Methods for calculating the maximum and minimum horizontal ground stress

Abstract

The application discloses a method for calculating horizontal maximum stress and horizontal minimum stress, which is based on a well logging horizontal stress calculation method (ADS method), and determines a formation horizontal skeleton stress non-equilibrium factor, a Poisson ratio, an overlying stratum pressure, a Biot coefficient and a formation pore pressure to calculate the maximum horizontal stress and the minimum horizontal stress. The application is used for obtaining high-precision maximum horizontal stress and minimum horizontal stress, and uses azimuthal anisotropy obtained by wide-azimuth seismic data, rock physical modeling technology, pre-stack inversion and pressure prediction patent technology to fully consider micro anisotropy of the formation, and the prediction accuracy reaches the seismic observation scale.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of petroleum seismic exploration data interpretation, and relates to a method for predicting horizontal stress, in particular to a method for calculating the maximum horizontal stress and the minimum horizontal stress. BACKGROUND

[0002] Stress is an important data required for the development of unconventional oil and gas such as shale oil and gas, and the current pre-drilling stress prediction cannot meet the requirements of horizontal well drilling engineering.

[0003] The "ADS method" proposed by Zhou Wen, Xie Runcheng, etc. uses the acoustic travel time (AC) and density (DEN) data in logging to calculate the Poisson's ratio, elastic modulus and other necessary rock mechanics parameters, and further calculates the horizontal stress, the maximum horizontal stress σ H and the minimum horizontal stress σ h The calculation formula is as follows:

[0004]

[0005]

[0006] This method is a post-drilling stress calculation method, and the formation horizontal skeleton stress unbalance factor A g in the algorithm is a very important parameter, and Zhao Jun and Yang Fulin pointed out that A g reflects the difference between the two principal stresses in the horizontal direction, and the algorithm is as follows:

[0007]

[0008] Since D min and D max in the above formula cannot be obtained before drilling, the prediction demand of the stress parameters for horizontal drilling engineering cannot be met, and E ma is an elastic parameter related to the lithology of the formation, and at present, there is no reasonable obtaining scheme. At the same time, B in the ADS method is the Biot coefficient, which is a parameter related to the lithology, porosity and fluid of the formation, and this parameter can be obtained by logging data after drilling, but at present, there is no obtaining method in pre-drilling seismic prediction.

[0009] Therefore, the above-mentioned technology is only a logging interpretation method, and cannot be applied to the calculation of the maximum horizontal stress and the minimum horizontal stress in pre-drilling seismic prediction. SUMMARY

[0010] The purpose of the present application is to provide a method for calculating the maximum horizontal stress and the minimum horizontal stress, which is based on the ADS method and introduces the azimuth anisotropy strength to solve the problem of The Biot coefficient and the non-equilibrium factor of the formation horizontal skeleton stress are solved by using rock physics technology and pre-stack inversion method The maximum horizontal stress and the minimum horizontal stress are calculated in the seismic prediction before drilling by combining the high-precision pore pressure prediction method.

[0011] To achieve the above object, the technical scheme adopted by the present application is as follows:

[0012] A method for calculating the maximum horizontal stress and the minimum horizontal stress is based on the logging horizontal stress calculation method (ADS method), and the maximum horizontal stress σ H and the minimum horizontal stress σ h are calculated.

[0013]

[0014]

[0015] Wherein, A g is the non-equilibrium factor of the formation horizontal skeleton stress, υ is the Poisson ratio, σ v is the overburden pressure, is the Biot coefficient, P f is the formation pore pressure.

[0016] As a limitation,

[0017] Wherein, k is the scale coefficient, the value range is 1-3, E ma is the mineral skeleton Young's modulus data body, E b is the formation Young's modulus data body, D min and D max are the borehole double calipers.

[0018] As a further limitation, the functional relationship between the borehole double caliper and the azimuth anisotropy strength ε is:

[0019]

[0020] As a further limitation, the azimuth anisotropy strength ε is calculated by obtaining the full-azimuth common imaging point gather.

[0021] As a further limitation, the mineral skeleton Young's modulus data body E ma is obtained by attribute entity modeling of the well curve E ma '.

[0022] As a further limitation, the well curve E ma is calculated by the following formula:

[0023]

[0024] where v Pma is the mineral matrix P-wave velocity curve, v Sma is the mineral matrix S-wave velocity curve, v Pma and v Sma are obtained from rock physics modeling.

[0025] As a further limitation, where I P is the P-wave impedance, I S is the S-wave impedance, I P and I S are obtained from pre-stack inversion.

[0026]

[0027] where p b is the rock density, h is the depth domain sampling interval, H is the burial depth, and g is the gravity acceleration.

[0028] As another limitation, the Biot coefficient is calculated by determining the ratio of the matrix volume coefficient to the rock volume coefficient:

[0029]

[0030] where K b is the formation volume coefficient, and K ma is the mineral matrix volume coefficient.

[0031] As a further limitation, K ma is obtained from rock physics modeling; and K b is obtained from pre-stack inversion results by the following formula:

[0032]

[0033] Thanks to the above technical solutions, the present application has the following technical progress compared with the prior art:

[0034] The method of the present application determines the functional relationship between the borehole dual-lateral ratio and the azimuthal anisotropy strength, and overcomes the problem of the prior art that the full-space dual-lateral ratio The technical bottleneck that could not be obtained before drilling was addressed; by determining the bulk modulus and Young's modulus of the mineral skeleton throughout the entire space, the correspondence between the Biot coefficient and the formation lithology, porosity, and fluids was ensured, thus solving the problem of accurate prediction; the formation elastic parameters were determined using the pre-stack inversion method, and the non-equilibrium factor of the formation horizontal skeleton stress was obtained; the overlying formation pressure was calculated using the density inversion results; finally, the above results, along with the formation pore pressure prediction results obtained from the patent technology in Chinese invention patent application ZL201611255977.3, were substituted into the ADS method formula to calculate the maximum and minimum horizontal in-situ stress.

[0035] This method utilizes well logging data from seismic data and fully considers the microscopic anisotropy of the strata to achieve high-precision calculation of the maximum and minimum horizontal in-situ stresses.

[0036] This invention can be applied to the field of petroleum seismic exploration data processing technology to further calculate the maximum and minimum horizontal geostress with high precision, thereby improving the effectiveness of oil and gas exploration.

[0037] The present invention will now be described in further detail with reference to the accompanying drawings and specific embodiments. Attached Figure Description

[0038] Figure 1 This is a cross-sectional view of the anisotropic strength obtained in step S2 of this embodiment of the invention;

[0039] Figure 2 The percentage content of each lithology or mineral in well 116 obtained in step S4 of this embodiment of the invention, and the calculated K ma μ ma ρ ma v Pma v Sma And the result diagram of Young's modulus data of the mineral framework of Well 116;

[0040] Figure 3 This is a model diagram of the bulk modulus properties of the mineral skeleton obtained in step S5 of this embodiment of the invention;

[0041] Figure 4 This is a diagram of the Young's modulus property model of the mineral skeleton obtained in step S5 of this embodiment of the invention;

[0042] Figure 5 This is a cross-sectional view of the formation bulk modulus obtained in step S6 of this embodiment of the invention;

[0043] Figure 6 This is a Young's modulus profile of the formation obtained in step S6 of this embodiment of the invention;

[0044] Figure 7 This is a cross-sectional view of the non-equilibrium factor of the formation horizontal skeleton obtained in step S7 of this embodiment of the invention.

[0045] Figure 8 This is a diagram showing the formation pore pressure results obtained in step S8 of this embodiment of the invention.

[0046] Figure 9 This is a pressure profile of the overlying strata obtained in step S8 of this embodiment of the invention;

[0047] Figure 10 This is a profile of the maximum horizontal ground stress obtained in step S10 of this embodiment of the invention;

[0048] Figure 11 This is a profile of the minimum horizontal geostress obtained in step S10 of this embodiment of the invention. Detailed Implementation

[0049] Example: A method for calculating the maximum and minimum horizontal ground stress.

[0050] S1. Determine the basic method:

[0051] Obtain well logging data of 116 in a shale area in southern China, and study the 50km range of the area. 2 Using the common imaging point gather data with azimuth-preserving processing, the ADS method is determined as the basic method to calculate the maximum and minimum horizontal ground stress.

[0052] Among them, the maximum horizontal ground stress is σ H The calculation formula is as follows:

[0053]

[0054] The minimum horizontal ground stress is σ h The calculation formula is as follows:

[0055]

[0056] In the formula, A g υ is the non-equilibrium factor of the horizontal skeleton stress of the formation, σ is Poisson's ratio, and σ is the stress of the formation. v For the overlying formation pressure, C ma C is the skeleton compression coefficient. b The rock compressibility coefficient, P is the Biot coefficient. f S2. Calculate the formation pore pressure; S3. Calculate the anisotropy strength:

[0057] According to the method in Chinese patent application No. ZL201410742430.0, the common imaging point gather with azimuth-preserving processing can be directly obtained, and the azimuth anisotropy intensity can be calculated. Figure 1 This is a cross-sectional view of the anisotropic strength data.

[0058] S3. Determine the functional relationship between anisotropic strength and wellbore collapse in both well diameters:

[0059] The functional relationship between anisotropic strength and the two wellbore diameters of wellbore collapse is determined as follows:

[0060]

[0061] In the formula, D min and D max For wellbore collapse, there are two diameters, and ε is the anisotropic strength;

[0062] S4. Calculate the Young's modulus of the mineral framework of Well 116:

[0063] Using the equivalent medium theory in seismic rock physics, the percentage content curves of various lithologies or minerals were obtained from the well logging interpretation data of Well 116. The mineral framework bulk modulus K was then used to... ma mineral skeleton shear modulus μ ma and mineral skeleton density curve ρ ma ; Calculate the longitudinal wave velocity curve v of the mineral skeleton Pma Mineral skeleton transverse wave velocity curve v Sma Further calculations were performed on the Young's modulus data of the mineral framework of Well 116, and the results were plotted. Figure 2 ;

[0064] K ma The calculation formula is:

[0065] K ma =∑f i K i ;

[0066] In the formula, f i K represents the percentage content of each lithological or mineral framework component. i This refers to the bulk modulus of each lithology or mineral.

[0067] μ ma The calculation formula is:

[0068] μ ma =∑f i μ i ;

[0069] In the formula, μ i For each lithology or mineral, the shear modulus is used.

[0070] ρ ma The calculation formula is:

[0071] ρ ma =∑f i ρ i ;

[0072] In the formula, ρ i This refers to the density of each lithology or mineral.

[0073] v Pma The calculation formula is:

[0074]

[0075] v Sma The calculation formula is:

[0076]

[0077] Well curve E ma It can be calculated from the following formula:

[0078]

[0079] Substituting the P-wave velocity and S-wave velocity of the mineral skeleton into the above equation, we obtain the Young's modulus curve E of the mineral skeleton in Well 116. ma ',like Figure 2 The last column of curves is shown.

[0080] S5. Establish the attribute model:

[0081] Using interpolation, a mineral skeleton bulk modulus attribute model for a shale gas region in southern China was established using the Young's modulus curve and the mineral skeleton bulk modulus curve from Well 116, respectively. Figure 3 As shown; establish a Young's modulus property model for the mineral framework, such as Figure 4 As shown.

[0082] S6. Calculate the bulk modulus and Young's modulus of the formation:

[0083] The P-wave impedance, S-wave impedance, rock density, and Poisson's ratio of a shale gas region in southern China were calculated using the pre-stack inversion method. The formation bulk modulus and Young's modulus were also calculated.

[0084] The bulk modulus of the formation is K b ,like Figure 5 As shown, the calculation formula is:

[0085]

[0086] In the formula, I P For longitudinal wave impedance, I S This is the transverse wave impedance.

[0087] The Young's modulus of the formation is E b ,like Figure 6 As shown, the calculation formula is:

[0088]

[0089] S7. Utilizing the functional relationship between azimuth anisotropy intensity and wellbore collapse across two well diameters, the Young's modulus property model of the mineral skeleton, and the Young's modulus of the formation, calculate the formation horizontal skeleton stress non-equilibrium factor data volume, such as... Figure 7 For cross-sectional view;

[0090] The formula for calculating the non-equilibrium factor of horizontal stratigraphic stress is as follows:

[0091]

[0092] Where k is a scale coefficient ranging from 1 to 3.

[0093] S8. Calculate the formation pore pressure P in the study area according to the method in Chinese patent application No. ZL201611255977.3. f , Figure 8 Presentation of pore pressure profile;

[0094] Using the rock density in S4, the overlying strata pressure was calculated, and the results are as follows: Figure 9 As shown;

[0095] The formula for calculating the overlying formation pressure is as follows:

[0096]

[0097] In the formula, ρ b Let h be the rock density and h be the thickness of the sampling point in the depth domain.

[0098] S9. Based on the relationship between compressibility coefficient and bulk modulus The Biot coefficient is determined as follows:

[0099]

[0100] S10. Substitute the non-equilibrium factor of the formation horizontal skeleton stress, Poisson's ratio, overlying formation pressure, Biot coefficient, and formation pore pressure obtained in the above steps into the calculation formula for the maximum horizontal stress in S1 to obtain the maximum horizontal stress, as follows: Figure 10 The profile of maximum horizontal geostress is shown, with black representing high stress values ​​and white representing low stress values, which is in good agreement with the well logging interpretation results of maximum horizontal geostress.

[0101] Substituting the Poisson's ratio, overlying formation pressure, Biot coefficient, and formation pore pressure obtained from the above steps into the formula for calculating the minimum horizontal stress in S1, the minimum horizontal stress is obtained, as follows: Figure 11 The profile for minimum horizontal stress shows high stress values ​​in black and low stress values ​​in white, which is in good agreement with the logging interpretation results for minimum horizontal stress.

[0102] The horizontal maximum and minimum geostresses obtained by applying the above calculation method improve the accuracy of geostress prediction because the calculation process uses seismic data and considers the microscopic anisotropy of the strata. At the same time, rock physics theory provides methods for obtaining the skeleton Young's modulus and skeleton bulk modulus, making the longitudinal relative relationship of horizontal geostress prediction more accurate. This is an effective method to meet the geostress parameter requirements of modern horizontal drilling engineering.

[0103] It should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art can still modify the technical solutions described in the above embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.

Claims

1. A method of computing a horizontal maximum stress and a horizontal minimum stress, characterized by, The method is based on a well logging horizontal stress calculation method, and the maximum horizontal stress and the minimum horizontal stress are calculated ； ； wherein, is the formation horizontal skeleton stress non-equilibrium factor, is the Poisson's ratio, is the overburden pressure, is the Biot's coefficient, is the formation pore pressure; is the skeleton compressibility, is the rock compressibility; wherein k is a scale factor with a value ranging from 1 to 3, is a mineral matrix Young's modulus data volume, is a formation Young's modulus data volume, and is a borehole dual caliper; The function relationship between the borehole dual caliper and the azimuthal anisotropy strength ε is: ; The azimuth anisotropy intensity ε is calculated by acquiring full-azimuth common imaging point gathers; wherein, is the rock density, is the depth domain sampling interval, is the depth of burial, is the acceleration of gravity.

2. The method of claim 1, wherein, Mineral framework young's modulus data volume is derived from well logs ’ resulting from attribute solid modeling.

3. The method of claim 2, wherein, The well curve ’ Calculated from the following equation: wherein, is a mineral matrix P-wave velocity curve, is a mineral matrix S-wave velocity curve, and are both obtained from rock physics modeling.

4. The method of claim 1, wherein, Formation Young's modulus data volume is calculated from the formula: wherein, is the longitudinal wave impedance, is the transverse wave impedance, and are both obtained from pre-stack inversion, is the rock density.

5. The method for calculating the maximum and minimum horizontal ground stress according to claim 1, characterized in that, The Biot coefficient is calculated by determining the ratio of the formation volume factor to the mineral matrix volume factor: Biot = 1 wherein, is the formation volume factor, is the mineral matrix volume factor.

6. The method of claim 5, wherein, derived by rock physics modeling techniques; derived from pre-stack inversion results by the following equation: wherein, is the longitudinal wave impedance, is the transverse wave impedance.

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