Carbonate rock stratum crustal stress interpretation method

Abstract

The invention relates to a carbonate rock stratum crustal stress interpretation method, and belongs to the technical field of oil-gas field development engineering reservoir transformation. The interpretation process comprises the steps that firstly, a volume model is established, and the shale content of the carbonate rock stratum, the volume content of all minerals, the rock matrix porosity and the fracture hole series degree are interpreted through logging information; then, according to the shale content of the rock and the volume content of each mineral, calculating the transverse and longitudinal wave time difference of the skeleton, and calculating the transverse wave time difference of the rock according to the transverse and longitudinal wave time difference; secondly, according to the shale content of the rock and the volume content of each mineral, converting the dynamic rock mechanical parameters into static rock mechanical parameters by adopting multiple regression; the formation pressure is calculated according to an Eaton method; and finally, calculating vertical stress by using density and calculating maximum and minimum horizontal principal stress by using a combined spring model. According to the method, more accurate crustal stress data are provided for acid fracturing construction transformation of the carbonate reservoir.

Description

Technical Field

[0001] The invention relates to a carbonate rock formation in-situ stress interpretation method, belonging to the technical field of reservoir transformation in oil and gas field development engineering. Background Art

[0002] The current geostress is an important data support for the deployment of wells, prediction of wellbore deformation, reservoir fracturing and transformation in the exploration and development of unconventional oil and gas reservoirs such as tight sandstone gas. It is also an important theoretical basis for studying underground stress state, analyzing regional oil and gas migration and understanding regional oil and gas distribution characteristics. Geostress is generally composed of tectonic stress, gravity stress, thermal stress, pore pressure and other couplings. Its state is usually expressed by three normal stresses, namely the maximum horizontal principal stress, vertical principal stress and minimum horizontal principal stress. The magnitude and direction of geostress in different regions and different depths of the crust change with space and time, forming the current geostress field. Under the influence of various control factors, underground stress is unevenly distributed. Therefore, clarifying the distribution law of the current geostress field is the key to developing shale reservoirs.

[0003] At present, the commonly used interpretation of vertical stress at home and abroad is to establish the relationship between pressure coefficient and burial depth, and then obtain the formation pressure. The horizontal geostress interpretation models are mainly uniaxial strain models and anisotropic formation models. The first type of geostress calculation model mainly includes: Kinnick model, Matthews and Kelly model, Terzaghi model, Anderson geostress calculation model and Neberry modified Anderson model; the second type of geostress calculation model mainly includes: Huang model, combined spring model, differential model, etc.; anisotropic formation models better consider the horizontal tectonic stress and most of them introduce mechanical parameters such as Poisson's ratio and Young's modulus to calculate the maximum and minimum tectonic stress components of vertical stress in the horizontal direction, and then determine the maximum and minimum horizontal principal stress. The above method can be used to calculate the geostress, but the lithology differences of different rocks are not taken into account, which makes the geostress calculated by different rocks have errors, especially for the logging interpretation of geostress in complex carbonate formations. Summary of the invention

[0004] The purpose of the present invention is to provide a carbonate formation in-situ stress interpretation method to solve the problem of inaccurate interpretation of in-situ stress in complex carbonate formations using well logging data.

[0005] To achieve the above objectives, the technical solutions and beneficial effects of the present invention include:

[0006] A carbonate rock formation in-situ stress interpretation method of the present invention comprises the following steps:

[0007] 1) Based on the carbonate rock mineral content and porosity interpretation method, the rock mud mineral content V of the carbonate rock formation is obtained sh , Volume content of each mineral composition Rock matrix porosity and rock fracture porosity Said where i = 1, 2, 3…n, n is the number of mineral species in the carbonate reservoir;

[0008] 2) Based on the interpreted V of carbonate formations sh and Calculate the skeleton longitudinal wave time difference Δt mac and the time difference of the skeleton shear wave Δt mas , according to Δt mas and Δt mac The rock shear wave time difference Δt is calculated using the longitudinal and shear wave conversion formula. s ;

[0009] 3) Using Δt s The time difference with rock longitudinal wave Δt c Calculate the dynamic Young's modulus E d and the dynamic Poisson's ratio θ d , based on the constructed static Young's modulus E and E d , and V sh E is calculated based on the relationship between the constructed static Poisson's ratio θ and θ d , and V sh The relationship between is calculated to obtain θ;

[0010] 4) Calculate the formation pressure P based on the acoustic logging data p ;

[0011] 5) Calculate vertical stress σ based on density logging data v , based on the combined spring model and combined with σ v , E, θ and P p , calculate the maximum horizontal principal stress σ H and the horizontal minimum principal stress σ h .

[0012] The beneficial effects of the above scheme are as follows: first, based on the volume model, the mineral composition, content and porosity are interpreted using logging parameters such as the photoelectric absorption cross-section index, the skeleton longitudinal wave time difference and shear wave time difference are calculated based on the mineral composition and content, and the rock shear wave time difference is fitted, thereby improving the interpretation accuracy of the shear wave time difference; when converting dynamic and static rock mechanics parameters, the mineral content is introduced for multivariate regression, thereby improving the interpretation accuracy of static rock mechanics parameters; the Eaton method is used to interpret formation pressure, the combined spring model is used to interpret the magnitude of ground stress, and the static rock mechanics parameters determined based on mineral changes are substituted, thereby achieving accurate stress interpretation of carbonate rock formations.

[0013] As a further improvement of the scheme, the static Young's modulus E and E were constructed by using the multivariate regression method. d , and V sh The relationship between them is modeled as follows:

[0014]

[0015] Where a, b, c, and d are the multiple regression fitting coefficients.

[0016] The beneficial effects of the above scheme are: the dynamic Young's modulus is calculated, and the correspondence between the static Young's modulus and the dynamic Young's modulus, the rock mud mineral content of the carbonate rock formation and the volume content of each mineral component can be quickly and accurately obtained by multivariate regression. The static Young's modulus E is further calculated using the relationship model, thereby improving the interpretation accuracy of static rock mechanics parameters.

[0017] As a further improvement to the scheme, multiple regression method is used to construct θ and θ d , and V sh The relationship model is:

[0018]

[0019] Where e, fi, g, and h are the multiple regression fitting coefficients.

[0020] The beneficial effects of the above scheme are: the dynamic Poisson's ratio is calculated, and the corresponding relationship between the static Poisson's ratio and the dynamic Poisson's ratio, the rock mud mineral content of the carbonate rock formation and the volume content of each mineral component can be quickly and accurately obtained by multivariate regression. The static Poisson's ratio is further calculated using the relationship model, thereby improving the interpretation accuracy of static rock mechanical parameters.

[0021] As a further improvement of the scheme, V sh , and The steps include:

[0022] A. According to the natural gamma ray intensity index SH of the target layer, V is calculated sh , the calculation formula is:

[0023]

[0024]

[0025] In the formula, GR max and GR min They are the maximum and minimum values ​​of the natural gamma curve, and GR is the natural gamma reading of the mud-bearing target layer;

[0026] B. Based on the drilling fluid filtrate conductivity in the logging data, the Archie formula is used to calculate The calculation formula is:

[0027]

[0028] In the formula, σ LLD and σ LLS are the deep lateral conductivity and shallow lateral conductivity, σ mf and σ w are the conductivity of drilling fluid filtrate and formation water, respectively, and mf is the porosity index of the fracture;

[0029] C. According to V sh and The rock volume balance model was used to calculate and The calculation formula is:

[0030]

[0031] In the formula, Δt f , Δt sh , Δt mai and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data, Pe f 、Pe sh 、Pe mai and Pe are the photoelectric absorption cross-section index values ​​of fluid, mud, the photoelectric absorption cross-section index value of the ith mineral and the photoelectric absorption cross-section index value in the lithology density logging data, respectively. f 、CNL sh 、CNL mai and CNL are the neutron value of fluid, neutron value of shale, neutron value of the i-th mineral and neutron value in neutron logging data, respectively.

[0032] The beneficial effects of the above scheme are as follows: First, the rock fracture porosity is calculated using the Archie formula based on the drilling fluid filtrate conductivity in the logging data. Then, the rock mud mineral content V is calculated based on the natural gamma ray intensity index SH of the target layer. sh ,in accordance with With V sh Calculate the rock matrix porosity Finally, according to V sh and The rock volume balance model was used to calculate and Provide a basis for subsequent geostress calculations.

[0033] As a further improvement to the scheme, according to Δt mas and Δt max Calculate Δt using the longitudinal and transverse wave conversion formula s The calculation formula is: In the formula, Δt fs is the shear wave time difference of the pore fluid, Δt fc is the time difference of the longitudinal wave of the pore fluid, Δt c is the rock longitudinal wave time difference;

[0034] Where Δt mas The calculation formula is: Where Δt shs is the time difference of mud shear wave, Δt masi is the shear wave time difference value of the i-th mineral;

[0035] Where Δt mac The calculation formula is: In the formula, Δt shc is the time difference of mud longitudinal wave, Δt maci is the longitudinal wave time difference value of the ith mineral.

[0036] The beneficial effects of the above scheme are: according to the content of mud minerals V sh And the volume content of each mineral composition Indirectly calculate the rock shear wave time difference Δt s , which provides a basis for the calculation of dynamic Young's modulus and dynamic Poisson's ratio involved in the calculation of geostress.

[0037] As a further improvement to the scheme, the formation pressure P p The calculation formula is: p =G p ·H, where H is the measured depth, G p is the formation pressure gradient, and its calculation formula is:

[0038]

[0039] In the formula, G o is the static rock pressure gradient of the overlying strata, MPa / 100m; G w is the hydrostatic pressure gradient of formation water, MPa / 100m; Δt c is the measured value of the longitudinal wave time difference at the observation point, μs / m; Δt cn is the corresponding value of the longitudinal wave time difference on the normal compaction trend line at the same depth, μs / m; c is the compaction index.

[0040] The beneficial effects of the above scheme are: the formation pressure gradient G is calculated based on the acoustic logging data. p , using the formation pressure gradient G p The formation pressure P is calculated from the measured depth p , is the maximum horizontal principal stress σ H Provides basis for calculation.

[0041] As a further improvement to the scheme, σ v The calculation formula is: Where, ΔD i is the thickness of the stratum in the i-th section; ρ i is the average volume density of the ith section on the density logging curve; g is the gravitational acceleration.

[0042] As a further improvement to the scheme, σ H The calculation formula is:

[0043]

[0044] Where α is the effective stress coefficient, β1 is the strain of the rock formation in the direction of maximum horizontal stress, and β2 is the strain of the rock formation in the direction of minimum horizontal stress.

[0045] The beneficial effects of the above scheme are: based on the combined spring model and combined with σ v , E, θ and P p , calculate the maximum horizontal principal stress σ H , achieving accurate interpretation of the ground stress in carbonate formations.

[0046] As a further improvement to the scheme, σ h The calculation formula is:

[0047]

[0048] Where α is the effective stress coefficient, β1 is the strain of the rock formation in the direction of maximum horizontal stress, and β2 is the strain of the rock formation in the direction of minimum horizontal stress.

[0049] The beneficial effects of the above scheme are: based on the combined spring model and combined with σ v, E, θ and P p , calculate the minimum horizontal principal stress σ h , achieving accurate interpretation of the ground stress in carbonate formations.

[0050] As a further improvement to the scheme, the calculation formula of α is: BRIEF DESCRIPTION OF THE DRAWINGS

[0051] Figure 1 It is a cross-sectional diagram of the comprehensive interpretation of geostress logging of the present invention;

[0052] Figure 2 It is a well logging interpretation comparison diagram of the present invention. DETAILED DESCRIPTION

[0053] In order to make the purpose, technical solutions and advantages of the present invention more clear, the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments.

[0054] The purpose of the present invention is to provide a method for interpreting in-situ stress in carbonate rock formations, so as to solve the problems that the shear wave fitting is inaccurate due to the strong heterogeneity of carbonate rock formations, and the inaccurate interpretation of static rock mechanics parameters affects the in-situ stress interpretation results.

[0055] An embodiment of a carbonate rock formation in-situ stress interpretation method:

[0056] like Figure 1 As shown, this embodiment implements geostress logging interpretation through the following steps:

[0057] Step 1: Based on the carbonate rock mineral content and porosity interpretation method, the basic physical property parameters of the carbonate rock formation are interpreted using logging data to obtain the rock shale mineral content V of the carbonate rock formation. sh , Volume content of each mineral composition Rock matrix porosity and rock fracture porosity and will obtain and V sh as the final explanation.

[0058] Specifically, the basic physical property parameters of carbonate formations are interpreted using well logging data, wherein the well logging data include: sonic logging data, lithology density logging data, neutron logging data and resistivity logging data;

[0059] Obtain the rock mud mineral content V of the carbonate rock formation sh , Volume content of each mineral composition Rock matrix porosity and rock fracture porosity The process is:

[0060] Obtain rock mud mineral content V sh The calculation formula is:

[0061]

[0062]

[0063] In the formula, GR max and GR min are the maximum and minimum values ​​of the natural gamma curve, respectively, and are the prior values; GR is the natural gamma reading of the muddy target layer, and is the natural gamma logging data; SH is the natural gamma ray intensity index of the target layer.

[0064] Rock fracture porosity According to the drilling fluid filtrate conductivity in the logging data, Archie's formula is used to calculate it. The calculation formula is:

[0065]

[0066] In the formula, σ LLD and σ LLS are the deep lateral conductivity and shallow lateral conductivity respectively, and are the inverse of the resistivity logging data, σ mf and σ w are the conductivity of drilling fluid filtrate and formation water, respectively, are the logging data, mf is the porosity index of the fracture, and is the prior value;

[0067] Rock matrix porosity of carbonate reservoirs and the volume content of each mineral composition in carbonate reservoirs According to the rock argillaceous mineral content V sh and rock fracture porosity It is calculated using the macro rock volume balance model, and the calculation formula is:

[0068]

[0069] In the formula, is the volume content of the i-th mineral, Δt f , Δt sh , Δt mai and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data; Pe f 、Pe sh 、Pe mai and Pe are the photoelectric absorption cross-section index values ​​of fluid, mud, the photoelectric absorption cross-section index value of the ith mineral and the photoelectric absorption cross-section index value in the lithology density logging data, respectively; ρ f , sh ,mai and ρ b are the fluid density, shale density, density of the i-th mineral and density in the density logging data; CNL f 、CNL sh 、CNL mai and CNL are the neutron values ​​of fluid, shale, the neutron value of the i-th mineral and the neutron value in neutron logging data, respectively; where Pe, ρ b , Δt and CNL are the logging data of lithology density logging, density logging, compensated sonic velocity logging and compensated neutron logging respectively. Δt f , Δt sh , Δt mai 、Pe f 、Pe sh 、Pe mai , f , sh , mai 、CNL f 、CNL sh 、CNL mai is a priori value; i = 1, 2, 3, …, n, n is the number of mineral species in the carbonate reservoir;

[0070] Step 2: Based on the interpreted rock argillaceous mineral content V of the carbonate formation sh And the volume content of each mineral composition Using the volume model, the skeleton longitudinal wave time difference Δt is calculated mac and the time difference of the skeleton shear wave Δt mas , the rock shear wave time difference Δt is calculated using the longitudinal and shear wave conversion formula s .

[0071] Specifically, the skeleton shear wave time difference Δt mas The calculation formula is:

[0072]

[0073] In the formula, is the volume content of the i-th mineral, Δt shs , Δt masi They are respectively the shear wave time difference value of mud and the shear wave time difference value of the i-th mineral (which can be obtained through logging data query);

[0074] Skeleton longitudinal wave time difference Δt mac The calculation formula is:

[0075]

[0076] In the formula, is the volume content of the i-th mineral, Δt shc , Δtmaci They are the longitudinal wave time difference value of mud and the longitudinal wave time difference value of the i-th mineral (which can be obtained through logging data query);

[0077] Rock shear wave time difference Δt s According to the skeleton shear wave time difference Δt mas The time difference with the skeleton longitudinal wave Δt mac The calculation formula is:

[0078]

[0079] In the formula, Δt s is the rock shear wave time difference, Δt mas is the time difference of the skeleton shear wave, Δt fs is the shear wave time difference of the pore fluid, Δt c is the rock longitudinal wave time difference, Δt fc is the time difference of the longitudinal wave of the pore fluid, Δt max is the skeleton longitudinal wave time difference;

[0080] Step 3: Based on the interpreted rock argillaceous mineral content V of the carbonate formation sh And the volume content of each mineral composition Using multiple regression, the dynamic Young's modulus E from well logging interpretation d and Poisson's ratio θ d The static Young's modulus E and Poisson's ratio θ measured experimentally were fitted to establish the conversion formula between dynamic and static Young's modulus and Poisson's ratio, and the static Young's modulus E and static Poisson's ratio θ were obtained.

[0081] Specifically, the steps for interpreting static Young's modulus and Poisson's ratio are as follows:

[0082] 1) Calculate the dynamic Poisson's ratio θ d , and its calculation formula is: In the formula, Δt c is the rock longitudinal wave time difference; Δt s is the rock shear wave time difference;

[0083] 2) Calculate the dynamic Young's modulus E d , its calculation formula is: In the formula, ρ b is the density logging value; Δt c is the rock longitudinal wave time difference; Δt s is the rock shear wave time difference;

[0084] 3) According to multiple regression, the dynamic and static conversion formula is established, and the calculation formulas for static Young's modulus E and static Poisson's ratio θ are as follows:

[0085]

[0086]

[0087] In the formula, a, b i , c, d, e, f i , g, and h are the multiple regression fitting coefficients.

[0088] Step 4: Calculate the formation pressure gradient G using the Eaton method based on the acoustic logging data p and formation pressure P p (pore pressure).

[0089] Specifically, the formation pressure gradient G p The calculation formula is:

[0090] In the formula, G o is the static rock pressure gradient of the overlying strata, MPa / 100m; G w is the hydrostatic pressure gradient of formation water, MPa / 100m; Δt c is the measured value of the longitudinal wave time difference at the observation point, μs / m; Δt cn is the corresponding value of the P-wave time difference on the normal compaction trend line at the same depth, μs / m; c is the compaction index, obtained by fitting the measured pressure and the P-wave time difference; H is the measured depth, m; G p is the formation pressure gradient, MPa / 100m;

[0091] Step 5: Calculate the vertical stress σ using the integral method based on the density logging data v According to the combined spring model, the static Young's modulus E and static Poisson's ratio θ interpreted by well logging, as well as the formation pressure P p Parameters such as the horizontal maximum principal stress σ H and the horizontal minimum principal stress σ h .

[0092] Specifically, the vertical principal stress σ v The calculation formula is:

[0093] Where, ΔD i is the thickness of the stratum in the i-th section, m; ρ i is the average bulk density of the i-th segment on the density logging curve, g / cm 3 ; g is the acceleration due to gravity, m / s 2 .

[0094] According to the combined spring model, the maximum horizontal principal stress σ H The calculation formula is:

[0095]

[0096] In the formula, σ vis the vertical principal stress, MPa; P p is the pore pressure, MPa; θ is the static Poisson's ratio; α is the effective stress coefficient, which is equivalent to the porosity; E is the static Young's modulus, GPa; β1 is the strain of the rock formation in the direction of maximum horizontal stress, obtained experimentally; β2 is the strain of the rock formation in the direction of minimum horizontal stress, obtained experimentally.

[0097] According to the combined spring model, the horizontal minimum principal stress σ h The calculation formula is:

[0098]

[0099] In the formula, σ v is the vertical principal stress, MPa; P p is the pore pressure, MPa; θ is the static Poisson's ratio; α is the effective stress coefficient; E is the static Young's modulus, GPa; β1 is the strain of the rock formation in the direction of maximum horizontal stress, obtained experimentally; β2 is the strain of the rock formation in the direction of minimum horizontal stress, obtained experimentally.

[0100] Specifically, the effective stress coefficient α can be calculated using the porosity interpreted by well logging: Calculation, the calculation formula is:

[0101]

[0102] refer to Figure 2 It can be seen that the shear wave time difference explained by the present invention is higher in interpretation accuracy than the shear wave time difference extracted by the full wave train logging of the well acoustic wave; the static Young's modulus and Poisson's ratio explained by the present invention are more accurate than the static Young's modulus and Poisson's ratio explained by conventional linear fitting.

[0103] The present invention provides a method for determining the in-situ stress interpretation of complex carbonate formations. The method adopts a method for determining the parameters of the in-situ stress formula based on mineral changes, considers the influence of mineral changes on the mechanical properties of the rock in carbonate reservoirs, performs fitting based on field measured data, and improves the calculation accuracy of in-situ stress.

Claims

1. A method for interpreting in-situ stress in carbonate rock formations, characterized in that: The steps include: 1) Based on the carbonate rock mineral content and porosity interpretation method, the rock mud mineral content V of the carbonate rock formation is obtained sh , Volume content of each mineral composition Rock matrix porosity and rock fracture porosity Said where i = 1, 2, 3…n, n is the number of mineral species in the carbonate reservoir; 2) Based on the interpreted V of carbonate formations sh and Calculate the skeleton longitudinal wave time difference Δt mac and the time difference of the skeleton shear wave Δt mas , according to Δt mas and Δt mac The rock shear wave time difference Δt is calculated using the longitudinal and shear wave conversion formula. s ; 3) Using Δt s The time difference with rock longitudinal wave Δt c Calculate the dynamic Young's modulus E d and the dynamic Poisson's ratio θ d , based on the constructed static Young's modulus E and E d , and V sh E is calculated based on the relationship between the constructed static Poisson's ratio θ and θ d , and V sh The relationship between is calculated to obtain θ; 4) Calculate the formation pressure P based on the acoustic logging data p ; 5) Calculate vertical stress σ based on density logging data v , based on the combined spring model and combined with σ v , E, θ and P p , calculate the maximum horizontal principal stress σ H and the horizontal minimum principal stress σ h .

2. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: The static Young's modulus E and E were constructed by multiple regression method. d , and V sh The relationship between them is modeled as follows: Where a, b, c, and d are the multiple regression fitting coefficients.

3. The method for interpreting in-situ stress in carbonate formations according to claim 1, characterized in that: The multiple regression method is used to construct θ and θ d , and V sh The relationship model is: Where e, fi, g, and h are the multiple regression fitting coefficients.

4. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: According to the carbonate mineral content and porosity interpretation method, V sh , and The steps include: A. According to the natural gamma ray intensity index SH of the target layer, V is calculated sh , the calculation formula is: In the formula, GR max and GR min They are the maximum and minimum values ​​of the natural gamma curve, and GR is the natural gamma reading of the mud-bearing target layer; B. Based on the drilling fluid filtrate conductivity in the logging data, the Archie formula is used to calculate The calculation formula is: In the formula, σ LLD and σ LLS are the deep lateral conductivity and shallow lateral conductivity, σ mf and σ w are the conductivity of drilling fluid filtrate and formation water, respectively, and mf is the porosity index of the fracture; C. According to V sh and The rock volume balance model was used to calculate and The calculation formula is: In the formula, Δt f , Δt sh , Δt mai and Δt are respectively the fluid time difference value, the shale time difference value, the i-th mineral time difference value and the acoustic time difference value in the acoustic logging data, Pe f 、Pe sh 、Pe mai and Pe are the photoelectric absorption cross-section index values ​​of fluid, mud, the photoelectric absorption cross-section index value of the ith mineral and the photoelectric absorption cross-section index value in the lithology density logging data, respectively. f 、CNL sh 、CNL mai and CNL are the neutron value of fluid, neutron value of shale, neutron value of the i-th mineral and neutron value in neutron logging data, respectively.

5. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: According to Δt mas and Δt mac , using the longitudinal and transverse wave conversion formula to calculate Δt s The calculation formula is: In the formula, Δt fs is the shear wave time difference of the pore fluid, Δt fc is the time difference of the longitudinal wave of the pore fluid, Δt c is the rock longitudinal wave time difference; Where Δt mas The calculation formula is: Where Δt shs is the time difference of mud shear wave, Δt masi is the shear wave time difference value of the i-th mineral; Where Δt mac The calculation formula is: In the formula, Δt shc is the time difference of mud longitudinal wave, Δt maci is the longitudinal wave time difference value of the ith mineral.

6. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: Formation pressure P p The calculation formula is: p =G p ·H, where H is the measured depth, G p is the formation pressure gradient, and its calculation formula is: In the formula, G o is the static rock pressure gradient of the overlying strata, MPa / 100m; G w is the hydrostatic pressure gradient of formation water, MPa / 100m; Δt c is the measured value of the longitudinal wave time difference at the observation point, μs / m; Δt cn is the corresponding value of the longitudinal wave time difference on the normal compaction trend line at the same depth, μs / m; c is the compaction index.

7. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: σ v The calculation formula is: Where, ΔD i is the thickness of the stratum in the i-th section; ρ i is the average volume density of the ith section on the density logging curve; g is the gravitational acceleration.

8. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: σ H The calculation formula is: Where α is the effective stress coefficient, β1 is the strain of the rock formation in the direction of maximum horizontal stress, and β2 is the strain of the rock formation in the direction of minimum horizontal stress.

9. The carbonate rock formation in-situ stress interpretation method according to claim 1, characterized in that: σ h The calculation formula is: Where α is the effective stress coefficient, β1 is the strain of the rock formation in the direction of maximum horizontal stress, and β2 is the strain of the rock formation in the direction of minimum horizontal stress.

10. The carbonate stratum in-situ stress interpretation method according to claim 8 or 9, characterized in that: The calculation formula of α is:

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