An acoustic traveltime correction method, apparatus and related device

Abstract

This invention discloses a method, apparatus, and related equipment for acoustic transit time correction. The method may include: constructing a functional equation based on acoustic transit time logging response data, showing the relative values ​​of vertical and measurement transit time as a function of well inclination angle under different anisotropic conditions; determining the acoustic anisotropy coefficient at the measurement point; and substituting the obtained well inclination angle, acoustic transit time measurement value, and acoustic anisotropy coefficient at the measurement point into the functional equation to correct the acoustic transit time. This invention uses numerical simulation results of acoustic logging response as a basis to establish a functional equation showing the relative values ​​of vertical and measurement transit time as a function of well inclination angle under different anisotropic conditions. Then, based on the determined acoustic anisotropy coefficient and the measured well inclination angle and acoustic transit time measurement value at the measurement point, the corrected acoustic transit time is obtained, further ensuring the accuracy of porosity and hydrocarbon saturation calculations.

Description

Technical Field

[0001] This invention relates to the field of oil exploration well detection technology, and particularly to an acoustic transit time correction method, apparatus, and related equipment. This method is applicable to acoustic transit time correction considering well inclination and anisotropy in high-angle and horizontal well conditions. Background Technology

[0002] In recent years, tight oil and gas and shale oil and gas reservoirs have increasingly become the focus of exploration and development, and the number of highly deviated and horizontal wells has continued to increase. Due to the obvious elastic anisotropy of the formation (the difference between the acoustic velocity parallel to the formation plane and the acoustic velocity perpendicular to the formation plane), the acoustic transit time measured in these non-vertical wells is actually a comprehensive reflection of the acoustic transit time in the vertical and horizontal directions of the formation, which is significantly different from the acoustic transit time measured in vertical wells. Under the condition that the skeleton parameters (rock physical parameters such as skeleton density, skeleton acoustic transit time, and skeleton hydrogen index, which specifically refer to skeleton acoustic transit time when acoustic transit time correction is used) remain unchanged, they cannot be directly used to calculate the porosity and oil saturation of the formation. Summary of the Invention

[0003] The inventors discovered that in actual production exploration, the effects of formation anisotropy and well inclination must be considered to correct measurement time differences in order to obtain the acoustic time differences in the vertical and horizontal directions of the formation. Meanwhile, currently published literature, both domestically and internationally, lacks a practical, efficient, and highly operable acoustic time difference correction method that simultaneously considers the effects of well inclination and anisotropy. In view of the above problems, this invention is proposed to provide an acoustic time difference correction method, apparatus, and related equipment that overcomes or at least partially solves the aforementioned problems.

[0004] In a first aspect, embodiments of the present invention provide an acoustic time difference correction method, which may include:

[0005] Based on acoustic time-of-flight logging response data, a functional equation was constructed to describe the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different anisotropic conditions.

[0006] Determine the anisotropy coefficient of the acoustic wave at the measurement point;

[0007] The obtained well inclination angle and acoustic transit time of the measurement point, as well as the acoustic anisotropy coefficient of the measurement point, are substituted into the function equation to correct the acoustic transit time.

[0008] Optionally, the determination of the acoustic anisotropy coefficient at the measurement point includes:

[0009] Based on the pre-established functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample, and the clay content at the measurement point, the acoustic anisotropy coefficient at the measurement point is determined.

[0010] Optionally, establishing a pre-defined functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample may include:

[0011] Collect full-diameter rock cores to obtain core samples;

[0012] The acoustic anisotropy coefficient of the core sample was determined by performing an acoustic anisotropy experiment on the core sample.

[0013] The clay content of the core sample was determined by testing the clay content of the core sample.

[0014] Based on the acoustic anisotropy coefficient and the clay content of the core sample, a functional relationship between the acoustic anisotropy coefficient and the clay content is established.

[0015] Optionally, the determination of the acoustic anisotropy coefficient at the measurement point may include:

[0016] The anisotropy coefficient of the acoustic wave at the measurement point is determined based on the time difference between fast and slow transverse waves in the array acoustic data.

[0017] Optionally, the construction of a functional equation for the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different anisotropic conditions based on acoustic time-of-flight logging response data may include:

[0018] The finite difference method and / or three-dimensional fast and high-precision forward numerical simulation method are used to simulate the response data of sonic time-difference logging.

[0019] Based on the simulation results, a functional equation was constructed to show the relative values ​​of verticality and measurement time difference as a function of well inclination angle under different acoustic anisotropy coefficients.

[0020] In a second aspect, embodiments of the present invention provide an acoustic time difference correction device, which may include:

[0021] The module is used to construct a functional equation for the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different anisotropic conditions, based on sonic transit time logging response data.

[0022] The determination module is used to determine the acoustic anisotropy coefficient at the measurement point;

[0023] The correction module is used to input the acquired well inclination angle and acoustic time difference of the measurement point, as well as the acoustic anisotropy coefficient of the measurement point, into the function equation to correct the acoustic time difference.

[0024] Thirdly, embodiments of the present invention provide a method for calculating formation porosity, which may include: calculating formation porosity based on the acoustic transit time obtained by the acoustic transit time correction method described in the first aspect.

[0025] Fourthly, embodiments of the present invention provide a formation porosity calculation device, which may include: the acoustic transit time correction device and the calculation module described in the second aspect;

[0026] The calculation module is used to calculate the porosity of the formation based on the acoustic time difference obtained from the acoustic time difference correction device.

[0027] Fifthly, embodiments of the present invention provide a method for evaluating the performance of shale oil and gas reservoirs, which may include: evaluating the performance of the shale oil and gas reservoir based on the acoustic transit time obtained by the acoustic transit time correction method described in the first aspect.

[0028] In a sixth aspect, embodiments of the present invention provide an evaluation device for the performance of shale oil and gas reservoirs, which may include: the acoustic transit time correction device and the evaluation module described in the second aspect;

[0029] The evaluation module is used to evaluate the performance of the shale oil and gas reservoir based on the acoustic transit time obtained by the acoustic transit time correction device.

[0030] In a seventh aspect, embodiments of the present invention provide a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the acoustic transit time correction method as described in the first aspect, or the formation porosity calculation method as described in the third aspect, or the shale oil and gas reservoir performance evaluation method as described in the fifth aspect.

[0031] Eighthly, embodiments of the present invention provide a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the acoustic transit time correction method as described in the first aspect, or the formation porosity calculation method as described in the third aspect, or the shale oil and gas reservoir performance evaluation method as described in the fifth aspect.

[0032] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0033] This invention provides a method, apparatus, and related equipment for acoustic transit time correction. The method includes: constructing a functional equation based on acoustic transit time logging response data to determine the relative values ​​of vertical and measurement transit time under different anisotropic conditions, varying with well inclination angle; determining the acoustic anisotropy coefficient at the measurement point; and substituting the obtained well inclination angle, acoustic transit time measurement value, and acoustic anisotropy coefficient at the measurement point into the functional equation to correct the acoustic transit time. This invention, based on the experimental laws of acoustic anisotropy and numerical simulation results of acoustic logging response, establishes a functional relationship between the relative values ​​of vertical and measurement transit time and well inclination and anisotropy. It utilizes logging data to characterize the magnitude of P-wave and S-wave anisotropy, ultimately achieving acoustic transit time correction considering well inclination and anisotropy, further ensuring the accuracy of porosity and hydrocarbon saturation calculations.

[0034] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0035] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0036] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0037] Figure 1 This is a flowchart illustrating the acoustic time difference correction method provided in an embodiment of the present invention;

[0038] Figure 2 This is a schematic diagram illustrating the specific process of implementing step S11 in the embodiments of the present invention;

[0039] Figure 3 This invention provides a functional relationship between the relative values ​​of verticality and measurement time difference and the well inclination angle under different anisotropic conditions in the embodiments of the present invention.

[0040] Figure 4 This is the functional relationship between the longitudinal wave anisotropy coefficient and the clay content provided in the embodiments of the present invention;

[0041] Figure 5 This is the functional relationship between the transverse wave anisotropy coefficient and the clay content provided in the embodiments of the present invention;

[0042] Figure 6This is a schematic diagram of the process for pre-establishing the functional relationship between the acoustic anisotropy coefficient and the rock and soil content of the core sample, provided in an embodiment of the present invention.

[0043] Figure 7 This is a specific example of acoustic time difference correction for a horizontal well provided in an embodiment of the present invention;

[0044] Figure 8 This is a schematic diagram of the acoustic time difference correction device provided in an embodiment of the present invention. Detailed Implementation

[0045] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0046] This invention provides a method for correcting acoustic transit time. The purpose of this invention is to solve the problem that acoustic transit time measured in non-vertical wells such as highly deviated and horizontal wells cannot be directly used for calculating rock (oil shale, etc.) porosity and oil saturation due to significant differences between the results and those from vertical wells. (Refer to...) Figure 1 As shown, the method may include the following steps:

[0047] Step S11: Based on the acoustic time-of-flight logging response data, construct a functional equation for the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different anisotropic conditions.

[0048] This step involves model building, which is a numerical simulation of the response based on the acoustic transit time obtained from well logging. It sets the vertical acoustic transit time value for the formation and simulates the measurement results under different acoustic anisotropy and well inclination angles. Furthermore, it summarizes and establishes the functional relationship between the relative values ​​of vertical and measurement transit time under different anisotropic conditions and the well inclination angle, thus obtaining the functional equation.

[0049] Step S12: Determine the acoustic anisotropy coefficient at the measurement point.

[0050] This step determines the anisotropy coefficient of the sound wave, so that when performing calculations in step S13, the specific curve in the function equation of step S11 can be used to correct the sound wave time difference.

[0051] Step S13: Substitute the obtained well inclination angle, acoustic time difference, and acoustic anisotropy coefficient of the measurement point into the function equation to correct the acoustic time difference.

[0052] This step involves substituting the wellbore inclination angle, the measured acoustic transit time, and the acoustic anisotropy coefficient at the measurement point into the function equation in step S11 to correct the measured acoustic transit time, thus obtaining the corrected acoustic transit time. Specifically, it involves selecting and determining the functional relationship between the vertical and measured transit time relative values ​​and the wellbore inclination angle based on the formation's P-wave and S-wave anisotropy coefficients, and then substituting the measured acoustic transit time at the current depth and the wellbore inclination angle information into the functional relationship to calculate the desired vertical acoustic transit time value.

[0053] Based on the experimental law of acoustic anisotropy and the numerical simulation results of acoustic logging response, this invention establishes a functional relationship between the relative values ​​of verticality and measurement time difference and the changes in well inclination and anisotropy. It uses logging data to characterize the magnitude of P-wave and S-wave anisotropy, and finally realizes acoustic time difference correction considering well inclination and anisotropy, further ensuring the calculation accuracy of porosity and oil and gas saturation.

[0054] In an optional embodiment, refer to Figure 2 As shown, the implementation of step S11 above may specifically include the following steps:

[0055] Step S111: Simulate the acoustic time-difference logging response data using the finite difference method and / or the three-dimensional fast high-precision forward numerical simulation method.

[0056] The numerical simulation of sonic transit time logging response in this step refers to the use of the finite difference method or the three-dimensional fast high-precision forward modeling numerical simulation method to conduct numerical simulation of sonic transit time logging response. During the simulation, the main considerations are the changes in sonic transit time in the vertical direction of the formation, the anisotropy coefficient of the P-wave or S-wave, and the well inclination angle.

[0057] For example, refer to Figure 3 As shown, during the simulation, the well inclination angle changed from the vertical direction to the horizontal direction at intervals of 5°; the P-wave anisotropy coefficient changed from 0 to 0.5 at intervals of 0.02; and the vertical P-wave transit time changed from 200 μs / m to 350 μs / m at intervals of 20 μs / m.

[0058] It should be noted here that... Figure 3 The eps value represents the longitudinal wave anisotropy coefficient. Of course, the angle change interval in the embodiments of the present invention is not necessarily set to 5°, the longitudinal wave anisotropy coefficient does not absolutely change from 0 to 0.5, and the change interval is not limited to 0.02, etc. Those skilled in the art can adjust the above-mentioned numerical change range to determine the optimal simulation results, but the above adjustments cannot deviate from the overall concept of the present invention.

[0059] Step S112: Based on the simulation results, construct a functional equation for the relative values ​​of verticality and measurement time difference as a function of well inclination angle under different acoustic anisotropy coefficients.

[0060] This step involves summarizing and establishing the functional relationship between the relative values ​​of verticality and measurement time difference and the well inclination angle for different longitudinal or transverse anisotropy coefficients, thereby obtaining the functional equation.

[0061] Specifically, refer to Figure 3 As shown in the figure, this graph illustrates the functional relationship between the relative values ​​of vertical and measurement time differences under different anisotropic conditions, obtained from numerical simulation of the sonic transit logging response, and the variation of the vertical and measurement time differences with the well inclination angle. In the figure, the horizontal axis represents the well inclination angle, and the vertical axis represents the relative values ​​of vertical and measurement time differences, i.e., the difference between the measurement time difference and the vertical time difference divided by the vertical time difference, which can be expressed by the formula: "(measurement time difference of the inclination well - vertical time difference) / vertical time difference". Figure 3 In this context, the specific functional relationship (functional equation) is as follows:

[0062] eps = 0.1

[0063] eps = 0.2

[0064] eps = 0.3

[0065] eps = 0.4

[0066] eps = 0.5 from Figure 3 It can be seen that the "relative value of vertical and measurement time difference" has an approximately sinusoidal functional relationship with the wellbore inclination angle, and is independent of the magnitude of the formation time difference in the vertical direction. In other words, by adjusting the parameters in the simulation process, the overall shape of the function equation curve will not change. Compared to the functional relationship between slowness difference and wellbore inclination angle constructed in existing technologies, the time difference of the target formation changes accordingly after the target formation is changed, thus altering the constructed functional relationship. Therefore, using the functional relationship constructed with the "relative value of vertical and measurement time difference" and the wellbore inclination angle allows for rapid calculation of acoustic time difference without the need to construct charts for multiple formation time differences.

[0067] In another optional embodiment, step S12 can be implemented in two ways, as follows:

[0068] <Method 1>

[0069] Based on the pre-established functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample, and the clay content at the measurement point, the acoustic anisotropy coefficient at the measurement point is determined.

[0070] Reference Figure 4 As shown, this is the pre-established functional relationship between the longitudinal wave anisotropy coefficient and the clay content, referring to... Figure 5 As shown, this represents the pre-established functional relationship between the shear wave anisotropy coefficient and the clay content. The horizontal axis in the figure represents the clay content (V) of the core sample. clay The vertical axis represents the longitudinal wave anisotropy coefficient (ε) and the transverse wave anisotropy coefficient (γ) measured using the acoustic anisotropy experiment method. Figure 4 The functional relationship can be expressed as: Figure 5 The functional relationship can be expressed as: from Figure 4 and Figure 5 As can be seen, the anisotropy coefficients of both P-waves and S-waves in the formation are linearly related to the clay content. When the clay content is similar, the anisotropy coefficients of P-waves and S-waves are approximately equal.

[0071] It should be noted that the clay content at the measurement point in the embodiments of the present invention can be calculated based on conventional logging data of high-angle or horizontal wells. The calculation method may include, but is not limited to, the following: using natural gamma logging data, using resistivity logging data, using three-porosity logging data, etc.

[0072] In this embodiment of the invention, a functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample is established in advance in the laboratory, referring to... Figure 6 As shown, the following steps may be included:

[0073] Step S61: Collect full-diameter core samples from logging at different angles to obtain core samples.

[0074] This step involves drilling plunger samples from the full-diameter rock core in vertical, horizontal, and 45° directions to obtain the rock core sample.

[0075] Then, corresponding acoustic anisotropy experiments were conducted on the core samples, namely steps S62 and S63, to obtain key information such as the longitudinal and transverse anisotropy coefficients and clay content.

[0076] Step S62: Perform acoustic anisotropy experiments on the core sample to determine the acoustic anisotropy coefficient of the core sample. In this step, the acoustic anisotropy coefficient of the core sample can be measured under approximate formation conditions using existing acoustic anisotropy measurement methods.

[0077] Step S63: Analyze the clay content of the core sample to determine its clay content. This step can be achieved using XRD whole-rock diffraction analysis.

[0078] Step S64: Based on the acoustic anisotropy coefficient and clay content of the core sample, establish a functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample.

[0079] This step establishes a functional relationship between the longitudinal and transverse wave anisotropy coefficients and the clay content of the core sample, based on the acoustic anisotropy coefficients of the core sample determined in step S62 and the clay content of the core sample determined in step S63.

[0080] It should be noted that the execution order of steps S62 and S63 is not important. Step S62 can be executed first or step S63 can be executed first, or they can be executed simultaneously. This embodiment of the invention does not make any specific limitation on this.

[0081] <Method 2>

[0082] This invention also provides another method for determining the acoustic anisotropy coefficient of a measurement point, namely, determining the acoustic anisotropy coefficient of the measurement point based on the fast and slow transverse wave time difference in the array acoustic data.

[0083] Due to the limitation of measurement cost, array acoustic logging data is not collected for every well. However, the acoustic anisotropy coefficient measured by this method is more accurate. Therefore, if array acoustic logging data is collected in a well, this method is preferred for determining the acoustic anisotropy coefficient of the measurement point.

[0084] It should be noted that this method determines the shear wave anisotropy coefficient. However, since the P-wave anisotropy coefficient and the shear wave anisotropy coefficient of the same stratum are linearly related and approximately equal, the shear wave anisotropy coefficient of the measurement point can be used instead of the P-wave anisotropy coefficient for calculation.

[0085] It should also be noted that in this embodiment, the acoustic anisotropy coefficients obtained in Method 1 and Method 2 can be weighted and averaged, and this embodiment of the invention does not specifically limit this.

[0086] In a specific embodiment, taking numerical simulation results, experimental measurement data, and logging data from a horizontal well in a certain study area as an example, refer to... Figure 7 As shown in the figure, channel 7 represents the shear wave anisotropy coefficient obtained from the fast and slow shear wave time difference extracted by the array acoustic wave. The curve AC in channel 4 represents the anisotropy coefficient obtained from the fast and slow shear wave time difference extracted by the array acoustic wave. Figure 3 and Figure 5 The corrected vertical acoustic time difference is obtained, with the fifth curve in the figure serving as the reference. Figure 4 The longitudinal wave anisotropy coefficients obtained by the regularity are shown in Figure 11, which represents the porosity and oil saturation calculated using the corrected acoustic time difference, and Figure 10, which represents the porosity and oil saturation calculated directly using the measurement time difference.

[0087] In this embodiment, array acoustic logging data was acquired from the horizontal well, from which the fast and slow shear wave time differences were extracted. Figure 7The two curves in the sixth channel (DTS_SLOW represents slow shear wave time, and DTS_FAST represents fast shear wave time) can be further used to obtain the shear wave anisotropy coefficient of the formation. Figure 7 (Course 7). The natural gamma curve can also be used. Figure 7 (Step 2) Calculate the clay content, and then apply the functional relationship between the longitudinal and transverse wave anisotropy coefficients and the clay content. Figure 4 and Figure 5 Determine the anisotropy coefficients of the longitudinal and transverse waves at the current depth.

[0088] This invention addresses the challenge that the acoustic transit time measured in highly deviated and horizontal wells differs significantly from that measured in vertical wells, making it unsuitable for direct calculation of porosity and oil saturation. Based on experimental laws governing acoustic anisotropy and numerical simulation results of acoustic logging response, a functional relationship is established between the relative values ​​of vertical and measurement transit time and the variations in well deviation and anisotropy. Well logging data is used to characterize the magnitude of P-wave and S-wave anisotropy, ultimately achieving transit time correction that considers well deviation and anisotropy, thereby ensuring the accuracy of porosity and oil / gas saturation calculations.

[0089] Based on the same inventive concept, this invention also provides an acoustic time difference correction device, referring to... Figure 8 As shown, the device may include a construction module 81, a determination module 82, and a correction module 83, and its working principle is as follows:

[0090] The construction module 81 is used to construct a functional equation for the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different anisotropy conditions based on the acoustic time-of-flight logging response data. Optionally, the construction module 81 uses the finite difference method and / or a three-dimensional fast high-precision forward numerical simulation method to simulate the acoustic time-of-flight logging response data; then, based on the simulation results, the construction module 81 constructs a functional equation for the relative values ​​of vertical and measurement time difference as a function of well inclination angle under different acoustic anisotropy coefficients.

[0091] The determination module 82 is used to determine the acoustic anisotropy coefficient of the measurement point. Optionally, the determination module 82 can determine the acoustic anisotropy coefficient of the measurement point based on a pre-established functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample, as well as the clay content of the measurement point. Alternatively, the determination module 82 can determine the acoustic anisotropy coefficient of the measurement point based on the fast and slow shear wave transit times in the array acoustic data.

[0092] The correction module 83 is used to input the acquired well inclination angle of the measurement point, the measured acoustic time difference of the measurement point, and the acoustic anisotropy coefficient of the measurement point into the function equation to correct the acoustic time difference.

[0093] Based on the same inventive concept, this embodiment of the invention also provides a method for calculating formation porosity. First, the acoustic transit time is obtained using an acoustic transit time correction method, and then the formation porosity is calculated based on the acoustic transit time. For example... Figure 7 The formation porosity calculated in the rightmost path is more accurate.

[0094] Based on the same inventive concept, this embodiment of the invention also provides a formation porosity calculation device, which may include: an acoustic transit time correction device and a calculation module;

[0095] The calculation module is used to calculate the porosity of the formation based on the acoustic transit time obtained from the acoustic transit time correction device.

[0096] Based on the same inventive concept, this embodiment of the invention also provides a method for evaluating the performance of shale oil and gas reservoirs. First, the acoustic transit time is obtained by the acoustic transit time correction method, and then the performance of shale oil and gas reservoirs is evaluated based on the acoustic transit time.

[0097] Based on the same inventive concept, this embodiment of the invention also provides an evaluation device for shale oil and gas reservoir performance, which may include: an acoustic time difference correction device and an evaluation module;

[0098] The evaluation module is used to evaluate the performance of shale oil and gas reservoirs based on the acoustic transit time obtained from the acoustic transit time correction device.

[0099] Based on the same inventive concept, this embodiment of the invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-mentioned acoustic transit time correction method, or the above-mentioned formation porosity calculation method, or the above-mentioned shale oil and gas reservoir performance evaluation method.

[0100] Based on the same inventive concept, this embodiment of the invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the above-mentioned acoustic transit time correction method, or the above-mentioned formation porosity calculation method, or the above-mentioned shale oil and gas reservoir performance evaluation method.

[0101] It should be noted that since the principles by which these devices, computer-readable storage media, and computer devices solve the problem are similar to those of the aforementioned methods, the implementation of these devices, computer-readable storage media, and computer devices can refer to the implementation of the aforementioned methods, and will not be described in detail here.

[0102] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage and optical storage) containing computer-usable program code.

[0103] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0104] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0105] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0106] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A method for correcting acoustic time difference, characterized in that, include: The finite difference method and / or three-dimensional fast high-precision forward numerical simulation method are used to simulate the response data of sonic transit time logging. Based on the simulation results, a functional equation is constructed with the relative value of vertical and measurement time difference as the vertical axis and the well inclination angle as the horizontal axis, to express the variation of the relative value of vertical and measurement time difference with the well inclination angle under different anisotropic conditions. The relative value of vertical and measurement time difference is the ratio of the difference between the measurement time difference and the vertical time difference to the vertical time difference. Based on the pre-established functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample, and the clay content at the measurement point, the acoustic anisotropy coefficient at the measurement point is determined. The functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample is pre-established using the following method: a full-diameter core is collected to obtain a core sample; acoustic anisotropy is measured on the core sample to determine its acoustic anisotropy coefficient; the clay content of the core sample is detected to determine its clay content; and based on the acoustic anisotropy coefficient and the clay content of the core sample, a functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample is established. The obtained well inclination angle and acoustic transit time of the measurement point, as well as the acoustic anisotropy coefficient of the measurement point, are substituted into the function equation to correct the acoustic transit time.

2. The method according to claim 1, characterized in that, The acoustic anisotropy coefficient for determining the measurement point includes: The anisotropy coefficient of the acoustic wave at the measurement point is determined based on the time difference between fast and slow transverse waves in the array acoustic data.

3. An acoustic time difference correction device, characterized in that, include: The module is designed to simulate sonic transit logging response data using the finite difference method and / or a fast, high-precision three-dimensional forward numerical simulation method. Based on the simulation results, a functional equation was constructed with the relative value of vertical and measurement time difference as the vertical axis and the well inclination angle as the horizontal axis to express the variation of the relative value of vertical and measurement time difference with the well inclination angle under different anisotropic conditions; wherein, the relative value of vertical and measurement time difference is the ratio of the difference between measurement time difference and vertical time difference to the vertical time difference. The determination module is used to determine the acoustic anisotropy coefficient of a measurement point based on a pre-established functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample, as well as the clay content of the measurement point. The functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample is pre-established through the following method: collecting a full-diameter core sample; performing acoustic anisotropy experiments on the core sample to determine its acoustic anisotropy coefficient; detecting the clay content of the core sample to determine its clay content; and establishing a functional relationship between the acoustic anisotropy coefficient and the clay content of the core sample. The correction module is used to input the acquired well inclination angle and acoustic time difference of the measurement point, as well as the acoustic anisotropy coefficient of the measurement point, into the function equation to correct the acoustic time difference.

4. A method for calculating formation porosity, characterized in that, include: The porosity of the formation is calculated using the acoustic transit time obtained by the acoustic transit time correction method according to claim 1 or 2.

5. A device for measuring formation porosity, characterized in that, include: The acoustic time difference correction device and calculation module as described in claim 3; The calculation module is used to calculate the porosity of the formation based on the acoustic time difference obtained from the acoustic time difference correction device.

6. A method for evaluating the performance of shale oil and gas reservoirs, characterized in that, include: The acoustic transit time obtained by the acoustic transit time correction method according to claim 1 or 2 is used to evaluate the performance of the shale oil and gas reservoir.

7. A device for evaluating the performance of shale oil and gas reservoirs, characterized in that, include: The acoustic time difference correction device and evaluation module as described in claim 3; The evaluation module is used to evaluate the performance of the shale oil and gas reservoir based on the acoustic transit time obtained by the acoustic transit time correction device.

8. A computer-readable storage medium having a computer program stored thereon, characterized in that, When executed by the processor, the program implements the acoustic transit time correction method as described in claim 1 or 2, or the formation porosity calculation method as described in claim 4, or the shale oil and gas reservoir performance evaluation method as described in claim 6.

9. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the program, it implements the acoustic transit time correction method as described in claim 1 or 2, or the formation porosity calculation method as described in claim 4, or the shale oil and gas reservoir performance evaluation method as described in claim 6.

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