Seismic data imaging processing method and apparatus

Abstract

The present application relates to the technical field of seismic data processing, etc. Provided in the embodiments of the present application are a seismic data imaging processing method and an apparatus. The method comprises: taking the horizontal plane where a shot point is located as a datum plane, separately performing shot point datum plane correction on a first longitudinal wave stacking velocity, a first longitudinal wave stacked section, a first converted wave stacking velocity, a first kappa and a first converted wave stacked section under dual datum planes, so as to obtain a second longitudinal wave stacking velocity, a second longitudinal wave stacked section, a second converted wave stacking velocity, a second kappa and a second converted wave stacked section under the shot point datum plane. Thus, real positions of receiver points and the shot point can be accurately reflected, thus improving the accuracy of converted-wave prestack time migration imaging results.

Description

Earthquake Data Imaging Processing Methods and Devices

[0001] This application claims priority to Chinese Patent Application No. 202411691488.7, filed on November 25, 2024, entitled "Method and Apparatus for Imaging Seismic Data", the entire contents of which are incorporated herein by reference. Technical Field

[0002] This application relates to the technical field of earthquake data processing, and in particular to an earthquake data imaging processing method and apparatus. Background Technology

[0003] In recent years, ocean bottom node (OBN) seismic exploration technology has developed rapidly and has become an important trend in marine seismic exploration.

[0004] In related OBN seismic exploration techniques, it is assumed that the shot point and the receiver point are located on the same horizontal plane for subsequent data processing.

[0005] This assumption is difficult to accurately reflect the true location of the shot point and receiver point in the complex marine environment, thus resulting in poor accuracy of the offset imaging results obtained during data processing. Summary of the Invention

[0006] This application provides a seismic data imaging processing method and apparatus to improve the accuracy of migration imaging results.

[0007] In a first aspect, embodiments of this application provide a seismic data imaging processing method, including:

[0008] Acquire the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area;

[0009] Based on the first P-wave seismic data from each receiver point, the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes are determined using the hyperbolic method.

[0010] Based on the first converted wave seismic data from each receiver point, the first converted wave stacking velocity, first KPa, and first converted wave stacking profile under the dual reference planes are determined through stacking velocity analysis.

[0011] Using the horizontal plane where the shot point is located as the reference plane, the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile are corrected by the shot point reference plane to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane.

[0012] Based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second Kappa, and the second converted wave stacking profile, the parameters to be processed corresponding to the common conversion point are determined. The parameters to be processed are used to obtain the converted wave pre-stack time migration imaging results.

[0013] In one optional implementation, acquiring the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area includes:

[0014] Acquire the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0015] Preprocessing is performed on the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0016] Depth correction is performed on each geophone point to obtain the time correction amount of the seismic trace for each geophone point.

[0017] Based on the time correction of the seismic traces of each receiver point, the P-wave seismic data of all seismic traces of each receiver point after preprocessing are corrected to obtain the first P-wave seismic data of each receiver point.

[0018] Based on the time correction of the seismic traces at each receiver point, the converted wave seismic data of all seismic traces at each receiver point after preprocessing are corrected to obtain the first converted wave seismic data of each receiver point.

[0019] In one optional implementation, the preprocessing of the second P-wave seismic data and the second converted wave seismic data at each receiver point includes:

[0020] The second P-wave seismic data from each receiver point are subjected to P-wave seismic data preprocessing. The P-wave seismic data preprocessing process includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, and amplitude recovery.

[0021] The preprocessed P-wave seismic data is sorted into common center point gathers, which include P-wave seismic data from all seismic traces of each receiver point after preprocessing.

[0022] The second converted wave seismic data of each receiver point are preprocessed using converted wave seismic data. The preprocessing procedure includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, amplitude recovery, and marking of pre-set common conversion points in the trace head.

[0023] The preprocessed converted wave seismic data is sorted into common conversion point gathers, which include converted wave seismic data from all seismic traces of each receiver point after preprocessing.

[0024] In one optional implementation, the identifier of the pre-set common switching point in the track header includes:

[0025] Determine the location of the common conversion point;

[0026] Based on the location of the common switching point, the identifier of the common switching point is preset in the track header.

[0027] In one optional implementation, determining the location of the common conversion point includes:

[0028] Obtain the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point;

[0029] The initial horizontal distance is determined based on the horizontal propagation distance of the water layer, the P-wave to S-wave velocity ratio, and the distance between the shot point and the receiver point.

[0030] Based on the initial horizontal distance, the nth iteration is performed to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration, where n is an integer greater than or equal to 1;

[0031] Determine whether the horizontal distance in the nth iteration satisfies the iteration condition;

[0032] If the horizontal distance in the nth iteration does not meet the iteration condition, the horizontal distance between the common conversion point and the shot point is determined based on the horizontal distance in the nth iteration.

[0033] The position of the common conversion point is obtained by measuring the horizontal distance between the common conversion point and the shot point.

[0034] In one optional implementation, the first P-wave superposition velocity and the second P-wave superposition velocity satisfy the following first model:

[0035] Among them, t pp0 V represents the vertical two-way travel time of the P-wave below the reference plane of the shot point. P2 This represents the superposition velocity of the second longitudinal wave. This represents the vertical two-way travel time of the P-wave under the dual reference planes. This represents the superposition velocity of the first longitudinal wave. Indicates the longitudinal wave velocity of the sea layer. This indicates the travel time of longitudinal waves in the ocean layer.

[0036] In one optional implementation, the first converted wave superposition velocity and the second converted wave superposition velocity satisfy the following second model:

[0037] Among them, t c0 V represents the vertical two-way travel time of the converted wave under the reference plane of the shot point. c2 This indicates the superposition velocity of the second converted wave. This represents the vertical two-way travel time of the converted wave under the dual reference planes. This represents the superposition velocity of the first converted wave. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

[0038] In one alternative implementation, the first Kappa and the second Kappa satisfy the following third model:

[0039] Where, k eff This indicates the second Kappa. This indicates the first Kappa.

[0040] In one optional implementation, the parameters to be processed include the vertical velocity ratio, effective velocity ratio, optimal velocity, and third kappa corresponding to the common conversion point;

[0041] The step of determining the parameters to be processed corresponding to the common conversion point based on the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second Kappa, and the second converted wave superposition profile includes:

[0042] The vertical velocity ratio is determined based on the second longitudinal wave superposition profile and the second converted wave superposition profile;

[0043] The effective velocity ratio is determined based on the second longitudinal wave superposition velocity and the second converted wave superposition velocity;

[0044] The common imaging point gather is determined based on the second converted wave superposition velocity, the second Kpa, the vertical velocity ratio, and the effective velocity ratio;

[0045] Based on the common imaging point gather, the second converted wave superposition velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa.

[0046] Secondly, embodiments of this application provide a seismic data imaging processing apparatus, comprising:

[0047] The acquisition module is used to acquire the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area;

[0048] The determination module is used to determine the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes based on the first P-wave seismic data of each receiver point using the hyperbolic method.

[0049] The determining module is further configured to determine the first converted wave stacking velocity, the first KPa, and the first converted wave stacking profile under the dual reference plane by performing stacking velocity analysis processing based on the first converted wave seismic data of each receiver point.

[0050] The correction module is used to perform shot point reference plane correction on the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile, respectively, with the horizontal plane where the shot point is located as the reference plane, to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane.

[0051] The determining module is further configured to determine the parameters to be processed corresponding to the common conversion point based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second Kappa, and the second converted wave stacking profile. The parameters to be processed are used to obtain the converted wave pre-stack time-migration imaging result.

[0052] In one alternative implementation, the acquisition module is specifically used for:

[0053] Acquire the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0054] Preprocessing is performed on the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0055] Depth correction is performed on each geophone point to obtain the time correction amount of the seismic trace for each geophone point.

[0056] Based on the time correction of the seismic traces of each receiver point, the P-wave seismic data of all seismic traces of each receiver point after preprocessing are corrected to obtain the first P-wave seismic data of each receiver point.

[0057] Based on the time correction of the seismic traces at each receiver point, the converted wave seismic data of all seismic traces at each receiver point after preprocessing are corrected to obtain the first converted wave seismic data of each receiver point.

[0058] In one alternative implementation, the acquisition module is specifically used for:

[0059] The second P-wave seismic data from each receiver point are subjected to P-wave seismic data preprocessing. The P-wave seismic data preprocessing process includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, and amplitude recovery.

[0060] The preprocessed P-wave seismic data is sorted into common center point gathers, which include P-wave seismic data from all seismic traces of each receiver point after preprocessing.

[0061] The second converted wave seismic data of each receiver point are preprocessed using converted wave seismic data. The preprocessing procedure includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, amplitude recovery, and marking of pre-set common conversion points in the trace head.

[0062] The preprocessed converted wave seismic data is sorted into common conversion point gathers, which include converted wave seismic data from all seismic traces of each receiver point after preprocessing.

[0063] In one alternative implementation, the acquisition module is specifically used for:

[0064] Determine the location of the common conversion point;

[0065] Based on the location of the common switching point, the identifier of the common switching point is preset in the track header.

[0066] In one alternative implementation, the acquisition module is specifically used for:

[0067] Obtain the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point;

[0068] The initial horizontal distance is determined based on the horizontal propagation distance of the water layer, the P-wave to S-wave velocity ratio, and the distance between the shot point and the receiver point.

[0069] Based on the initial horizontal distance, the nth iteration is performed to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration, where n is an integer greater than or equal to 1;

[0070] Determine whether the horizontal distance in the nth iteration satisfies the iteration condition;

[0071] If the horizontal distance in the nth iteration does not meet the iteration condition, the horizontal distance between the common conversion point and the shot point is determined based on the horizontal distance in the nth iteration.

[0072] The position of the common conversion point is obtained by measuring the horizontal distance between the common conversion point and the shot point.

[0073] In one optional implementation, the first P-wave superposition velocity and the second P-wave superposition velocity satisfy the following first model:

[0074] Among them, t pp0 V represents the vertical two-way travel time of the P-wave below the reference plane of the shot point. P2 This represents the superposition velocity of the second longitudinal wave. This represents the vertical two-way travel time of the P-wave under the dual reference planes. This represents the superposition velocity of the first longitudinal wave. Indicates the longitudinal wave velocity of the sea layer. This indicates the travel time of longitudinal waves in the ocean layer.

[0075] In one optional implementation, the first converted wave superposition velocity and the second converted wave superposition velocity satisfy the following second model:

[0076] Among them, t c0 V represents the vertical two-way travel time of the converted wave under the reference plane of the shot point. c2 This indicates the superposition velocity of the second converted wave. This represents the vertical two-way travel time of the converted wave under the dual reference planes. This represents the superposition velocity of the first converted wave. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

[0077] In one alternative implementation, the first Kappa and the second Kappa satisfy the following third model:

[0078] Where, k eff This indicates the second Kappa. This indicates the first Kappa.

[0079] In one optional implementation, the parameters to be processed include the vertical velocity ratio, effective velocity ratio, optimal velocity, and third kappa corresponding to the common conversion point;

[0080] The determining module is specifically used for:

[0081] The vertical velocity ratio is determined based on the second longitudinal wave superposition profile and the second converted wave superposition profile;

[0082] The effective velocity ratio is determined based on the second longitudinal wave superposition velocity and the second converted wave superposition velocity;

[0083] The common imaging point gather is determined based on the second converted wave superposition velocity, the second Kpa, the vertical velocity ratio, and the effective velocity ratio;

[0084] Based on the common imaging point gather, the second converted wave superposition velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa.

[0085] Thirdly, embodiments of this application provide an electronic device, including: a memory and a processor;

[0086] The memory stores the instructions that the computer executes;

[0087] The processor executes computer execution instructions stored in memory, causing any of the methods provided in the first aspect to be performed.

[0088] Fourthly, embodiments of this application provide a computer-readable storage medium storing computer-executable instructions, which, when executed by a processor, are used to implement any of the methods provided in the first aspect.

[0089] Fifthly, embodiments of this application provide a computer program product, including a computer program that, when executed by a processor, implements the method provided in any of the first aspects.

[0090] This application provides a seismic data imaging processing method and apparatus. The method includes: determining the first P-wave stacking velocity and the first P-wave stacking profile under two reference planes using the hyperbolic method based on the first P-wave seismic data from each receiver point; determining the first converted wave stacking velocity, the first Kpa, and the first converted wave stacking profile under two reference planes based on the first converted wave seismic data from each receiver point through stacking velocity analysis; and performing shot point reference plane correction on the first P-wave stacking velocity, the first P-wave stacking profile, the first converted wave stacking velocity, the first Kpa, and the first converted wave stacking profile, respectively, using the horizontal plane where the shot point is located as the reference plane, to obtain the second P-wave stacking velocity, the second P-wave stacking profile, the second converted wave stacking velocity, the second Kpa, and the second converted wave stacking profile under the shot point reference plane. Through reference plane correction, the true positions of the receiver points and shot points can be accurately reflected, thereby improving the accuracy of the converted wave pre-stack time migration imaging results. Attached Figure Description

[0091] To more clearly illustrate the technical solutions in this application, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0092] Figure 1 is a schematic diagram of an application scenario of the seismic data imaging processing method provided in an embodiment of this application;

[0093] Figure 2 is one of the flowcharts of the seismic data imaging processing method provided in the embodiments of this application;

[0094] Figure 3 is a second schematic flowchart of the seismic data imaging processing method provided in the embodiments of this application;

[0095] Figure 4 is a flowchart illustrating the process of determining the location of the common conversion point according to an embodiment of this application;

[0096] Figure 5 is a schematic flowchart of the seismic data imaging processing method provided in the embodiments of this application (third one).

[0097] Figure 6 shows the analysis flow of the pre-stack time migration initial velocity model of a converted wave provided in an embodiment of this application;

[0098] Figure 7 shows a pre-stack time migration velocity analysis flowchart of a converted wave according to an embodiment of this application;

[0099] Figure 8 is a diagram showing the effect of velocity analysis on a unified reference surface provided in an embodiment of this application;

[0100] Figure 9 is a diagram showing the effect of dual-reference-plane velocity analysis according to an embodiment of this application;

[0101] Figure 10 is a schematic diagram of the structure of the seismic data imaging processing device provided in the embodiment of this application;

[0102] Figure 11 is a schematic diagram of the structure of the electronic device provided in the embodiment of this application.

[0103] The accompanying drawings illustrate specific embodiments of this application, which will be described in more detail below. These drawings and descriptions are not intended to limit the scope of the concept in any way, but rather to illustrate the concept of this application to those skilled in the art through reference to particular embodiments. Detailed Implementation

[0104] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numbers in different drawings represent the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with this application. Rather, they are merely examples of apparatuses and methods consistent with some aspects of this application as detailed in the appended claims.

[0105] In the embodiments of this application, the term "comprising" and its variations can refer to a non-limiting inclusion; the term "or" and its variations can refer to "and / or". The terms "first", "second", etc., in this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. In this application, "multiple" refers to two or more. "And / or" describes the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent: A existing alone, A and B existing simultaneously, and B existing alone. The character " / " generally indicates that the preceding and following related objects have an "or" relationship. The term "at least one of the following" or similar expressions in this application refer to any combination of these items, including any combination of a single item or multiple items. For example, at least one of a, b, or c can represent: a, b, c, ab, ac, bc, or abc, where a, b, and c can be single or multiple.

[0106] In this application, the terms "exemplary" or "for example" are used to indicate that something is an example, illustration, or description. Any embodiment or design described as "exemplary" or "for example" in this application should not be construed as being more preferred or advantageous than other embodiments or designs. Specifically, the use of terms such as "exemplary" or "for example" is intended to present the relevant concepts in a specific manner.

[0107] First, an exemplary description of the application scenarios of the seismic data imaging processing method provided in this application is given.

[0108] Figure 1 is a schematic diagram of an application scenario of the seismic data imaging processing method provided in an embodiment of this application. For example, as shown in Figure 1, it includes multiple shot points, multiple receiver points, and a conversion point. The multiple shot points include, for example, shot point 1 and shot point 2. The multiple receiver points include, for example, receiver point 1, receiver point 2, receiver point 3, and receiver point 4. The conversion point is, for example, point a in the seafloor strata.

[0109] The firing point can generate seismic waves, which will propagate towards the seabed and penetrate the seabed strata.

[0110] Geophones are pre-positioned at designated locations on the seabed. A geophone typically contains components such as seismic sensors, a data acquisition system, and a power supply to collect seismic waves generated by the shot point, obtaining first P-wave seismic data and first converted wave seismic data.

[0111] A transition point is the location where a seismic wave changes its wave type when it encounters a seafloor stratum. For example, if a P-wave becomes a S-wave at point a in the seafloor stratum, then point a is the transition point.

[0112] After completing the acquisition of first P-wave and first converted wave seismic data over a certain period, the receiver points are retrieved to obtain the first P-wave and first converted wave seismic data recorded at the receiver points.

[0113] The first P-wave seismic data and the first converted wave seismic data can be processed by electronic equipment to obtain migration imaging results, which can be used for geological interpretation and oil and gas resource evaluation. The technical solution of this application and how it solves the above-mentioned technical problems are described in detail below with specific embodiments. These specific embodiments can be combined with each other, and the same or similar concepts or processes may not be described again in some embodiments. The embodiments of this application will be described below with reference to the accompanying drawings.

[0114] Figure 2 is a schematic flowchart of one of the seismic data imaging processing methods provided in this application embodiment. As shown in Figure 2, the method includes:

[0115] S201. Obtain the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area.

[0116] Optionally, the execution subject of this application embodiment can be an electronic device or a seismic data imaging processing device installed in an electronic device. Electronic devices include, for example, laptops, tablets, and desktop computers. The seismic data imaging processing device can be implemented through software and / or hardware.

[0117] Optionally, the detector point can be a seabed node, a microseismic detector, a seabed seismograph, etc.

[0118] For details on the execution process of S203, please refer to S301 to S305, which will not be repeated here.

[0119] S202. Based on the first P-wave seismic data from each receiver point, the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes are determined using the hyperbolic method.

[0120] S203. Based on the first converted wave seismic data from each receiver point, the first converted wave stacking velocity, the first kappa, and the first converted wave stacking profile under the dual reference plane are determined through stacking velocity analysis.

[0121] For details on the execution process of S203, please refer to S503, which will not be repeated here.

[0122] S204. Using the horizontal plane where the shot point is located as the reference plane, the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile are corrected by the shot point reference plane to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane.

[0123] For details on the execution process of S204, please refer to S504; it will not be repeated here.

[0124] S205. Based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second KPa and the second converted wave stacking profile, determine the parameters to be processed corresponding to the common conversion point. The parameters to be processed are used to obtain the converted wave pre-stack time migration imaging results.

[0125] For details on the execution process of S205, please refer to S505-S508, which will not be repeated here.

[0126] In the seismic data imaging processing method provided in the embodiment of Figure 2, based on the first P-wave seismic data of each receiver point, the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference plane are determined by the hyperbolic method. Based on the first converted wave seismic data of each receiver point, the first converted wave stacking velocity, the first Kpa, and the first converted wave stacking profile under the dual reference plane are determined by stacking velocity analysis. Using the horizontal plane where the shot point is located as the reference plane, the first P-wave stacking velocity, the first P-wave stacking profile, the first converted wave stacking velocity, the first Kpa, and the first converted wave stacking profile are corrected by the shot point reference plane to obtain the second P-wave stacking velocity, the second P-wave stacking profile, the second converted wave stacking velocity, the second Kpa, and the second converted wave stacking profile under the shot point reference plane. This can accurately reflect the true location of the receiver point and the shot point, improve the accuracy of converted wave velocity processing in seismic data imaging processing, and thus improve the accuracy of the stacking profile (the stacking profile includes the converted wave stacking profile and the P-wave stacking profile) and the converted wave pre-stack time migration imaging results.

[0127] Based on any of the above embodiments, the seismic data imaging processing method provided in the embodiments of this application will be further described below with reference to FIG3.

[0128] Figure 3 is a second schematic flowchart of the seismic data imaging processing method provided in this application embodiment. As shown in Figure 3, the method includes:

[0129] S301. Obtain the second P-wave seismic data and the second converted wave seismic data at each receiver point.

[0130] Optionally, when the receiver is a seabed node, seabed nodes are pre-deployed on the seabed. Second P-wave seismic data and second converted wave seismic data are collected by the observation method of generating seismic waves at the sea surface through shot points and receiving seismic waves at the seabed nodes, thereby obtaining second P-wave seismic data and second converted wave seismic data distributed at each seabed node.

[0131] Optionally, when the receiver is a seabed node, the second P-wave seismic data is received through the vertical component of the seabed node, and the second converted wave data is received through the horizontal component of the seabed node.

[0132] S302. Preprocess the second P-wave seismic data and the second converted wave seismic data of each receiver point.

[0133] In one optional embodiment, the second P-wave seismic data of each receiver point is preprocessed with P-wave seismic data. The P-wave seismic data preprocessing process includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, and amplitude recovery. The preprocessed P-wave seismic data is sorted into common center point gathers, which include P-wave seismic data of all seismic traces of each receiver point after preprocessing.

[0134] In one optional embodiment, the second converted wave seismic data of each receiver point is preprocessed using converted wave seismic data. The preprocessing procedure includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, amplitude recovery, and marking of pre-set common conversion points in the trace head. The preprocessed converted wave seismic data is then sorted into common conversion point gathers, which include converted wave seismic data from all seismic traces of each receiver point after preprocessing.

[0135] S303. Perform depth correction on each geophone point to obtain the time correction amount of the seismic trace at each geophone point.

[0136] Specifically, S303 includes:

[0137] Based on the degree of seabed undulation, the common center point within the target work area is divided into preset areas, and the average seabed depth of all common center points within each preset area is determined. This average value is the smoothed seawater depth of the common center point.

[0138] Based on the degree of seabed undulation, the corrected detector depth is obtained by using the smoothed common midpoint seawater depth.

[0139] Based on the corrected receiver depth, the time correction amount of the seismic traces at each receiver is obtained.

[0140] Optionally, the preset area range includes, but is not limited to: circles with large radii and rectangular windows.

[0141] Optionally, the degree of seabed undulation can be divided into: seabed with little undulation and seabed with significant undulation.

[0142] Taking a circle with a large radius as an example, the following illustrative examples illustrate the cases of small and large seabed undulations:

[0143] When the seabed undulations are not significant, a circle with a radius of 2 km is selected. Based on the circle with a radius of 2 km, the common center point within the target work area is divided to obtain multiple circular regions containing multiple common center points. The average seabed depth of each common center point within each circular region is determined, and this average value is used as the seawater depth of the common center point after smoothing the low undulations. The depth of the geophone is corrected to the seawater depth of the common center point after smoothing the low undulations. The time correction amount of the seismic traces of each geophone is obtained through the fourth model.

[0144] When the seabed is highly undulating, a circle with a radius of 5km is selected to divide the target work area into multiple circular regions containing multiple common center points. The average seabed depth of each common center point in each circular region is determined, and this average value is used as the seawater depth of the common center point after smoothing the high undulations. The depth of the geophone is corrected to the seawater depth of the common center point after smoothing the high undulations at the geophone location. The time correction amount of the seismic traces of each geophone is obtained through the fifth model.

[0145] Optionally, the original depth of the i-th receiver, the seawater depth at the common midpoint after smoothing the low undulations corresponding to the i-th receiver, and the time correction of the seismic trace of the i-th receiver satisfy the following fourth model: T i =-(H c -H g ) / V ws

[0146] Among them, T i H represents the time correction amount of the seismic trace at the i-th receiver point. g H represents the original depth of the i-th receiver point. c V represents the common midpoint seawater depth corresponding to the smoothed low-undulation seismic trace at the i-th receiver point. ws This indicates the shallow transverse wave replacement velocity.

[0147] For example, the shallow shear wave replacement velocity can be 750 m / s.

[0148] Optionally, the original depth of the i-th receiver, the seawater depth at the common midpoint after smoothing the high undulations at the receiver location corresponding to the seismic trace of the i-th receiver, and the time correction amount of the seismic trace of the i-th receiver satisfy the following fifth model: Ti =-(H cg -H g ) / V ws

[0149] Among them, H cg The depth of the seawater at the common center point after smoothing the high undulations at the location of the corresponding geophone in the seismic trace of the i-th geophone is represented.

[0150] S304. Based on the time correction of the seismic traces at each receiver point, correct the P-wave seismic data of all seismic traces at each receiver point after preprocessing to obtain the first P-wave seismic data of each receiver point.

[0151] S305. Based on the time correction of the seismic traces at each receiver point, correct the converted wave seismic data of all seismic traces at each receiver point after preprocessing to obtain the first converted wave seismic data of each receiver point.

[0152] S306, including the aforementioned S202 to S205, will not be repeated here.

[0153] In the seismic data imaging processing method provided in the embodiment of Figure 3, depth correction is performed on each receiver point to obtain the time correction amount of the seismic traces of each receiver point; based on the time correction amount of the seismic traces of each receiver point, the preprocessed P-wave seismic data of each receiver point is corrected to obtain the first P-wave seismic data of each receiver point; based on the time correction amount of the seismic traces of each receiver point, the preprocessed converted wave seismic data of each receiver point is corrected to obtain the first converted wave seismic data of each receiver point. This method realizes the correction of the receiver point position according to the seabed undulation, reducing the influence of seabed topographic undulation on the processing of the first P-wave seismic data and the first converted wave seismic data.

[0154] In one optional embodiment, the identifier of the pre-set common switching point in the track header includes:

[0155] Determine the location of the common conversion point;

[0156] Based on the location of the common switching point, the common switching point marker is pre-set in the track header.

[0157] The location of the common conversion point will be explained in detail below with reference to Figure 4.

[0158] Figure 4 is a flowchart illustrating the process of determining the location of a common conversion point according to an embodiment of this application. As shown in Figure 4, the method includes:

[0159] S401, Obtain the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point.

[0160] S402. Determine the initial horizontal distance based on the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point.

[0161] Optionally, the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, the distance between the shot point and the receiver point, and the initial horizontal distance satisfy the following sixth model:

[0162] in, The initial horizontal distance represents the horizontal distance between the incident point on the seabed and the common conversion point, and r represents the P-wave / S-wave velocity ratio. This represents the horizontal distance between the initial water layer's location protruding underground and the receiver point. Wherein, This represents the initial horizontal propagation distance in the water layer, which is the horizontal distance between the shot point and the incident point on the seabed. x represents the distance between the shot point and the receiver point.

[0163] S403. Based on the initial horizontal distance, perform the nth iteration to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration, where n is an integer greater than or equal to 1.

[0164] Optionally, the horizontal distance in the nth iteration satisfies the following seventh model:

[0165] in, This represents the horizontal distance in the nth iteration. Let z represent the horizontal distance in the (n-1)th iteration, and z represent the depth of the target layer, which is the depth from the target layer to the seabed. This represents the horizontal distance between the location of the water layer propagating underground in the (n-1)th iteration and the receiver point, where... The angle of incidence for water to propagate underground satisfies the following eighth model:

[0166] Where, θ n V represents the incident angle of the water layer propagating underground in the nth iteration. p0 V represents the velocity of the water layer. p1 denoted by , which represents the equivalent underground velocity, and arcsin represents the arcsine function.

[0167] The horizontal propagation distance of the water layer satisfies the following ninth model:

[0168] in, Let h0 represent the horizontal propagation distance of the water layer in the nth iteration, h0 represent the depth from the shot reference plane to the seabed reference plane, and tan represent the tangent function.

[0169] S404. Determine whether the horizontal distance in the nth iteration satisfies the iteration condition.

[0170] S405a. If the horizontal distance in the nth iteration satisfies the iteration condition, repeat S403-S405.

[0171] Optionally, when S403 is executed repeatedly, the initial horizontal distance in S403 is replaced with the horizontal distance of the nth iteration.

[0172] S405b. If the horizontal distance in the nth iteration does not meet the iteration conditions, determine the horizontal distance between the common conversion point and the shot point based on the horizontal distance in the nth iteration.

[0173] Optionally, the iteration condition can be greater than or equal to a pre-set specific value, such as 0.01. Specifically, the difference between the horizontal distance determined in the current iteration and the horizontal distance obtained in the previous iteration is determined, and it is determined whether the difference is greater than or equal to the pre-set specific value.

[0174] For example, when the iteration condition is greater than or equal to 0.01, the difference between the horizontal distance of the nth iteration and the horizontal distance of the (n-1)th iteration is determined;

[0175] When the difference is greater than or equal to 0.01, the iteration condition is met, and S402-S404 are repeated.

[0176] When the difference is less than 0.01, the iteration condition is not met, and the horizontal distance between the common conversion point and the shot point in the nth iteration is obtained as follows:

[0177] Optionally, the horizontal distance between the common conversion point and the shot point satisfies the following tenth model:

[0178] in, This represents the horizontal distance between the common conversion point and the shot point in the nth iteration.

[0179] S406. The position of the common conversion point is obtained by measuring the horizontal distance between the common conversion point and the shot point.

[0180] Optionally, since the location of the shot point is known, the location of the common conversion point can be obtained by measuring the horizontal distance between the common conversion point and the shot point.

[0181] In the seismic data imaging processing method provided in the embodiment of Figure 4, the initial horizontal distance is determined based on the horizontal propagation distance of the water layer, the P-wave / S-wave velocity ratio, and the distance between the shot point and the receiver point. Based on the initial horizontal distance, the nth iteration is performed to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration. If the horizontal distance of the nth iteration does not meet the iteration conditions, the horizontal distance between the common conversion point and the shot point is determined based on the horizontal distance of the nth iteration. Through multiple iterations, the horizontal distance between the common conversion point and the shot point can be accurately confirmed, thereby determining the true location of the common conversion point and providing effective technical support for subsequent seismic data imaging processing.

[0182] Based on any of the above embodiments, the seismic data imaging processing method provided in the embodiments of this application will be further described below with reference to FIG5.

[0183] Figure 5 is a third schematic flowchart of the seismic data imaging processing method provided in this application embodiment. As shown in Figure 5, the method includes:

[0184] S501. Obtain the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area.

[0185] For details on the execution process of S501, please refer to the aforementioned S301 to S305, which will not be repeated here.

[0186] S502. Based on the first P-wave seismic data from each receiver point, the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes are determined using the hyperbolic method.

[0187] S503. Based on the first converted wave seismic data from each receiver point, the first converted wave stacking velocity, the first kappa, and the first converted wave stacking profile under the dual reference plane are determined through stacking velocity analysis.

[0188] Optionally, the first converted wave seismic data undergoes stacking velocity analysis to flatten and straighten the reflection wave phase axes at near and medium-to-far offsets. The converted wave stacking velocity and Kpa are continuously adjusted until the reflection wave phase axes at both near and medium-to-far offsets achieve the desired flattening and straightening. After all phase axes are successfully flattened and straightened, the first converted wave stacking velocity, first Kpa, and first converted wave stacking profile are obtained under dual reference planes. The converted wave stacking velocity is used to control the phase axis at the near offset; Kpa is used to control the phase axis at the medium-to-far offset.

[0189] Specifically, the relationship curve between the travel time of the converted wave under the dual reference plane and the superposition velocity of the first converted wave and the first kappa is obtained through the eleventh model, and the superposition velocity of the first converted wave and the first kappa under the dual reference plane are determined.

[0190] Optionally, the converted wave travel time, the first converted wave superposition velocity, and the first Kappa under the dual reference planes satisfy the following eleven models:

[0191] in,

[0192] in, Indicates the travel time of the converted wave under dual reference planes. The vertical two-way travel time of the converted wave under dual reference planes is represented by x, where x represents the distance between the shot point and the receiver point. This represents the first converted wave superposition velocity under dual reference planes. This represents the first Kappa under the dual reference planes.

[0193] S504. Using the horizontal plane where the shot point is located as the reference plane, the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile are corrected by the shot point reference plane to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane.

[0194] In one optional embodiment, the first P-wave superposition velocity and the second P-wave superposition velocity satisfy the following first model:

[0195] Among them, t pp0 V represents the vertical two-way travel time of the P-wave below the shot reference plane. p2 This represents the superposition velocity of the second longitudinal wave below the reference plane of the shot point. This indicates the vertical two-way travel time of the P-wave under dual reference planes. This represents the superposition velocity of the first longitudinal wave under the dual reference planes. Indicates the longitudinal wave velocity of the sea layer. This indicates the travel time of longitudinal waves in the ocean layer.

[0196] In one optional embodiment, the first converted wave superposition velocity and the second converted wave superposition velocity satisfy the following second model:

[0197] Among them, t c0 V represents the vertical two-way travel time of the converted wave below the shot reference plane. c2 This represents the superposition velocity of the second converted wave below the reference plane of the shot point. This represents the vertical two-way travel time of the converted wave under dual reference planes. This represents the first converted wave superposition velocity under dual reference planes. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

[0198] Optionally, the "straight wave velocity in the seawater layer" mentioned in this application is only a hypothetical parameter in the embodiments, used to determine other related physical quantities, and is not the actual propagation speed of shear waves in the seawater layer.

[0199] In one alternative embodiment, the first Kappa and the second Kappa satisfy the following third model:

[0200] Where, k eff This indicates the second Kappa below the shot reference plane. This represents the first Kappa under the dual reference planes.

[0201] Optionally, the P-wave stacking profile can be corrected to the horizontal plane where the shot point is located by using the P-wave velocity of the seawater layer; the converted wave stacking profile can be corrected to the horizontal plane where the shot point is located by using the S-wave velocity of the seawater layer.

[0202] For example, the longitudinal wave velocity of the seawater layer can be taken as 1500 m / s, and the transverse wave velocity of the seawater layer can be taken as 750 m / s.

[0203] S505. Determine the vertical velocity ratio based on the superimposed profile of the second longitudinal wave and the superimposed profile of the second converted wave.

[0204] Optionally, a comparative analysis is performed on the second longitudinal wave superposition profile and the second converted wave superposition profile to obtain the vertical velocity ratio.

[0205] Specifically, the similarity of the second longitudinal wave superposition profile and the second converted wave superposition profile is identified (i.e., comparative analysis is performed) to identify the wave groups corresponding to the second longitudinal wave superposition profile and the second converted wave superposition profile.

[0206] Based on wave group similarity identification and well synthetic record calibration, the vertical velocity ratio is determined.

[0207] Optionally, the vertical velocity ratio can be determined by the vertical two-way travel time of the shear wave, the vertical two-way travel time of the longitudinal wave, or the vertical two-way travel time of the converted wave.

[0208] Optionally, the vertical velocity ratio satisfies the following ninth model:

[0209] Where γ0 represents the vertical velocity ratio, t ss0 t represents the two-way vertical travel time of a transverse wave. pp0 t represents the vertical two-way travel time of the P-wave below the shot reference plane. c0 This indicates the vertical two-way travel time of the converted wave below the shot reference plane.

[0210] S506. Determine the effective velocity ratio based on the superposition velocity of the second longitudinal wave and the superposition velocity of the second converted wave.

[0211] Optionally, the second P-wave superposition velocity, the second converted wave superposition velocity, and the effective velocity ratio satisfy the following tenth model:

[0212] Where, γ eff V represents the effective speed ratio. p2 V represents the superposition velocity of the second longitudinal wave. c2 This indicates the superposition velocity of the second converted wave.

[0213] Optionally, S506 can also be replaced by: determining the effective speed ratio based on the vertical speed ratio. Wherein, the vertical speed ratio and the effective speed ratio satisfy the following eleventh model: γ eff =n1γ0

[0214] Here, n1 is an empirical parameter. By default, n1 can take the value 0.8.

[0215] S507. Determine the common imaging point gather based on the second converted wave superposition velocity, the second Kpa, the vertical velocity ratio, and the effective velocity ratio.

[0216] Optionally, S507 includes:

[0217] Based on the second converted wave stacking velocity, the second Kappa, the vertical velocity ratio, and the effective velocity ratio, the converted wave pre-stack time migration velocity parameters under the shot point reference plane are determined by the converted wave pre-stack time migration model.

[0218] Using the horizontal plane where the seabed is located as the reference plane, the first shear wave velocity, the first shear wave anisotropy parameter and the first shear wave vertical travel time are corrected by the seabed reference plane to obtain the second shear wave velocity, the second shear wave anisotropy parameter and the second shear wave vertical travel time under the seabed reference plane.

[0219] Based on the second shear wave velocity, the second shear wave anisotropy parameter, and the second shear wave vertical travel time, the pre-stack time migration velocity parameter of the converted wave is updated to obtain the pre-stack time migration velocity parameter of the converted wave under the dual reference plane.

[0220] Using the converted wave scattering model, and based on the converted wave pre-stack time migration velocity parameters under dual reference planes, the first converted wave pre-stack time migration process is performed to obtain the common imaging point gather.

[0221] The pre-stack time migration velocity parameters of the converted wave under the shot reference plane include: P-wave velocity, first S-wave velocity, P-wave anisotropy parameter, first S-wave anisotropy parameter, P-wave vertical travel time, and first S-wave vertical travel time.

[0222] The pre-stack time migration velocity parameters of the converted wave under dual reference planes include: P-wave velocity, second S-wave velocity, P-wave anisotropy parameter, second S-wave anisotropy parameter, P-wave vertical travel time, and second S-wave vertical travel time.

[0223] Optionally, the pre-stack time migration model for the converted wave is:

[0224] Among them, V c2 k represents the superposition velocity of the second converted wave. eff γ represents the second KPa, γ0 represents the vertical velocity ratio, and γ eff V represents the effective speed ratio. p V represents the longitudinal wave velocity. s2 η represents the velocity of the first transverse wave. eff ζ represents the anisotropy parameter of the longitudinal wave. eff t represents the anisotropy parameter of the first transverse wave. s0 t represents the vertical travel time of the first transverse wave. p0 The vertical travel time of the P-wave below the shot reference plane, t c0 This indicates the vertical two-way travel time of the converted wave below the shot reference plane.

[0225] Optionally, the first shear wave velocity, the first shear wave vertical travel time, the second shear wave velocity, and the second shear wave vertical travel time satisfy the following twelfth model:

[0226] in, Indicates the vertical travel time of the second transverse wave. t represents the velocity of the second transverse wave. c0 V represents the vertical travel time of the first transverse wave. s2 Indicates the velocity of the first transverse wave. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

[0227] Optionally, the first shear wave anisotropy parameter and the second shear wave anisotropy parameter satisfy the following thirteenth model:

[0228] in, ζ represents the anisotropy parameter of the second transverse wave. eff This represents the anisotropy parameter of the first transverse wave.

[0229] Alternatively, the travel time of the transverse waves in the ocean layer satisfies the following fourteenth model:

[0230] Where H0 represents the depth from which the shot reference plane is corrected to the seabed reference plane.

[0231] Alternatively, the converted wave scattering model is as follows:

[0232] Where, x p x represents the horizontal distance from the scattering point to the shot point. s This represents the horizontal distance from the scattering point to the detector point. This represents the travel time model for upward transverse waves.

[0233] Optionally, an up-flow transverse wave travel time model can be selected based on the degree of seabed undulation at the receiver point.

[0234] Alternatively, when the seabed undulations are small, the uplifting transverse wave travel time model is as follows:

[0235] Among them, H cR V represents the water depth at which the reflection point is located after smoothing. It can be the seawater depth at the common center point after smoothing the low undulations of the seismic trace. ws This indicates the shallow transverse wave replacement velocity.

[0236] Alternatively, when there are significant seabed undulations, the uplifting shear wave travel time model is as follows:

[0237] Among them, H Rm V represents the water depth at which the geophone point is located after smoothing. It can be the seawater depth at the common midpoint of the smoothed surface at the geophone point location corresponding to the seismic trace. ws This indicates the shallow transverse wave replacement velocity.

[0238] S508. Based on the common imaging point gather, the second converted wave superposition velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa.

[0239] Optionally, S508 includes:

[0240] Based on the common imaging point gather, residual time difference analysis is performed using the eleventh model to correct the first converted wave superposition velocity and the first KPa under the dual reference plane, resulting in the corrected velocity and corrected KPa.

[0241] Determine whether the in-phase axis of the common imaging point convergence is in an ideal flattened and straightened state;

[0242] If the phase axis is not in the ideal flattening and straightening state, the pre-stack time migration model of the converted wave is adjusted by the corrected velocity, the corrected Kappa, and the sixteenth model until the phase axis of the obtained common imaging point gather is in the ideal flattening and straightening state.

[0243] If the image is in an ideal flattened and straightened state, the converted wave superposition velocity and KPa corresponding to the common imaging point gather under the dual reference plane are determined as the optimal velocity and the third KPa.

[0244] Alternatively, the sixteenth model is as follows:

[0245] in, Used to replace γ0 in the pre-stack time migration model of the converted wave. Replace γ in the pre-stack time migration model of the converted wave eff γ0 represents the vertical velocity ratio; This represents the vertical two-way travel time of the converted wave under dual reference planes, and replaces t in the pre-stack time migration model of the converted wave. c0 ; Indicates the travel time of transverse waves in the ocean layer; This represents the corrected velocity under dual reference planes and replaces V in the pre-stack time migration model of the converted wave. c2 V c2 Indicates the superposition velocity of the second converted wave; This represents the corrected Kappa under dual reference planes, replacing k in the pre-stack time migration model of the converted wave. eff ; Replace t in the pre-stack time migration model of the converted wave s0 .

[0246] Optionally, the pre-stack time migration model of the converted wave is adjusted using the corrected velocity, the corrected Kappa, and the sixteenth model to further obtain the V of the second iteration. p , η eff , t p0 and By using the transformed wave scattering model, based on V in the second iteration p , η eff , t p0 and Obtain the common imaging point gather for the second iteration; iterate multiple times until the in-phase axis in the obtained common imaging point gather is in an ideal flattened and straightened state, and determine the converted wave superposition velocity and KPa corresponding to the common imaging point gather under the dual reference plane at this time as the optimal velocity and the third KPa.

[0247] Furthermore, the effective velocity ratio is scanned to obtain the pre-stack time migration velocity model of the converted wave, which is used to obtain the pre-stack time migration imaging results of the converted wave. The pre-stack time migration velocity model includes the optimal velocity, the third kappa, the vertical velocity ratio, and the effective velocity ratio.

[0248] Optionally, the effective velocity ratio includes: providing a series of effective velocity ratio values; obtaining new pre-stack time migration parameters of the converted wave using a pre-stack time migration model based on the series of effective velocity ratio values; obtaining new common imaging point gathers and stacking profiles corresponding to each coefficient shift based on the new pre-stack time migration parameters; and selecting a new spatiotemporally variable effective velocity ratio by comparing the flattening degree of the new common imaging point gathers and the imaging focusing quality of the new stacking profiles.

[0249] Optionally, a series of effective velocity ratios are given, including: γ in the pre-stack time migration model of the converted wave obtained in the last iteration. eff Based on this, multiply by a series of percentage values ​​to obtain a series of effective speed ratio values. These percentage values ​​may be, for example, 110%, 100%, 90%, etc.

[0250] Optionally, selecting a new effective velocity ratio that varies with time and space can be either the effective velocity ratio obtained by multiplying the time-space variation coefficient by the effective velocity ratio of the original model, or it can be by directly selecting the γ corresponding to the new common imaging point gather and the stacked profile. eff .

[0251] Optionally, when obtaining the common imaging point gather after adjusting the pre-stack time migration model of the converted wave, the converted wave stacking velocity and KPa under the dual reference plane are obtained directly through the pre-stack time migration model of the converted wave, and the conversion formula of the converted wave stacking time migration velocity parameter under the dual reference plane is no longer used, that is, the seabed reference plane is no longer corrected through the twelfth model.

[0252] In the seismic data imaging processing method provided in the embodiment of Figure 5, common imaging point gathers are determined based on the second converted wave stacking velocity, the second KPa, the vertical velocity ratio, and the effective velocity ratio. Based on the common imaging point gathers, the second converted wave stacking velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa. The common imaging point gathers obtained through multiple iterations and dual reference plane correction can obtain more accurate optimal velocity and the third KPa, thereby improving the accuracy of migration imaging results.

[0253] Figure 6 illustrates an analysis flow for the initial velocity model of pre-stack time migration of converted waves provided in an embodiment of this application. The process involves acquiring converted wave seismic data, then smoothing and correcting the receiver points; performing stacking velocity analysis on the dual reference planes to obtain the first converted wave stacking velocity, the first KPa, and the first converted wave stacking profile; using the horizontal plane where the shot point is located as the reference plane, the first converted wave stacking velocity, the first KPa, and the first converted wave stacking profile are corrected using the shot point reference plane to obtain the second converted wave stacking velocity, the second KPa, and the second converted wave stacking profile under the shot point reference plane; introducing P-wave seismic data stacking velocity analysis, calculating the vertical velocity ratio and the effective velocity ratio, and obtaining the initial velocity model of pre-stack time migration of converted waves under the shot point reference plane (i.e., the second converted wave stacking velocity, the second KPa, the vertical velocity ratio, and the effective velocity ratio). The specific steps of the embodiment in Figure 6 are similar to those in steps S501-S506, and will not be repeated here.

[0254] Figure 7 illustrates a pre-stack time migration velocity analysis flowchart for converted waves provided in an embodiment of this application. Specifically, the initial pre-stack time migration velocity model of the converted waves shown in Figure 6 is obtained. Using this model, the pre-stack time migration velocity parameters of the converted waves at the shot point reference plane are obtained. Using the horizontal plane where the seabed is located as the reference plane, the first shear wave velocity, the first shear wave anisotropy parameter, and the first shear wave vertical travel time in the pre-stack time migration velocity parameters are corrected for the shot point reference plane, resulting in the second shear wave velocity, the second shear wave anisotropy parameter, and the second shear wave vertical travel time at the seabed reference plane. The pre-stack time migration velocity parameters of the converted waves are then updated to obtain... The pre-stack time migration velocity parameters of the converted wave under dual reference planes are obtained; based on the pre-stack time migration velocity parameters of the converted wave under dual reference planes, the first pre-stack time migration processing of the converted wave is performed to obtain the common imaging point gather; based on the velocity and corrected Kappa through the common imaging point gather, the pre-stack time migration model of the converted wave is updated, and the common imaging point gather is obtained again; when the in-phase axis in the common imaging point gather is flattened and straightened, the iteration ends, the effective velocity ratio is scanned, and the pre-stack time migration velocity model of the converted wave (optimal velocity, third Kappa, vertical velocity ratio, and effective velocity ratio) is obtained. The specific steps of the embodiment in Figure 7 are similar to the steps in S507-S508, and will not be repeated here.

[0255] Optionally, the pre-stack time migration model of the converted wave can be used to obtain the pre-stack time migration velocity parameters of the converted wave under dual reference planes, or it can be used to obtain the pre-stack time migration velocity parameters of the converted wave under the shot reference plane.

[0256] Figure 8 shows the effect of velocity analysis using a unified reference plane according to an embodiment of this application, and Figure 9 shows the effect of velocity analysis using a dual reference plane according to an embodiment of this application. A comparison of Figures 8 and 9 shows that the dual reference plane scheme provided in this embodiment can improve the velocity analysis effect.

[0257] Optionally, when both the vertical velocity ratio and the effective velocity ratio are equal to 1, the embodiments of this application can also be used to improve the accuracy of P-wave pre-stack time migration imaging results.

[0258] Based on the same technical concept, this application also provides a seismic data imaging processing apparatus. This seismic data imaging processing apparatus can achieve the functions of the aforementioned embodiments. The seismic data imaging processing apparatus provided in this application embodiment will be described below with reference to FIG10.

[0259] Figure 10 is a schematic diagram of the structure of the seismic data imaging processing apparatus provided in an embodiment of this application. As shown in Figure 10, the seismic data imaging processing apparatus 100 includes:

[0260] The acquisition module 1001 is used to acquire the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area.

[0261] The determination module 1002 is used to determine the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes by using the hyperbolic method based on the first P-wave seismic data of each receiver point.

[0262] The determination module 1002 is also used to determine the first converted wave stacking velocity, the first KPa and the first converted wave stacking profile under the dual reference plane by performing stacking velocity analysis processing based on the first converted wave seismic data of each receiver point.

[0263] The correction module 1003 is used to perform shot point reference plane correction on the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile, respectively, with the horizontal plane where the shot point is located as the reference plane, to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane.

[0264] The determination module 1002 is further configured to determine the parameters to be processed corresponding to the common conversion point based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second Kappa, and the second converted wave stacking profile. The parameters to be processed are used to obtain the converted wave pre-stack time migration imaging result.

[0265] It should be noted that the seismic data imaging processing apparatus 100 provided in this application embodiment can implement all the method steps implemented in the above method embodiment and can achieve the same technical effect. Here, the parts that are the same as those in the method embodiment and the beneficial effects will not be described in detail.

[0266] In one optional implementation, the acquisition module 1001 is specifically used for:

[0267] Acquire the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0268] Preprocessing is performed on the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points;

[0269] Depth correction is performed on each geophone point to obtain the time correction amount of the seismic trace for each geophone point.

[0270] Based on the time correction of the seismic traces of each receiver point, the P-wave seismic data of all seismic traces of each receiver point after preprocessing are corrected to obtain the first P-wave seismic data of each receiver point.

[0271] Based on the time correction of the seismic traces at each receiver point, the converted wave seismic data of all seismic traces at each receiver point after preprocessing are corrected to obtain the first converted wave seismic data of each receiver point.

[0272] In one optional implementation, the acquisition module 1001 is specifically used for:

[0273] The second P-wave seismic data from each receiver point are subjected to P-wave seismic data preprocessing. The P-wave seismic data preprocessing process includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, and amplitude recovery.

[0274] The preprocessed P-wave seismic data is sorted into common center point gathers, which include P-wave seismic data from all seismic traces of each receiver point after preprocessing.

[0275] The second converted wave seismic data of each receiver point are preprocessed using converted wave seismic data. The preprocessing procedure includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, amplitude recovery, and marking of pre-set common conversion points in the trace head.

[0276] The preprocessed converted wave seismic data is sorted into common conversion point gathers, which include converted wave seismic data from all seismic traces of each receiver point after preprocessing.

[0277] In one optional implementation, the acquisition module 1001 is specifically used for:

[0278] Determine the location of the common conversion point;

[0279] Based on the location of the common switching point, the identifier of the common switching point is preset in the track header.

[0280] In one optional implementation, the acquisition module 1001 is specifically used for:

[0281] Obtain the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point;

[0282] The initial horizontal distance is determined based on the horizontal propagation distance of the water layer, the P-wave to S-wave velocity ratio, and the distance between the shot point and the receiver point.

[0283] Based on the initial horizontal distance, the nth iteration is performed to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration, where n is an integer greater than or equal to 1;

[0284] Determine whether the horizontal distance in the nth iteration satisfies the iteration condition;

[0285] If the horizontal distance in the nth iteration does not meet the iteration condition, the horizontal distance between the common conversion point and the shot point is determined based on the horizontal distance in the nth iteration.

[0286] The position of the common conversion point is obtained by measuring the horizontal distance between the common conversion point and the shot point.

[0287] In one optional implementation, the first P-wave superposition velocity and the second P-wave superposition velocity satisfy the following first model:

[0288] Among them, t pp0 V represents the vertical two-way travel time of the P-wave below the reference plane of the shot point. P2 This represents the superposition velocity of the second longitudinal wave. This represents the vertical two-way travel time of the P-wave under the dual reference planes. This represents the superposition velocity of the first longitudinal wave. Indicates the longitudinal wave velocity of the sea layer. This indicates the travel time of longitudinal waves in the ocean layer.

[0289] In one optional implementation, the first converted wave superposition velocity and the second converted wave superposition velocity satisfy the following second model:

[0290] Among them, t c0 V represents the vertical two-way travel time of the converted wave under the reference plane of the shot point. c2 This indicates the superposition velocity of the second converted wave. This represents the vertical two-way travel time of the converted wave under the dual reference planes. This represents the superposition velocity of the first converted wave. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

[0291] In one alternative implementation, the first Kappa and the second Kappa satisfy the following third model:

[0292] Where, k eff This indicates the second Kappa. This indicates the first Kappa.

[0293] In one optional implementation, the parameters to be processed include the vertical velocity ratio, effective velocity ratio, optimal velocity, and third kappa corresponding to the common conversion point;

[0294] The determining module 1002 is specifically used for:

[0295] The vertical velocity ratio is determined based on the second longitudinal wave superposition profile and the second converted wave superposition profile;

[0296] The effective velocity ratio is determined based on the second longitudinal wave superposition velocity and the second converted wave superposition velocity;

[0297] The common imaging point gather is determined based on the second converted wave superposition velocity, the second Kpa, the vertical velocity ratio, and the effective velocity ratio;

[0298] Based on the common imaging point gather, the second converted wave superposition velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa.

[0299] It should be noted that the seismic data imaging processing apparatus 100 provided in this application embodiment can implement all the method steps implemented in the above method embodiment and can achieve the same technical effect. Here, the parts that are the same as those in the method embodiment and the beneficial effects will not be described in detail.

[0300] It should be understood that the aforementioned seismic data imaging processing device 100 is embodied in the form of functional modules. The term "module" here may refer to application-specific integrated circuits (ASICs), electronic circuits, processors (e.g., shared processors, proprietary processors, or group processors) and memories for executing one or more software or firmware programs, integrated logic circuits, and / or other suitable components that support the described functions.

[0301] Figure 11 is a schematic diagram of the structure of an electronic device provided in an embodiment of this application. As shown in Figure 11, the electronic device 110 may include a memory 1101 and a processor 1102. Exemplarily, each part of the memory 1101 and the processor 1102 is interconnected via a bus 1103.

[0302] Memory 1101 is used to store program instructions.

[0303] The processor 1102 is used to execute the program instructions stored in the memory to cause the electronic device to perform the above-described method.

[0304] All or part of the steps of each of the above method embodiments can be implemented by hardware associated with program instructions. The aforementioned program can be stored in a readable memory. When the program is executed, it performs the steps of each of the above method embodiments; and the aforementioned memory (storage medium) includes: read-only memory (ROM), RAM, flash memory, hard disk, solid-state drive, magnetic tape, floppy disk, optical disk, and any combination thereof.

[0305] This application provides a computer-readable storage medium storing computer-executable instructions that, when executed by a processor, are used to implement the method described in the above-described method embodiments.

[0306] This application also provides a computer program product, including a computer program that, when executed by a processor, can implement the methods shown in the above-described method embodiments.

[0307] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means that implement the functions specified in one or more flowcharts and / or one or more block diagrams.

[0308] These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer-implemented process, such that the instructions, which execute on the computer or other programmable apparatus, provide steps for implementing the functions specified in one or more flowcharts and / or one or more block diagrams.

[0309] Those skilled in the art can make various modifications and variations to the embodiments of this application without departing from the spirit and scope of this application. Therefore, if these modifications and variations to the embodiments of this application fall within the scope of the claims of this application and their equivalents, this application also intends to include these modifications and variations.

[0310] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numbers in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with this application. Rather, they are merely examples of apparatuses and methods consistent with some aspects of this application as detailed in the appended claims.

Claims

1. A seismic data imaging processing method, characterized in that, include: Acquire the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area; Based on the first P-wave seismic data from each receiver point, the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes are determined using the hyperbolic method. Based on the first converted wave seismic data from each receiver point, the first converted wave stacking velocity, first KPa, and first converted wave stacking profile under the dual reference planes are determined through stacking velocity analysis. Using the horizontal plane where the shot point is located as the reference plane, the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile are corrected by the shot point reference plane to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane. Based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second Kappa, and the second converted wave stacking profile, the parameters to be processed corresponding to the common conversion point are determined. The parameters to be processed are used to obtain the converted wave pre-stack time migration imaging results.

2. The method according to claim 1, characterized in that, The acquisition of the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area includes: Acquire the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points; Preprocessing is performed on the second P-wave seismic data and the second converted wave seismic data at each of the aforementioned receiver points; Depth correction is performed on each geophone point to obtain the time correction amount of the seismic trace for each geophone point. Based on the time correction of the seismic traces of each receiver point, the P-wave seismic data of all seismic traces of each receiver point after preprocessing are corrected to obtain the first P-wave seismic data of each receiver point. Based on the time correction of the seismic traces at each receiver point, the converted wave seismic data of all seismic traces at each receiver point after preprocessing are corrected to obtain the first converted wave seismic data of each receiver point.

3. The method according to claim 2, characterized in that, The preprocessing of the second P-wave seismic data and the second converted wave seismic data at each receiver point includes: The second P-wave seismic data from each receiver point are subjected to P-wave seismic data preprocessing. The P-wave seismic data preprocessing process includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, and amplitude recovery. The preprocessed P-wave seismic data is sorted into common center point gathers, which include P-wave seismic data from all seismic traces of each receiver point after preprocessing. The second converted wave seismic data of each receiver point are preprocessed using converted wave seismic data. The preprocessing procedure includes one or more of the following: loading the observation system, static correction, wavefield separation, pre-stack denoising, amplitude recovery, and marking of pre-set common conversion points in the trace head. The preprocessed converted wave seismic data is sorted into common conversion point gathers, which include converted wave seismic data from all seismic traces of each receiver point after preprocessing.

4. The method according to claim 3, characterized in that, The identifiers of the pre-set common conversion points in the track header include: Determine the location of the common conversion point; Based on the location of the common switching point, the identifier of the common switching point is preset in the track header.

5. The method according to claim 4, characterized in that, Determining the location of the common conversion point includes: Obtain the horizontal propagation distance of the water layer, the ratio of P-wave to S-wave velocity, and the distance between the shot point and the receiver point; The initial horizontal distance is determined based on the horizontal propagation distance of the water layer, the P-wave to S-wave velocity ratio, and the distance between the shot point and the receiver point. Based on the initial horizontal distance, the nth iteration is performed to determine the horizontal distance of the nth iteration, the incident angle of the water layer propagating underground in the nth iteration, and the horizontal propagation distance of the water layer in the nth iteration, where n is an integer greater than or equal to 1; Determine whether the horizontal distance in the nth iteration satisfies the iteration condition; If the horizontal distance in the nth iteration does not meet the iteration condition, the horizontal distance between the common conversion point and the shot point is determined based on the horizontal distance in the nth iteration. The position of the common conversion point is obtained by measuring the horizontal distance between the common conversion point and the shot point.

6. The method according to claim 1 or 2, characterized in that, The first longitudinal wave superposition velocity and the second longitudinal wave superposition velocity satisfy the following first model: Among them, t pp0 V represents the vertical two-way travel time of the P-wave below the reference plane of the shot point. P2 This represents the superposition velocity of the second longitudinal wave. This represents the vertical two-way travel time of the P-wave under the dual reference planes. This represents the superposition velocity of the first longitudinal wave. Indicates the longitudinal wave velocity of the sea layer. This indicates the travel time of longitudinal waves in the ocean layer.

7. The method according to claim 1 or 2, characterized in that, The superposition velocities of the first and second converted waves satisfy the following second model: Among them, t c0 V represents the vertical two-way travel time of the converted wave below the reference plane of the shot point. c2 This indicates the superposition velocity of the second converted wave. This represents the vertical two-way travel time of the converted wave under the dual reference planes. This represents the superposition velocity of the first converted wave. Indicates the transverse wave velocity of the sea layer. This indicates the travel time of transverse waves in the ocean layer.

8. The method according to claim 7, characterized in that, The first Kappa and the second Kappa satisfy the following third model: Where, k eff This indicates the second Kappa. This indicates the first Kappa.

9. The method according to claim 1 or 2, characterized in that, The parameters to be processed include the vertical velocity ratio, effective velocity ratio, optimal velocity, and third kappa corresponding to the common conversion point; The step of determining the parameters to be processed corresponding to the common conversion point based on the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second Kappa, and the second converted wave superposition profile includes: The vertical velocity ratio is determined based on the second longitudinal wave superposition profile and the second converted wave superposition profile; The effective velocity ratio is determined based on the second longitudinal wave superposition velocity and the second converted wave superposition velocity; The common imaging point gather is determined based on the second converted wave superposition velocity, the second Kpa, the vertical velocity ratio, and the effective velocity ratio; Based on the common imaging point gather, the second converted wave superposition velocity and the second KPa are corrected to obtain the optimal velocity and the third KPa.

10. A seismic data imaging processing device, characterized in that, include: The acquisition module is used to acquire the first P-wave seismic data and the first converted wave seismic data of each receiver point in the target work area; The determination module is used to determine the first P-wave stacking velocity and the first P-wave stacking profile under the dual reference planes based on the first P-wave seismic data of each receiver point using the hyperbolic method. The determining module is further configured to determine the first converted wave stacking velocity, the first KPa, and the first converted wave stacking profile under the dual reference plane by performing stacking velocity analysis processing based on the first converted wave seismic data of each receiver point. The correction module is used to perform shot point reference plane correction on the first P-wave superposition velocity, the first P-wave superposition profile, the first converted wave superposition velocity, the first KPa and the first converted wave superposition profile, respectively, with the horizontal plane where the shot point is located as the reference plane, to obtain the second P-wave superposition velocity, the second P-wave superposition profile, the second converted wave superposition velocity, the second KPa and the second converted wave superposition profile under the shot point reference plane. The determining module is further configured to determine the parameters to be processed corresponding to the common conversion point based on the second longitudinal wave stacking velocity, the second longitudinal wave stacking profile, the second converted wave stacking velocity, the second Kappa, and the second converted wave stacking profile. The parameters to be processed are used to obtain the converted wave pre-stack time-migration imaging result.

11. An electronic device, characterized in that, include: Memory, processor; The memory stores computer-executed instructions; The processor executes computer execution instructions stored in the memory, causing the processor to perform the method as described in any one of claims 1-9.

12. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores computer-executable instructions, which, when executed by a processor, are used to implement the method as described in any one of claims 1-9.

13. A computer program product, characterized in that, Includes a computer program that, when executed by a processor, implements the method described in any one of claims 1-9.

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