A method for predicting stress gradient of artificial fracture extension

Abstract

The present application relates to a kind of artificial fracture extension stress gradient prediction method, belong to the field of petroleum engineering, including: collection basic data;Calculate the overburden stress of reservoir section;Obtain formation real pore pressure;Calculate rock mechanics parameters;Calculate geostress, including maximum horizontal principal stress and minimum horizontal principal stress;Calculate wellbore stability parameters, including reservoir section formation breakdown pressure and reservoir section formation collapse pressure, and based on actual drilling leakage parameter correction reservoir section's leakage pressure, based on actual drilling hole diameter data, correction reservoir section's collapse pressure;Calculate the artificial fracture extension stress gradient of reservoir reconstruction well section.The present application can accurately obtain the artificial fracture extension stress gradient size of the rock of reservoir section, provide basis for completion equipment optimization design and reservoir reconstruction parameter optimization, to realize efficient reconstruction and production increase.

Description

Technical Field

[0001] This invention relates to a method for predicting the stress gradient of artificial crack propagation, belonging to the field of petroleum engineering technology. Background Technology

[0002] The artificial fracture extension stress gradient is a crucial engineering parameter in well completion and testing in the petroleum engineering industry. This parameter represents the rock-physical properties of an oil and gas reservoir obtained through artificial intervention. It is a critical foundational parameter for evaluating the difficulty of artificial fracture extension, optimizing well completion string configuration, selecting wellhead equipment grades, and accurately predicting reservoir stimulation flow rate and pump pressure. It directly impacts whether the oil and gas reservoir can be fully stimulated and whether the well can achieve its expected production capacity. A low prediction of this parameter may lead to an under-configured well testing string, resulting in excessive string friction and insufficient reservoir stimulation flow rate, hindering full reservoir stimulation and hindering industrial oil and gas production. Conversely, a high prediction may result in excessive test string margins and over-configured wellhead equipment, leading to significant economic waste.

[0003] Current technologies mostly rely on empirical methods for prediction, specifically referencing the artificial fracture extension stress gradient values ​​obtained from adjacent wells that have already been stimulated in the reservoir, to design the completion string and reservoir stimulation parameters for new wells. This method works well when reservoir characteristics are similar or under the same stimulation conditions. However, its accuracy drops significantly when the reservoirs of the new and old wells belong to different structures and geological strata, or when the new well is far from the old well. Another method for obtaining the artificial fracture extension stress gradient in a new well is small-scale fracturing testing. However, by the time the well site is ready for testing, the completion string has usually been inserted and on-site reservoir stimulation preparations have been completed, resulting in a significant time lag. This only allows for limited real-time optimization of on-site operations and cannot fundamentally reduce costs and increase efficiency for the entire completion and reservoir stimulation plan from the design stage. Summary of the Invention

[0004] To address the shortcomings of existing technologies, this invention proposes a method for predicting the stress gradient of artificial fracture extension. This method can accurately obtain the magnitude of the stress gradient of artificial fracture extension in reservoir rock, providing a basis for the optimized design of well completion equipment and the selection of reservoir stimulation parameters, thereby achieving efficient stimulation and production improvement.

[0005] The present invention adopts the following technical solution:

[0006] A method for predicting the stress gradient of artificial crack propagation includes the following steps:

[0007] S1, collect basic data, including well logging data and basic data related to drilling engineering;

[0008] S2, calculate the overburden stress of the reservoir section;

[0009] S3, obtain the true pore pressure of the formation. ;

[0010] S4, Calculate rock mechanical parameters, including shear modulus. bulk modulus Young's modulus Poisson's ratio Shear strength, tensile strength of rock, cohesion of rock, and internal friction angle of rock, etc.

[0011] S5, calculates the geostress, including the maximum and minimum horizontal principal stresses;

[0012] S6, calculate wellbore stability parameters, including formation fracturing pressure and formation collapse pressure in the reservoir section, and correct the leakage pressure in the reservoir section based on actual drilling leakage parameters, and correct the collapse pressure in the reservoir section based on actual drilling caliber data;

[0013] S7. Using the fracture pressure and leakage pressure corrected in step S6 as constraints, calculate the artificial fracture extension stress gradient of the reservoir stimulation section.

[0014] Preferably, in step S1, the logging data includes resistivity curves, sonic transit time curves, and density logging; the basic data related to drilling engineering include reservoir section ground failure test data, actual well diameter data, and reservoir drilling loss information, etc.

[0015] The above logging data and drilling engineering related basic data are organized into two-dimensional data according to the drilling depth, that is, organized sequentially along the well depth to form a continuous curve along the well depth, which serves as the basis for subsequent calculations and corrections.

[0016] Preferably, in step S2, the overlying stress The calculation formula is:

[0017]

[0018] in, Indicates the current depth; Indicates the current depth Density logging is a curve value continuously recorded along the well depth, and the formation density value is different at different depths; Represents the gravitational acceleration constant; Indicates the logging depth.

[0019] Preferably, step S3 includes:

[0020] S31, using the Eaton method, the pore pressure of the reservoir section is calculated using resistivity curves and acoustic transit time curves respectively;

[0021] S32, Collect formation pore pressure from formation test data of adjacent wells to the target well;

[0022] S33. Taking into account the reservoir pore pressure calculated from the resistivity curve and the sonic transit time curve respectively, the value that is closer to the formation pore pressure obtained in step S32 is selected as the true formation pore pressure. .

[0023] In this invention, by comparing the pore pressure curves calculated using resistivity curves and acoustic transit time curves, we can see which one is closer to the true value of the formation (formation pore pressure), thus obtaining a highly reliable pore pressure calculation method.

[0024] Preferably, in step S4, the shear modulus The formula is as follows:

[0025]

[0026] This indicates density logging; sonic transit time curves include shear wave transit time curves and longitudinal wave transit time curves. Represents the transverse wave time difference curve;

[0027] bulk modulus The formula is as follows:

[0028]

[0029] Represents the P-wave time difference curve;

[0030] Young's modulus The formula is as follows:

[0031]

[0032] Poisson's ratio The formula is as follows:

[0033] .

[0034] Cohesion, internal friction angle, and shear strength are usually obtained by direct or indirect calculation using well logging data, and the resulting parameters are all continuous curves along the well depth.

[0035] Preferably, in step S5, the maximum horizontal principal stress ;

[0036] Minimum horizontal principal stress ;

[0037] in, Poisson's ratio, For overlying stress, This is the Biot coefficient, which can be empirically determined, generally between 0.8 and 1. The more fractured the strata, the smaller the value; the denser the strata, the closer the value is to 1. This represents the actual pore pressure of the formation. For Young's modulus, The strain generated in the direction of the maximum horizontal principal stress; The strain is generated in the direction of the minimum horizontal principal stress.

[0038] Preferably, the implementation process of step S6 is as follows:

[0039] S61, Rupture Pressure The calculation formula is as follows:

[0040]

[0041] In the formula, Tensile strength of rock;

[0042] S62, collapse pressure The calculation formula is as follows:

[0043]

[0044] For rock cohesion, The internal friction angle of the rock;

[0045] S63, Joint Correction:

[0046] Adjust the Biot coefficient in the minimum horizontal principal stress calculation formula based on the equivalent density of actual drilling leakage pressure. This makes the calculated leakage pressure It is equal to or close to the equivalent density of actual drilling leakage pressure, thus ensuring that the calculated leakage pressure can objectively reflect the true characteristics of the formation. For example, during the drilling process of well A, a loss of drilling fluid occurred at a depth of 6100 meters, with a loss of 22 cubic meters of drilling fluid and a drilling fluid density of 1.96 g / cm³. 3 (i.e., leakage pressure equivalent density), and the leakage pressure equivalent calculated for this well at 6100 meters is 1.80 g / cm³. 3 Comparing the two, it is evident that the calculated leakage pressure equivalent is generally too low, and relevant parameters need to be adjusted so that the calculated leakage pressure equivalent at 6100 meters is equal to or close to the actual drilling leakage pressure equivalent density. This would allow the calculated leakage pressure to objectively reflect the true characteristics of the formation. Due to the uncertainty of each well, the Biot coefficient or tectonic stress coefficient are empirical values ​​and may have errors. Therefore, the calculated results may differ from the actual situation and require fine-tuning to ensure that the single-well calculation results are consistent with the actual drilling conditions.

[0047] Simultaneously, based on actual wellbore data, the formation collapse pressure in the reservoir section was corrected, and the calculated collapse pressure was adjusted accordingly. Adjust the collapse pressure by comparing it with the actual drilled density in the actual drilled well caliper data. In the calculation formula , and Biot coefficient This makes the calculated collapse pressure of the reservoir section... If the density in this reservoir section is higher than the actual drilling density, it is assumed that the calculated collapse pressure can objectively characterize the formation characteristics. For example, during the drilling process of a certain well B, a collapse occurred at a depth of 6100-6110 meters. The actual drilling diameter data shows that the diameter at this depth is significantly increased, such as an increase of 15%. Based on the comparison between the collapse pressure calculated in step S62 and the actual drilling density, the parameters such as the structural stress coefficient and Biot coefficient in the collapse pressure calculation formula are adjusted so that the calculated collapse pressure in this well section is higher than the actual drilling density.

[0048] Comprehensive regulation , and Biot coefficient When the following conditions are met simultaneously: leakage pressure Equivalent to the actual drilling leakage pressure equivalent density, the collapse pressure of the reservoir section. The control was completed when the density in the reservoir section exceeded the actual drilling density.

[0049] S64, according to the adjusted , and Biot coefficient Recalculate the corrected leakage pressure and rupture pressure .

[0050] Preferably, step S7 includes:

[0051] S71, Crack Propagation Stress = , where a+b=1, where a represents the leakage pressure weighting coefficient and b represents the rupture pressure weighting coefficient, which are obtained from the block characteristics statistics. Generally, a=b=0.5 is assumed. The curve of the change of each crack extension stress with depth is obtained through S71, that is, the crack extension stress curve.

[0052] S72, Based on the crack propagation stress curve calculated in step S71, the crack propagation stress value of the modified section is taken as the average value of the crack propagation stress curve of the modified section.

[0053] S73, convert the fracture propagation stress value of the modified section determined in step S72 into an propagation stress gradient. In this field, the fracture propagation stress value of the modified section is also called the average fracture propagation equivalent density value, that is, the fluid column pressure value at the corresponding well depth under this density, with units of g / cm³. 3The unit of stress gradient extension is MPa / 100m. For example, the average fracture extension stress (equivalent density value) at a depth of 5000 meters is 2.35 g / cm³. 3 Converted to MPa, it is 2.35 × 0.00981 (coefficient) × 5000 = 115.2675 MPa, which is equivalent to an extension stress gradient of 2.30535 MPa / 100m.

[0054] Due to the influence of natural fracture development or high porosity, the existing technology of directly using leakage pressure / minimum horizontal principal stress as the extended stress gradient for reservoir stimulation tends to be too low. In actual design, the difficulty of reservoir stimulation is underestimated, resulting in increased actual construction difficulty, incomplete and insufficient reservoir stimulation, and reduced production improvement.

[0055] Using fracture pressure as the extended stress gradient can lead to an overestimation of the reservoir stimulation difficulty in reservoir stimulation design, resulting in economic waste such as excessive tubing configuration and overly large stimulation scale.

[0056] In reservoir stimulation design, the extended stress gradient is often derived from the pressure gradient of adjacent wells after pump shutdown. This method has a significant margin of error. No matter how similar an adjacent well may be, it cannot replace the pressure gradient of the current well.

[0057] This invention cleverly utilizes wellbore stability parameters and, combined with well stimulation requirements, calculates the well's leakage pressure and fracture pressure to estimate the reservoir extension stress gradient using the well's drilling data. Compared to borrowing parameter values ​​from adjacent wells, this method more closely reflects the objective conditions of the current well and offers higher accuracy.

[0058] For any details not covered in this invention, please refer to the prior art.

[0059] The beneficial effects of this invention are as follows:

[0060] The artificial fracture extension stress gradient prediction method of this invention utilizes actual drilling leakage parameters, actual drilling caliper data, and well logging data of the reservoir section after drilling completion. Through rock mechanics parameter calculation and in-situ stress calculation, it ultimately obtains the wellbore stability parameters of the reservoir section, including collapse pressure, leakage pressure, and fracture pressure, thereby achieving a quantitative evaluation of formation wellbore stability characteristics. Based on the calculated wellbore stability parameters, an accurate formation fracture extension stress gradient can be further obtained.

[0061] The method of this invention achieves precise calculation and is more scientific and accurate than previous wellbore methods that directly borrow pressure gradients from adjacent wells or take averages from multiple wells. Using this method, it has been applied to over 20 exploration and appraisal wells with limited data. Comparing the data after drilling, the extended stress gradient calculated by this invention significantly reduces the prediction error from 15% to less than 8% compared to previous empirical methods. This significant reduction in error is of great reference value for the economic optimization of completion tubing and reservoir stimulation parameters (pump pressure prediction, stimulation scale), enabling reduced tubing costs and economical and efficient single-well stimulation to increase production. Attached Figure Description

[0062] The accompanying drawings, which form part of this application, are used to provide a further understanding of this application. The illustrative embodiments of this application and their descriptions are used to explain this application and do not constitute an undue limitation of this application.

[0063] Figure 1 This is a flowchart of the artificial crack propagation stress gradient prediction method of the present invention;

[0064] Figure 2 This is a schematic diagram of the calculation results of the artificial crack extension stress gradient according to a certain embodiment of the present invention. Detailed Implementation

[0065] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this invention will be clearly and completely described below with reference to the accompanying drawings. However, this is not the only description; all aspects not described in detail herein are based on conventional techniques in the art.

[0066] Example 1

[0067] A method for predicting stress gradients in artificial crack propagation, such as Figure 1 As shown, it includes the following steps:

[0068] S1, collect basic data, including well logging data and basic data related to drilling engineering;

[0069] Well logging data includes resistivity curves, sonic transit time curves, and density logging; basic data related to drilling engineering include reservoir section ground failure test data, actual well diameter data, and information on leakage during reservoir drilling, etc.

[0070] The above logging data and drilling engineering related basic data are organized into two-dimensional data according to the drilling depth, that is, organized sequentially along the well depth to form a continuous curve along the well depth, which serves as the basis for subsequent calculations and corrections.

[0071] S2, calculate the overburden stress of the reservoir section;

[0072] Overlying stress The calculation formula is:

[0073]

[0074] in, Indicates the current depth; Indicates the current depth Density logging; Represents the gravitational acceleration constant; Indicates the logging depth.

[0075] S3, obtain the true pore pressure of the formation. Specifically:

[0076] S31, using the Eaton method, the pore pressure of the reservoir section is calculated using resistivity curves and acoustic transit time curves respectively;

[0077] S32, Collect formation pore pressure from formation test data of adjacent wells to the target well;

[0078] S33. Taking into account the reservoir pore pressure calculated from the resistivity curve and the sonic transit time curve respectively, the value that is closer to the formation pore pressure obtained in step S32 is selected as the true formation pore pressure. .

[0079] In this invention, by comparing the pore pressure curves calculated using resistivity curves and acoustic transit time curves, we can see which one is closer to the true value of the formation (formation pore pressure), thus obtaining a highly reliable pore pressure calculation method.

[0080] S4, Calculate rock mechanical parameters, including shear modulus. bulk modulus Young's modulus Poisson's ratio Shear strength, tensile strength of rock, cohesion of rock, and internal friction angle of rock, etc.

[0081] shear modulus The formula is as follows:

[0082]

[0083] This indicates density logging; sonic transit time curves include shear wave transit time curves and longitudinal wave transit time curves. Represents the transverse wave time difference curve;

[0084] bulk modulus The formula is as follows:

[0085]

[0086] Represents the P-wave time difference curve;

[0087] Young's modulus The formula is as follows:

[0088]

[0089] Poisson's ratio The formula is as follows:

[0090] .

[0091] Cohesion, internal friction angle, and shear strength are usually obtained by direct or indirect calculation using well logging data, and the resulting parameters are all continuous curves along the well depth.

[0092] S5, calculates the geostress, including the maximum and minimum horizontal principal stresses;

[0093] Maximum horizontal principal stress ;

[0094] Minimum horizontal principal stress ;

[0095] in, Poisson's ratio, For overlying stress, This is the Biot coefficient, which can be empirically determined, generally between 0.8 and 1. The more fractured the strata, the smaller the value; the denser the strata, the closer the value is to 1. This represents the actual pore pressure of the formation. For Young's modulus, The strain generated in the direction of the maximum horizontal principal stress; The strain is generated in the direction of the minimum horizontal principal stress.

[0096] S6, calculate wellbore stability parameters, including formation fracturing pressure and formation collapse pressure in the reservoir section, and correct the reservoir section leakage pressure based on actual drilling leakage parameters, and correct the reservoir section collapse pressure based on actual drilling caliper data; specifically including:

[0097] S61, Rupture Pressure The calculation formula is as follows:

[0098]

[0099] In the formula, Tensile strength of rock;

[0100] S62, collapse pressure The calculation formula is as follows:

[0101]

[0102] For rock cohesion, The internal friction angle of the rock;

[0103] S63, Joint Correction:

[0104] Adjust the Biot coefficient in the minimum horizontal principal stress calculation formula based on the equivalent density of actual drilling leakage pressure. This makes the calculated leakage pressure It is equal to or close to the equivalent density of actual drilling leakage pressure, thus ensuring that the calculated leakage pressure can objectively reflect the true characteristics of the formation. For example, during the drilling process of well A, a loss of drilling fluid occurred at a depth of 6100 meters, with a loss of 22 cubic meters of drilling fluid and a drilling fluid density of 1.96 g / cm³. 3 (i.e., leakage pressure equivalent density), and the leakage pressure equivalent calculated for this well at 6100 meters is 1.80 g / cm³. 3 Comparing the two, it is evident that the calculated leakage pressure equivalent is generally too low, and relevant parameters need to be adjusted so that the calculated leakage pressure equivalent at 6100 meters is equal to or close to the actual drilling leakage pressure equivalent density. This would allow the calculated leakage pressure to objectively reflect the true characteristics of the formation. Due to the uncertainty of each well, the Biot coefficient or tectonic stress coefficient are empirical values ​​and may have errors. Therefore, the calculated results may differ from the actual situation and require fine-tuning to ensure that the single-well calculation results are consistent with the actual drilling conditions.

[0105] Simultaneously, based on actual wellbore data, the formation collapse pressure in the reservoir section was corrected, and the calculated collapse pressure was adjusted accordingly. Adjust the collapse pressure by comparing it with the actual drilled density in the actual drilled well caliper data. In the calculation formula , and Biot coefficient This makes the calculated collapse pressure of the reservoir section... If the density in this reservoir section is higher than the actual drilling density, it is assumed that the calculated collapse pressure can objectively characterize the formation characteristics. For example, during the drilling process of a certain well B, a collapse occurred at a depth of 6100-6110 meters. The actual drilling diameter data shows that the diameter at this depth is significantly increased, such as an increase of 15%. Based on the comparison between the collapse pressure calculated in step S62 and the actual drilling density, the parameters such as the structural stress coefficient and Biot coefficient in the collapse pressure calculation formula are adjusted so that the calculated collapse pressure in this well section is higher than the actual drilling density.

[0106] Comprehensive regulation , and Biot coefficient When the following conditions are met simultaneously: leakage pressure Equivalent to the actual drilling leakage pressure equivalent density, the collapse pressure of the reservoir section. The control was completed when the density in the reservoir section exceeded the actual drilling density.

[0107] S64, according to the adjusted , and Biot coefficient Recalculate the corrected leakage pressure and rupture pressure .

[0108] S7, using the fracture pressure and leakage pressure corrected in step S6 as constraints, calculate the artificial fracture propagation stress gradient in the reservoir stimulation section, specifically including:

[0109] S71, Crack Propagation Stress = , where a+b=1, where a represents the leakage pressure weighting coefficient and b represents the rupture pressure weighting coefficient, which are obtained from the block characteristics statistics. Generally, a=b=0.5 is assumed. The curve of the change of each crack extension stress with depth is obtained through S71, that is, the crack extension stress curve.

[0110] S72, Based on the crack propagation stress curve calculated in step S71, the crack propagation stress value of the modified section is taken as the average value of the crack propagation stress curve of the modified section.

[0111] S73, convert the fracture propagation stress value of the modified section determined in step S72 into an propagation stress gradient. In this field, the fracture propagation stress value of the modified section is also called the average fracture propagation equivalent density value, that is, the fluid column pressure value at the corresponding well depth under this density, with units of g / cm³. 3 The unit of stress gradient extension is MPa / 100m. For example, the average fracture extension stress (equivalent density value) at a depth of 5000 meters is 2.35 g / cm³. 3 Converted to MPa, it is 2.35 × 0.00981 (coefficient) × 5000 = 115.2675 MPa, which is equivalent to an extension stress gradient of 2.30535 MPa / 100m.

[0112] like Figure 2 As shown, the elongation stress of the modified section ① obtained through Example 1 above was 2.20 g / cm. 3 This translates to an elongation stress gradient of 2.20 g / cm. 3 ×0.981=2.158MPa / 100m; the extension stress of the modified section ② is 2.10g / cm. 3 This translates to an extensional stress gradient of 2.10 g / cm. 3 ×0.981=2.06MPa / 100m, which shows that the values ​​of the two reservoir stimulation sections are significantly different.

[0113] Comparative Example 1

[0114] A traditional method for obtaining extended stress gradients in reservoir sections using empirical methods, applied to predict the extended stress gradients of the same well in Example 1, includes the following steps:

[0115] A. After reviewing data from adjacent wells, it was found that there were 3 instances of sand fracturing in the reservoir of this well. The instantaneous shutdown pressure value was read from the construction curve to calculate the shutdown stress gradient. The values ​​for the 3 instances were 2.6 MPa / 100m, 2.55 MPa / 100m, and 2.2 MPa / 100m, respectively. Therefore, the stress gradients for artificial fracture extension in the reservoir section of these 3 instances are considered to be 2.6 MPa / 100m, 2.55 MPa / 100m, and 2.2 MPa / 100m, respectively.

[0116] B. The predicted well is the fourth well in the area. In order to improve the accuracy of the stress gradient of the artificial fracture extension in the reservoir, it is necessary to consider the parameters obtained from the construction of the first three wells. Therefore, it is more reasonable to take the average value of the aforementioned three wells for the fourth well. Thus, the predicted value is 2.45 MPa / 100m.

[0117] The empirical method for obtaining the stress gradient of reservoir segment extension can only obtain the stress gradient of fracture extension of the corresponding stimulated segment. For example, if the prediction of well A is made, only one value can be predicted for the reservoir segment of well A, that is, the predicted value of both reservoir stimulated segment ① and reservoir stimulated segment ② is 2.45MPa / 100m, and it is not possible to make precise predictions separately.

[0118] Construction practice was conducted to verify the wells in Example 1 and the comparative example: Well A adopted segmented sand fracturing construction, and the stress gradient of the fracture extension was calculated by reading the pump shutdown pressure, i.e. the true value. The stress gradient of the fracture extension in the modified section ① was 2.25MPa / 100m, and the stress gradient of the fracture extension in the modified section ② was 2.20MPa / 100m.

[0119] In Comparative Example 1, the predicted value of well A is 2.45 MPa / 100m. The prediction errors are 8.89% for section ① and 11.4% for section ②.

[0120] In Embodiment 1 of the present invention, the predicted stress gradient value for crack propagation in modified section ① is 2.158 MPa / 100m, and the predicted stress gradient value for crack propagation in modified section ② is 2.06 MPa / 100m. Referring to the actual values ​​from construction practice, the errors are 4.3% and 6.4%, respectively. It is evident that the method in Embodiment 1 of the present invention significantly reduces the error compared to the empirical method.

[0121] The above description represents the preferred embodiments of the present invention. It should be noted that those skilled in the art can make various improvements and modifications without departing from the principles of the present invention, and these improvements and modifications should also be considered within the scope of protection of the present invention.

Claims

1. A method for predicting the stress gradient of artificial crack propagation, characterized in that, Includes the following steps: S1, collect basic data, including well logging data and basic data related to drilling engineering; S2, calculate the overburden stress of the reservoir section; S3, Obtain the true pore pressure of the formation. ; S4, Calculate rock mechanical parameters, including shear modulus. bulk modulus Young's modulus Poisson's ratio Shear strength, tensile strength of rock, cohesion of rock, and angle of internal friction of rock; S5, calculates the geostress, including the maximum and minimum horizontal principal stresses; S6, calculate wellbore stability parameters, including formation fracturing pressure and formation collapse pressure in the reservoir section, and correct the leakage pressure in the reservoir section based on actual drilling leakage parameters, and correct the collapse pressure in the reservoir section based on actual drilling caliber data; S7. Using the fracture pressure and leakage pressure corrected in step S6 as constraints, calculate the artificial fracture extension stress gradient in the reservoir stimulation section. The implementation process of step S6 is as follows: S61, Rupture Pressure The calculation formula is as follows: In the formula, For the tensile strength of rock, Poisson's ratio, For overlying stress, For Biot coefficient, This represents the actual pore pressure of the formation. For Young's modulus, The strain generated in the direction of the maximum horizontal principal stress; The strain generated in the direction of the minimum horizontal principal stress; S62, collapse pressure The calculation formula is as follows: For rock cohesion, The internal friction angle of the rock; S63, Joint Correction: Adjust the Biot coefficient in the minimum horizontal principal stress calculation formula based on the equivalent density of actual drilling leakage pressure. This makes the calculated leakage pressure This is equal to the equivalent density of the actual drilling leakage pressure, thus ensuring that the calculated leakage pressure objectively reflects the true characteristics of the formation. ; Simultaneously, based on actual wellbore data, the formation collapse pressure in the reservoir section was corrected, and the calculated collapse pressure was adjusted accordingly. Adjust the collapse pressure by comparing it with the actual drilled density in the actual drilled well caliper data. In the calculation formula , and Biot coefficient This makes the calculated collapse pressure of the reservoir section... The density in this reservoir section is higher than that of actual drilling, meaning that the calculated collapse pressure is considered to objectively characterize the formation features. Comprehensive regulation , and Biot coefficient When the following conditions are met simultaneously: leakage pressure Equivalent to the actual drilling leakage pressure equivalent density, the collapse pressure of the reservoir section. The control was completed when the density in the reservoir section was higher than the actual drilling density; S64, according to the adjusted , and Biot coefficient Recalculate the corrected leakage pressure and rupture pressure .

2. The method for predicting the stress gradient of artificial crack propagation according to claim 1, characterized in that, In step S1, the logging data includes resistivity curves, sonic transit time curves, and density logging; the basic data related to drilling engineering include reservoir section ground failure test data, actual well diameter data, and reservoir drilling loss information.

3. The method for predicting the stress gradient of artificial crack propagation according to claim 2, characterized in that, In step S2, the overlying stress The calculation formula is: in, Indicates the current depth; Indicates the current depth Density logging; Represents the gravitational acceleration constant; Indicates the logging depth.

4. The method for predicting the stress gradient of artificial crack propagation according to claim 3, characterized in that, Step S3 includes: S31, using the Eaton method, calculates the pore pressure of the reservoir section using resistivity curves and acoustic transit time curves respectively. S32, Collect formation pore pressure from formation test data of adjacent wells to the target well; S33. Taking into account the reservoir pore pressure calculated from the resistivity curve and the sonic transit time curve respectively, the value that is closer to the formation pore pressure obtained in step S32 is selected as the true formation pore pressure. .

5. The method for predicting the stress gradient of artificial crack propagation according to claim 4, characterized in that, In step S4, the shear modulus The formula is as follows: This indicates density logging; sonic transit time curves include shear wave transit time curves and longitudinal wave transit time curves. Represents the transverse wave time difference curve; bulk modulus The formula is as follows: Represents the P-wave time difference curve; Young's modulus The formula is as follows: Poisson's ratio The formula is as follows: 。 6. The method for predicting the stress gradient of artificial crack propagation according to claim 5, characterized in that, In step S5, the maximum horizontal principal stress ; Minimum horizontal principal stress ; in, Poisson's ratio, For overlying stress, For Biot coefficient, This represents the actual pore pressure of the formation. For Young's modulus, The strain generated in the direction of the maximum horizontal principal stress; The strain is generated in the direction of the minimum horizontal principal stress.

7. The method for predicting the stress gradient of artificial crack propagation according to claim 1, characterized in that, Step S7 includes: S71, Crack Propagation Stress = , where a+b=1, where a represents the leakage pressure weighting coefficient and b represents the rupture pressure weighting coefficient, and the curve of the change of each crack extension stress with depth is obtained, that is, the crack extension stress curve. S72, Based on the crack propagation stress curve calculated in step S71, the crack propagation stress value of the modified section is taken as the average value of the crack propagation stress curve of the modified section. S73, the average crack propagation stress of the modified section determined in step S72 is converted into the propagation stress gradient.

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