Step 602: If the difference between the lifting and lowering weights is greater than or equal to the first preset threshold, the difference between the lowering and lowering weights is less than or equal to the second preset threshold, and the reaming speed is greater than the third preset threshold, then the construction risk level is the second level risk.

[0153] Step 603: If the difference in the lifting weight is greater than or equal to the first preset threshold, the difference in the lowering weight is less than or equal to the second preset threshold, and the reaming speed is less than or equal to the third preset threshold, then the construction risk level is the first level risk.

[0154] In the embodiments of this article, the first preset threshold value, the second preset threshold value and the third preset threshold value can be obtained by analyzing data from multiple drilled wells in the target formation. Preferably, the first preset threshold value is 100kN, the second preset threshold value is 50kN, and the third preset threshold value is 0.5m / min.

[0155] According to one embodiment of the present invention, determining the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion further includes:

[0156] Based on the rock failure criterion, and according to the wellbore collapse width corresponding to each construction risk level, respectively calculating the formation collapse pressure of each construction risk level;

[0157] If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the third-level risk, the drilling risk is the third-level risk;

[0158] If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the second-level risk and greater than the formation collapse pressure corresponding to the third-level risk, then the drilling risk is the second-level risk;

[0159] If the density of the drilling fluid to be drilled is greater than the formation collapse pressure corresponding to the second-level risk, the drilling risk is the first-level risk.

[0160] In this embodiment, the formation collapse pressure corresponding to the wellbore collapse width for each risk level is calculated based on the preferred rock failure criterion. When the formation collapse pressure is greater than the actual drilling fluid density, the wellbore will not collapse; when the formation collapse pressure is less than or equal to the actual drilling fluid density, the wellbore will collapse. Therefore, based on the above, when the drilling fluid density of the well to be drilled is less than the formation collapse pressure corresponding to a certain risk level, it indicates that the wellbore corresponding to that risk level will not collapse. Therefore, it can be determined that the construction risk level is that risk level at the drilling fluid density of the well to be drilled.

[0161] At the same time, it can also accurately guide the selection of reasonable drilling fluid density for on-site construction based on the determined construction risk level and the preferred rock failure criterion. The specific process is similar to the above steps and will not be repeated here.

[0162] Based on the same inventive concept, the embodiment of this specification also provides a shale gas formation drilling risk assessment device, such as Figure 7 As shown, it includes a mechanical parameter calculation model establishment unit 701, a rock failure criterion selection unit 702, a construction risk level determination unit 703, and a drilling risk assessment unit 704. Further,

[0163] Mechanical parameter calculation model establishment unit 701, used to establish a rock mechanical parameter calculation model and a ground stress parameter calculation model of the target formation;

[0164] A rock failure criterion selection unit 702 is configured to select a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled;

[0165] A construction risk level determination unit 703 is configured to determine a construction risk level corresponding to a degree of wellbore collapse of the drilled well according to the construction status of the drilled well;

[0166] The drilling risk assessment unit 704 is configured to determine the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion.

[0167] The beneficial effects achieved by the above-mentioned device are consistent with the beneficial effects achieved by the above-mentioned method, and will not be described in detail in the embodiments of this specification.

[0168] like Figure 9The figure shows a flow chart for assessing shale gas formation drilling risk according to an embodiment of this disclosure. The figure describes the steps involved in assessing shale gas formation drilling risk. It should be noted that the steps and sequence described in this figure are not the only steps and sequences for assessing shale gas formation drilling risk according to this embodiment of this disclosure. Those skilled in the art will be able to derive other steps and sequences for assessing shale gas formation drilling risk based on the description in this figure, and this disclosure does not limit these steps and sequences.

[0169] Specifically, the steps for assessing the risk of drilling in shale gas formations include:

[0170] Step 901: establishing a rock mechanics parameter calculation model based on well logging data and core test data of the wells drilled in the target formation;

[0171] In this step, the rock mechanical parameters may include Poisson's ratio, Young's modulus, uniaxial compressive strength, and rock internal friction angle. The well logging data of the drilled well may include well depth, longitudinal wave velocity, shear wave velocity, and rock bulk density. The core test data is obtained by testing a core sample in the target formation. The core sample can be taken out of the target formation by a special drilling rig. The core test data has the same composition as the rock mechanical parameters. Specifically, an initial calculation model for rock mechanical parameters is established using formulas (1) to (4) of this specification. Then, the initial calculation model for rock mechanical parameters described in formulas (1) to (4) is corrected using the core test data (Poisson's ratio, Young's modulus, uniaxial compressive strength, and rock internal friction angle) to obtain the rock mechanical parameter calculation model.

[0172] Step 902: establishing a geostress parameter calculation model based on the wellbore parameters of the drilled well, the pore pressure of the target formation, core test data, and the rock mechanics parameter calculation model;

[0173] In this step, the in-situ stress parameters may include the maximum horizontal principal stress, the minimum horizontal principal stress, and the vertical stress. The wellbore parameters of the drilled well may include the well depth, the well inclination angle, and the azimuth. The core test data may also include the maximum horizontal principal stress, the minimum horizontal principal stress, and the vertical stress. Specifically, an initial calculation model for the in-situ stress parameters may be established using Formulas (5) to (7). The initial calculation model for the in-situ stress parameters established using Formulas (5) to (7) is then corrected using the core test data (maximum horizontal principal stress, minimum horizontal principal stress, and vertical stress) to obtain the calculation model for the in-situ stress parameters.

[0174] Step 903: Selecting a rock failure criterion based on a rock mechanics parameter calculation model, a ground stress parameter calculation model, wellbore parameters of the drilled well, and drilling fluid density of the drilled well;

[0175] In this step, the rock failure criterion includes the Mohr-Coulomb rock failure criterion and the modified Lade rock failure criterion. The curve of the formation collapse pressure calculated by the Mohr-Coulomb rock failure criterion and the curve of the formation collapse pressure calculated by the modified Lade rock failure criterion as a function of the wellbore depth are respectively calculated by formulas (8) to (15) in this specification.

[0176] Then, a curve showing the variation of formation collapse pressure with wellbore depth is calculated based on the Mohr-Coulomb rock failure criterion and a curve showing the variation of formation collapse pressure with wellbore depth is calculated based on the modified Lade rock failure criterion, and the difference between the formation collapse pressure of the Mohr-Coulomb rock failure criterion and the modified Lade rock failure criterion and the density of the drilling fluid in the well is calculated, respectively, wherein the formation collapse pressure and the density of the drilling fluid in the well are at the same wellbore depth;

[0177] Then determine whether the difference at the same wellbore depth is consistent with the well diameter at the wellbore depth. If so, record the number of consistent values.

[0178] Finally, the rock failure criterion that meets the largest number of criteria is selected.

[0179] Step 904: determining a construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction status of the drilled well;

[0180] In this step, the construction conditions include the actual lifting weight, theoretical lifting weight, actual lowering weight, theoretical lowering weight and eye-marking speed of the drilling tool. The construction risk levels sorted in descending order of construction risk include level one risk, level two risk and level three risk, among which the risk level of level one risk is greater than that of level two risk, and the risk level of level two risk is greater than that of level three risk.

[0181] If the difference between the upper and lower hanging weights is less than the first preset threshold value, the difference between the lower and lower hanging weights is greater than the second preset threshold value, and the reaming speed is 0, the construction risk level is level 3 risk;

[0182] If the difference between the upper hanging weight and the lower hanging weight is greater than or equal to the first preset threshold value, the difference between the lower hanging weight and the lower hanging weight is less than or equal to the second preset threshold value, and the reaming speed is greater than the third preset threshold value, the construction risk level is level 2 risk;

[0183] If the difference in the upper hanging weight is greater than or equal to the first preset threshold value, the difference in the lowering hanging weight is less than or equal to the second preset threshold value, and the eye-marking speed is less than or equal to the third preset threshold value, the construction risk level is level one risk.

[0184] In this step, the first preset threshold value is 100 kN, the second preset threshold value is 50 kN, and the third preset threshold value is 0.5 m / min.

[0185] Step 905: Determine the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion.

[0186] In this step, first, based on the preferred rock failure criterion, according to the wellbore collapse width corresponding to each construction risk level, the formation collapse pressure of each construction risk level is calculated respectively; if the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the third-level risk, the drilling risk is the third-level risk; if the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the second-level risk and greater than the formation collapse pressure corresponding to the third-level risk, the drilling risk is the second-level risk; if the density of the drilling fluid to be drilled is greater than the formation collapse pressure corresponding to the second-level risk, the drilling risk is the first-level risk.

[0187] like Figure 10 The diagram shows a schematic diagram of the structure of a computer device according to an embodiment of the present invention. The apparatus herein may be a computer device according to this embodiment, executing the method described above. Computer device 1002 may include one or more processing devices 1004, such as one or more central processing units (CPUs), each of which may implement one or more hardware threads. Computer device 1002 may also include any storage resources 1006 for storing any type of information, such as code, settings, data, etc. For example, and without limitation, storage resources 1006 may include any one or more combinations of the following: any type of RAM, any type of ROM, flash memory devices, hard disks, optical disks, etc. More generally, any storage resource may use any technology to store information. Furthermore, any storage resource may provide volatile or non-volatile retention of information. Furthermore, any storage resource may represent a fixed or removable component of computer device 1002. In one embodiment, when processing device 1004 executes associated instructions stored in any storage resource or combination of storage resources, computer device 1002 may perform any operation of the associated instructions. The computer device 1002 also includes one or more drive mechanisms 1008 for interacting with any storage resources, such as a hard disk drive mechanism, an optical disk drive mechanism, and the like.

[0188] The computer device 1002 may also include an input / output module 1010 (I / O) for receiving various inputs (via input devices 1012) and for providing various outputs (via output devices 1014). A specific output mechanism may include a presentation device 1016 and an associated graphical user interface (GUI) 1018. In other embodiments, the input / output module 1010 (I / O), input devices 1012, and output devices 1014 may not be included, and the computer device 1002 may simply be a computer device in a network. The computer device 1002 may also include one or more network interfaces 1020 for exchanging data with other devices via one or more communication links 1022. One or more communication buses 1024 couple the components described above together.

[0189] The communication link 1022 may be implemented in any manner, for example, via a local area network, a wide area network (e.g., the Internet), a point-to-point connection, etc., or any combination thereof. The communication link 1022 may include any combination of hardwired links, wireless links, routers, gateway functions, name servers, etc., governed by any protocol or combination of protocols.

[0190] Corresponding to Figure 2-Figure 6 、 Figure 9 In the method, an embodiment of the present invention further provides a computer-readable storage medium, on which a computer program is stored, and when the computer program is executed by a processor, the above steps are executed.

[0191] The embodiment of the present invention also provides a computer readable instruction, wherein when the processor executes the instruction, the program causes the processor to execute the following Figure 2-Figure 6 、 Figure 9 The method shown.

[0192] It should be understood that in the various embodiments of this document, the size of the serial numbers of the above-mentioned processes does not mean the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this document.

[0193] It should also be understood that in the embodiments herein, the term "and / or" merely describes an association between associated objects, indicating that three possible relationships exist. For example, "A and / or B" could represent: A alone, A and B simultaneously, or B alone. Furthermore, the character " / " in this document generally indicates an "or" relationship between the associated objects.

[0194] Those skilled in the art will appreciate that the units and algorithm steps of each example described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, computer software, or a combination of the two. In order to clearly illustrate the interchangeability of hardware and software, the above description has generally described the composition and steps of each example according to function. Whether these functions are performed in hardware or software depends on the specific application and design constraints of the technical solution. Professional and technical personnel can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this document.

[0195] Those skilled in the art will clearly understand that, for the convenience and brevity of description, the specific working processes of the systems, devices and units described above can refer to the corresponding processes in the aforementioned method embodiments and will not be repeated here.

[0196] In the several embodiments provided herein, it should be understood that the disclosed systems, devices, and methods can be implemented in other ways. For example, the device embodiments described above are merely illustrative. For example, the division of the units is merely a logical function division. In actual implementation, there may be other division methods, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. In addition, the mutual coupling or direct coupling or communication connection shown or discussed can be an indirect coupling or communication connection through some interfaces, devices, or units, or can be an electrical, mechanical, or other form of connection.

[0197] The units described as separate components may or may not be physically separate, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed across multiple network units. Some or all of the units may be selected according to actual needs to achieve the purpose of the embodiments herein.

[0198] In addition, the functional units in the various embodiments herein may be integrated into a single processing unit, each unit may exist physically separately, or two or more units may be integrated into a single unit. The aforementioned integrated units may be implemented in the form of hardware or software functional units.

[0199] If the integrated unit is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this article is essentially or the part that contributes to the existing technology, or all or part of the technical solution can be embodied in the form of a software product, which is stored in a storage medium and includes several instructions for enabling a computer device (which can be a personal computer, server, or network device, etc.) to execute all or part of the steps of the method described in each embodiment of this article. The aforementioned storage medium includes: various media that can store program code, such as a USB flash drive, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disk.

[0200] This article uses specific embodiments to illustrate the principles and implementation methods of this article. The description of the above embodiments is only used to help understand the methods and core ideas of this article. At the same time, for those skilled in the art, based on the ideas of this article, there will be changes in the specific implementation methods and application scope. In summary, the content of this specification should not be understood as a limitation to this article.

Claims

1. A shale gas formation drilling risk assessment method, characterized in that: The method comprises, Establish rock mechanics parameter calculation model and ground stress parameter calculation model of target formation; Selecting a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled; Determining a construction risk level corresponding to a degree of wellbore collapse of the drilled well according to the construction status of the drilled well; Determining the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion; The wellbore collapse degree includes the wellbore collapse width and well diameter at all wellbore depths; The rock failure criterion is further selected based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the drilled well in the target formation and the drilling fluid density of the drilled well. Based on each candidate rock failure criterion, a curve of formation collapse pressure versus wellbore depth for each candidate rock failure criterion is calculated according to the wellbore collapse width at each wellbore depth, the rock mechanics parameter calculation model, and the in-situ stress parameter calculation model; Selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and a curve of the formation collapse pressure varying with wellbore depth; The rock failure criterion is selected from the candidate rock failure criteria according to the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and the curve of the formation collapse pressure varying with the wellbore depth, further comprising: Based on the curve of the formation collapse pressure varying with the wellbore depth, calculating the difference between the formation collapse pressure of each candidate rock failure criterion and the density of the drilling fluid in the wellbore, the formation collapse pressure and the density of the drilling fluid in the wellbore being at the same wellbore depth; Determine whether the difference at the same wellbore depth is consistent with the wellbore diameter at the wellbore depth; if so, record the number of consistent values; The rock failure criterion with the largest number of compliances is selected from the candidate rock failure criterions.

2. The shale gas formation drilling risk assessment method according to claim 1, characterized in that: Before selecting the rock failure criterion from the candidate rock failure criteria according to the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and the curve of the formation collapse pressure varying with the wellbore depth, the method further includes: The depth of the wellbore at which the wellbore has collapsed is removed.

3. The shale gas formation drilling risk assessment method according to claim 1, characterized in that: The construction conditions include the actual lifting weight, theoretical lifting weight, actual lowering weight, theoretical lowering weight and eye-reaming speed of the drilling tool.

4. The shale gas formation drilling risk assessment method according to claim 3, characterized in that: Determining the construction risk level corresponding to the degree of wellbore collapse of the drilled well according to the construction status of the drilled well further includes: Calculating the difference between the actual lifting weight and the theoretical lifting weight at each wellbore depth, and the difference between the actual lowering weight and the theoretical lowering weight, and determining the reaming speed at each wellbore depth; The construction risk level corresponding to the wellbore collapse width of the drilled well is determined according to the lifting hanging weight difference, the lowering hanging weight difference, the eye-removing speed and the predetermined threshold value.

5. The shale gas formation drilling risk assessment method according to claim 4, characterized in that: The construction risk levels arranged in descending order of construction risk include level one risk, level two risk and level three risk; Determining the construction risk level corresponding to the wellbore collapse width of the drilled well based on the lifting hanging weight difference, the lowering hanging weight difference, the reaming speed and the predetermined threshold value further includes: If the difference between the lifting and hanging weights is less than the first preset threshold value, the difference between the lowering and hanging weights is greater than the second preset threshold value, and the reaming speed is 0, the construction risk level is the third level risk; If the difference between the lifting and hanging weights is greater than or equal to the first preset threshold value, the difference between the lowering and hanging weights is less than or equal to the second preset threshold value, and the reaming speed is greater than the third preset threshold value, then the construction risk level is the second level risk; If the difference in the lifting hanging weight is greater than or equal to the first preset threshold value, the difference in the lowering hanging weight is less than or equal to the second preset threshold value, and the eye-marking speed is less than or equal to the third preset threshold value, the construction risk level is the first-level risk.

6. The shale gas formation drilling risk assessment method according to claim 5, characterized in that: Determining the drilling risk corresponding to the density of the drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion further includes: Based on the rock failure criterion, and according to the wellbore collapse width corresponding to each construction risk level, respectively calculating the formation collapse pressure of each construction risk level; If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the third-level risk, the drilling risk is the third-level risk; If the density of the drilling fluid to be drilled is less than the formation collapse pressure corresponding to the second-level risk and greater than the formation collapse pressure corresponding to the third-level risk, then the drilling risk is the second-level risk; If the density of the drilling fluid to be drilled is greater than the formation collapse pressure corresponding to the second-level risk, the drilling risk is the first-level risk.

7. A shale gas formation drilling risk assessment device, characterized in that: include, A mechanical parameter calculation model establishment unit is used to establish a rock mechanical parameter calculation model and a ground stress parameter calculation model for the target formation; a rock failure criterion selection unit, configured to select a rock failure criterion based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the well drilled in the target formation, and the drilling fluid density of the well drilled; a construction risk level determining unit, configured to determine a construction risk level corresponding to a degree of wellbore collapse of the drilled well according to the construction status of the drilled well; a drilling risk assessment unit, configured to determine a drilling risk corresponding to a density of a drilling fluid to be drilled in the target formation according to the construction risk level and the rock failure criterion; The wellbore collapse degree includes the wellbore collapse width and well diameter at all wellbore depths; The rock failure criterion is further selected based on the rock mechanics parameter calculation model, the ground stress parameter calculation model, the degree of wellbore collapse of the drilled well in the target formation and the drilling fluid density of the drilled well. Based on each candidate rock failure criterion, a curve of formation collapse pressure versus wellbore depth for each candidate rock failure criterion is calculated according to the wellbore collapse width at each wellbore depth, the rock mechanics parameter calculation model, and the in-situ stress parameter calculation model; Selecting the rock failure criterion from the candidate rock failure criteria based on the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and a curve of the formation collapse pressure varying with wellbore depth; The rock failure criterion is selected from the candidate rock failure criteria according to the drilling fluid density of the drilled well, the well diameter at each wellbore depth, and the curve of the formation collapse pressure varying with the wellbore depth, further comprising: Based on the curve of the formation collapse pressure varying with the wellbore depth, calculating the difference between the formation collapse pressure of each candidate rock failure criterion and the density of the drilling fluid in the wellbore, the formation collapse pressure and the density of the drilling fluid in the wellbore being at the same wellbore depth; Determine whether the difference at the same wellbore depth is consistent with the wellbore diameter at the wellbore depth; if so, record the number of consistent values; The rock failure criterion with the largest number of compliances is selected from the candidate rock failure criterions.

8. A computer device comprising a memory, a processor, and a computer program stored in the memory, characterized in that: When the processor executes the computer program, the method according to any one of claims 1 to 6 is implemented.

9. A computer storage medium having a computer program stored thereon, characterized in that: When the computer program is executed by a processor of a computer device, the method according to any one of claims 1 to 6 is executed.

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