Earthquake data processing methods and devices

Abstract

This application discloses a seismic data processing method and apparatus, relating to the field of geological exploration. The method includes: obtaining a P-wave constraint coefficient based on the seismic wave depth domain velocity field and the P-wave sonic transit time logging curve of the target well; constraining the seismic wave depth domain velocity field using the P-wave constraint coefficient to obtain a well-constrained P-wave velocity volume; obtaining a S-wave constraint coefficient based on the P-wave and S-wave sonic transit time logging curves of the target well; constraining the well-constrained P-wave velocity volume using the S-wave constraint coefficient to obtain a well-constrained S-wave velocity volume; calculating the P-wave travel time based on the well-constrained P-wave velocity volume; calculating the S-wave travel time based on the well-constrained S-wave velocity volume; and performing a combined analysis of the P-wave and S-wave travel times to obtain the converted wave gamma field of the target area, reducing the error of the final converted wave gamma field and improving its accuracy.

Description

Technical Field

[0001] This application relates to the field of geological exploration, and in particular to a seismic data processing method and apparatus. Background Technology

[0002] In converted-wave seismic data processing, pre-stack time migration (PSTM) is a commonly used technique. PSTM often requires calculating a simplified equation for the converted-wave travel curve. This simplified equation includes the PSTM formula, which, starting from the converted-wave time domain, uses four parameters to dynamically correct the common-conversion point (CCP) gathers. This formula yields the time-domain-based PSTM results. Among the factors affecting the PSTM results, the accuracy of the converted-wave gamma field is the most significant.

[0003] In related technologies, converted wave gamma fields are typically picked manually using seismic data interaction software.

[0004] However, the process of picking up the converted wave gamma field through interactive software involves many parameters, and these parameters affect each other, resulting in low accuracy of the picked-up converted wave gamma field. Summary of the Invention

[0005] This application provides a seismic data processing method and apparatus that can improve the accuracy of converted wave gamma fields. The technical solution is as follows:

[0006] On the one hand, a seismic data processing method is provided, the method comprising:

[0007] Obtain the seismic wave depth domain velocity field of the target area, which is used to indicate the propagation speed of seismic waves in the target area, which contains the measured target well;

[0008] Based on the seismic wave depth domain velocity field and the P-wave sonic time difference logging curve of the target well, the P-wave constraint coefficient is obtained. The seismic wave depth domain velocity field is constrained by the P-wave constraint coefficient to obtain the well-constrained P-wave velocity volume. The well-constrained P-wave velocity volume is used to indicate the propagation speed of the seismic wave after P-wave constraint in the target area.

[0009] Based on the P-wave sonic transit time logging curve and the S-wave sonic transit time logging curve of the target well, the S-wave constraint coefficient is obtained. The S-wave constraint coefficient is used to constrain the well-constrained P-wave velocity volume to obtain the well-constrained S-wave velocity volume. The well-constrained S-wave velocity volume is used to indicate the propagation speed of seismic waves after passing through the S-wave constraint in the target area.

[0010] Based on the well-constrained P-wave velocity volume, the P-wave travel time is calculated, which indicates the propagation time of the seismic wave through the P-wave constraint in the target region; and based on the well-constrained S-wave velocity volume, the S-wave travel time is calculated, which indicates the propagation time of the seismic wave through the S-wave constraint in the target region.

[0011] By combining the P-wave travel time and the S-wave travel time for analysis, the converted wave gamma field of the target region is obtained. The converted wave gamma field is used to obtain the converted wave pre-stack time migration profile of the target well through migration. The converted wave pre-stack time migration profile is used to characterize the geological morphology of the target well.

[0012] On the other hand, a seismic data processing apparatus is provided, the apparatus comprising:

[0013] The acquisition module is used to acquire the seismic wave depth domain velocity field of the target area, which is used to indicate the propagation speed of seismic waves in the target area, which contains the measured target well;

[0014] The processing module is used to obtain the P-wave constraint coefficient based on the seismic wave depth domain velocity field and the P-wave sonic time difference logging curve of the target well, and to constrain the seismic wave depth domain velocity field through the P-wave constraint coefficient to obtain the well-constrained P-wave velocity volume. The well-constrained P-wave velocity volume is used to indicate the propagation speed of the seismic wave after P-wave constraint in the target area.

[0015] The processing module is further configured to obtain a shear wave constraint coefficient based on the P-wave sonic time-of-flight logging curve and the S-wave sonic time-of-flight logging curve of the target well, and to constrain the well-constrained P-wave velocity volume using the shear wave constraint coefficient to obtain a well-constrained S-wave velocity volume. The well-constrained S-wave velocity volume is used to indicate the propagation speed of seismic waves after passing through the shear wave constraint in the target area.

[0016] The calculation module is configured to calculate the P-wave travel time based on the well-constrained P-wave velocity volume, wherein the P-wave travel time is used to indicate the propagation time of the seismic wave through the P-wave constraint in the target region; and to calculate the S-wave travel time based on the well-constrained S-wave velocity volume, wherein the S-wave travel time is used to indicate the propagation time of the seismic wave through the S-wave constraint in the target region.

[0017] The combined analysis module is used to perform combined analysis on the P-wave travel time and the S-wave travel time to obtain the converted wave gamma field of the target area. The converted wave gamma field is used to obtain the converted wave pre-stack time migration profile of the target well through migration. The converted wave pre-stack time migration profile is used to characterize the geological morphology of the target well.

[0018] On the other hand, a computer device is provided, the computer device including a processor and a memory, the memory storing at least one instruction, at least one program, code set or instruction set, the at least one instruction, the at least one program, the code set or instruction set being loaded and executed by the processor to implement any of the seismic data processing methods described in the embodiments of this application.

[0019] On the other hand, a computer-readable storage medium is provided, wherein at least one piece of program code is stored in the computer-readable storage medium, the at least one piece of program code being loaded and executed by a processor to implement the seismic data processing method described in any of the embodiments of this application.

[0020] On the other hand, a computer program product or computer program is provided, which includes computer instructions stored in a computer-readable storage medium. A processor of a computer device reads the computer instructions from the computer-readable storage medium and executes the computer instructions, causing the computer device to perform any of the seismic data processing methods described in the embodiments of this application.

[0021] The beneficial effects of the technical solutions provided in this application include at least the following:

[0022] The seismic wave depth domain velocity field is constrained by the P-wave and S-wave sonic transit time logging curves to obtain well-constrained P-wave velocity volumes and well-constrained S-wave velocity volumes. Based on these well-constrained P-wave and S-wave velocity volumes, the P-wave travel time and the S-wave travel time are calculated to obtain the converted-wave gamma field. Constraining the seismic data using well logging data reduces the error in the final converted-wave gamma field and improves its accuracy. Attached Figure Description

[0023] To more clearly illustrate the technical solutions in the embodiments of this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0024] Figure 1 This is a schematic diagram of an implementation environment provided by an exemplary embodiment of this application;

[0025] Figure 2 This is a flowchart of a seismic data processing method provided in an exemplary embodiment of this application;

[0026] Figure 3This is a flowchart of a seismic data processing method provided in another exemplary embodiment of this application;

[0027] Figure 4 This is a complete flowchart of a seismic data processing method provided in an exemplary embodiment of this application;

[0028] Figure 5 This is a schematic diagram of the pre-stack time migration profile of the converted wave obtained by manually picking up the gamma field migration.

[0029] Figure 6 This is a schematic diagram of a pre-stack time migration profile of converted waves obtained by a seismic data processing method provided through an exemplary embodiment of this application.

[0030] Figure 7 This is a structural block diagram of an earthquake data processing apparatus provided in an exemplary embodiment of this application;

[0031] Figure 8 This is a structural block diagram of a seismic data processing apparatus provided in another exemplary embodiment of this application;

[0032] Figure 9 This is a structural block diagram of a computer device provided in an exemplary embodiment of this application. Detailed Implementation

[0033] To make the objectives, technical solutions, and advantages of this application clearer, the embodiments of this application will be described in further detail below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. Based on the embodiments in this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0034] In this application, the terms "first" and "second" are used to distinguish between identical or similar items that have essentially the same function. It should be understood that there is no logical or temporal dependency between "first" and "second", nor is there any limitation on the quantity or execution order.

[0035] Figure 1 This is a schematic diagram of an implementation environment provided by an exemplary embodiment of this application, such as... Figure 1 As shown, the implementation environment includes a terminal 110, a server 120, a communication network 130, and a detection device 140. The terminal 110 and the server 120 are connected through the communication network 130. Optionally, the communication network 130 can be a wired network or a wireless network, and this embodiment does not limit it.

[0036] Terminal 110 can be a smartphone, tablet, laptop, desktop computer, smart home appliance, smart vehicle terminal, smart speaker, digital camera, etc., but is not limited to these. Optionally, a target application is installed in terminal 110. Indicatively, the target application can be a traditional application, a cloud application, a mini-program or application module within a host application, or a web platform; this embodiment does not limit this. Optionally, the target application provides a function for obtaining the converted wave gamma field.

[0037] Server 120 is used to provide background services for the target application installed on terminal 110. It is worth noting that server 120 can be a standalone physical server, a server cluster or distributed system composed of multiple physical servers, or a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communication, middleware services, domain name services, security services, CDN (Content Delivery Network), and big data and artificial intelligence platforms.

[0038] The detection device 140 is installed in the target area to detect seismic data and well logging data, where there are target wells that need to be detected. The detection device 140 is connected to the terminal 110, which can directly obtain the detected seismic data and well logging data from the detection device 140; or, the terminal 110 can obtain the detected seismic data and well logging data through a relay device (e.g., a mobile storage device).

[0039] Based on the above implementation environment, the process of obtaining the converted wave gamma field is introduced:

[0040] In a schematic manner, one or more detection devices 140 are set up in the target area. When the detection device 140 detects the seismic data of the target area and the logging data of the target well in the target area, it will send them to the terminal 110. The terminal 110 processes the seismic data of the target area to obtain the seismic wave depth domain velocity field of the target area, and processes the logging data of the target well in the target area to obtain the P-wave sonic transit time logging curve and the P-wave sonic transit time logging curve of the target well.

[0041] In the target application of terminal 110, firstly, the seismic wave depth domain velocity field and P-wave sonic transit time logging curves are analyzed to obtain the well-constrained P-wave velocity volume; secondly, the P-wave sonic transit time logging curves and S-wave sonic transit time logging curves are analyzed to obtain the well-constrained S-wave velocity volume; and based on the well-constrained P-wave velocity volume and the well-constrained S-wave velocity volume, the P-wave travel time and S-wave travel time are calculated; finally, the P-wave travel time and S-wave travel time are combined and analyzed to obtain the converted wave gamma field of the target area.

[0042] In some optional embodiments, the process of obtaining the converted wave gamma field described above can be implemented in server 120. Schematic, terminal 110 sends seismic data and well logging data to server 120. After obtaining the converted wave gamma field of the target area in server 120, the converted wave gamma field is fed back to terminal 110.

[0043] It should be noted that all information (including but not limited to user device information, user personal information, etc.), data (including but not limited to data used for analysis, stored data, displayed data, etc.), and signals involved in this application have been authorized by the user or fully authorized by all parties, and the collection, use, and processing of related data must comply with the relevant laws, regulations, and standards of the relevant countries and regions. For example, the seismic data and well logging data involved in this application were obtained with full authorization.

[0044] Based on the above introduction and implementation environment, the seismic data processing method provided in the embodiments of this application will be described. Figure 2 This is a flowchart of the seismic data processing method provided in the embodiments of this application, applied to, for example... Figure 1 The following explanation uses the terminal or server shown as an example. Figure 2 As shown, the method includes:

[0045] Step 201: Obtain the seismic wave depth domain velocity field of the target area.

[0046] The seismic wave depth domain velocity field is used to indicate the propagation speed of seismic waves in the target area, which includes the measured target well.

[0047] Optionally, the target area may contain one or more measured target wells.

[0048] Optionally, in order to obtain the seismic wave depth domain velocity field of the target area, it is also necessary to obtain seismic data, well logging data and other data with geological structural characteristics of the target area. The seismic data is obtained by: exciting seismic waves at one or more excitation points in the target area and collecting the seismic wave data through detection equipment.

[0049] Optionally, a joint modeling process is performed based on acquired seismic data, well logging data, and other data with geological structural characteristics to determine the seismic wave depth-domain velocity field of the target area. The depth-domain velocity field reflects the variation of seismic wave velocity with depth. Illustratively, a time-domain geological model and an initial time-domain velocity field are established based on seismic data, well logging data, and other data with geological structural characteristics. A time-depth conversion is then performed based on the time-domain geological model and the initial time-domain velocity field to obtain the seismic wave depth-domain velocity field.

[0050] In some alternative embodiments, the seismic wave velocity field described above can also be a seismic wave time-domain velocity field, which is illustrative and reflects how the velocity of the seismic wave changes over time.

[0051] The velocity field includes one-dimensional, two-dimensional, and three-dimensional velocity fields. For a one-dimensional velocity field, the velocity field is a series of velocity values. This is because the depth or time is arranged at equal intervals from small to large in the velocity field. Therefore, the recording of depth or time is usually omitted in the velocity field. Only the sampling interval (i.e., depth interval or time interval) and velocity value are recorded. The sampling interval is usually recorded using some track heads.

[0052] Optionally, a two-dimensional velocity field is an arrangement of a series of one-dimensional velocity fields, and a three-dimensional velocity field is an arrangement of a series of two-dimensional velocity fields. These arrangements can be located in space using x and y coordinates; or, their location in the work area can be determined using lines and common reflection points (common depth points).

[0053] Step 202: Based on the seismic wave depth domain velocity field and the P-wave sonic time difference logging curve of the target well, the P-wave constraint coefficient is obtained. The seismic wave depth domain velocity field is constrained by the P-wave constraint coefficient to obtain the well-constrained P-wave velocity volume.

[0054] The well-constrained P-wave velocity volume is used to indicate the propagation speed of seismic waves after P-wave constraints in the target area, that is, the propagation speed of seismic waves after P-wave constraint coefficients in the target area.

[0055] Optionally, the seismic wave depth domain velocity field includes several sample points, where each sample point represents a velocity-depth pair and each sample point represents a different spatial location; the P-wave sonic transit time logging curve of the target well also has several value points, each value point also represents a velocity-depth pair and each value point represents a different spatial location.

[0056] It should be noted that since the target well is located within the target area, the spatial location represented by the point on the P-wave sonic transit time logging curve is included within the spatial location represented by the sample point in the seismic depth domain velocity field. Optionally, sample points and point values ​​at the same spatial location can be combined for analysis to obtain the P-wave constraint coefficient. Based on the P-wave constraint coefficient, the velocity values ​​in the sample points are constrained to obtain the P-wave constrained velocity. Schematic, the first velocity value of the seismic depth domain velocity field at the first spatial location and the second velocity value of the P-wave sonic transit time logging curve of the target well at the first spatial location are obtained. The P-wave constraint coefficient is obtained by proportionalizing the second velocity value and the first velocity value. Multiplying the P-wave constraint coefficient by the first velocity value yields the P-wave constrained velocity. The constrained velocities of the seismic depth domain velocity field at various spatial locations within the target area are calculated. The resulting set of P-wave constrained velocity-depth pairs is the well-constrained P-wave velocity volume.

[0057] Optionally, if there is only one well in the target area, it is only necessary to calculate the P-wave constraint velocity corresponding to the spatial location of the point on the P-wave sonic transit time logging curve of that well. The resulting well-constrained P-wave velocity volume only represents the P-wave constraint velocity of the seismic wave in that well. If there are multiple wells in the target area, it is necessary to calculate the P-wave constraint velocity corresponding to the spatial location of the point on the P-wave sonic transit time logging curve of each of the multiple wells. The resulting well-constrained P-wave velocity volume represents the P-wave constraint velocity of the seismic wave in multiple wells.

[0058] Step 203: Based on the P-wave sonic transit time logging curve and the S-wave sonic transit time logging curve of the target well, the S-wave constraint coefficient is obtained. The S-wave constraint coefficient is used to constrain the well-constrained P-wave velocity volume to obtain the well-constrained S-wave velocity volume.

[0059] Well-constrained shear wave velocity volume is used to indicate the propagation speed of seismic waves after shear wave constraint in the target area, that is, the propagation speed of seismic waves after shear wave constraint coefficient in the target area.

[0060] Optionally, the shear wave sonic transit time logging curve of the target well has several points, each representing a velocity-depth pair, and each point represents a different spatial location.

[0061] Optionally, the shear wave sonic transit time logging (SLT) curve points and longitudinal wave sonic transit time logging (LLT) curve points located in the same spatial position are combined and analyzed to obtain the shear wave constraint coefficient. Based on the shear wave constraint coefficient, the velocity values ​​at the LLT curve points are constrained to obtain the shear wave constraint velocity. Schematic, based on step 202, after obtaining the second velocity value of the LLT curve of the target well at the first spatial position, the third velocity value of the shear wave sonic transit time logging curve of the target well at the first spatial position is obtained. The third velocity value is proportional to the second velocity value to obtain the shear wave constraint coefficient. Multiplying this shear wave constraint coefficient by the second velocity value yields the shear wave constraint velocity. The constrained velocity of the LLT curve of the target well at each spatial position is calculated, and the resulting set of shear wave constraint velocity-depth pairs is the well-constrained shear wave velocity volume.

[0062] Optionally, if there is only one well in the target area, it is only necessary to calculate the constraint velocity corresponding to the spatial location of the sampling point on the shear wave sonic transit time logging curve of the well. The resulting well-constrained P-wave velocity volume only represents the shear wave constraint velocity of the seismic wave in that well. If there are multiple wells in the target area, it is necessary to calculate the shear wave constraint velocity corresponding to the spatial location of the sampling point on the shear wave sonic transit time logging curve of each of the multiple wells. The resulting well-constrained shear wave velocity volume represents the shear wave constraint velocity of the seismic wave in multiple wells.

[0063] Step 204: Calculate the P-wave travel time based on the well-constrained P-wave velocity volume.

[0064] P-wave travel time is used to indicate the propagation time of a seismic wave in the target region after being constrained by the P-wave constraint, that is, the propagation time of a seismic wave in the target region after being constrained by the P-wave constraint coefficient.

[0065] Optionally, if the calculation of P-wave travel time is to calculate the P-wave travel time at each spatial location (i.e., the point of reference) of the well-constrained P-wave velocity body, then the process of calculating the P-wave travel time further includes the following steps:

[0066] Step 1: Calculate the one-way travel time of the P-waves at the target location in the target area based on the well-constrained P-wave velocity volume. The one-way travel time of the P-waves indicates the actual time required for the P-wave-constrained seismic waves to reach the target location in the target area.

[0067] Optionally, the target area contains n target locations, where n is a positive integer and is greater than or equal to 1; based on the difference between the average P-wave travel time of the i-th target location and the average P-wave travel time of the (i-1)-th target location, n-1 average P-wave travel time differences are obtained, where i is less than or equal to n, wherein the average P-wave travel time is used to indicate the average time required for the P-wave constrained seismic wave to reach the target location in the target area; the n-1 average P-wave travel time differences are accumulated to obtain the one-way P-wave travel time corresponding to the n-th target location in the target area.

[0068] Optionally, the formula for calculating the one-way travel time of the P-wave corresponding to the nth target position is:

[0069]

[0070] Where, Δt p0i It represents t p0i -t p0i-1 That is, the difference between the average P-wave travel time at the i-th target location and the average P-wave travel time at the (i-1)-th target location, t p0 The one-way travel time of the longitudinal wave corresponding to the nth target position.

[0071] To illustrate, if the velocity of a seismic wave after being constrained by the P-wave constraint coefficient at a certain target location is v1, and the depth of that target location is h1, then the average travel time of the P-wave at that target location is h1 / v1, which represents the time required for the seismic wave to travel at an average velocity v1 to the target location at a depth h1. Since the velocity of seismic waves varies at different locations within the target area, the average travel time of P-waves obviously cannot represent the actual time it takes for the seismic waves to reach the target location. Therefore, the actual one-way travel time of P-waves is calculated to represent the actual one-way travel time of the seismic waves to a certain location in the target area. If there are 10 target locations arranged in ascending order of depth, to calculate the one-way travel time of the P-waves at the 10th target location, the average travel time of the P-waves corresponding to each of the 10 locations needs to be calculated. Assuming that the average travel times of the P-waves calculated from the 1st to the 10th target locations are 1ms, 2ms, 3ms, 4ms, 5ms, 6ms, 7ms, 8ms, 9ms, and 10ms respectively, the average travel times of the P-waves at adjacent locations are subtracted from each other to obtain 9 differences. The sum of these 9 differences gives the one-way travel time of the P-waves at the 10th target location as 9ms.

[0072] Step 2: Integrate the one-way travel times of the longitudinal waves at various locations in the target area to obtain the longitudinal wave travel time.

[0073] Indicatively, by calculating the one-way travel time of the P-wave at each location in the target region, the one-way travel time of the P-wave at each location in the target region constitutes the P-wave travel time.

[0074] Step 205: Calculate the shear wave travel time based on the well-constrained shear wave velocity volume.

[0075] Shear wave travel time is used to indicate the propagation time of a seismic wave in the target area after being constrained by shear wave constraints, that is, the propagation time of a seismic wave in the target area after being constrained by the shear wave constraint coefficient.

[0076] Optionally, the calculation of shear wave travel time, i.e., the calculation of shear wave travel time at each spatial location (i.e., the point of reference) of the well-constrained shear wave velocity body, further includes the following steps:

[0077] Step 1: Based on the well-constrained shear wave velocity volume, calculate the one-way travel time of the shear wave at the target location in the target area. The one-way travel time of the shear wave is used to indicate the actual time required for the seismic wave, after being constrained by the shear wave, to reach the target location in the target area.

[0078] Optionally, the target area contains n target locations, where n is a positive integer and is greater than or equal to 1; based on the difference between the average travel time of the shear wave at the j-th target location and the average travel time of the shear wave at the (j-1)-th target location, n-1 average travel time differences of the shear wave are obtained, where j is less than or equal to n. The average travel time of the shear wave is used to indicate the average time required for the seismic wave constrained by the shear wave to reach the target location in the target area; the n-1 average travel time differences of the shear wave are accumulated to obtain the one-way travel time of the shear wave corresponding to the n-th target location in the target area.

[0079] Optionally, the formula for calculating the one-way travel time of the shear wave corresponding to the nth target position is:

[0080]

[0081] Where, Δt s0j It represents t s0j -t s0j-1 That is, the difference between the average travel time of the shear wave at the j-th target location and the average travel time of the shear wave at the (j-1)-th target location, t s0 The transverse wave one-way travel time corresponding to the nth target position.

[0082] For specific calculation instructions on the one-way travel of shear waves, please refer to step 204 for specific calculation instructions on the one-way travel of longitudinal waves, which will not be repeated here.

[0083] Step 2: Integrate the transverse wave one-way travel times at various locations in the target area to obtain the transverse wave travel time.

[0084] Schematic, by calculating the one-way travel time of the shear wave at each location in the target region, the one-way travel time of the shear wave at each location in the target region constitutes the shear wave travel time.

[0085] Step 206: Perform combined analysis of the longitudinal wave travel time and the transverse wave travel time to obtain the converted wave gamma field of the target region.

[0086] Converted wave gamma fields are used to obtain pre-stack time-migration profiles of the target well through migration, and these profiles are used to characterize the geological morphology of the target well.

[0087] Optionally, the longitudinal wave travel time and the transverse wave travel time are summed to obtain the converted wave travel time; a candidate gamma field is obtained based on the proportional relationship between the transverse wave travel time and the longitudinal wave travel time; and the converted wave travel time and the candidate gamma field are matched to obtain the converted wave gamma field.

[0088] To illustrate, firstly, the one-way travel time of the converted wave at each location in the target region is calculated. Taking the calculation of the one-way travel time of the converted wave at the target location as an example, the one-way travel time of the P-wave and the one-way travel time of the S-wave at the target location is added together to obtain the one-way travel time of the converted wave. The formula for calculating the one-way travel time of the converted wave is:

[0089] Formula 3: t c0 =t p0 +t s0

[0090] Among them, t c0 Let the one-way travel time of the converted wave corresponding to the nth target location be denoted as ; then the one-way travel time of the converted waves at each location in the target area constitutes the converted wave travel time.

[0091] Secondly, the candidate gamma field at each location in the target region is calculated. Taking the calculation of the candidate gamma field at the target location as an example, the candidate gamma field at the target location is obtained by dividing the one-way travel time of the shear wave by the one-way travel time of the longitudinal wave. The formula for calculating the candidate gamma field at the target location is:

[0092]

[0093] Where γ0 is the candidate gamma field corresponding to the nth target position.

[0094] Finally, the converted wave travel time of the nth target position and the candidate gamma field of the nth target position are output in correspondence, thus obtaining the converted wave gamma field of the nth target position. The converted wave gamma field is output at each position in the target region, and the output converted wave gamma field is in the form of a velocity-time pair.

[0095] In some optional embodiments, the above summation of P-wave travel time and S-wave travel time also includes weighted summation of P-wave travel time and S-wave travel time. Schematic, according to actual geological characteristics, weighting coefficients are assigned to either P-wave travel time or S-wave travel time to obtain a weighted converted wave travel time.

[0096] In some optional embodiments, after outputting the converted-wave gamma field, the converted-wave gamma field can be interpolated and extrapolated to obtain converted-wave gamma fields with equal time intervals. Optionally, the converted-wave gamma field is extrapolated to predict points outside the range of values ​​of the converted-wave gamma field; the converted-wave gamma field is interpolated to predict points within the range of values ​​of the converted-wave gamma field; thus obtaining the target converted-wave gamma field.

[0097] In this context, the sample points in the target converted wave gamma field are uniformly distributed, meaning that the time interval between two adjacent sample points is the same.

[0098] In a schematic way, the original sample points are processed by adding sample points to make the sample points in the target converted wave gamma field evenly distributed. The values ​​of the added sample points are then obtained by extrapolation calculation or interpolation prediction.

[0099] In a schematic manner, the obtained converted wave gamma field is applied to the calculation of the converted wave pre-stack time migration equation for the target well to obtain the converted wave pre-stack time migration profile of the target well.

[0100] In summary, the seismic data processing method provided in this application constrains the seismic wave depth domain velocity field using P-wave sonic transit time logging curves and S-wave sonic transit time logging curves to obtain well-constrained P-wave velocity volumes and well-constrained S-wave velocity volumes. Based on these well-constrained P-wave velocity volumes and well-constrained S-wave velocity volumes, the P-wave travel time and the S-wave travel time are calculated to obtain the converted wave gamma field. By constraining the seismic data based on the well logging data, the error in the final converted wave gamma field is reduced, and the accuracy of the converted wave gamma field is improved.

[0101] The seismic data processing method provided in this application matches the calculated converted wave gamma field with the converted wave travel time to output a time-domain-based converted wave gamma field. It also performs interpolation and extrapolation calculations on the converted wave gamma field to ensure that each sample point in the converted wave gamma field is evenly distributed, thereby optimizing the pre-stack time migration profile of the converted wave obtained based on the converted wave gamma field.

[0102] In some optional embodiments, the aforementioned seismic wave depth-domain velocity field includes the P-wave pre-stack depth migration velocity field. Schematic, after determining the P-wave depth-domain velocity field, pre-stack depth migration processing is performed on the P-wave depth-domain velocity to obtain the final P-wave pre-stack depth migration velocity field. Please refer to... Figure 3 The process of obtaining the well-constrained P-wave velocity volume and the well-constrained S-wave velocity volume also includes the following steps:

[0103] Step 2021: Fit and analyze the P-wave sonic transit time logging curve of the target well to obtain the initial P-wave velocity smooth curve of the target well.

[0104] Optionally, before fitting and analyzing the P-wave sonic transit time logging curve of the target well, it is necessary to grid the obtained P-wave sonic transit time logging curve of the target well to the line point number (line, cdp) of the corresponding processing area according to the coordinate position (x, y) of the target well.

[0105] Before fitting analysis, the P-wave sonic transit time logging curve of the target well is actually a series of discrete velocity-time pairs. Optionally, by quantitatively analyzing the series of discrete velocity-time pairs, a suitable fitting formula can be selected to fit the series of discrete velocity-time pairs into a continuous smooth curve.

[0106] To illustrate, let's take the following formula as an example of how the fitting formula can be implemented:

[0107] Formula 5: v = at 2 +bt+c

[0108] Substitute all sample points from the P-wave sonic transit time log of the target well into Formula 5 to obtain the optimal coefficients a, b, and c, which is the final fitting formula. Optionally, the optimal functional relationship can be selected based on the closeness of the sample points to the functional relationship.

[0109] The fitted velocity-time pair is obtained based on the optimal functional relationship. The fitted velocity-time pair is then gridded according to the coordinate position (x, y) of the target well to obtain the line point number (line, cdp) of the corresponding processing area, thus obtaining the initial P-wave velocity smoothing curve of the target well.

[0110] Step 2022: Extrapolate the initial P-wave velocity smoothing curve of the target well to the target location range to obtain the target P-wave velocity smoothing curve of the target well.

[0111] Schematic, the target location interval is the interval between the minimum and maximum depths corresponding to the sample points in the seismic wave depth-domain velocity field of the target area. Then, based on the optimal functional relationship obtained in step 2022, the unknown velocity-time pairs within the target location interval are solved to obtain the target P-wave velocity smoothing curve of the target well, and the depth interval of each sample point in the target P-wave velocity smoothing curve is the same as the depth interval of each sample point in the pre-stack depth migration velocity field of the P-wave.

[0112] Step 2023: Extract the velocity-depth pairs of the pre-stack depth migration velocity field of the P-wave in the target location interval of the target region to obtain the migration velocity curve.

[0113] Optionally, if there is only one target well in the target area, it is only necessary to extract the velocity-depth pairs at the same position of each sample point in the target P-wave velocity smoothing curve of the target well, and the extracted velocity-depth curve is the migration velocity curve; if there are multiple wells in the target area, it is necessary to extract the velocity-depth pairs at the same position of each sample point in the P-wave velocity smoothing curve of each of the multiple wells respectively, and form the migration velocity curves corresponding to the multiple wells respectively.

[0114] Step 2024: Based on the percentage of velocity values ​​at the same position of the target P-wave velocity smooth curve and the offset velocity curve of the target well, obtain the P-wave well percentage volume, and use the P-wave well percentage volume as the P-wave constraint coefficient.

[0115] Optionally, if the target P-wave velocity smoothing curve and the offset velocity curve of the target well are in the (x, y) coordinate system, then the velocity values ​​of the target P-wave velocity smoothing curve and the offset velocity curve of the target well at the same coordinate position are proportionally calculated to obtain the velocity percentage. For example, if the velocity value of the target P-wave velocity smoothing curve of the target well is 20 m / s and the velocity value of the offset velocity curve is 40 m / s, then the percentage obtained by the proportion is 50%. If the target P-wave velocity smoothing curve and the offset velocity curve of the target well are in the (line, cdp) work area, then the velocity values ​​of the target P-wave velocity smoothing curve and the offset velocity curve of the target well at the same depth position are proportionally calculated to obtain the velocity percentage.

[0116] Optionally, after scaling up the velocity values ​​corresponding to all coordinate positions or line points in the target P-wave velocity smoothing curve or offset velocity curve of the target well, the velocity percentage corresponding to all coordinate positions is the P-wave well percentage volume, which is also the P-wave constraint coefficient.

[0117] In some optional embodiments, if there are multiple wells in the target region, it is necessary to perform proportional analysis on the migration velocity curves and P-wave velocity smoothing curves corresponding to each well to obtain a family of P-wave multi-well percentage curves. Optionally, it is also necessary to interpolate and extrapolate the family of P-wave multi-well percentage curves to form a P-wave well percentage body with the same spatial range as the pre-stack depth migration velocity field. Schematic, this makes the line and cdp intervals of the family of P-wave multi-well percentage curves the same as the line and cdp intervals of the pre-stack depth migration velocity field.

[0118] The interpolation formula used above is a linear interpolation formula. That is, if A(i1, b1) and B(i2, b2) are two points, and point P(i, b) lies on the straight line determined by the two points, then (b-b1) / (i-i1) = (b2-b1) / (i2-i1) is the slope of the straight line. The straight line required for interpolation is determined by the interpolation formula. The extrapolation formula used above is Formula 5. The extrapolation method for the P-wave multi-well percentage curve family can refer to the extrapolation method for the P-wave sonic time-of-flight logging curve in step 2021, which will not be repeated here. Optionally, the P-wave multi-well percentage curve family is first interpolated and extrapolated along the line direction, and then interpolated and extrapolated in the cdp direction, finally obtaining the P-wave well percentage volume with the same spatial range as the P-wave pre-stack depth migration velocity field.

[0119] Step 2025: Calculate the product of the P-wave well percentage volume and the P-wave pre-stack depth migration velocity field to obtain the well-constrained P-wave velocity volume.

[0120] The P-wave well percentage volume contains multiple well percentages, each corresponding to a coordinate position or line point number. Schematic, the well-constrained P-wave velocity can be obtained by multiplying the well percentages with the same coordinate position or line point number by the velocity of the P-wave pre-stack depth migration velocity field.

[0121] The well-constrained P-wave velocity volume is the set of well-constrained P-wave velocities obtained by multiplying the well percentage of all coordinate positions or line points in the P-wave well percentage volume with the corresponding P-wave pre-stack depth migration velocity field.

[0122] Step 2031: Fit and analyze the shear wave sonic transit time logging curve of the target well to obtain the initial shear wave velocity smooth curve of the target well.

[0123] Fitting analysis of the shear wave sonic time-of-flight logging curves yields the initial smoothed shear wave velocity curve of the target well, which can be found in step 2021 and will not be repeated here.

[0124] Step 2032: Extrapolate the initial shear wave velocity smoothing curve of the target well to the target location range to obtain the target shear wave velocity smoothing curve of the target well.

[0125] Based on the optimal functional relationship obtained in step 2031, the unknown velocity-time pair within the target location interval is solved to obtain the target shear wave velocity smoothing curve of the target well, and the depth interval of each sample point in the target shear wave velocity smoothing curve is the same as the depth interval of each sample point in the pre-stack depth migration velocity field of the P-wave.

[0126] Step 2033: Based on the percentage of velocity values ​​at the same position of the target P-wave velocity smooth curve and the target S-wave velocity smooth curve of the target well, obtain the S-wave well percentage volume, and use the S-wave well percentage volume as the S-wave constraint coefficient.

[0127] Optionally, if the target P-wave velocity smoothing curve and the target S-wave velocity smoothing curve of the target well are in the (x, y) coordinate system, then the velocity values ​​of the target S-wave velocity smoothing curve and the target P-wave velocity smoothing curve of the target well at the same coordinate position are proportionally calculated to obtain the velocity percentage; if the target P-wave velocity smoothing curve and the target S-wave velocity smoothing curve of the target well are in the (line, cdp) work area, then the velocity values ​​of the target S-wave velocity smoothing curve and the target P-wave velocity smoothing curve of the target well at the same depth position are proportionally calculated to obtain the velocity percentage.

[0128] Optionally, after scaling up the velocity values ​​corresponding to all coordinate positions or line points in the target P-wave velocity smoothing curve or the target S-wave velocity smoothing curve of the target well, the velocity percentage corresponding to all coordinate positions is the S-wave well percentage volume, which is also the S-wave constraint coefficient.

[0129] In some optional embodiments, if there are multiple wells in the target region, it is necessary to perform proportional analysis on the smoothed shear wave velocity curves and the smoothed p-wave velocity curves corresponding to each well to obtain a family of shear wave multi-well percentage curves. Optionally, it is also necessary to interpolate and extrapolate the family of shear wave multi-well percentage curves to form a shear wave well percentage volume with the same spatial range as the p-wave pre-stack depth migration velocity field.

[0130] Step 2034: Calculate the product of the shear wave percentage volume and the well-constrained longitudinal wave velocity volume to obtain the well-constrained shear wave velocity volume.

[0131] The shear wave percentage volume contains multiple well percentages, each corresponding to a coordinate position or line point number. To illustrate, the well-constrained shear wave velocity can be obtained by multiplying the well percentages with the same coordinate position or line point number by the velocity of the well-constrained longitudinal wave velocity volume.

[0132] The well-constrained P-wave velocity volume is the set of all coordinate positions or line point numbers in the shear wave well percentage volume, multiplied by the corresponding well-constrained P-wave velocity volume.

[0133] In some alternative embodiments, multiple measured wells exist in the target area, and the final P-wave pre-stack depth migration velocity field, P-wave sonic transit time logging curves, and S-wave sonic transit time logging curves are known. Please refer to [reference needed]. Figure 4 The diagram illustrates a complete flowchart of a seismic data processing method provided in an exemplary embodiment of this application, the method comprising the following steps:

[0134] S1: Read the longitudinal wave sonic time difference logging curve.

[0135] Indicatively, read the P-wave sonic time-of-flight logging curves corresponding to each well in the target area. These curves are a series of velocity-time pairs. Based on the location coordinates (x, y) of each well, the line point number (line, cdp) of the corresponding processing area is gridded out.

[0136] S2: Extract the longitudinal wave smooth curve and extrapolate it to the top and bottom.

[0137] To illustrate, a smooth curve is first extracted from the P-wave sonic transit time logging curve. The formula for extracting the smooth curve is the fitting formula, also known as Formula 5. By substituting the existing sample points on the P-wave sonic transit time logging curve into Formula 5 to obtain the optimal coefficients a, b, and c, a functional relationship is obtained. This functional relationship is the final fitting formula, which is the P-wave smooth curve.

[0138] Secondly, based on this functional relationship, the P-wave smoothing curve is extrapolated to the same depth interval as the top and bottom of the P-wave pre-stack depth migration velocity field, and the depth interval of the P-wave smoothing curve is re-extracted to be the same as the depth interval of the P-wave pre-stack depth migration velocity field.

[0139] S3: Read the pre-stack depth migration velocity field of the longitudinal wave and extract the velocity curve at the well location.

[0140] Schematic illustration: The final pre-stack depth migration velocity field of the P-wave is read. Velocity-depth pairs are extracted from the final pre-stack depth migration velocity field of the P-wave based on the well location x, y coordinates, or line, CDP point numbers, forming a curve composed of a series of velocity-depth pairs. The extracted depth position sequence t1 is the same as the well acoustic time difference extracted depth sequence t2.

[0141] S4: Family of percentage curves for multiple wells with longitudinal wave.

[0142] That is, based on the velocity curves at each well location and the P-wave smoothing curves of each well obtained above, a family of P-wave percentage curves for multiple wells is obtained.

[0143] Schematic representation: The velocity values ​​of the P-wave smoothed curve and the velocity curve at the well location are proportionally calculated at the same spatial position (based on x, y coordinates) or the same depth position (based on line, CDP line point number), i.e., by dividing them to obtain the velocity percentage. This percentage-depth pair is recorded, and the recording format sequence is the same as that of the P-wave smoothed curve. This process continues until all wells within the target area have been calculated, thus forming a family of P-wave multi-well percentage curves.

[0144] S5: The P-wave percentage curve family is interpolated and extrapolated to form the P-wave percentage volume.

[0145] Schematic, the family of percentage curves for P-wave multi-wells is interpolated and extrapolated to form a percentage volume with the same spatial range as the pre-stack depth migration velocity field of P-waves. Optionally, the line and cdp intervals of the family of percentage curves for P-wave multi-wells are the same as the line and cdp intervals of the pre-stack depth migration velocity field of P-waves.

[0146] The interpolation formula used above is the linear interpolation formula. That is, if A(i1, b1) and B(i2, b2) are two points, and point P(i, b) lies on the straight line determined by these two points, then (b-b1) / (i-i1) = (b2-b1) / (i2-i1) is the slope of the straight line. The formula used above for extrapolation is Formula 5.

[0147] Optionally, the family of P-wave multi-well percentage curves is first interpolated and extrapolated along the line direction, and then extrapolated and interpolated in the cdp direction to finally obtain a P-wave well percentage volume with the same spatial range as the pre-stack depth migration velocity field of P-waves. This P-wave well percentage volume is composed of multiple P-wave well percentages.

[0148] S6: Proportional to multi-well constrained P-wave velocity body.

[0149] That is, the P-wave pre-stack depth migration velocity field is proportional to the aforementioned P-wave well percentage volume to obtain the multi-well constrained P-wave velocity volume. Schematic, multiplying the P-wave pre-stack depth migration velocity at the same spatial location or the same depth location with its corresponding P-wave well percentage yields the multi-well constrained P-wave velocity volume.

[0150] S7: Read the transverse wave sonic time-of-flight logging curve.

[0151] Indicatively, the shear wave sonic time-of-flight logging curves corresponding to each well in the target area are read. These curves are a series of velocity-time pairs. The line point number (line,cdp) of the corresponding processing area is gridded according to the position coordinates (x,y) of each well.

[0152] S8: Extract the smooth curve of the transverse wave and extrapolate it to the top and bottom.

[0153] To illustrate, a smooth curve is first extracted from the shear wave sonic transit time logging curve. The formula for extracting the smooth curve is the fitting formula, also known as Formula 5. By substituting the existing sample points on the shear wave sonic transit time logging curve into Formula 5 to obtain the optimal coefficients a, b, and c, a functional relationship is obtained. This functional relationship is the final fitting formula, which is the shear wave smooth curve.

[0154] Secondly, based on this functional relationship, the shear wave smoothing curve is extrapolated to the same top and bottom as the depth interval of the pre-stack depth migration velocity field of the P-wave, and the depth interval of the shear wave smoothing curve is re-extracted to be the same as the depth interval of the pre-stack depth migration velocity field of the P-wave.

[0155] S9: Family of percentage curves for shear wave multi-wells.

[0156] That is, based on the smoothed shear wave curves and the smoothed longitudinal wave curves of each well, a family of percentage curves for shear waves in multiple wells is obtained.

[0157] Schematic representation: The velocity values ​​of the P-wave smoothed curve and the S-wave smoothed curve at the same spatial location or depth are proportionally calculated by dividing them by each other to obtain a velocity percentage. This percentage is recorded in a percentage-depth pair format, with the recording format sequence being the same as that of the P-wave smoothed curve. This process continues until all wells within the target area have been calculated, thus forming a family of S-wave multi-well percentage curves.

[0158] S10: The percentage curves of multiple shear waves are interpolated and extrapolated to form the percentage volume of shear waves.

[0159] The specific process for forming the percentage volume of the shear wave well can be found in S5, and will not be repeated here.

[0160] S11: Proportional to multi-well constrained shear wave velocity body.

[0161] That is, the percentage volume of the shear wave wells is used to proportional the percentage volume of the longitudinal wave wells to the multi-well constrained shear wave velocity volume. Schematic, multiplying the velocity of the multi-well constrained shear wave velocity volume at the same spatial location or the same depth position with its corresponding shear wave well percentage yields the multi-well constrained shear wave velocity volume.

[0162] S12: Calculate the one-way travel time of the longitudinal wave.

[0163] To illustrate, the formula for calculating the one-way travel time of the P-wave at each sample point on the multi-well constrained P-wave velocity body is Formula 1.

[0164] S13: Calculate the one-way travel time of the transverse wave.

[0165] To illustrate, the formula for calculating the one-way travel time of the shear wave at each sample point on the multi-well constrained shear wave velocity body is Formula 2.

[0166] S14: Calculate the transformed wave gamma field.

[0167] To illustrate, the converted wave gamma field at each sample point on a multi-well constrained P-wave velocity body or a multi-well constrained S-wave velocity body is calculated. The formula for calculating the converted wave gamma field is Formula 4.

[0168] S15: Calculate the travel time of the converted wave.

[0169] For illustration purposes, the formula for calculating the converted wave gamma field at each sample point on a multi-well constrained P-wave velocity body or a multi-well constrained S-wave velocity body is Formula 3.

[0170] S16: Output conversion wave gamma field.

[0171] Schematic diagram: Since the pre-stack time offset of the converted wave is a time-domain offset, the converted wave gamma field is output according to the arrival time of the converted wave, that is, in the form of a converted wave time-converted wave gamma field pair. The time of the converted wave is t. c0 That is, when the converted wave actually travels, its corresponding gamma field is γ0.

[0172] Optionally, the output converted wave gamma field can be interpolated and extrapolated to form gamma fields with equal time intervals. Schematic, industrial software can be used to interpolate and extrapolate the converted wave gamma field and then resample it at equal intervals.

[0173] After the above steps, the obtained converted wave gamma field lays a relatively accurate initial gamma field foundation for the pre-stack time migration of the converted wave.

[0174] This is illustrative; please refer to it. Figure 5 and Figure 6 , Figure 5 A schematic diagram of the pre-stack time migration profile of the converted wave obtained by manually picked gamma field migration is shown in Figure 500. Figure 6 A schematic diagram 600 is shown of a pre-stack time-migrated profile of a converted wave obtained from a gamma field acquired by a seismic data processing method provided in an exemplary embodiment of this application, after migration. (Comparison) Figure 5 and Figure 6 It can be seen that the profile imaging effect obtained by the converted wave gamma field migration through this method is significantly better than the profile imaging effect of manually picked gamma fields.

[0175] Please refer to Figure 7 The diagram illustrates a structural block diagram of a seismic data processing apparatus provided in an exemplary embodiment of this application, the apparatus comprising the following modules:

[0176] The acquisition module 710 is used to acquire the seismic wave depth domain velocity field of the target area, which is used to indicate the propagation speed of seismic waves in the target area, where the target area contains a measured target well.

[0177] The processing module 720 is used to obtain the P-wave constraint coefficient based on the seismic wave depth domain velocity field and the P-wave sonic time difference logging curve of the target well, and to constrain the seismic wave depth domain velocity field through the P-wave constraint coefficient to obtain the well-constrained P-wave velocity volume. The well-constrained P-wave velocity volume is used to indicate the propagation speed of the seismic wave after passing through the P-wave constraint in the target area.

[0178] The processing module 720 is further configured to obtain a shear wave constraint coefficient based on the P-wave sonic time-of-flight logging curve and the shear wave sonic time-of-flight logging curve of the target well, and to perform constraint processing on the well-constrained P-wave velocity volume using the shear wave constraint coefficient to obtain a well-constrained shear wave velocity volume. The well-constrained shear wave velocity volume is used to indicate the propagation speed of seismic waves after shear wave constraint in the target area.

[0179] The calculation module 730 is configured to calculate the P-wave travel time based on the well-constrained P-wave velocity volume, wherein the P-wave travel time is used to indicate the propagation time of the seismic wave through the P-wave constraint in the target region; and to calculate the S-wave travel time based on the well-constrained S-wave velocity volume, wherein the S-wave travel time is used to indicate the propagation time of the seismic wave through the S-wave constraint in the target region.

[0180] The combined analysis module 740 is used to perform combined analysis on the P-wave travel time and the S-wave travel time to obtain the converted wave gamma field of the target area. The converted wave gamma field is used to obtain the converted wave pre-stack time migration profile of the target well through migration. The converted wave pre-stack time migration profile is used to characterize the geological morphology of the target well.

[0181] In some optional embodiments, the calculation module 730 is further configured to calculate the one-way travel time of the P-wave at the target location in the target area based on the well-constrained P-wave velocity volume, wherein the one-way travel time of the P-wave is used to indicate the actual time required for the P-wave constrained seismic wave to reach the target location in the target area; the calculation module 730 is further configured to integrate the one-way travel times of the P-wave at various locations in the target area to obtain the P-wave travel time.

[0182] In some optional embodiments, the target area includes n target locations, where n is a positive integer; the calculation module 730 is further configured to obtain n-1 P-wave average travel time difference values ​​based on the difference between the P-wave average travel time of the i-th target location and the P-wave average travel time of the (i-1)-th target location, where i is less than or equal to n, and the P-wave average travel time is used to indicate the average time required for a seismic wave constrained by P-waves to reach a target location in the target area; the calculation module 730 is further configured to accumulate the n-1 P-wave average travel time difference values ​​to obtain the P-wave one-way travel time corresponding to the n-th target location in the target area.

[0183] In some optional embodiments, the calculation module 730 is further configured to calculate the one-way travel time of the shear wave at the target location in the target area based on the well-constrained shear wave velocity volume, wherein the one-way travel time of the shear wave is used to indicate the actual time required for the seismic wave constrained by the shear wave to reach the target location in the target area; the calculation module 730 is further configured to integrate the one-way travel times of the shear wave at various locations in the target area to obtain the shear wave travel time.

[0184] In some optional embodiments, the target area includes n target locations, where n is a positive integer; the calculation module 730 is further configured to obtain n-1 shear wave average travel time difference values ​​based on the difference between the shear wave average travel time of the j-th target location and the shear wave average travel time of the (j-1)-th target location, where j is less than or equal to n, and the shear wave average travel time is used to indicate the average time required for a seismic wave constrained by shear waves to reach a target location in the target area; the calculation module 730 is further configured to accumulate the n-1 shear wave average travel time difference values ​​to obtain the shear wave one-way travel time corresponding to the n-th target location in the target area.

[0185] Please refer to Figure 8 In some optional embodiments, the combined analysis module 740 includes:

[0186] Summation unit 741 is used to sum the longitudinal wave travel time and the transverse wave travel time to obtain the converted wave travel time.

[0187] The scaling unit 742 is used to obtain a candidate gamma field based on the scaling relationship between the transverse wave travel time and the longitudinal wave travel time;

[0188] The matching unit 743 is used to match the converted wave travel time with the candidate gamma field to obtain the converted wave gamma field.

[0189] In some optional embodiments, the calculation module 730 is further configured to perform extrapolation calculation on the converted wave gamma field, the extrapolation calculation being used to predict points outside the value range of the converted wave gamma field; the calculation module 730 is further configured to perform interpolation calculation on the converted wave gamma field, the interpolation calculation being used to predict points within the value range of the converted wave gamma field; the calculation module 730 is further configured to obtain a target converted wave gamma field, in which each sample point is uniformly distributed.

[0190] In some optional embodiments, the seismic wave depth domain velocity field includes the P-wave pre-stack depth migration velocity field; the processing module 720 further includes:

[0191] The fitting analysis unit 721 is used to perform fitting analysis on the P-wave sonic transit time logging curve of the target well to obtain the initial P-wave velocity smoothing curve of the target well.

[0192] Extrapolation unit 722 is used to extrapolate the initial P-wave velocity smoothing curve of the target well to the target location range to obtain the target P-wave velocity smoothing curve of the target well;

[0193] Extraction unit 723 is used to extract the velocity-depth pairs of the pre-stack depth migration velocity field of the longitudinal wave in the target location interval of the target region to obtain the migration velocity curve.

[0194] The calculation unit 724 is used to obtain the P-wave well percentage volume based on the percentage of the velocity values ​​at the same position of the target P-wave velocity smooth curve and the offset velocity curve of the target well, and to use the P-wave well percentage volume as the P-wave constraint coefficient.

[0195] The constraint unit 725 is used to calculate the product of the P-wave well percentage volume and the P-wave pre-stack depth offset velocity field to obtain the well-constrained P-wave velocity volume.

[0196] In some optional embodiments, the fitting analysis unit 721 is further configured to perform fitting analysis on the shear wave sonic transit time logging curve of the target well to obtain the initial shear wave velocity smoothing curve of the target well; the extrapolation unit 722 is further configured to extrapolate the initial shear wave velocity smoothing curve of the target well to the target position interval to obtain the target shear wave velocity smoothing curve of the target well; the calculation unit 724 is further configured to obtain the shear wave well percentage volume based on the percentage of velocity values ​​at the same position of the target P-wave velocity smoothing curve and the target shear wave velocity smoothing curve of the target well, and use the shear wave well percentage volume as the shear wave constraint coefficient; the constraint unit 725 is further configured to perform product calculation on the shear wave well percentage volume and the well constraint P-wave velocity volume to obtain the well constraint shear wave velocity volume.

[0197] In summary, the seismic data processing apparatus provided in this application constrains the seismic wave depth domain velocity field using P-wave sonic transit time logging curves and S-wave sonic transit time logging curves to obtain well-constrained P-wave velocity volumes and well-constrained S-wave velocity volumes. Based on these well-constrained P-wave velocity volumes and well-constrained S-wave velocity volumes, the P-wave travel time and the S-wave travel time are calculated to obtain the converted wave gamma field. By constraining the seismic data based on the logging data, the error in the final converted wave gamma field is reduced, and the accuracy of the converted wave gamma field is improved.

[0198] It should be noted that the seismic data processing apparatus provided in the above embodiments is only an example of the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the device can be divided into different functional modules to complete all or part of the functions described above. In addition, the seismic data processing apparatus and seismic data processing method embodiments provided in the above embodiments belong to the same concept, and their specific implementation process can be found in the method embodiments, which will not be repeated here.

[0199] Figure 9 This is a schematic diagram of the structure of a computer device provided in one embodiment of this application. Specifically, the computer device 900 includes a Central Processing Unit (CPU) 901, a system memory 904 including Random Access Memory (RAM) 902 and Read-Only Memory (ROM) 903, and a system bus 905 connecting the system memory 904 and the CPU 901. The computer device 900 also includes a basic input / output (I / O) system 906 that facilitates the transfer of information between various devices within the computer, and a mass storage device 907 for storing the operating system 913, application programs 914, and other program modules 915.

[0200] The basic input / output system 906 includes a display 908 for displaying information and an input device 905 for user input, such as a mouse or keyboard. Both the display 908 and the input device 905 are connected to the central processing unit 901 via an input / output controller 910 connected to the system bus 905. The basic input / output system 906 may also include the input / output controller 910 for receiving and processing input from multiple other devices such as a keyboard, mouse, or electronic stylus. Similarly, the input / output controller 910 also provides output to a display screen, printer, or other types of output devices.

[0201] Mass storage device 907 is connected to central processing unit 901 via a mass storage controller (not shown) connected to system bus 905. Mass storage device 907 and its associated computer-readable media provide non-volatile storage for computer device 900. That is, mass storage device 907 may include computer-readable media (not shown) such as hard disk or compact disc read-only memory (CD-ROM) drive.

[0202] Without loss of generality, computer-readable media can include computer storage media and communication media. Computer storage media includes volatile and non-volatile, removable and non-removable media implemented using any method or technology for storing information such as computer-readable instructions, data structures, program modules, or other data. Computer storage media include RAM, ROM, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other solid-state storage technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape cassettes, magnetic tape, disk storage, or other magnetic storage devices. Of course, those skilled in the art will recognize that computer storage media are not limited to the above-mentioned types. The system memory 904 and mass storage device 907 described above can be collectively referred to as memory.

[0203] According to various embodiments of this application, the computer device 900 can also be connected to a remote computer on a network, such as the Internet, for operation. That is, the computer device 900 can be connected to a network 912 via a network interface unit 911 connected to a system bus 905, or the network interface unit 911 can be used to connect to other types of networks or remote computer systems (not shown).

[0204] This application also provides a computer-readable storage medium storing at least one instruction, at least one program, a code set, or an instruction set, wherein the at least one instruction, the at least one program, the code set, or the instruction set is loaded and executed by a processor to implement the seismic data processing method provided in the above-described method embodiments.

[0205] This application provides a computer program product or computer program that includes computer instructions stored in a computer-readable storage medium. A processor of a computer device reads the computer instructions from the computer-readable storage medium and executes the computer instructions, causing the computer device to perform the seismic data processing method provided in the above-described method embodiments.

[0206] The sequence numbers of the embodiments in this application are for descriptive purposes only and do not represent the superiority or inferiority of the embodiments.

[0207] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a read-only memory, a disk, or an optical disk.

[0208] The above description is merely an optional embodiment of this application and is not intended to limit this application. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application.

Claims

1. A method of seismic data processing, characterized by, The method comprises: acquiring a seismic wave depth domain velocity field of a target region, the seismic wave depth domain velocity field being used to indicate a propagation velocity of a seismic wave in the target region, the target region containing a measured target well; obtaining a P-wave constraint coefficient based on the seismic wave depth domain velocity field and a P-wave acoustic travel time logging curve of the target well, and performing constraint processing on the seismic wave depth domain velocity field through the P-wave constraint coefficient to obtain a well-constrained P-wave velocity volume, the well-constrained P-wave velocity volume being used to indicate a P-wave-constrained propagation velocity of a seismic wave in the target region; obtaining a S-wave constraint coefficient based on the P-wave acoustic travel time logging curve of the target well and a S-wave acoustic travel time logging curve of the target well, and performing constraint processing on the well-constrained P-wave velocity volume through the S-wave constraint coefficient to obtain a well-constrained S-wave velocity volume, the well-constrained S-wave velocity volume being used to indicate a S-wave-constrained propagation velocity of a seismic wave in the target region; calculating a P-wave travel time based on the well-constrained P-wave velocity volume, the P-wave travel time being used to indicate a P-wave-constrained propagation time of a seismic wave in the target region; and calculating a S-wave travel time based on the well-constrained S-wave velocity volume, the S-wave travel time being used to indicate a S-wave-constrained propagation time of a seismic wave in the target region; performing combined analysis on the P-wave travel time and the S-wave travel time to obtain a converted wave gamma field of the target region, the converted wave gamma field being used to obtain a converted wave pre-stack time migration profile of the target well through migration, the converted wave pre-stack time migration profile being used to represent a geological form of the target well.

2. The method of claim 1, wherein, The calculating a P-wave travel time based on the well-constrained P-wave velocity volume comprises: calculating a P-wave one-way travel time at a target position of the target region based on the well-constrained P-wave velocity volume, the P-wave one-way travel time being used to indicate an actual time length required for a P-wave-constrained seismic wave to reach the target position of the target region; integrating P-wave one-way travel times at various positions of the target region to obtain the P-wave travel time.

3. The method of claim 2, wherein, The target region contains n target positions, n being a positive integer; The calculating a P-wave one-way travel time at a target position of the target region based on the well-constrained P-wave velocity volume comprises: obtaining n-1 P-wave average travel time differences based on a difference between a P-wave average travel time of an i-th target position and a P-wave average travel time of an i-1-th target position, i being less than or equal to n, the P-wave average travel time being used to indicate an average time length required for a P-wave-constrained seismic wave to reach the target position of the target region; cumulatively adding the n-1 P-wave average travel time differences to obtain the P-wave one-way travel time corresponding to an n-th target position of the target region.

4. The method of claim 1, wherein, The calculating a S-wave travel time based on the well-constrained S-wave velocity volume comprises: calculating a S-wave one-way travel time at a target position of the target region based on the well-constrained S-wave velocity volume, the S-wave one-way travel time being used to indicate an actual time length required for a S-wave-constrained seismic wave to reach the target position of the target region; obtaining the travel time of the shear wave at each position in the target region.

5. The method of claim 4, wherein, The target region includes n target positions, and n is a positive integer. The method further includes: obtaining n-1 average travel time differences of the shear wave based on a difference between the average travel time of the shear wave at the jth target position and the average travel time of the shear wave at the (j-1)th target position, where j is less than or equal to n, and the average travel time of the shear wave is used to indicate an average time length required for a seismic wave passing through the shear wave constraint to reach a target position in the target region; obtaining the one-way travel time of the shear wave at the nth target position in the target region by accumulating the n-1 average travel time differences of the shear wave.

6. The method according to any one of claims 1 to 5, characterized in that, The method further includes: performing a combination analysis on the travel time of the P-wave and the travel time of the S-wave to obtain a converted wave gamma field of the target region, including: performing a summation process on the travel time of the P-wave and the travel time of the S-wave to obtain a converted wave travel time; obtaining a candidate gamma field based on a proportional relationship between the travel time of the S-wave and the travel time of the P-wave; 7. The method of claim 6, wherein, matching the converted wave travel time and the candidate gamma field to obtain the converted wave gamma field. The method further includes: performing extrapolation calculation on the converted wave gamma field to predict a point outside a value range of the converted wave gamma field; performing interpolation calculation on the converted wave gamma field to predict a point within the value range of the converted wave gamma field; 8. The method according to any one of claims 1 to 5, characterized in that, obtaining a target converted wave gamma field in which sample points are uniformly distributed. The seismic wave depth domain velocity field includes a P-wave prestack depth migration velocity field. The method further includes: performing fitting analysis on the slowness curve of the P-wave to obtain an initial P-wave velocity smoothing curve of the target well; extrapolating the initial P-wave velocity smoothing curve of the target well to a target position interval to obtain a target P-wave velocity smoothing curve of the target well; extracting a velocity-depth pair of the P-wave prestack depth migration velocity field in the target position interval of the target region to obtain a migration velocity curve; obtaining a P-wave well percentage body based on a percentage of velocity values of the target P-wave velocity smoothing curve of the target well and the migration velocity curve at the same position, and taking the P-wave well percentage body as the P-wave constraint coefficient; 9. The method of claim 8, wherein, performing product calculation on the P-wave well percentage body and the P-wave prestack depth migration velocity field to obtain the well-constrained P-wave velocity body. The method further includes: performing fitting analysis on the slowness curve of the P-wave to obtain an initial P-wave velocity smoothing curve of the target well; extrapolating the initial P-wave velocity smoothing curve of the target well to a target position interval to obtain a target P-wave velocity smoothing curve of the target well; extracting a velocity-depth pair of the P-wave prestack depth migration velocity field in the target position interval of the target region to obtain a migration velocity curve; obtaining a P-wave well percentage body based on a percentage of velocity values of the target P-wave velocity smoothing curve of the target well and the migration velocity curve at the same position, and taking the P-wave well percentage body as the P-wave constraint coefficient; performing product calculation on the P-wave well percentage body and the P-wave prestack depth migration velocity field to obtain the well-constrained P-wave velocity body. Perform fitting analysis on the shear wave acoustic travel time log curve of the target well to obtain an initial shear wave velocity smooth curve of the target well; Perform extrapolation on the initial shear wave velocity smooth curve of the target well to the target position interval to obtain a target shear wave velocity smooth curve of the target well; Obtain a shear wave well percentage volume based on the percentage of the velocity values of the target longitudinal wave velocity smooth curve of the target well and the target shear wave velocity smooth curve of the target well at the same position, and take the shear wave well percentage volume as the shear wave constraint coefficient; Perform product calculation on the shear wave well percentage volume and the well-constrained longitudinal wave velocity volume to obtain the well-constrained shear wave velocity volume.

10. A seismic data processing apparatus, characterized by comprising: The device comprises: An acquisition module configured to acquire a seismic wave depth domain velocity field of a target area, the seismic wave depth domain velocity field being configured to indicate the propagation velocity of seismic waves in the target area, and the target area containing a measured target well; A processing module configured to obtain a longitudinal wave constraint coefficient based on the seismic wave depth domain velocity field and the longitudinal wave acoustic travel time log curve of the target well, to perform constraint processing on the seismic wave depth domain velocity field through the longitudinal wave constraint coefficient, and to obtain a well-constrained longitudinal wave velocity volume, the well-constrained longitudinal wave velocity volume being configured to indicate the propagation velocity of seismic waves in the target area after longitudinal wave constraint; The processing module is further configured to obtain a shear wave constraint coefficient based on the longitudinal wave acoustic travel time log curve of the target well and the shear wave acoustic travel time log curve of the target well, to perform constraint processing on the well-constrained longitudinal wave velocity volume through the shear wave constraint coefficient, and to obtain a well-constrained shear wave velocity volume, the well-constrained shear wave velocity volume being configured to indicate the propagation velocity of seismic waves in the target area after shear wave constraint; A calculation module configured to calculate a longitudinal wave travel time based on the well-constrained longitudinal wave velocity volume, the longitudinal wave travel time being configured to indicate the propagation time of seismic waves in the target area after longitudinal wave constraint, and to calculate a shear wave travel time based on the well-constrained shear wave velocity volume, the shear wave travel time being configured to indicate the propagation time of seismic waves in the target area after shear wave constraint; A combined analysis module configured to perform combined analysis on the longitudinal wave travel time and the shear wave travel time to obtain a converted wave gamma field of the target area, the converted wave gamma field being configured to obtain a converted wave pre-stack time migration profile of the target well through migration, and the converted wave pre-stack time migration profile being configured to represent the geological form of the target well.

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