A method, device, medium and product for determining shallow velocity in pre-stack depth migration

Abstract

This invention discloses a method, device, medium, and product for determining shallow velocities in pre-stack depth migration. The method includes: performing angular-domain pre-stack depth migration on seismic data based on a preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes, determining similarity spectra and gather curvature; determining analysis points and analysis point analysis windows based on the post-stack data volumes, determining the initial dip angle of the formation based on the similarity spectrum, performing a formation dip angle scan within the analysis point analysis window according to the initial dip angle of the formation, and determining the coherence values ​​between adjacent seismic traces along each formation dip angle direction; determining the formation dip angle of the analysis point based on the maximum coherence value, and determining the seismic wave propagation information of the analysis point based on the formation dip angle; performing travel-time inversion based on the seismic wave propagation information to obtain velocity disturbances and determine the shallow velocity field; using the shallow velocity field as a preset background velocity field, returning to determine the gather curvature of the omnidirectional common reflection angle gathers until the gather curvature meets preset conditions, thereby improving the accuracy of the shallow velocity field.

Description

Technical Field

[0001] This invention relates to the field of seismic data processing technology, and in particular to a method, device, medium, and product for determining shallow velocities in pre-stack depth migration. Background Technology

[0002] In recent years, the breadth and depth of seismic exploration have undergone tremendous changes. Seismic exploration has shifted from risk exploration to lithological exploration. The main task facing major oilfields in the future is the development of oil and gas reservoirs. The deployment ratio of horizontal wells in oil and gas reservoir development is increasing. The directional requirements of horizontal wells are extremely high for seismic data, and the well-seismic error requirement is within the meter range. However, due to the influence of shallow geological conditions, the accuracy of surface velocity models is difficult to determine. Shallow surface velocities seriously affect the results of migration imaging. Therefore, in the seismic data migration imaging processing stage, it is necessary to maximize the accuracy of shallow velocity models and reduce the impact of shallow velocities on migration imaging, thereby improving the imaging quality of seismic data, reducing well-seismic errors in migration imaging results, accurately reflecting structural features, and truly reflecting the geological features of stratigraphic structures, finely depicting sand body boundaries, and lithological targets.

[0003] Currently, data-driven tomographic inversion techniques have been widely adopted for depth velocity modeling in both theoretical research and practical production. However, conventional shot-receiver distance domain and offset vector tile (OVT) domain migration data are limited by observation methods, resulting in limited effective information from shallow layers. This is especially true in the Loess Plateau region, where seismic data is affected by surface factors, leading to irregular observation methods, severe absorption attenuation, and scattering phenomena, resulting in a near-complete lack of effective shallow layer information. Due to this lack of effective shallow layer information, data-driven velocity modeling techniques struggle to obtain high-precision shallow velocity models. The accuracy of shallow velocity is a crucial factor affecting the quality of seismic migration imaging. Therefore, effectively improving the accuracy of shallow velocity models to enhance pre-stack depth migration imaging quality, providing more reliable data for interpretation, and guiding horizontal well steering are pressing challenges for oil and gas reservoir development. Summary of the Invention

[0004] This invention provides a method, device, medium, and product for determining shallow velocity in pre-stack depth migration, in order to solve the problem of low accuracy of current shallow velocity.

[0005] According to one aspect of the present invention, a method for determining shallow layer velocity in pre-stack depth migration is provided, wherein the method includes:

[0006] Based on a preset background velocity field, perform pre-stack depth migration in the angle domain on the seismic data to obtain an all-round common reflection angle gather and a post-stack data volume, and determine the similarity spectrum and gather curvature of the all-round common reflection angle gather;

[0007] Based on the post-stack data volume, analysis points and analysis point analysis windows are determined. Based on the similarity spectrum, the initial dip angle of the strata is determined. Within the analysis point analysis window, a strata dip angle scan is performed according to the initial dip angle of the strata to determine the coherence value between adjacent seismic traces along the direction of each strata dip angle.

[0008] The dip angle of the strata at the analysis point is determined based on the maximum value of the coherence value, and ray tracing is performed based on the dip angle to determine the seismic wave propagation information at the analysis point.

[0009] The velocity disturbance is obtained by performing travel time inversion based on the seismic wave propagation information, and the shallow velocity field is determined according to the preset background velocity field and the velocity disturbance.

[0010] Using the shallow velocity field as a preset background velocity field, the operation of performing pre-stack depth offset in the angle domain based on the preset background velocity field to obtain the omnidirectional common reflection angle gather and post-stack data volume is repeated until the curvature of the gather meets the preset condition.

[0011] According to another aspect of the present invention, an apparatus for determining shallow velocity in pre-stack depth migration is provided, wherein the apparatus comprises:

[0012] The gather determination module is used to perform angular domain pre-stack depth migration on seismic data based on a preset background velocity field to obtain an all-round common reflection angle gather and a post-stack data volume, and to determine the similarity spectrum and gather curvature of the all-round common reflection angle gather.

[0013] The coherence value determination module is used to determine analysis points and analysis point analysis windows based on the post-stack data volume, determine the initial dip angle of the strata based on the similarity spectrum, perform strata dip angle scanning according to the initial dip angle of the strata within the analysis point analysis window, and determine the coherence value between adjacent seismic traces along the direction of each strata dip angle.

[0014] The information determination module is used to determine the dip angle of the strata at the analysis point based on the maximum value of the coherence value, and to perform ray tracing based on the dip angle of the strata to determine the seismic wave propagation information of the analysis point;

[0015] The velocity field determination module is used to perform travel time inversion based on the seismic wave propagation information to obtain the velocity disturbance amount, and to determine the shallow velocity field according to the preset background velocity field and the velocity disturbance amount;

[0016] The velocity field optimization module is used to take the shallow velocity field as a preset background velocity field, and return to perform the operation of performing angular domain pre-stack depth offset based on the preset background velocity field to obtain the all-round common reflection angle gather and post-stack data volume until the curvature of the gather meets the preset conditions.

[0017] According to another aspect of the present invention, an electronic device is provided, the electronic device comprising:

[0018] At least one processor; and

[0019] A memory communicatively connected to the at least one processor; wherein,

[0020] The memory stores a computer program that can be executed by the at least one processor, which enables the at least one processor to perform a method for determining shallow velocity in pre-stack depth migration as described in any embodiment of the present invention.

[0021] According to another aspect of the present invention, a computer-readable storage medium is provided, the computer-readable storage medium storing computer instructions for causing a processor to execute and implement a method for determining shallow velocity in pre-stack depth migration as described in any embodiment of the present invention.

[0022] According to another aspect of the present invention, embodiments of the present invention also provide a computer program product, the computer program product including a computer program, which, when executed by a processor, implements a method for determining shallow velocity in pre-stack depth migration according to any embodiment of the present invention.

[0023] The technical solution of this invention involves performing angular domain pre-stack depth migration on seismic data based on a preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes. It then determines the similarity spectrum and gather curvature of the omnidirectional common reflection angle gathers, determines analysis points and analysis windows based on the post-stack data volumes, and performs stratigraphic dip scanning within the analysis window according to the similarity spectrum to obtain coherence values ​​between adjacent seismic traces along the direction of each stratigraphic dip. The maximum value of the coherence values ​​is used to obtain the stratigraphic dip at the analysis point, improving the accuracy of the stratigraphic dip at the analysis point. Furthermore, it performs ray tracing based on the stratigraphic dip to determine the seismic wave propagation information at the analysis point, performs travel time inversion based on the seismic wave propagation information to obtain velocity perturbation, and determines the shallow velocity field according to the preset background velocity field and velocity perturbation. Using the shallow velocity field as the preset background velocity field, it returns to the operation of performing angular domain pre-stack depth migration based on the preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes until the gather curvature meets preset conditions, thereby improving the accuracy of the shallow velocity field and achieving high-precision imaging.

[0024] It should be understood that the description in this section is not intended to identify key or essential features of the embodiments of the present invention, nor is it intended to limit the scope of the invention. Other features of the invention will become readily apparent from the following description. Attached Figure Description

[0025] To more clearly illustrate the technical solutions in the embodiments of the present invention, 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 the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0026] Figure 1 This is a flowchart of a method for determining shallow velocity in pre-stack depth migration according to Embodiment 1 of the present invention;

[0027] Figure 2 This is a flowchart of a method for determining shallow layer velocity in pre-stack depth migration according to Embodiment 2 of the present invention;

[0028] Figure 3 This is a schematic diagram of the polar coordinate parameters of an underground analysis point according to Embodiment 2 of the present invention;

[0029] Figure 4 This is a schematic diagram of the dip angle of a stratum provided in Embodiment 2 of the present invention;

[0030] Figure 5 This is a schematic diagram of a formation dip angle scan according to Embodiment 2 of the present invention;

[0031] Figure 6 This is a flowchart of a method for determining shallow layer velocity in pre-stack depth migration according to Embodiment 3 of the present invention;

[0032] Figure 7 This is a schematic diagram of a common imaging point gather ray path provided according to Embodiment 3 of the present invention;

[0033] Figure 8 This is a schematic diagram of the local parameter relationship of an imaging point according to Embodiment 3 of the present invention;

[0034] Figure 9 This is a schematic diagram of a tomographic imaging method according to Embodiment 3 of the present invention;

[0035] Figure 10 This is a schematic diagram of a device for determining shallow velocity in pre-stack depth offset according to Embodiment 4 of the present invention;

[0036] Figure 11 This is a schematic diagram of the structure of an electronic device that implements a method for determining shallow velocity in pre-stack depth offset according to an embodiment of the present invention. Detailed Implementation

[0037] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0038] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0039] Example 1

[0040] Figure 1 This is a flowchart of a method for determining shallow layer velocity in pre-stack depth migration according to Embodiment 1 of the present invention. This embodiment is applicable to the situation where optimization confirmation of mid-shallow layer velocity is required. This method can be executed by a device for determining shallow layer velocity in pre-stack depth migration. This device can be implemented in hardware and / or software and can be configured in an electronic device. Figure 1 As shown, the method includes:

[0041] S110. Based on the preset background velocity field, perform pre-stack depth migration in the angle domain on the seismic data to obtain the all-round common reflection angle gather and the post-stack data volume, and determine the similarity spectrum and gather curvature of the all-round common reflection angle gather.

[0042] The preset background velocity field can be understood as the propagation velocity of seismic waves in the subsurface medium, used to describe the average velocity distribution at different depths or in different areas. The preset background velocity field can be determined by analogy based on velocity information from well-explored areas; alternatively, it can be determined through sonic logging combined with seismic stratification information. Angle-domain pre-stack depth migration is a method for depth migration imaging, which repositions seismic waves to their actual reflection locations in the subsurface, forming angle-domain depth imaging results. Omni-Directional Common Reflection Angle Gather (OCRA) is a collection of seismic traces obtained by classifying and organizing seismic data according to reflection angles and azimuths. Post-stack data volume refers to the collection of seismic data obtained after stacking processing; the post-stack data volume can present seismic data in a three-dimensional form. Generally, the post-stack data volume can contain information such as the amplitude, frequency, and phase of seismic waves. Similarity spectrum is used to measure the degree of similarity between different seismic traces in the OCRA; gather curvature is used to describe the curvature of the OCRA data.

[0043] In this embodiment, a pre-stack depth migration in the angular domain can be performed on pre-stack seismic data using a preset background velocity field to reposition seismic waves to their true subsurface reflection locations. The data is then classified according to reflection angles to obtain a holistic common reflection angle gather, and the post-stack data volume is determined. Finally, the similarity spectrum and gather curvature of the holistic common reflection angle gather are determined. In actual operation, ray tracing imaging of the analysis points in the pre-stack seismic data towards the ground can be performed under a preset background velocity field to determine the dip and azimuth of the analysis points (i.e., the dip and azimuth of the formation, and the opening and azimuth of the ray pair). The holistic common reflection angle gather is determined using a local angular domain migration imaging equation. The seismic data is then stacked to obtain the post-stack data volume. The coherence values ​​between different seismic traces in the holistic common reflection angle gather are then determined. A similarity spectrum is constructed by arranging the seismic traces according to their azimuth and reflection angles. Simultaneously, the time and reflection angle of each seismic trace in the holistic common reflection angle gather are determined to establish the local slope of each trace. The gather curvature of the holistic common reflection angle gather is determined by differentiating the local slopes.

[0044] S120. Based on the post-stack data volume, determine the analysis points and analysis point analysis windows. Based on the similarity spectrum, determine the initial dip angle of the strata. Within the analysis point analysis window, perform a strata dip angle scan according to the initial dip angle of the strata to determine the coherence value between adjacent seismic traces along the direction of each strata dip angle.

[0045] The analysis point analysis window refers to the window range used to determine the dip angle of the strata at the analysis point. In actual operation, the analysis point analysis window can be constructed based on the analysis point. Stratigraphic dip angle scanning can be understood as the process of finding the dip direction and angle of the strata based on the initial dip angle. Coherence value refers to the degree of similarity between different seismic traces in seismic data; the coherence value is usually a value between 0 and 1. The larger the coherence value, the higher the similarity between seismic traces; the lower the coherence value, the greater the difference between seismic traces.

[0046] In this embodiment, analysis points can be extracted from the post-stack data volume to determine their coordinates and reflection depth. An analysis window is then determined based on these coordinates and reflection depth. The energy peak value at the corresponding location of the analysis point is determined using a similarity spectrum. The dip angle corresponding to the energy peak value is taken as the initial dip angle. A dip angle scan is then performed using the analysis window based on the initial dip angle to determine multiple dip angles. The coherence values ​​between adjacent seismic traces along the direction of each dip angle are then determined based on both the initial dip angle and the multiple dip angles.

[0047] In actual operation, multiple consecutive adjacent seismic traces centered on the geodetic coordinates of the analysis point can be used as the horizontal analysis window, and multiple consecutive sampling points centered on the reflection depth of the analysis point can be used as the vertical analysis window to obtain the analysis point analysis window. Then, the dip angle of the stratum corresponding to the energy peak is determined by referring to the similarity spectrum as the initial dip angle of the stratum. The stratum dip angle is scanned according to the initial dip angle to determine the candidate stratum dip angle. The average energy of the seismic trace and the total energy of all traces in the corresponding analysis point analysis window are determined based on the initial dip angle and the candidate stratum dip angle, respectively. The ratio of the average energy of the seismic trace to the total energy of all traces is used as the coherence value between adjacent seismic traces along the direction of the initial dip angle of the stratum.

[0048] In one embodiment, the center point of the analysis window can be determined as the analysis point, and multiple initial stratigraphic dip angles can be determined for the analysis point. Based on each initial stratigraphic dip angle, the coherence value between adjacent seismic traces can be determined. In actual operation, multiple reflection time samples can be determined according to the reflection time corresponding to the reflection depth of the analysis window at the analysis point. The distance between each seismic trace and the analysis point can be determined, and the reflection time of each sample point can be determined as the sample point reflection time. The average energy of the seismic trace and the total energy of all traces can be determined using the distance, sample point reflection time, and initial stratigraphic dip angle. The ratio of the average energy of the seismic trace to the total energy of all traces is then determined as the coherence value between adjacent seismic traces. In one embodiment, the coherence value between adjacent seismic traces can be determined using the following formula: Where t is the time corresponding to the analysis point, the vertical analysis window is within ±K sample points above and below time t (k = -K, -K+1, -K+2, ..., K), J is the total number of channels (j = 1, 2, 3...J), and x j and y jThis represents the distance between the j-th trace and the center point t within the analysis window in the x and y directions, respectively. p and q represent the dip angles in the x and y directions of the local reflection interface where the center point is located within the analysis window, respectively. u0 is the standard trace (i.e., the seismic trace where the analysis point is located), u j (u j =u1,u2,u j2 ,...u J To determine the j-th target trace in the direction, the similarity coefficient C(t,p,q) is the ratio of the energy of the average trace within the analysis window to the energy of all traces.

[0049] S130. Determine the dip angle of the strata at the analysis point based on the maximum value of the coherence value, and perform ray tracing based on the dip angle to determine the seismic wave propagation information of the analysis point.

[0050] In this context, the dip angle of the strata at the analysis point can be understood as the final dip angle of the strata at that point. Generally, the initial dip angle of the strata corresponding to the maximum coherence value can be used as the dip angle of the strata at the analysis point. Seismic wave propagation information can be understood as the data information of an earthquake during its propagation process. For example, seismic wave propagation information may include at least the remaining depth difference, the preset incident angle, the ray path, and the travel time difference.

[0051] In this embodiment, the coherence values ​​between adjacent seismic traces along each stratum dip direction can be compared, and the initial dip angle of the stratum corresponding to the maximum coherence value is taken as the stratum dip angle at the analysis point. Under the constraint of the stratum dip angle at the analysis point, two-point ray tracing can be performed at the analysis point along a preset source-receiver offset, a preset normal, and a preset incident angle to determine the ray path corresponding to zero source-receiver offset and the ray path corresponding to non-zero source-receiver offset, as well as the travel time difference corresponding to zero source-receiver offset and the travel time difference corresponding to non-zero source-receiver offset. The remaining depth difference, the preset incident angle, the ray path corresponding to zero source-receiver offset and the ray path corresponding to non-zero source-receiver offset at the analysis point, as well as the travel time difference corresponding to zero source-receiver offset and the travel time difference corresponding to non-zero source-receiver offset, are used as seismic wave propagation information. In other words, tomography can be performed based on the stratum dip angle constraint at the analysis point to determine seismic wave propagation information. In one embodiment, the remaining depth difference can be determined by the gather curvature; the ray path can be determined by the remaining depth difference, the dip angle of the analysis point, and the preset incident angle; the travel time difference can be represented by the velocity disturbance, the dip angle of the analysis point, the preset incident angle, and the remaining depth difference.

[0052] S140. Based on the seismic wave propagation information, perform travel time inversion to obtain the velocity disturbance amount, and determine the shallow velocity field according to the preset background velocity field and velocity disturbance amount.

[0053] Among them, the velocity disturbance can be understood as the difference between the actual velocity and the preset background velocity field.

[0054] In this embodiment, travel time inversion can be performed based on seismic wave propagation information to establish a tomographic inversion equation. Solving the tomographic inversion equation yields the velocity perturbation, and the preset background velocity field is updated based on this velocity perturbation to obtain the shallow velocity field. In actual operation, the tomographic inversion equation can be used to determine the travel path corresponding to the non-zero shot-receiver offset based on the preset incident angle and the ray path corresponding to the non-zero shot-receiver offset in the seismic wave propagation information; determine the difference between the travel path and the ray path corresponding to the zero shot-receiver offset in the seismic wave propagation information; determine the target travel time difference corresponding to the non-zero shot-receiver offset based on the preset incident angle and the travel time difference corresponding to the non-zero shot-receiver offset; determine the difference between the target travel time difference and the travel time difference corresponding to the zero shot-receiver offset in the seismic wave propagation information; and use the ratio of the difference between the travel path and the ray path corresponding to the zero shot-receiver offset in the seismic wave propagation information to the difference between the target travel time difference and the travel time difference corresponding to the zero shot-receiver offset in the seismic wave propagation information as the velocity perturbation.

[0055] S150. Using the shallow velocity field as the preset background velocity field, return to execute the operation of performing pre-stack depth offset in the angle domain based on the preset background velocity field to obtain the all-round common reflection angle gather and post-stack data volume until the gather curvature meets the preset conditions.

[0056] In one embodiment, the curvature of the gather satisfies a preset condition, including the gather curvature being less than a preset gather curvature threshold.

[0057] In this embodiment, the shallow velocity field can be used as a preset background velocity field. Angle-domain pre-stack depth migration is then performed on the pre-stack seismic data according to the preset background velocity field to obtain a comprehensive common reflection angle gather. The operation of determining the comprehensive common reflection angle gather is then performed, and it is determined whether the gather curvature of the comprehensive common reflection angle gather is less than a preset gather curvature threshold. If the gather curvature of the comprehensive common reflection angle gather is less than the preset gather curvature threshold, the shallow velocity field is used as the final shallow velocity field. If the gather curvature of the comprehensive common reflection angle gather is greater than or equal to the preset gather curvature threshold, the analysis point and analysis window are determined again based on the post-stack data volume. A stratigraphic dip scan is performed within the analysis window with reference to the similarity spectrum to obtain the coherence value between adjacent seismic traces along each stratigraphic dip direction. Based on the coherence value, the stratigraphic dip angle of the analysis point is obtained, and ray tracing is performed based on the stratigraphic dip angle to determine the seismic wave propagation information of the analysis point. Travel time inversion is performed based on the seismic wave propagation information to obtain the velocity disturbance. The shallow velocity field is determined according to the preset background velocity field and the velocity disturbance, until the gather curvature meets the preset condition.

[0058] In this embodiment of the invention, angular domain pre-stack depth migration is performed on seismic data based on a preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes. The similarity spectrum and gather curvature of the omnidirectional common reflection angle gathers are determined. Analysis points and analysis windows are determined based on the post-stack data volumes. Referencing the similarity spectrum, stratigraphic dip scanning is performed within the analysis window of each analysis point to obtain coherence values ​​between adjacent seismic traces along each stratigraphic dip direction. The maximum value of the coherence value is used to determine the stratigraphic dip of the analysis point, improving its accuracy. Ray tracing is then performed based on the stratigraphic dip to determine the seismic wave propagation information of the analysis point. Travel time inversion is performed based on the seismic wave propagation information to obtain velocity perturbation. A shallow velocity field is determined according to the preset background velocity field and the velocity perturbation. Using the shallow velocity field as the preset background velocity field, the operation of angular domain pre-stack depth migration based on the preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes is repeated until the gather curvature meets preset conditions, thereby improving the accuracy of the shallow velocity field and achieving high-precision imaging.

[0059] Example 2

[0060] Figure 2 This is a flowchart of a method for determining shallow layer velocity in pre-stack depth migration according to Embodiment 2 of the present invention. This embodiment is a further optimization and extension based on the above embodiments, and can be combined with various optional technical solutions in the above embodiments. Figure 2 As shown, the method includes:

[0061] S201. Under the preset background velocity field, perform ray tracing imaging of the analysis points in the pre-stack seismic data toward the ground to determine the polar coordinate parameters of the analysis points and the post-stack data volume.

[0062] Polar coordinate parameters refer to parameters that describe the location and orientation characteristics of analysis points in pre-stack seismic data. For example, polar coordinate parameters may include, but are not limited to, stratigraphic dip and azimuth angles, and ray pair opening and azimuth angles. Analysis points can be imaging points in pre-stack seismic data.

[0063] In one embodiment, imaging points can be determined as analysis points from pre-stack seismic data. Based on a preset background velocity field, the propagation path of rays is determined for each imaging point using a ray tracing algorithm, thus determining the image. The dip and azimuth angles of the inner normals, and the opening and azimuth angles of the ray pairs are determined according to the imaging. The dip and azimuth angles of the formations, and the opening and azimuth angles of the ray pairs are used as the polar coordinate parameters of the analysis points. In one embodiment, Figure 3 This is a schematic diagram of the polar coordinate parameters of an underground analysis point according to Embodiment 2 of the present invention, as shown below. Figure 3As shown, M is the analysis point, i.e., the imaging point; v1 and v2 are the dip and azimuth angles of the inner normal at analysis point M, i.e., the dip and azimuth angles of the strata; and γ1 and γ2 are the opening and azimuth angles of the ray pairs. The seismic data are then stacked to obtain the post-stack data volume.

[0064] S202. Integrate the polar coordinate parameter components of the analysis point to obtain the omnidirectional common reflection angle gather.

[0065] In this embodiment, the polar coordinate parameter components of the analysis point can be integrated to determine the omnidirectional common reflection angle gather. In actual operation, the following formula can be used to determine the omnidirectional common reflection angle gather:

[0066] Where v1 and v2 are the dip and azimuth angles of the inner normal at analysis point M, i.e., the dip and azimuth angles of the formation, and γ1 and γ2 are the opening angle and azimuth angle of the ray pair. N ν The number of face elements of the directional angular sphere, n ν,i The number of clicks on element i of the directional angular sphere;

[0067] dA v =sinv1dv1dv2.

[0068] S203. Determine the coherence values ​​between different seismic traces in the all-round common reflection angle trace set, and construct a similarity spectrum by arranging the traces in the order of azimuth and reflection angle.

[0069] In the embodiments, the coherence values ​​between different seismic traces in the all-round common reflection angle trace set can be determined separately, and a similarity spectrum can be constructed by arranging the coherence values ​​in the order of azimuth and reflection angle.

[0070] S204. Determine the time and reflection angle of each seismic trace in the all-round common reflection angle gather, determine the local slope of each seismic trace, and perform differential calculation on each local slope to determine the gather curvature of the all-round common reflection angle gather.

[0071] In the embodiment, the time and reflection angle of each seismic trace in the all-round common reflection angle gather can be determined, the local slope of each seismic trace can be determined according to the time and reflection angle, and the gather curvature of the gather with a fixed all-round common reflection angle can be obtained by differentiating the local slope.

[0072] S205. Identify and analyze points based on the post-stack data volume to determine the spatial location of the analysis points.

[0073] The spatial location includes coordinate information and reflection depth. Coordinate information can be understood as the geodetic coordinates of the analysis point, while reflection depth refers to the vertical depth of the reflection interface underground when a seismic wave encounters a wave impedance interface during its propagation in the underground medium.

[0074] In this embodiment, analysis points can be located within the post-stack data volume, and their coordinates and reflection depth can be identified as their spatial location. In actual operation, analysis points can be identified within the offset profile of the post-stack data volume.

[0075] S206. Based on spatial location, determine at least one consecutive adjacent seismic trace centered on coordinate information as the horizontal analysis window, and determine at least one consecutive sampling point centered on reflection depth as the vertical analysis window.

[0076] In this embodiment, after determining the spatial location of the analysis point, multiple consecutive adjacent seismic traces are identified as horizontal analysis windows centered on the coordinate information, and multiple sampling points are identified as vertical analysis windows centered on the reflection depth. In one embodiment, assuming the reflection time of the analysis point is t, the analysis window of the analysis point can be determined as sampling points ±K points above and below time t (k = -K, -K+1, -K+2, ..., K), and the mode time of each sampling point is determined as the reflection time of the sampling point. If the interval between each sampling point is Δt, the reflection time of the sampling point is t + kΔt.

[0077] S207. Use the horizontal analysis window and the vertical analysis window as analysis point analysis windows.

[0078] In this embodiment, after determining the horizontal analysis window and the vertical analysis window, the analysis point analysis window can be constructed according to the horizontal analysis window and the vertical analysis window.

[0079] S208. Determine the dip angle of the formation corresponding to the energy peak in the similar spectrum of the analysis point as the initial dip angle of the formation at the analysis point.

[0080] The initial dip angle of the strata includes the dip angle of the strata along the transverse survey line and the dip angle of the strata along the longitudinal survey line. The dip angle of the strata along the longitudinal survey line refers to the dip angle of the longitudinal survey line relative to a certain reference direction; the dip angle of the strata along the survey line refers to the dip angle of the lateral survey line relative to a certain reference direction.

[0081] In one embodiment, Figure 4 This is a schematic diagram of the dip angle of a formation according to Embodiment 2 of the present invention, as shown below. Figure 4 As shown, p represents the dip angle of the strata in the x-direction (cross-sectional direction); q represents the dip angle of the strata in the y-direction (vertical direction). In actual operation, the energy peak value of the analysis point in the similarity spectrum can be determined, and the dip angle of the strata corresponding to the energy peak value can be determined. The dip angle of the strata corresponding to the energy peak value is then used as the initial dip angle of the strata at the analysis point.

[0082] S209. Determine the average energy and total energy of seismic traces within the analysis window of the analysis point based on the analysis point analysis window and the initial dip angle of the strata.

[0083] In the embodiment, the distance between each seismic trace in the analysis window and the analysis point can be determined. If J is the total number of traces (j = 1, 2, 3…J), x j and y j This represents the distance in the x and y directions between the j-th trace and the analysis point t within the analysis window. The average energy of the seismic trace and the total energy of all traces can be determined based on the distance, the reflection time of the sampling point, and the initial dip angle. In one embodiment, the average energy of the seismic trace can be determined using the following formula: The total energy of the Tao can be determined by the following formula: Where t is the time corresponding to the reflection depth of the analysis point, t+kΔt is the reflection time of the sampling point, and x j and y j represents the distance in the x and y directions between trace j and the center point t within the analysis window of the analysis point; p and q represent the dip angles in the x and y directions of the local reflection interface where the center point within the analysis window of the analysis point is located, respectively; u0 is the standard trace (i.e., the seismic trace where the analysis point is located), u j (u j =u1,u2,u j2 ,...u J To determine the j-th target path in the direction.

[0084] S210. The ratio of the average energy of the seismic trace to the total energy of all traces is taken as the coherence value between adjacent seismic traces along the initial dip angle of the strata.

[0085] In this embodiment, the ratio of average energy of a horizontal trace to the total energy of all traces can be determined, and this ratio is used as the coherence value between adjacent seismic traces. The coherence value can be determined using the following formula: Where t is the time corresponding to the reflection depth of the analysis point, the vertical analysis point analysis window is between ±K sampling points above and below time t (k=-K, -K+1, -K+2, …, K), J is the total number of channels (j=1,2,3…J), x j and y j This represents the distance between the j-th trace and the analysis point in the x and y directions, respectively. p and q represent the dip angles in the x and y directions of the local reflection interface where the center point of the analysis window is located, respectively. u0 is the standard trace (i.e., the seismic trace where the analysis point is located), u j (u j =u1,u2,u j2 ,...u J To determine the j-th target trace in the direction, the similarity coefficient C(t,p,q) is the ratio of the average trace energy within the analysis window of the analysis point to the energy of all traces.

[0086] S211. Based on the analysis point analysis window, perform stratigraphic dip scanning according to the preset dip angle scanning range to determine the dip angle of candidate stratigraphic layers, and determine the coherence value between adjacent seismic traces of the analysis point along the direction of each candidate stratigraphic dip angle.

[0087] The preset dip angle scanning range can be understood as the angular range within which a dip angle scan is performed based on the initial dip angle of the formation. In actual operation, the preset dip angle scanning range may include, but is not limited to, 60 degrees, 90 degrees, etc. In one embodiment, Figure 5 This is a schematic diagram of a formation dip angle scan according to Embodiment 2 of the present invention, as shown below. Figure 5 As shown, the dip angle of the formation can be scanned to determine the candidate dip angles of the formation. The candidate dip angles can be multiple dip angles of the formation between the maximum and minimum dip angles of the test.

[0088] In this embodiment, a stratigraphic dip scan can be performed in the analysis point analysis window according to a preset dip scan range to obtain at least one candidate stratigraphic dip angle. The average energy of the seismic traces and the total energy of all traces within the analysis point analysis window are determined based on the analysis point analysis window and the candidate stratigraphic dip angles. The ratio of the average energy of the seismic traces to the total energy of all traces is analyzed to determine the coherence value between adjacent seismic traces along the direction of each candidate stratigraphic dip angle.

[0089] S212. Determine the initial dip angle / candidate dip angle of the formation corresponding to the maximum value among the coherence values ​​as the dip angle of the formation at the analysis point.

[0090] In this embodiment, the maximum value among the coherence values ​​can be determined, and the initial dip angle or candidate dip angle of the formation corresponding to the maximum value of the coherence values ​​can be used as the dip angle of the formation at the analysis point.

[0091] S213. Determine the remaining depth difference of the analysis point based on the curvature of the gather, and perform two-point ray tracing of the analysis point along the preset shot-receiver distance, preset normal and preset incident angle to determine the ray path and travel time difference of the analysis point.

[0092] The ray path includes the ray path corresponding to zero shot-receiver distance and the ray path corresponding to non-zero shot-receiver distance; the travel time difference includes the travel time difference corresponding to zero shot-receiver distance and the travel time difference corresponding to non-zero shot-receiver distance. The residual depth difference refers to the difference between the imaging depth and the true depth of the subsurface geological interface.

[0093] In this embodiment, the correlation between gather curvature and residual depth difference can be determined, and the residual depth difference of the analysis point can be determined according to the correlation. The change in gather curvature is related to the dip of the strata, and the gather curvature can be converted into residual depth difference. Two-point ray tracing is performed on each analysis point with preset shot-receiver distance, preset normal, and preset incident angle, and the ray path and travel time of the analysis point are recorded.

[0094] S214. Use the remaining depth difference, preset incident angle, ray path, and travel time difference as the seismic wave propagation information of the analysis point.

[0095] S215. Construct tomographic equations based on seismic wave propagation information, and determine the velocity disturbance by solving the tomographic equations.

[0096] In one embodiment, a tomographic equation is constructed based on seismic wave propagation information, and the velocity disturbance is determined by solving the tomographic equation, including:

[0097] The travel path corresponding to the non-zero source-receiver distance is determined according to the preset incident angle in the seismic wave propagation information and the ray path corresponding to the non-zero source-receiver distance.

[0098] The difference between the travel path and the ray path corresponding to zero shot-receiver distance in the seismic wave propagation information is taken as the first difference.

[0099] Determine the target travel time corresponding to the non-zero gun-receiver distance according to the preset incident angle and the travel time corresponding to the non-zero gun-receiver distance;

[0100] The difference between the target travel time and the travel time corresponding to zero shot-receiver distance in the seismic wave propagation information is determined as the second difference;

[0101] The ratio of the second difference to the first difference is determined as the velocity disturbance.

[0102] In this embodiment, the cosine value of the preset incident angle can be determined. The ratio of the ray path corresponding to the non-zero shot-receiver offset to the cosine value of the preset incident angle is determined as the travel path corresponding to the non-zero shot-receiver offset. The difference between the travel path and the ray path corresponding to the zero shot-receiver offset in the seismic wave propagation information is taken as the first difference. The ratio of the travel time difference corresponding to the non-zero shot-receiver offset to the cosine value of the preset incident angle is determined as the target travel time difference corresponding to the non-zero shot-receiver offset. The difference between the target travel time difference and the travel time difference corresponding to the zero shot-receiver offset in the seismic wave propagation information is taken as the second difference. The ratio of the second difference to the first difference is determined as the velocity disturbance. In actual operation, the tomographic equations constructed from the seismic wave propagation information can be: Where h is the half-shot distance, θ is the preset incident angle, Δt is the travel time difference (i.e., the difference between the actual (underground) travel time and the model travel time), L is the ray path, and ΔS is the difference between the actual (underground) slowness and the model slowness S, i.e., the velocity disturbance. Let L(0) be the travel path corresponding to a non-zero shot-receiver distance, and L(0) be the travel path corresponding to a zero shot-receiver distance. The travel time difference Δt can be expressed by the residual depth difference ΔZ: Δt = 2 × ΔS × ΔZ × cosθ × cosα; where α is the dip angle of the stratum at the analysis point. The velocity disturbance can be determined by solving the tomographic equations.

[0103] S216. Update the preset background velocity field as a shallow velocity field according to the velocity disturbance.

[0104] In this embodiment, the shallow velocity field can be obtained by subtracting the velocity disturbance from the preset background velocity field.

[0105] S217. Using the shallow velocity field as the preset background velocity field, return to execute the operation of performing pre-stack depth offset in the angle domain based on the preset background velocity field to obtain the all-round common reflection angle gather and post-stack data volume until the gather curvature meets the preset conditions.

[0106] In this embodiment of the invention, ray tracing imaging of analysis points from pre-stack seismic data towards the ground is performed under a preset background velocity field to determine the polar coordinate parameters of the analysis points and the post-stack data volume. The polar coordinate parameter components of the analysis points are integrated to obtain a omnidirectional common reflection angle gather. The coherence values ​​between different seismic traces in the omnidirectional common reflection angle gather are determined. A similarity spectrum is constructed by arranging the seismic traces in order of azimuth and reflection angle. The time and reflection angle of each seismic trace in the omnidirectional common reflection angle gather are determined to determine the local slope of each seismic trace. The gather curvature of the omnidirectional common reflection angle gather is determined by differentiating each local slope. Analysis points are identified based on the post-stack data volume, and their spatial locations are determined. Based on the spatial locations, at least one consecutive adjacent seismic trace centered on the coordinate information is determined as a lateral analysis window, and at least one consecutive sampling point centered on the reflection depth is determined as a longitudinal analysis window. The lateral and longitudinal analysis windows are used as analysis point analysis windows to improve the accuracy of the analysis point analysis windows. The dip angle of the stratum corresponding to the energy peak in the similarity spectrum of the analysis point is determined as the initial dip angle of the stratum at the analysis point. Based on the analysis point analysis windows... The average energy of the seismic traces within the analysis window is determined by the initial dip angle of the strata. The ratio of this average energy to the total energy is used as the coherence value between adjacent seismic traces along the direction of the initial dip angle. Based on the analysis window, a strata dip angle scan is performed according to a preset dip angle scan range to determine candidate strata dip angles. The coherence value between adjacent seismic traces along the direction of each candidate strata dip angle is then determined. The initial dip angle / candidate strata dip angle corresponding to the maximum value of the coherence value is used as the strata dip angle at the analysis point, thus making the strata dip angle at the analysis point more accurate. Accuracy: The remaining depth difference of the analysis point is determined based on the curvature of the gather, and two-point ray tracing is performed on the analysis point along the preset shot-receiver distance, preset normal, and preset incident angle to determine the ray path and travel time difference of the analysis point. The remaining depth difference, preset incident angle, ray path, and travel time difference are used as the seismic wave propagation information of the analysis point. Based on the seismic wave propagation information, a tomographic equation is constructed. The velocity disturbance is determined by solving the tomographic equation, and the preset background velocity field is updated according to the velocity disturbance as the shallow velocity field, which facilitates the modeling of the shallow velocity field and improves the accuracy of the shallow velocity field.

[0107] Example 3

[0108] In one embodiment, Figure 6 This is a flowchart illustrating a method for determining shallow velocity in pre-stack depth migration according to Embodiment 3 of the present invention. This embodiment uses a preset velocity model as the preset background velocity field, a real model as the shallow velocity field, and imaging points as analysis points as examples to further explain a method for determining shallow velocity in pre-stack depth migration. Figure 6 As shown, the method includes:

[0109] S310. Based on the background velocity field, perform pre-stack depth migration in the angle domain to obtain the all-around reflection angle gather and post-stack data volume.

[0110] In one embodiment, angular domain offset is used for ray tracing imaging from the imaging point to the ground, with all rays participating in the imaging process to ensure true amplitude imaging. Since the polar coordinate parameters of the underground imaging point (M) have four components (e.g., ... Figure 3 Therefore, integrating each of the two components separately yields the omnidirectional common reflection angle gather and the omnidirectional directional reflection angle gather. The omnidirectional common reflection angle gather can be determined using the following formula:

[0111] Where v1 and v2 are the dip and azimuth angles of the inner normal at analysis point M, i.e., the dip and azimuth angles of the formation, and γ1 and γ2 are the opening angle and azimuth angle of the ray pair. N ν The number of face elements of the directional angular sphere, n ν,i The number of clicks on element i of the directional angular sphere;

[0112] dA v =sinv1dv1dv2.

[0113] S320. Similarity spectrum calculation and gather curvature picking are performed based on reflection angle gathers.

[0114] S330: Based on angular domain offset imaging data, fine characterization of stratigraphic dip angles is carried out, and stratigraphic information is matched.

[0115] Because shallow-layer imaging in the angle domain has high accuracy and provides a clear understanding of the stratigraphic structure, the dip angle is picked up on the migration profile and matched to the gather data. Specifically, accurate dip angle information is obtained at each imaging point using multi-trace similarity coherence technology and then applied to the seismic gather data. The coherence value can be determined using the following formula: Where t is the time corresponding to the reflection depth of the imaging point, the vertical analysis point analysis window is within ±K sample points above and below time t (k=-K, -K+1, -K+2, …, K), J is the total number of channels (j=1,2,3…J), x j and yj This represents the distance in the x and y directions between the j-th trace and the center point t within the analysis window of the analysis point. p and q represent the dip angles in the x and y directions of the local reflection interface where the center point within the analysis window of the analysis point is located, respectively. u0 is the standard trace (i.e., the seismic trace where the imaging point is located), u j (u j =u1,u2,u j2 ,...u J To determine the j-th target trace in a given direction, the similarity coefficient C(t,p,q) is the ratio of the average trace energy to the total energy of all traces within the analysis window at the analysis point. For a given center point t, given different dip angles p and q, the dip angle of the formation is determined by calculating the corresponding coherence values ​​and taking the p and q corresponding to the maximum coherence value.

[0116] S340. Conduct tomographic inversion under the constraint of stratigraphic dip angle to obtain high-precision velocity perturbation.

[0117] Based on reliable and effective prior information, the velocity transformation obtained through inversion is more accurate. The subsurface medium is discretized into many cubic grid cells containing velocity information. By using accurate gather curvature and similar velocity spectra, ray tracing is employed to establish and solve the tomographic inversion equation to obtain the velocity changes. First, for each remaining depth difference pick point, two-point ray tracing is performed along the specified shot-receiver distance, normal, and equal opening angle. The ray path and travel time are recorded, and the velocity perturbation is obtained through inversion.

[0118] In one embodiment, Figure 7 This is a schematic diagram of a common imaging point gather ray path according to Embodiment 3 of the present invention. Figure 7 As shown, when the preset velocity model is close to the real model, the common imaging point gather satisfies the following: Figure 7 The relationship shown. Figure 7 In the diagram, S is the shot point corresponding to a certain trace in the imaging gather, R is the corresponding receiver point, A is the imaging point at the migration velocity, A' is the imaging position at the correct velocity, the solid line SAR is the propagation path of the ray at the migration velocity, the dashed line SA'R is the propagation path of the ray at the assumed true velocity, the distance AB is the remaining depth difference picked up, ψ is the dip angle of the formation, and θ... These are the offset incident angle and the theoretical incident angle, respectively. When the propagation path is relatively long and the velocity error is relatively small, we approximate it as... The red line indicates the location of the common imaging point.

[0119] At the local point of reflection, we can assume that the slowness s is constant, and since the two propagation paths are closer to each other in places far from the reflection point. Figure 8 This is a schematic diagram of the local parameter relationship of an imaging point according to Embodiment 3 of the present invention, as shown below. Figure 8 As shown, the travel time disturbance is equal to the difference between the two paths multiplied by the slowness s. That is, Δt RMO=2sΔL; where Δt RMO The travel time perturbation manifests as the residual travel time difference (RMO) in the imaging trace concentration; ΔL = Δzcosθcosψ, Δz = AB; therefore, Δt RMO =2scosθcosψΔz; As can be seen from the above equation, tomographic inversion in the imaging domain requires automatic picking of the stratigraphic dip angle ψ on the migration profile, which is... Figure 9 α, and the residual depth difference Δz on the imaging gather.

[0120] In one embodiment, Figure 9 This is a schematic diagram of a tomographic imaging method according to Embodiment 3 of the present invention, as shown below. Figure 9 As shown, h is half the shot-receiver distance, θ is half the opening angle, which is half the opening angle γ1 of the omnidirectional common reflection angle concentrated ray pair, Δt is the travel time difference (i.e., the difference between the actual (underground) travel time and the model travel time), L is the ray path, and ΔS is the difference between the actual (underground) slowness and the model slowness S, i.e., the velocity disturbance. Let L(0) be the travel path corresponding to a non-zero shot-receiver offset, L(0) be the travel path corresponding to a zero shot-receiver offset, and α be the dip angle of the strata at the analysis point. The tomographic equations constructed from seismic wave propagation information can be: The travel time difference Δt can be represented by the remaining depth difference ΔZ:

[0121] Δt = 2 × ΔS × ΔZ × cosθ × cosα. The velocity disturbance can be determined by solving the tomographic equation. As shown in the above formula, L(h) = Δzcosθcosα; where Δz is the remaining depth difference and α is the dip angle of the formation at the analysis point.

[0122] S350, anomaly handling of velocity disturbances and velocity synthesis.

[0123] In one embodiment, the velocity in the abnormal area can be modified and edited by combining the background velocity field and well logging information to make the velocity trend more reasonable. Then, the velocity change is merged with the background velocity to obtain a high-precision shallow velocity field.

[0124] Example 4

[0125] Figure 10 This is a schematic diagram of a device for determining shallow layer velocity in pre-stack depth migration according to Embodiment 4 of the present invention. Figure 10 As shown, the device includes: a gather determination module 41, a coherence value determination module 42, an information determination module 43, a velocity field determination module 44, and a velocity field optimization module 45.

[0126] Among them, the gather determination module 41 is used to perform angular domain pre-stack depth migration on seismic data based on a preset background velocity field to obtain an all-round common reflection angle gather and a post-stack data volume, and to determine the similarity spectrum and gather curvature of the all-round common reflection angle gather.

[0127] The coherence value determination module 42 is used to determine the analysis point and analysis point analysis window based on the post-stack data volume, determine the initial dip angle of the strata based on the similarity spectrum, perform strata dip angle scanning according to the initial dip angle of the strata within the analysis point analysis window, and determine the coherence value between adjacent seismic traces along the direction of each strata dip angle.

[0128] The information determination module 43 is used to determine the dip angle of the strata at the analysis point based on the maximum value of the coherence value, and to perform ray tracing based on the dip angle of the strata to determine the seismic wave propagation information of the analysis point;

[0129] The velocity field determination module 44 is used to perform travel time inversion based on the seismic wave propagation information to obtain the velocity disturbance amount, and to determine the shallow velocity field according to the preset background velocity field and the velocity disturbance amount;

[0130] The velocity field optimization module 45 is used to take the shallow velocity field as a preset background velocity field, and return to perform the operation of performing angular domain pre-stack depth offset based on the preset background velocity field to obtain the all-round common reflection angle gather and post-stack data volume until the curvature of the gather meets the preset conditions.

[0131] The technical solution of this invention involves a gather determination module performing pre-stack depth migration in the angle domain on seismic data based on a preset background velocity field to obtain a comprehensive common reflection angle gather and a post-stack data volume. This module determines the similarity spectrum and gather curvature of the comprehensive common reflection angle gather. A coherence value determination module determines analysis points and analysis windows based on the post-stack data volume. Referring to the similarity spectrum, a stratigraphic dip scan is performed within the analysis window according to the analysis point to obtain the coherence value between adjacent seismic traces along each stratigraphic dip direction. Finally, an information determination module determines the stratigraphic dip angle at the analysis point based on the maximum value of the coherence value, thereby improving the accuracy of the analysis point's information. The accuracy of the dip angle is improved; the velocity field determination module performs ray tracing based on the dip angle to determine the seismic wave propagation information of the analysis point, and performs travel time inversion based on the seismic wave propagation information to obtain the velocity disturbance. The shallow velocity field is determined according to the preset background velocity field and the velocity disturbance. The velocity field optimization module uses the shallow velocity field as the preset background velocity field, and returns to perform angular domain pre-stack depth migration based on the preset background velocity field to obtain the all-round common reflection angle gather and post-stack data volume until the gather curvature meets the preset conditions, thereby improving the accuracy of the shallow velocity field and achieving high-precision imaging.

[0132] In one embodiment, the gather determination module 41 includes:

[0133] The parameter determination unit is used to perform ray tracing imaging of the analysis points in the pre-stack seismic data toward the ground under a preset background velocity field, and to determine the polar coordinate parameters of the analysis points and the post-stack data volume.

[0134] The gather determination unit is used to integrate the polar coordinate parameter components of the analysis point to obtain the omnidirectional common reflection angle gather;

[0135] The similarity spectrum determination unit is used to determine the coherence values ​​between different seismic traces in the all-round common reflection angle trace set, and constructs a similarity spectrum according to the order of the azimuth and reflection angle of the seismic traces;

[0136] The gather curvature determination unit is used to determine the time and reflection angle of each seismic trace in the all-round common reflection angle gather, determine the local slope of each seismic trace, and perform differential calculation on each local slope to determine the gather curvature of the all-round common reflection angle gather.

[0137] In one embodiment, the coherence value determination module 42 includes:

[0138] A spatial location determination unit is used to identify analysis points based on the post-stack data volume and determine the spatial location of the analysis points; wherein, the spatial location includes coordinate information and reflection depth;

[0139] The analysis window determination unit is used to determine, based on the spatial location, at least one consecutive adjacent seismic trace centered on the coordinate information as a horizontal analysis window, and at least one consecutive sampling point centered on the reflection depth as a vertical analysis window;

[0140] The target analysis window determination unit is used to use the horizontal analysis window and the vertical analysis window as analysis point analysis windows;

[0141] An initial dip angle determination unit is used to determine the dip angle of the formation corresponding to the energy peak in the similar spectrum of the analysis point as the initial dip angle of the formation at the analysis point; wherein, the initial dip angle of the formation includes the dip angle of the formation in the transverse survey line direction and the dip angle of the formation in the longitudinal survey line direction;

[0142] An energy determination unit is used to determine the average energy and total energy of seismic traces within the analysis window of the analysis point based on the analysis window of the analysis point and the initial dip angle of the formation.

[0143] The first coherence value determination unit is used to take the ratio of the average energy of the seismic trace to the total energy of all traces as the coherence value between adjacent seismic traces along the direction of the initial dip angle of the stratum.

[0144] The second coherence value determination unit is used to perform stratigraphic dip scanning based on the analysis point analysis window and according to a preset dip angle scanning range to determine the dip angle of candidate stratigraphic layers, and to determine the coherence value between adjacent seismic traces of the analysis point along the direction of each candidate stratigraphic dip angle.

[0145] In one embodiment, the information determination module 43 includes:

[0146] The target dip angle determination unit is used to determine the initial dip angle / candidate dip angle of the formation corresponding to the maximum value in the coherence value as the dip angle of the formation at the analysis point.

[0147] The time difference determination unit is used to determine the remaining depth difference of the analysis point based on the curvature of the gather, and to perform two-point ray tracing of the analysis point along a preset shot-receiver distance, a preset normal and a preset incident angle to determine the ray path and travel time difference of the analysis point;

[0148] Among them, the ray path includes the ray path corresponding to zero shot-receiver distance and the ray path corresponding to non-zero shot-receiver distance; the travel time difference includes the travel time difference corresponding to zero shot-receiver distance and the travel time difference corresponding to non-zero shot-receiver distance.

[0149] The information determination unit is used to analyze seismic wave propagation information by taking the remaining depth difference, preset incident angle, ray path, and travel time difference as the analysis point.

[0150] In one embodiment, the velocity field determination module 44 includes:

[0151] The disturbance determination unit is used to construct tomographic equations based on seismic wave propagation information and determine the velocity disturbance by solving the tomographic equations.

[0152] The velocity field determination unit is used to update the preset background velocity field as a shallow velocity field according to the velocity disturbance.

[0153] In one embodiment, the disturbance determination unit is specifically used for:

[0154] The travel path corresponding to the non-zero source-receiver distance is determined according to the preset incident angle in the seismic wave propagation information and the ray path corresponding to the non-zero source-receiver distance.

[0155] The difference between the travel path and the ray path corresponding to zero shot-receiver distance in the seismic wave propagation information is taken as the first difference.

[0156] Determine the target travel time corresponding to the non-zero gun-receiver distance according to the preset incident angle and the travel time corresponding to the non-zero gun-receiver distance;

[0157] The difference between the target travel time and the travel time corresponding to zero shot-receiver distance in the seismic wave propagation information is determined as the second difference;

[0158] The ratio of the second difference to the first difference is determined as the velocity disturbance.

[0159] In one embodiment, the curvature of the gather satisfies a preset condition, including the gather curvature being less than a preset gather curvature threshold.

[0160] The device for determining shallow velocity in pre-stack depth migration provided in this embodiment of the invention can execute the method for determining shallow velocity in pre-stack depth migration provided in any embodiment of the invention, and has the corresponding functional modules and beneficial effects of the method.

[0161] Example 5

[0162] Figure 11 This is a schematic diagram of an electronic device implementing a method for determining shallow velocity in pre-stack depth migration according to an embodiment of the present invention. The electronic device is intended to represent various forms of digital computers, such as laptop computers, desktop computers, workbenches, personal digital assistants, servers, blade servers, mainframe computers, and other suitable computers. The electronic device can also represent various forms of mobile devices, such as personal digital processors, cellular phones, smartphones, wearable devices (e.g., helmets, glasses, watches, etc.), and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely illustrative and are not intended to limit the implementation of the invention described and / or claimed herein.

[0163] like Figure 11 As shown, the electronic device 10 includes at least one processor 11 and a memory, such as a read-only memory (ROM) 12 or a random access memory (RAM) 13, communicatively connected to the at least one processor 11. The memory stores computer programs executable by the at least one processor. The processor 11 can perform various appropriate actions and processes based on the computer program stored in the ROM 12 or loaded from storage unit 18 into the RAM 13. The RAM 13 may also store various programs and data required for the operation of the electronic device 10. The processor 11, ROM 12, and RAM 13 are interconnected via a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0164] Multiple components in electronic device 10 are connected to I / O interface 15, including: input unit 16, such as keyboard, mouse, etc.; output unit 17, such as various types of displays, speakers, etc.; storage unit 18, such as disk, optical disk, etc.; and communication unit 19, such as network card, modem, wireless transceiver, etc. Communication unit 19 allows electronic device 10 to exchange information / data with other devices through computer networks such as the Internet and / or various telecommunications networks.

[0165] Processor 11 can be a variety of general-purpose and / or special-purpose processing components with processing and computing capabilities. Some examples of processor 11 include, but are not limited to, a central processing unit (CPU), a graphics processing unit (GPU), various special-purpose artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, a digital signal processor (DSP), and any suitable processor, controller, microcontroller, etc. Processor 11 performs the various methods and processes described above, such as methods for determining shallow velocities in pre-stack depth migration.

[0166] In some embodiments, the method for determining shallow velocities in pre-stack depth migration can be implemented as a computer program tangibly contained in a computer-readable storage medium, such as storage unit 18. In some embodiments, part or all of the computer program can be loaded and / or mounted on electronic device 10 via ROM 12 and / or communication unit 19. When the computer program is loaded into RAM 13 and executed by processor 11, one or more steps of the method for determining shallow velocities in pre-stack depth migration described above can be performed. Alternatively, in other embodiments, processor 11 can be configured to perform the method for determining shallow velocities in pre-stack depth migration by any other suitable means (e.g., by means of firmware).

[0167] Various embodiments of the systems and techniques described above herein can be implemented in digital electronic circuit systems, integrated circuit systems, field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), application-specific standard products (ASSPs), systems-on-a-chip (SoCs), payload-programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various embodiments may include implementations in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which may be a dedicated or general-purpose programmable processor, capable of receiving data and instructions from a storage system, at least one input device, and at least one output device, and transmitting data and instructions to the storage system, the at least one input device, and the at least one output device.

[0168] Computer programs used to implement the methods of the present invention may be written in any combination of one or more programming languages. These computer programs may be provided to a processor of a general-purpose computer, a special-purpose computer, or other programmable data processing device, such that when executed by the processor, the computer programs cause the functions / operations specified in the flowcharts and / or block diagrams to be performed. The computer programs may be executed entirely on a machine, partially on a machine, or as a standalone software package, partially on a machine and partially on a remote machine, or entirely on a remote machine or server.

[0169] In the context of this invention, a computer-readable storage medium can be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, apparatus, or device. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared, or semiconductor systems, apparatus, or devices, or any suitable combination thereof. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. More specific examples of machine-readable storage media include electrical connections based on one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fibers, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof.

[0170] To provide interaction with a user, the systems and techniques described herein can be implemented on an electronic device having: a display device (e.g., a CRT (cathode ray tube) or LCD (liquid crystal display) monitor) for displaying information to the user; and a keyboard and pointing device (e.g., a mouse or trackball) through which the user provides input to the electronic device. Other types of devices can also be used to provide interaction with the user; for example, feedback provided to the user can be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user can be received in any form (including sound input, voice input, or tactile input).

[0171] The systems and technologies described herein can be implemented in computing systems that include backend components (e.g., as data servers), or computing systems that include middleware components (e.g., application servers), or computing systems that include frontend components (e.g., user computers with graphical user interfaces or web browsers through which users can interact with implementations of the systems and technologies described herein), or any combination of such backend, middleware, or frontend components. The components of the system can be interconnected via digital data communication of any form or medium (e.g., communication networks). Examples of communication networks include local area networks (LANs), wide area networks (WANs), blockchain networks, and the Internet.

[0172] A computing system can include clients and servers. Clients and servers are generally located far apart and typically interact through communication networks. The client-server relationship is created by computer programs running on the respective computers and having a client-server relationship with each other. The server can be a cloud server, also known as a cloud computing server or cloud host, which is a hosting product within the cloud computing service system to address the shortcomings of traditional physical hosts and VPS services, such as high management difficulty and weak business scalability.

[0173] In one embodiment, the present invention further includes a computer program product, which includes a computer program that, when executed by a processor, implements a method for determining shallow velocity in pre-stack depth migration according to any embodiment of the present invention.

[0174] In implementing the computer program product, computer program code for performing the operations of this invention can be written in one or more programming languages ​​or a combination thereof. Programming languages ​​include object-oriented programming languages ​​such as Java, Smalltalk, and C++, as well as conventional procedural programming languages ​​such as C or similar languages. The program code can be executed entirely on the user's computer, partially on the user's computer, as a standalone software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In cases involving remote computers, the remote computer can be connected to the user's computer via any type of network—including a local area network (LAN) or a wide area network (WAN)—or can be connected to an external computer (e.g., via the Internet using an Internet service provider).

[0175] It should be understood that the various forms of processes shown above can be used, with steps reordered, added, or deleted. For example, the steps described in this invention can be executed in parallel, sequentially, or in different orders, as long as the desired result of the technical solution of this invention can be achieved, and this is not limited herein.

[0176] The specific embodiments described above do not constitute a limitation on the scope of protection of this invention. Those skilled in the art should understand that various modifications, combinations, sub-combinations, and substitutions can be made according to design requirements and other factors. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of this invention should be included within the scope of protection of this invention.

Claims

1. A method for determining shallow layer velocity in pre-stack depth migration, characterized in that, include: Based on a preset background velocity field, perform pre-stack depth migration in the angle domain on the seismic data to obtain an all-round common reflection angle gather and a post-stack data volume, and determine the similarity spectrum and gather curvature of the all-round common reflection angle gather; Based on the post-stack data volume, analysis points and analysis point analysis windows are determined. Based on the similarity spectrum, the initial dip angle of the strata is determined. Within the analysis point analysis window, a strata dip angle scan is performed according to the initial dip angle of the strata to determine the coherence value between adjacent seismic traces along the direction of each strata dip angle. The dip angle of the strata at the analysis point is determined based on the maximum value of the coherence value, and ray tracing is performed based on the dip angle to determine the seismic wave propagation information at the analysis point. The velocity disturbance is obtained by performing travel time inversion based on the seismic wave propagation information, and the shallow velocity field is determined according to the preset background velocity field and the velocity disturbance. Using the shallow velocity field as a preset background velocity field, the operation of performing pre-stack depth offset in the angle domain based on the preset background velocity field to obtain the omnidirectional common reflection angle gather and post-stack data volume is repeated until the curvature of the gather meets the preset condition.

2. The method according to claim 1, characterized in that, The process of performing angular domain pre-stack depth migration on seismic data based on a preset background velocity field to obtain omnidirectional common reflection angle gathers and post-stack data volumes, and determining the similarity spectrum and gather curvature of the omnidirectional common reflection angle gathers, includes: Under a preset background velocity field, ray-tracing imaging is performed on the ground from the analysis points in the pre-stack seismic data to determine the polar coordinate parameters of the analysis points and the post-stack data volume. Integrate the polar coordinate parameter components of the analysis point to obtain the omnidirectional common reflection angle gather; Determine the coherence values ​​between different seismic traces in the all-round common reflection angle trace set, and construct a similarity spectrum according to the order of the azimuth and reflection angle of the seismic traces; The time and reflection angle of each seismic trace in the all-round common reflection angle gather are determined to determine the local slope of each seismic trace, and the gather curvature of the all-round common reflection angle gather is determined by differential analysis of each local slope.

3. The method according to claim 1, characterized in that, The process of determining analysis points and analysis point analysis windows based on the post-stack data volume, determining the initial dip angle of the formation based on the similarity spectrum, performing a formation dip angle scan within the analysis point analysis window according to the initial dip angle of the formation, and determining the coherence value between adjacent seismic traces along the direction of each formation dip angle includes: Based on the post-stack data volume, the analysis points are identified, and the spatial location of the analysis points is determined; wherein, the spatial location includes coordinate information and reflection depth; Based on the spatial location, at least one consecutive adjacent seismic trace centered on the coordinate information is determined as the horizontal analysis window, and at least one consecutive sampling point centered on the reflection depth is determined as the vertical analysis window. The horizontal analysis window and the vertical analysis window are used as analysis point analysis windows; The dip angle of the stratum corresponding to the energy peak in the similar spectrum of the analysis point is determined as the initial dip angle of the stratum at the analysis point; wherein, the initial dip angle of the stratum includes the dip angle of the stratum in the transverse survey line direction and the dip angle of the stratum in the longitudinal survey line direction; The average energy and total energy of the seismic traces within the analysis window of the analysis point are determined based on the analysis point analysis window and the initial dip angle of the formation. The ratio of the average energy of the seismic trace to the total energy of all traces is used as the coherence value between adjacent seismic traces along the initial dip angle of the stratum. Based on the analysis point analysis window, a stratigraphic dip angle scan is performed according to a preset dip angle scan range to determine the dip angle of candidate stratigraphic layers, and the coherence value between adjacent seismic traces of the analysis point along the direction of each candidate stratigraphic dip angle is determined.

4. The method according to claim 1, characterized in that, The process of determining the dip angle of the strata at the analysis point based on the maximum value of the coherence value, and performing ray tracing based on the dip angle to determine the seismic wave propagation information at the analysis point, includes: The initial dip angle / candidate dip angle of the formation corresponding to the maximum value among the coherence values ​​is determined as the dip angle of the formation at the analysis point. The remaining depth difference of the analysis point is determined based on the curvature of the gather, and two-point ray tracing is performed on the analysis point along the preset shot-receiver distance, preset normal and preset incident angle to determine the ray path and travel time difference of the analysis point; The ray path includes the ray path corresponding to zero shot-receiver distance and the ray path corresponding to non-zero shot-receiver distance; the travel time difference includes the travel time difference corresponding to zero shot-receiver distance and the travel time difference corresponding to non-zero shot-receiver distance. The remaining depth difference, the preset incident angle, the ray path, and the travel time difference are used as the seismic wave propagation information of the analysis point.

5. The method according to claim 1, characterized in that, The step of performing travel-time inversion based on the seismic wave propagation information to obtain the velocity disturbance, and determining the shallow velocity field according to the preset background velocity field and the velocity disturbance, includes: Based on the seismic wave propagation information, a tomographic equation is constructed, and the velocity disturbance is determined by solving the tomographic equation. The preset background velocity field is updated as a shallow velocity field according to the velocity perturbation.

6. The method according to claim 5, characterized in that, The process of constructing tomographic equations based on the seismic wave propagation information and determining velocity disturbances by solving the tomographic equations includes: The travel path corresponding to the non-zero source-receiver distance is determined according to the preset incident angle in the seismic wave propagation information and the ray path corresponding to the non-zero source-receiver distance. The difference between the travel path and the ray path corresponding to zero shot-receiver distance in the seismic wave propagation information is taken as the first difference. The target travel time difference corresponding to the non-zero gun-receiver distance is determined according to the preset incident angle and the travel time difference corresponding to the non-zero gun-receiver distance. The difference between the target travel time difference and the travel time difference corresponding to zero shot-receiver distance in the seismic wave propagation information is determined as the second difference; The ratio of the second difference to the first difference is determined as the velocity disturbance.

7. The method according to claim 1, characterized in that, The curvature of the set meets the preset conditions, including the curvature of the set being less than a preset set curvature threshold.

8. An electronic device, characterized in that, The electronic device includes: At least one processor; and A memory communicatively connected to the at least one processor; wherein, The memory stores a computer program executable by the at least one processor, which enables the at least one processor to perform the method for determining shallow velocity in pre-stack depth migration as described in any one of claims 1-7.

9. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores computer instructions that, when executed by a processor, implement the method for determining shallow velocity in pre-stack depth migration as described in any one of claims 1-7.

10. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the method for determining shallow velocity in pre-stack depth migration according to any one of claims 1-7.

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