CN111983682B - Seismic profile imaging method and device and electronic equipment - Google Patents

Seismic profile imaging method and device and electronic equipment Download PDF

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CN111983682B
CN111983682B CN202010907288.6A CN202010907288A CN111983682B CN 111983682 B CN111983682 B CN 111983682B CN 202010907288 A CN202010907288 A CN 202010907288A CN 111983682 B CN111983682 B CN 111983682B
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offset
aperture
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CN111983682A (en
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刘礼农
张江杰
李正伟
许宏桥
高红伟
张剑锋
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Institute of Geology and Geophysics of CAS
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Abstract

The application provides a seismic profile imaging method, a seismic profile imaging device and an electronic device, wherein the method comprises the following steps: processing the initial common offset prestack data set to obtain an inclination gather; obtaining a first migration aperture set of each imaging point of the imaging space according to the dip angle gather; obtaining a constant Q scanning gather according to the initial common offset prestack data set; generating an equivalent Q value model according to the constant Q scanning gather; correcting the first offset aperture set of each imaging point of the imaging space based on the equivalent Q value model to obtain a second offset aperture set of each imaging point of the imaging space; and performing high-precision attenuation imaging processing on the initial common offset prestack data set based on a preset offset velocity model, an equivalent Q value model and a second offset aperture set to obtain an offset profile and a prestack gather. The problem of low resolution of seismic data can be solved by the method in the embodiment.

Description

Seismic profile imaging method and device and electronic equipment
Technical Field
The application relates to the technical field of seismic data analysis, in particular to a seismic profile imaging method, a seismic profile imaging device and electronic equipment.
Background
In seismic exploration, it is a research goal of geophysicists to improve the resolving power of seismic data on underground structures. But the seismic data has a reduced ability to resolve subsurface formations due to geological internal uncertainties. The main factor causing the reduction of the seismic data resolution is the absorption of seismic waves by the earth medium.
Disclosure of Invention
In view of the above, an object of the embodiments of the present application is to provide a seismic profile imaging method, apparatus and electronic device. The problem of low seismic data resolution can be solved.
In a first aspect, an embodiment of the present application provides a seismic profiling method, including:
processing the initial common offset prestack data set to obtain an inclination gather;
obtaining a first migration aperture set of each imaging point of an imaging space according to the dip angle gather;
obtaining a constant Q scanning gather according to the initial common offset prestack data set;
generating an equivalent Q value model according to the constant Q scanning gather;
correcting the first offset aperture set of each imaging point of the imaging space based on the equivalent Q value model to obtain a second offset aperture set of each imaging point of the imaging space;
and performing high-precision attenuation imaging processing on the initial common offset prestack data set based on a preset offset velocity model, the equivalent Q value model and the second offset aperture set to obtain an offset profile and a prestack gather.
In an alternative embodiment, the processing the initial common-offset prestack data set to obtain the dip gather includes:
processing according to the initial common offset prestack data set to obtain an inclination gather in the main measuring line direction;
and processing according to the initial common offset prestack data set to obtain an inclination gather in the direction of the crossline.
In an alternative embodiment, the dip gather for the inline direction is represented as:
Figure BDA0002661621720000021
the dip gather in the crossline direction is represented as:
Figure BDA0002661621720000022
wherein the content of the first and second substances,
Figure BDA0002661621720000023
the dip gathers representing the inline direction,
Figure BDA0002661621720000024
dip gathers, T, representing crossline direction02T tableShowing vertical two-way travel at imaging point (x, y, T), f'mRepresenting the semi-conductor number of seismic traces, N representing the total number of traces of said initial common-offset prestack dataset as input, (x)s,ys) Representing the shot point coordinate corresponding to the mth seismic channel, (x)g,yg) Representing the coordinates of the detection point, τ, corresponding to the mth seismic tracesRepresenting the travel time, τ, from shot to image pointgRepresenting travel times from a detection point to an imaging point, the inclination angle associated with said travel times
Figure BDA0002661621720000025
And
Figure BDA0002661621720000026
expressed as:
Figure BDA0002661621720000027
Figure BDA0002661621720000028
wherein, VrmsRepresents the root mean square velocity at the imaging point (x, y, T).
In the seismic profile imaging method in the embodiment of the application, the pre-stack data is analyzed to obtain the dip angle gather in the main measuring line direction and the cross measuring line direction, effective signals and noise can be well distinguished according to the dip angle gather, and the first migration aperture set of each imaging point in the imaging space is obtained, so that the migration noise suppression problem in high-precision attenuation imaging is facilitated to be solved.
In an alternative embodiment, the deriving a constant Q scan gather from the initial common-offset prestack data set comprises:
constructing a constant Q model according to a preset equivalent Q value sequence;
according to the constant Q model, performing inverse Q filtering processing on the initial common offset pre-stack data set to obtain a second common offset pre-stack data set;
and based on the seismic wave propagation group velocity after the medium absorption, processing the second common offset prestack data set by applying a conventional prestack time migration process to obtain a constant Q scanning gather.
In the seismic section imaging method in the embodiment of the application, the initial common offset prestack data set is subjected to inverse Q filtering processing, and the influence of medium absorption on the seismic wave propagation group velocity is considered in travel time calculation in conventional prestack time migration processing, so that the obtained constant Q scanning gather can better show the influence of different Q value parameters on the amplitude, phase and travel time in a seismic imaging section, and the seismic data resolving capability corresponding to different Q values is facilitated to be investigated.
In an alternative embodiment, the generating an equivalent Q value model from the constant Q scan gather includes:
and based on the constant Q scanning gather, determining an equivalent Q value at the analysis time window according to the resolution ratios of the offset profiles corresponding to different equivalent Q values in the analysis time window so as to establish an equivalent Q value model.
In the seismic section imaging method in the embodiment of the application, the equivalent Q value is obtained according to the resolution ratios of the migration sections corresponding to different equivalent Q values in the analysis time window, so that the constructed equivalent Q value model can be more accurate.
In an alternative embodiment, the second set of offset apertures is represented as:
Figure BDA0002661621720000031
the first set of offset apertures is represented as:
Figure BDA0002661621720000041
wherein the second set of offset apertures ApertureQThe correspondence with the first set of offset apertures Aperture is expressed as:
Figure BDA0002661621720000042
Figure BDA0002661621720000043
Figure BDA0002661621720000044
Figure BDA0002661621720000045
Figure BDA0002661621720000046
wherein (x, y, T) represents coordinates of an imaging point,
Figure BDA0002661621720000047
indicating that the inline direction is offset from the left boundary of the aperture,
Figure BDA0002661621720000048
indicating the right boundary of the inline direction offset aperture,
Figure BDA0002661621720000049
indicating that the crossline direction is offset from the left boundary of the aperture,
Figure BDA00026616217200000410
representing the right boundary of the crossline direction-shifted aperture, f representing the dominant frequency of the initial common-offset prestack dataset, fQRepresenting the main frequency of the pre-stack data with the preset common offset distance after the resolution ratio is improved; qeffRepresenting the value of the equivalent Q value model at the imaging point,
Figure BDA00026616217200000411
indicating the left boundary of the corrected inline direction shift aperture,
Figure BDA00026616217200000412
a right boundary representing the corrected inline direction offset aperture;
Figure BDA00026616217200000413
indicating the left boundary of the corrected crossline direction shift aperture,
Figure BDA00026616217200000414
indicating the corrected crossline direction shifted right boundary of the aperture.
In the seismic section imaging method in the embodiment of the application, the migration aperture with the changed sub-azimuth angle is introduced, so that a certain signal-to-noise ratio level can be maintained while the sub-azimuth high-resolution seismic section and the post-migration pre-stack gather are output.
In an optional implementation manner, based on the preset migration velocity model, the equivalent Q-value model, and the second migration aperture set, the initial common-offset pre-stack data set is subjected to high-precision attenuation imaging processing to obtain a migration profile and a pre-stack trace set, and the migration profile and the pre-stack trace set are implemented by the following formulas:
Figure BDA0002661621720000051
wherein (x, y, T) represents coordinates of an imaging point, h represents offset distance, theta represents azimuth angle, theta belongs to U, U represents an azimuth angle set preset based on the azimuth anisotropy property of the target work area, and U is {0,90, theta1,θ2,θ3,...,θnAnd (x, y, T, theta, h) represents the obtained pre-stack gather after the deviation of the sub-azimuth angle, wherein the seismic pre-stack gather corresponding to different h is superposed to represent a high-resolution deviation profile I of the sub-azimuth angleS(x, y, T, θ), N represents the initial co-offset prestack data set, the weight function
Figure BDA0002661621720000052
Denotes the offset aperture as a function of azimuth, d ζ denotes the attenuation band length,ζθthe method for calculating the dip angle of the mth pre-stack seismic channel in the azimuth theta direction includes the following steps:
Figure BDA0002661621720000053
Figure BDA0002661621720000054
indicating the left and right boundaries of the offset aperture in the azimuth theta direction,
Figure BDA0002661621720000055
is set by the second offset aperture
Figure BDA0002661621720000056
The element(s) of (a) is calculated as:
Figure BDA0002661621720000057
Figure BDA0002661621720000058
weight function
Figure BDA0002661621720000061
The expression of (a) is:
Figure BDA0002661621720000062
wherein ω represents the initial co-offset pre-stack data angular frequency of the input, ω0Representing the input initial common offset pre-stack data main frequency, F (omega) representing the m channel pre-stack seismic channel data to be transformed into a frequency domain through Fourier transform processing, j representing an imaginary unit, QeffRepresenting equivalent Q-value model at imaging point (x, y, T)The value of (a) is selected,
Figure BDA0002661621720000063
representing the travel time from shot to imaging point taking into account the effect of medium absorption on the group velocity of seismic wave propagation,
Figure BDA0002661621720000064
the travel time from the imaging point to the geophone point, which takes into account the effects of medium absorption on the group velocity of seismic wave propagation, is expressed as:
Figure BDA0002661621720000065
in the seismic profile imaging method in the embodiment of the application, based on a preset migration velocity model, an equivalent Q value model and a second migration aperture set, high-precision attenuation imaging processing is performed on an initial common-migration-distance pre-stack data set to obtain a migration profile and a pre-stack gather, so that high-frequency component attenuation of a compensation medium can be realized, frequency dispersion of the medium is corrected, and meanwhile, seismic wave propagation time errors caused by the absorption effect of the medium need to be corrected, so that the determined migration profile can accurately represent geological conditions.
In a second aspect, an embodiment of the present application further provides a seismic profiling imaging apparatus, including:
the processing module is used for processing the initial common offset prestack data set to obtain an inclination angle gather;
the first obtaining module is used for obtaining a first offset aperture set of each imaging point of the imaging space according to the dip angle gather;
a second obtaining module, configured to obtain a constant Q scan gather according to the initial common offset prestack data set;
the generating module is used for generating an equivalent Q value model according to the constant Q scanning gather;
a third obtaining module, configured to correct the first offset aperture set of each imaging point in the imaging space based on the equivalent Q-value model, so as to obtain a second offset aperture set of each imaging point in the imaging space;
and the fourth obtaining module is used for carrying out high-precision attenuation imaging processing on the initial common-offset prestack data set based on a preset offset velocity model, the equivalent Q value model and the second offset aperture set to obtain an offset profile and a prestack gather.
In a third aspect, an embodiment of the present application further provides an electronic device, including: a processor, a memory storing machine readable instructions executable by the processor which when executed by the electronic device perform the steps of the seismic profiling method described above.
In a fourth aspect, the present application further provides a computer-readable storage medium, on which a computer program is stored, where the computer program is executed by a processor to perform the steps of the seismic section imaging method.
According to the seismic section imaging method and device and the electronic equipment, the migration section and the prestack gather are obtained based on the preset migration velocity model, the equivalent Q value model and the second migration aperture set, migration noise can be suppressed, and migration calculation efficiency is improved. And the high-resolution seismic profile and the prestack gather can be output in azimuth.
In order to make the aforementioned objects, features and advantages of the present application more comprehensible, embodiments accompanied with figures are described in detail below.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present application, the drawings that are required to be used in the embodiments will be briefly described below, it should be understood that the following drawings only illustrate some embodiments of the present application and therefore should not be considered as limiting the scope, and for those skilled in the art, other related drawings can be obtained from the drawings without inventive effort.
FIG. 1 is a schematic cross-sectional view of a migration obtained using a conventional prestack time migration technique.
FIG. 2 is a schematic diagram of CRP gathers obtained using conventional prestack time migration techniques.
FIG. 3 is a schematic cross-sectional view of a shift obtained using conventional attenuation imaging techniques during the shift process.
FIG. 4 is a schematic representation of CRP gathers obtained using conventional attenuation imaging techniques.
Fig. 5 is a block diagram of an electronic device according to an embodiment of the present application.
Fig. 6 is a flowchart of a seismic profile imaging method according to an embodiment of the present application.
FIG. 7 is a schematic diagram of a layer velocity model used in generating a common-offset prestack data set according to an embodiment of the present application.
FIG. 8 is a diagram of a layer Q model used in the generation of a common-offset prestack data set in the practice of the present application.
FIG. 9 is a schematic diagram of a vertical profile of the predetermined offset velocity model at a location.
FIG. 10 is a diagram of a vertical profile of the equivalent Q model at a location.
Fig. 11 is a schematic diagram of an offset section obtained using the seismic section imaging method in the present embodiment.
Fig. 12 is a schematic diagram of a CRP gather obtained using the seismic profiling method in this example.
FIG. 13 is a schematic view of a sub-azimuth CRP gather obtained using the seismic profile imaging method of this embodiment.
Fig. 14 is a functional block diagram of a seismic section imaging device according to an embodiment of the present disclosure.
Detailed Description
The technical solution in the embodiments of the present application will be described below with reference to the drawings in the embodiments of the present application.
It should be noted that: like reference numbers and letters refer to like items in the following figures, and thus, once an item is defined in one figure, it need not be further defined and explained in subsequent figures. Meanwhile, in the description of the present application, the terms "first", "second", and the like are used only for distinguishing the description, and are not to be construed as indicating or implying relative importance.
In seismic exploration, it is a goal of geophysicists to improve the ability of seismic data to resolve subsurface formations. Research shows that the main factor causing the reduction of the seismic data resolving power is the absorption of seismic waves by the earth medium. Because the earth medium is not an ideal elastomer, the vibration of the mass point of the medium in the propagation of the seismic wave can cause part of the energy of the wave to be converted into heat energy due to the friction effect, and the viscous absorption effect of the medium is obtained. For identifying hydrocarbon reservoirs by seismic migration imaging, the absorption impact of the earth's media on seismic waves is manifested in three ways:
firstly, the high-frequency component of the migration result is attenuated, and the attenuation degree of the amplitude is different along with the change of the frequency of the seismic wave, because the vibration period of the mass point of the high-frequency component seismic wave is short and the speed is high when the high-frequency component seismic wave is transmitted, the proportion of the high-frequency component seismic wave converted into heat energy is high, and the higher the frequency of the component seismic wave is, the stronger the attenuation is;
secondly, due to the reasons, the viscosity of the medium has different influences on the propagation velocity of seismic waves with different frequency components, so that the dispersion of seismic wavelets is caused, and the phase of a seismic event is distorted on an offset section;
and thirdly, the absorption also causes the group velocity of seismic wave propagation to become small, which is shown in the seismic migration imaging element, namely, the propagation travel time of the seismic wave becomes large.
Although in the conventional migration, the influence of the medium absorption effect is included in the received data itself, so that the group velocity error is indirectly considered in the velocity modeling process, if the influence of the medium absorption factor on the seismic wave propagation velocity is not clear, a large error is finally generated when the prestack time migration result is matched with the logging information. Therefore, to eliminate the effect of medium absorption on seismic wave propagation, one of the three factors is not necessary. That is, not only the attenuation of the high frequency component of the medium along the propagation path of the seismic wave during the seismic prestack imaging process needs to be compensated and the frequency dispersion thereof needs to be corrected, but also the seismic wave propagation time error caused by the absorption effect of the medium needs to be corrected.
At present, some technical solutions for improving the seismic imaging resolution exist, such as unsteady deconvolution, various kinds of widened band techniques based on statistical assumptions, well logging data, inverse Q filtering, and the like. The inventor of the application researches the technical schemes, and finds that unsteady deconvolution is a resolution improving method developed aiming at seismic resolution reduction caused by viscous absorption, but unsteady deconvolution has more difficulty in estimating unsteady wavelets of space variation, and the method generally cannot realize dispersion correction at the same time. The resolution of the seismic method is improved by introducing information except seismic records in various frequency extension technologies, and the use premise is that the wavelets of the seismic records are time-invariant, so even if the technologies are applied, the absorption attenuation of seismic waves must be compensated in the preprocessing, and the consistency of the seismic wavelets is realized. The inverse Q filtering method starts from viscous absorption for compensating seismic wave amplitude, but neglects the influence of a seismic wave propagation path on amplitude attenuation in terms of inverse Q filtering for prestack seismic data, so that a large error exists when the method is applied to a non-uniform Q value model. The inverse Q filtering of the post-stack data can process the situation of the layered Q value model, but because seismic traces with different offset distances or incidence angles are stacked in the stacking process, the amplitude values with different degrees of absorption attenuation are processed in the same way by applying the inverse Q filtering method, so that the elimination of the absorption attenuation is limited.
Further research shows that if absorption compensation of a medium and seismic prestack time offset are combined together, the attenuated high-frequency components of seismic waves are recovered along a seismic wave propagation path in the offset imaging process, and the resolution of a seismic offset imaging section can be improved. If only the absorption effect of the medium on the high-frequency attenuation and phase correction of the seismic waves are considered, travel time calculation in the process of realizing the migration algorithm follows the seismic wave travel time calculation algorithm of the conventional prestack time migration method; furthermore, the induced offset aperture parameter field related to the propagation of the seismic wave, which suppresses the compensation noise and improves the calculation efficiency, is only determined based on the dip trace set generated by the conventional prestack time offset method. That is, the two ideas ignore the influence of the absorption of the medium on the group velocity of the seismic wave propagation, so that an error exists when the depth of the underground target layer is positioned by the result data processed by the technology. In addition, in natural gas hydrate exploration, the existence of the hydrate enables the underground medium to show the characteristics of azimuth anisotropy while the absorption attenuation characteristics are remarkably changed; also, in hydrocarbon exploration development, identifying fractures is the primary means of exploration for fractured reservoirs, and the presence of fractures also tends to cause the subsurface medium to exhibit azimuthal anisotropy, and the presence of fluids or gases in fractures also causes large changes in the medium absorption characteristics. For the exploration, development and monitoring of the two important natural gas hydrate reservoirs and fracture-type oil and gas reservoirs, azimuth-based high-resolution seismic profiles and prestack gathers are needed as basic data, and although the two technologies developed at present can provide high-resolution prestack time migration profiles, the two technologies developed at present cannot provide azimuth-specific seismic prestack gathers for lithological inversion and fluid identification.
As shown in fig. 1, fig. 1 shows a schematic diagram of a migration profile obtained using a conventional pre-stack time migration technique. As shown in fig. 2, fig. 2 is a schematic diagram of a Common Reflection Point (CRP) gather obtained by using a conventional prestack time migration technique.
In the example shown in fig. 1 and 2, any point in the illustration is a point in a two-dimensional space, where the abscissa represents distance and the unit may be meter (m); the ordinate represents time, which may be in seconds(s).
Illustratively, the example shown in fig. 2 is the CRP gather at X-4 km in fig. 1. Where X represents the abscissa in two-dimensional space.
As shown in fig. 3, a schematic diagram of a migration profile obtained using conventional attenuation imaging techniques during migration is shown. As shown in FIG. 4, FIG. 4 is a schematic representation of a CRP gather obtained using conventional attenuation imaging techniques.
Illustratively, the example shown in fig. 4 is the CRP gather at x-4 km in fig. 3.
In conclusion, the high-resolution imaging technology for research cannot meet the requirements of high-precision fine carving on underground mineral reservoirs and oil and gas reservoirs in different directions and fully considering medium absorption influence. Based on this, the inventors of the present application provide a seismic profiling method, apparatus, electronic device and computer readable storage medium, which can further improve upon the above-mentioned deficiencies. This is described below by means of several examples.
Example one
To facilitate understanding of the present embodiment, the electronic device for performing a seismic profiling method disclosed in the embodiments of the present application will be described in detail first.
Fig. 5 is a block diagram of an electronic device. The electronic device 100 may include a memory 111, a memory controller 112, a processor 113, a peripheral interface 114, an input-output unit 115, and a display unit 116. It will be understood by those skilled in the art that the structure shown in fig. 5 is merely an illustration and is not intended to limit the structure of the electronic device 100. For example, electronic device 100 may also include more or fewer components than shown in FIG. 5, or have a different configuration than shown in FIG. 5.
The above-mentioned elements of the memory 111, the memory controller 112, the processor 113, the peripheral interface 114, the input/output unit 115 and the display unit 116 are electrically connected to each other directly or indirectly, so as to implement data transmission or interaction. For example, the components may be electrically connected to each other via one or more communication buses or signal lines. The processor 113 is used to execute the executable modules stored in the memory.
The Memory 111 may be, but is not limited to, a Random Access Memory (RAM), a Read Only Memory (ROM), a Programmable Read-Only Memory (PROM), an Erasable Read-Only Memory (EPROM), an electrically Erasable Read-Only Memory (EEPROM), and the like. The memory 111 is configured to store a program, and the processor 113 executes the program after receiving an execution instruction, and the method executed by the electronic device 100 defined by the process disclosed in any embodiment of the present application may be applied to the processor 113, or implemented by the processor 113.
The processor 113 may be an integrated circuit chip having signal processing capability. The Processor 113 may be a general-purpose Processor, and includes a Central Processing Unit (CPU), a Network Processor (NP), and the like; the Integrated Circuit may also be a Digital Signal Processor (DSP), an Application Specific Integrated Circuit (ASIC), a Field Programmable Gate Array (FPGA) or other programmable logic device, a discrete gate or transistor logic device, or a discrete hardware component. The various methods, steps, and logic blocks disclosed in the embodiments of the present application may be implemented or performed. A general purpose processor may be a microprocessor or the processor may be any conventional processor or the like.
The peripheral interface 114 couples various input/output devices to the processor 113 and memory 111. In some embodiments, the peripheral interface 114, the processor 113, and the memory controller 112 may be implemented in a single chip. In other examples, they may be implemented separately from the individual chips.
The input/output unit 115 is used to provide input data to the user. The input/output unit 115 may be, but is not limited to, a mouse, a keyboard, and the like.
The display unit 116 provides an interactive interface (e.g., a user operation interface) between the electronic device 100 and the user or is used for displaying image data to the user for reference. In this embodiment, the display unit may be a liquid crystal display or a touch display. In the case of a touch display, the display can be a capacitive touch screen or a resistive touch screen, which supports single-point and multi-point touch operations. The support of single-point and multi-point touch operations means that the touch display can sense touch operations simultaneously generated from one or more positions on the touch display, and the sensed touch operations are sent to the processor for calculation and processing.
For example, the display unit 116 may display the offset profile determined based on the initial co-offset pre-stack data.
The electronic device 100 in this embodiment may be configured to perform each step in each method provided in this embodiment. The implementation of the seismic profile imaging method is described in detail below by way of several embodiments.
Example two
Please refer to fig. 6, which is a flowchart of a seismic profile imaging method according to an embodiment of the present application. The specific flow shown in fig. 6 will be described in detail below.
Step 201, the initial common offset prestack data set is processed to obtain a dip gather.
Optionally, the initial common-offset prestack data may be determined by a seismic wave forward modeling method according to a preset interval velocity model and a preset interval Q value model.
Illustratively, the common offset prestack data set described above may be obtained by the layer velocity model shown in fig. 7 and the layer Q value model shown in fig. 8.
As illustrated in fig. 7, where different depths correspond to different velocities. Illustratively, the speed is determined to be 3000m/s in the range of depths from 3km to 4km, 2500m/s in the range of depths from 1km to 3km, and 2000m/s in the range of depths from 0km to 1 km.
As shown in fig. 8, where different layer Q values correspond at different depths. Illustratively, the layer Q value is determined to be 60 in the range of depths of 3km to 4km, 40 in the range of depths of 1km to 3km, and 20 in the range of depths of 0km to 1 km.
Alternatively, the dip gathers described above may include dip gathers in the inline direction and dip gathers in the crossline direction.
Illustratively, the dip gather for the inline direction may be represented as:
Figure BDA0002661621720000141
the dip gather for the crossline direction can be expressed as:
Figure BDA0002661621720000142
wherein the content of the first and second substances,
Figure BDA0002661621720000143
the dip gathers representing the inline direction,
Figure BDA0002661621720000144
dip gathers, T, representing crossline direction02T denotes the vertical two-way travel at imaging point (x, y, T), f'mRepresenting the semi-conductor number of seismic traces, N representing the total number of traces of said initial common-offset prestack dataset as input, (x)s,ys) Representing the shot point coordinate corresponding to the mth seismic channel, (x)g,yg) Representing the coordinates of the detection point, τ, corresponding to the mth seismic tracesRepresenting the travel time, τ, from shot to image pointgRepresenting travel times from a detection point to an imaging point, the inclination angle associated with said travel times
Figure BDA0002661621720000145
And
Figure BDA0002661621720000146
expressed as:
Figure BDA0002661621720000147
Figure BDA0002661621720000148
wherein, VrmsRepresents the root mean square velocity at the imaging point (x, y, T).
And 202, obtaining a first offset aperture set of each imaging point of the imaging space according to the dip angle gather.
Alternatively, using inline directionDip angle gather
Figure BDA0002661621720000151
And liaison survey line direction dip angle gather
Figure BDA0002661621720000152
And obtaining a first offset aperture set at all the imaging points by applying a human-computer interaction pickup method.
The first set of offset apertures may be expressed as:
Figure BDA0002661621720000153
wherein (x, y, T) represents coordinates of an imaging point,
Figure BDA0002661621720000154
indicating that the inline direction is offset from the left boundary of the aperture,
Figure BDA0002661621720000155
indicating the right boundary of the inline direction offset aperture,
Figure BDA0002661621720000156
indicating that the crossline direction is offset from the left boundary of the aperture,
Figure BDA0002661621720000157
indicating that the crossline direction is offset from the right boundary of the aperture.
And step 203, obtaining a constant Q scanning gather according to the initial common offset prestack data set.
Optionally, step 203 may include the following steps.
Step 2031, a constant Q model is constructed according to a preset equivalent Q value sequence.
Illustratively, Q is equal to a preset equivalent Q value sequence1,Q2,Q3,...,QlAny one of the equivalent Q values Qi。
Optionally, for any one equivalent Q value QiEstablishing a value of QiThe constant Q model of (1).
Step 2032, according to the constant Q model, performing inverse Q filtering processing on the initial common offset pre-stack data set to obtain a second common offset pre-stack data set.
Step 2033, based on the propagation group velocity of the seismic wave after the medium absorption, applying a conventional prestack time migration process to the second common-offset prestack data set to process, so as to obtain a constant Q scanning gather. In the present processing step, the travel time of Q factor is taken into consideration
Figure BDA0002661621720000158
Travel time τ replacing conventional prestack time migrations、τg. The above-mentioned
Figure BDA0002661621720000159
τs、τgRespectively expressed as:
Figure BDA00026616217200001510
Figure BDA0002661621720000161
Figure BDA0002661621720000162
Figure BDA0002661621720000163
traversing a preset equivalent Q value sequence Q ═ Q1,Q2,Q3,...,QlObtaining a corresponding preset equivalent Q value sequence Q ═ Q1,Q2,Q3,...,QlOffset profile cluster QmigSection i1,2, 3. The cluster of offset profiles is referred to as the constant Q scan gather.
And 204, generating an equivalent Q value model according to the constant Q scanning gather.
Optionally, based on the constant Q scan gather, an equivalent Q value at the analysis time window may be determined according to resolutions of offset profiles corresponding to different equivalent Q values in the analysis time window, so as to establish an equivalent Q value model.
Exemplarily, based on the constant Q scanning gather, a man-machine interaction method is applied, and the value of the equivalent Q value at the analysis time window is determined according to the resolution improvement condition of the offset profile corresponding to different equivalent Q values in the analysis time window, so as to establish an equivalent Q value model of the target work area.
Step 205, correcting the first offset aperture set of each imaging point of the imaging space based on the equivalent Q-value model to obtain a second offset aperture set of each imaging point of the imaging space.
Illustratively, the second set of offset apertures is represented as:
Figure BDA0002661621720000164
the first set of offset apertures is represented as:
Figure BDA0002661621720000165
wherein the second set of offset apertures ApertureQThe correspondence with the first set of offset apertures, aperature, is expressed as:
Figure BDA0002661621720000171
Figure BDA0002661621720000172
Figure BDA0002661621720000173
Figure BDA0002661621720000174
Figure BDA0002661621720000175
wherein (x, y, T) represents coordinates of an imaging point,
Figure BDA0002661621720000176
indicating that the inline direction is offset from the left boundary of the aperture,
Figure BDA0002661621720000177
indicating the right boundary of the inline direction offset aperture,
Figure BDA0002661621720000178
indicating that the crossline direction is offset from the left boundary of the aperture,
Figure BDA0002661621720000179
representing the right boundary of the crossline direction-shifted aperture, f representing the dominant frequency of the initial common-offset prestack dataset, fQRepresenting the main frequency of the pre-stack data with the preset common offset distance after the resolution ratio is improved; qeffRepresenting the value of the equivalent Q value model at the imaging point,
Figure BDA00026616217200001710
indicating the left boundary of the corrected inline direction shift aperture,
Figure BDA00026616217200001711
a right boundary representing the corrected inline direction offset aperture;
Figure BDA00026616217200001712
indicating the left boundary of the corrected crossline direction shift aperture,
Figure BDA00026616217200001713
indicating the corrected crossline direction shifted right boundary of the aperture.
And 206, based on a preset migration velocity model, the equivalent Q value model and the second migration aperture set, performing high-precision attenuation imaging processing on the initial common-offset pre-stack data set to obtain a migration profile and a pre-stack trace set.
Illustratively, the prestack gather described above may be a CRP gather.
Illustratively, the prestack gathers described above may be corner gathers.
Alternatively, the preset migration velocity model described above may be established based on the initial common-offset pre-stack data set using a pre-stack time migration velocity analysis method.
Illustratively, as shown in fig. 9, fig. 9 shows a vertical profile of the preset migration velocity model at a position.
In the example shown in fig. 9, the vertical profile of the preset offset velocity model at X ═ 4km is shown.
Illustratively, as shown in fig. 10, fig. 10 shows a vertical value curve diagram of the equivalent Q value model at a position.
In the example shown in fig. 10, the vertical profile of the equivalent Q-value model at X ═ 4km is shown.
In an embodiment, the performing, based on a preset migration velocity model, the equivalent Q-value model, and the second migration aperture set, high-precision attenuation imaging processing on the initial common-offset prestack data set to obtain a migration profile and a prestack gather is performed by the following formulas:
Figure BDA0002661621720000181
wherein (x, y, T) represents coordinates of an imaging point, h represents offset distance, theta represents azimuth angle, theta belongs to U, U represents an azimuth angle set preset based on the azimuth anisotropy property of the target work area, and U is {0,90, theta1,θ2,θ3,...,θnAnd I (x, y, T, theta, h) represents the obtained pre-stack gather after the deviation of the sub-azimuth angles, wherein the seismic pre-stack gathers corresponding to different h are stackedPlus, then represents the high resolution offset profile I of the sub-azimuthS(x, y, T, θ), N represents the initial co-offset prestack data set, the weight function
Figure BDA0002661621720000182
Denotes the offset aperture as a function of azimuth, d ζ denotes the attenuation band length, ζθRepresenting the corresponding dip angle of the mth pre-stack seismic channel in the azimuth theta direction;
the calculation mode of the inclination angle corresponding to the mth pre-stack seismic channel in the azimuth theta direction is as follows:
Figure BDA0002661621720000191
Figure BDA0002661621720000192
indicating the left and right boundaries of the offset aperture in the azimuth theta direction,
Figure BDA0002661621720000193
is set by the second offset aperture
Figure BDA0002661621720000194
The elements of (2) are obtained:
Figure BDA0002661621720000195
Figure BDA0002661621720000196
weight function
Figure BDA0002661621720000197
The expression of (a) is:
Figure BDA0002661621720000198
wherein ω represents the initial co-offset pre-stack data angular frequency of the input, ω0Representing the input initial common offset pre-stack data main frequency, F (omega) representing the m channel pre-stack seismic channel data to be transformed into a frequency domain through Fourier transform processing, j representing an imaginary unit, QeffRepresenting the value of the equivalent Q value model at the imaging point (x, y, T),
Figure BDA0002661621720000199
representing the travel time from shot to imaging point taking into account the effect of medium absorption on the group velocity of seismic wave propagation,
Figure BDA00026616217200001910
the travel time from the imaging point to the geophone point, which takes into account the effects of medium absorption on the group velocity of seismic wave propagation, is expressed as:
Figure BDA00026616217200001911
as shown in fig. 11, fig. 11 is a schematic diagram of an offset profile obtained by the seismic profile imaging method in the present embodiment. As shown in fig. 12, fig. 12 is a schematic diagram of a CRP gather obtained by the seismic profiling method in the present embodiment.
As shown in fig. 12, the example shown in fig. 12 is a CRP gather at x-4 km.
FIG. 13 shows a sub-azimuth CRP gather schematic using the seismic profile imaging method of the present embodiment.
The seismic profile imaging method and device provided by the embodiment of the application can suppress offset noise and improve offset calculation efficiency; three main influence factors of medium absorption on seismic wave propagation can be eliminated simultaneously, namely high-frequency attenuation of the seismic wave is compensated, frequency dispersion is corrected, and travel time calculation errors of the seismic wave are corrected; the seismic profile and the prestack gather with high resolution can be output in different directions, so that the method has important application values for natural gas hydrate identification, fine characterization of gas-containing fluid migration channels of hydrate reservoirs, deep-ultra deep lithologic oil and gas reservoir exploration and crack type oil and gas reservoir exploration.
Further, three influence factors of medium absorption on seismic wave propagation are considered and corrected in the method in the embodiment: the method is used for solving the problems of high-frequency attenuation of offset amplitude caused by different influences on different frequency components of seismic waves, phase distortion of a same-phase axis of an offset section caused by difference between seismic wave propagation group velocity and phase velocity caused by absorption, and offset travel time calculation errors caused by the influence on the seismic wave propagation group velocity.
Furthermore, in order to suppress and compensate noise, a migration aperture with sub-azimuth angle change is introduced, so that a certain signal-to-noise ratio level can be maintained while a sub-azimuth high-resolution seismic section and a migration post-stack gather are output.
Furthermore, a high-resolution seismic migration profile with different azimuth angles and a post-migration pre-stack gather can be generated, and the research and the drawing of the anisotropic property of the medium azimuth are facilitated.
EXAMPLE III
Based on the same application concept, the embodiment of the present application further provides a seismic section imaging apparatus corresponding to the seismic section imaging method, and since the principle of the apparatus in the embodiment of the present application for solving the problem is similar to that in the embodiment of the seismic section imaging method, the implementation of the apparatus in the embodiment of the present application may refer to the description in the embodiment of the method, and repeated details are not repeated.
Fig. 14 is a schematic diagram of functional modules of a seismic section imaging apparatus according to an embodiment of the present disclosure. The various modules in the seismic profile imaging apparatus in this embodiment are used to perform the various steps in the above-described method embodiments. The seismic profile imaging apparatus includes: a processing module 301, a first obtaining module 302, a second obtaining module 303, a generating module 304, a third obtaining module 305, and a fourth obtaining module 306; wherein the content of the first and second substances,
a processing module 301, configured to process the initial common offset prestack data set to obtain an inclination gather;
a first obtaining module 302, configured to obtain a first offset aperture set of each imaging point in the imaging space according to the dip gather;
a second obtaining module 303, configured to obtain a constant Q scan gather according to the initial common offset prestack data set;
a generating module 304, configured to generate an equivalent Q-value model according to the constant Q-scan gather;
a third obtaining module 305, configured to correct the first offset aperture set of each imaging point of the imaging space based on the equivalent Q-value model to obtain a second offset aperture set of each imaging point of the imaging space;
a fourth obtaining module 306, configured to perform high-precision attenuation imaging processing on the initial common-offset prestack data set based on a preset offset velocity model, the equivalent Q-value model, and the second offset aperture set, so as to obtain an offset profile and a prestack gather.
In a possible implementation manner, the processing module 301 is configured to:
processing according to the initial common offset prestack data set to obtain an inclination gather in the main measuring line direction;
and processing according to the initial common offset prestack data set to obtain an inclination gather in the direction of the crossline.
In one possible embodiment, the dip gather for the inline direction is represented as:
Figure BDA0002661621720000211
the dip gather in the crossline direction is represented as:
Figure BDA0002661621720000221
wherein the content of the first and second substances,
Figure BDA0002661621720000222
the dip gathers representing the inline direction,
Figure BDA0002661621720000223
dip gathers, T, representing crossline direction02T denotes the vertical two-way travel at imaging point (x, y, T), f'mRepresenting the semi-conductor number of seismic traces, N representing the total number of traces of said initial common-offset prestack dataset as input, (x)s,ys) Representing the shot point coordinate corresponding to the mth seismic channel, (x)g,yg) Representing the coordinates of the detection point, τ, corresponding to the mth seismic tracesRepresenting the travel time, τ, from shot to image pointgRepresenting travel times from a detection point to an imaging point, the inclination angle associated with said travel times
Figure BDA0002661621720000224
And
Figure BDA0002661621720000225
expressed as:
Figure BDA0002661621720000226
Figure BDA0002661621720000227
wherein, VrmsRepresents the root mean square velocity at the imaging point (x, y, T).
In a possible implementation manner, the second obtaining module 303 is configured to:
constructing a constant Q model according to a preset equivalent Q value sequence;
according to the constant Q model, performing inverse Q filtering processing on the initial common offset pre-stack data set to obtain a second common offset pre-stack data set;
and based on the seismic wave propagation group velocity after the medium absorption, processing the second common offset prestack data set by applying a conventional prestack time migration process to obtain a constant Q scanning gather.
In a possible implementation manner, the generating module 304 is configured to:
and based on the constant Q scanning gather, determining an equivalent Q value at the analysis time window according to the resolution ratios of the offset profiles corresponding to different equivalent Q values in the analysis time window so as to establish an equivalent Q value model.
In one possible implementation, the second set of offset apertures is represented as:
Figure BDA0002661621720000231
the first set of offset apertures is represented as:
Figure BDA0002661621720000232
wherein the second set of offset apertures ApertureQThe correspondence with the first set of offset apertures, aperature, is expressed as:
Figure BDA0002661621720000233
Figure BDA0002661621720000234
Figure BDA0002661621720000235
Figure BDA0002661621720000236
Figure BDA0002661621720000237
where f denotes the dominant frequency of the initial co-offset prestack data set, fQRepresenting the main frequency of the pre-stack data with the preset common offset distance after the resolution ratio is improved; qeffRepresenting the value of the equivalent Q value model at the imaging point,
Figure BDA0002661621720000238
indicating the left boundary of the corrected inline direction shift aperture,
Figure BDA0002661621720000239
a right boundary representing the corrected inline direction offset aperture;
Figure BDA00026616217200002310
indicating the left boundary of the corrected crossline direction shift aperture,
Figure BDA00026616217200002311
indicating the corrected crossline direction shifted right boundary of the aperture.
In a possible implementation, the fourth obtaining module 306 is implemented by the following formula:
Figure BDA0002661621720000241
wherein (x, y, T) represents coordinates of an imaging point, h represents offset distance, theta represents azimuth angle, theta belongs to U, U represents an azimuth angle set preset based on the azimuth anisotropy property of the target work area, and U is {0,90, theta1,θ2,θ3,...,θnAnd (x, y, T, theta, h) represents the obtained pre-stack gather after the deviation of the sub-azimuth angle, wherein the seismic pre-stack gather corresponding to different h is superposed to represent a high-resolution deviation profile I of the sub-azimuth angleS(x, y, T, θ), N represents the initial co-offset prestack data set, the weight function
Figure BDA0002661621720000242
Denotes the offset aperture as a function of azimuth, d ζ denotes the attenuation band length, ζθRepresenting the corresponding dip angle of the mth pre-stack seismic channel in the azimuth theta direction;
the calculation mode of the inclination angle corresponding to the mth pre-stack seismic channel in the azimuth theta direction is as follows:
Figure BDA0002661621720000243
Figure BDA0002661621720000244
indicating the left and right boundaries of the offset aperture in the azimuth theta direction,
Figure BDA0002661621720000245
is set by the second offset aperture
Figure BDA0002661621720000246
The element(s) of (a) is calculated as:
Figure BDA0002661621720000247
Figure BDA0002661621720000248
weight function
Figure BDA0002661621720000249
The expression of (a) is:
Figure BDA00026616217200002410
wherein ω represents the initial co-offset pre-stack data angular frequency of the input, ω0Representing the input initial common offset pre-stack data main frequency, F (omega) representing the m channel pre-stack seismic channel data to be transformed into a frequency domain through Fourier transform processing, j representing an imaginary unit, QeffRepresenting the value of the equivalent Q value model at the imaging point (x, y, T),
Figure BDA0002661621720000251
representing the travel time from shot to imaging point taking into account the effect of medium absorption on the group velocity of seismic wave propagation,
Figure BDA0002661621720000252
the travel time from the imaging point to the geophone point, which takes into account the effects of medium absorption on the group velocity of seismic wave propagation, is expressed as:
Figure BDA0002661621720000253
furthermore, the present application also provides a computer readable storage medium, on which a computer program is stored, and the computer program is executed by a processor to execute the steps of the seismic section imaging method described in the above method embodiment.
The computer program product of the seismic section imaging method provided in the embodiment of the present application includes a computer-readable storage medium storing a program code, where instructions included in the program code may be used to execute the steps of the seismic section imaging method described in the above method embodiment, which may be specifically referred to in the above method embodiment, and are not described herein again.
In the embodiments provided in the present application, it should be understood that the disclosed apparatus and method can be implemented in other ways. The apparatus embodiments described above are merely illustrative, and for example, the flowchart and block diagrams in the figures illustrate the architecture, functionality, and operation of possible implementations of apparatus, methods and computer program products according to various embodiments of the present application. In this regard, each block in the flowchart or block diagrams may represent a module, segment, or portion of code, which comprises one or more executable instructions for implementing the specified logical function(s). It should also be noted that, in some alternative implementations, the functions noted in the block may occur out of the order noted in the figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently, or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved. It will also be noted that each block of the block diagrams and/or flowchart illustration, and combinations of blocks in the block diagrams and/or flowchart illustration, can be implemented by special purpose hardware-based systems which perform the specified functions or acts, or combinations of special purpose hardware and computer instructions.
In addition, functional modules in the embodiments of the present application may be integrated together to form an independent part, or each module may exist separately, or two or more modules may be integrated to form an independent part.
The functions, if implemented in the form of software functional modules and sold or used as a stand-alone product, may be stored in a computer readable storage medium. Based on such understanding, the technical solution of the present application or portions thereof that substantially contribute to the prior art may be embodied in the form of a software product stored in a storage medium and including instructions for causing a computer device (which may be a personal computer, a server, or a network device) to execute all or part of the steps of the method according to the embodiments of the present application. And the aforementioned storage medium includes: a U-disk, a removable hard disk, a Read-Only Memory (ROM), a Random Access Memory (RAM), a magnetic disk or an optical disk, and other various media capable of storing program codes. It is noted that, herein, relational terms such as first and second, and the like may be used solely to distinguish one entity or action from another entity or action without necessarily requiring or implying any actual such relationship or order between such entities or actions. Also, the terms "comprises," "comprising," or any other variation thereof, are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements but may include other elements not expressly listed or inherent to such process, method, article, or apparatus. Without further limitation, an element defined by the phrase "comprising … …" does not exclude the presence of other identical elements in a process, method, article, or apparatus that comprises the element.
The above description is only a preferred embodiment of the present application and is not intended to limit the present application, and various modifications and changes may be made by those skilled in the art. Any modification, equivalent replacement, improvement and the like made within the spirit and principle of the present application shall be included in the protection scope of the present application. It should be noted that: like reference numbers and letters refer to like items in the following figures, and thus, once an item is defined in one figure, it need not be further defined and explained in subsequent figures.
The above description is only for the specific embodiments of the present application, but the scope of the present application is not limited thereto, and any person skilled in the art can easily conceive of the changes or substitutions within the technical scope of the present application, and shall be covered by the scope of the present application. Therefore, the protection scope of the present application shall be subject to the protection scope of the claims.

Claims (9)

1. A method of seismic profiling, comprising:
processing the initial common offset prestack data set to obtain an inclination gather;
obtaining a first migration aperture set of each imaging point of an imaging space according to the dip angle gather;
obtaining a constant Q scanning gather according to the initial common offset prestack data set;
generating an equivalent Q value model according to the constant Q scanning gather;
correcting the first offset aperture set of each imaging point of the imaging space based on the equivalent Q value model to obtain a second offset aperture set of each imaging point of the imaging space;
based on a preset migration velocity model, the equivalent Q value model and the second migration aperture set, performing high-precision attenuation imaging processing on the initial common-offset pre-stack data set to obtain a migration profile and a pre-stack trace set;
the second set of offset apertures is represented as:
Figure FDA0002945194610000011
the first set of offset apertures is represented as:
Figure FDA0002945194610000012
wherein the second set of offset apertures ApertureQThe correspondence with the first set of offset apertures Aperture is expressed as:
Figure FDA0002945194610000013
Figure FDA0002945194610000014
Figure FDA0002945194610000015
Figure FDA0002945194610000021
Figure FDA0002945194610000022
wherein (x, y, T) represents coordinates of an imaging point,
Figure FDA0002945194610000023
indicating that the inline direction is offset from the left boundary of the aperture,
Figure FDA0002945194610000024
indicating the right boundary of the inline direction offset aperture,
Figure FDA0002945194610000025
indicating that the crossline direction is offset from the left boundary of the aperture,
Figure FDA0002945194610000026
representing the right boundary of the crossline direction-shifted aperture, f representing the dominant frequency of the initial common-offset prestack dataset, fQRepresenting a preset co-offset pre-stack data dominant frequency, Q, after resolution enhancement processingeffRepresenting the value of the equivalent Q value model at the imaging point,
Figure FDA0002945194610000027
indicating the left boundary of the corrected inline direction shift aperture,
Figure FDA0002945194610000028
a right boundary representing the corrected inline direction offset aperture;
Figure FDA0002945194610000029
indicating the left boundary of the corrected crossline direction shift aperture,
Figure FDA00029451946100000210
indicating the corrected crossline direction shifted right boundary of the aperture.
2. The method of claim 1, wherein the processing the initial common-offset prestack dataset to obtain a dip gather comprises:
processing according to the initial common offset prestack data set to obtain an inclination gather in the main measuring line direction;
and processing according to the initial common offset prestack data set to obtain an inclination gather in the direction of the crossline.
3. The method of claim 2, wherein the inline-direction dip gather is represented as:
Figure FDA00029451946100000211
the dip gather in the crossline direction is represented as:
Figure FDA0002945194610000031
wherein the content of the first and second substances,
Figure FDA0002945194610000032
the dip gathers representing the inline direction,
Figure FDA0002945194610000033
dip gathers, T, representing crossline direction02T denotes the vertical two-way travel at imaging point (x, y, T), f'mRepresenting the semi-conductor number of seismic traces, N representing the total number of traces of said initial common-offset prestack dataset as input, (x)s,ys) Representing the shot point coordinate corresponding to the mth seismic channel, (x)g,yg) Representing the coordinates of the detection point, τ, corresponding to the mth seismic tracesRepresenting the travel time, τ, from shot to image pointgRepresenting travel time from the detector point to the image point, the angle of inclination associated with the travel time
Figure FDA0002945194610000034
And
Figure FDA0002945194610000035
expressed as:
Figure FDA0002945194610000036
Figure FDA0002945194610000037
wherein, VrmsRepresents the root mean square velocity at the imaging point (x, y, T).
4. The method of claim 1, wherein obtaining a constant Q scan gather from the initial common-offset prestack dataset comprises:
constructing a constant Q model according to a preset equivalent Q value sequence;
according to the constant Q model, performing inverse Q filtering processing on the initial common offset pre-stack data set to obtain a second common offset pre-stack data set;
and based on the seismic wave propagation group velocity after the medium absorption, processing the second common offset prestack data set by applying a conventional prestack time migration process to obtain a constant Q scanning gather.
5. The method of claim 1, wherein generating an equivalent Q value model from the constant Q scan gather comprises:
and based on the constant Q scanning gather, determining an equivalent Q value at the analysis time window according to the resolution ratios of the offset profiles corresponding to different equivalent Q values in the analysis time window so as to establish an equivalent Q value model.
6. The method of claim 1, wherein the initial common offset prestack data set is subjected to high-precision attenuation imaging processing based on a preset offset velocity model, the equivalent Q-value model and the second offset aperture set to obtain an offset profile and a prestack gather, and the offset profile and the prestack gather are obtained by the following formulas:
Figure FDA0002945194610000041
wherein (x, y, T) represents coordinates of an imaging point, h represents an offset, and theta is shownShowing an azimuth angle, theta is equal to U, U represents a preset azimuth angle set based on the azimuth anisotropy property of the target work area, and U is equal to {0,90, theta1,θ2,θ3,...,θnAnd (x, y, T, theta, h) represents the obtained pre-stack gather after the deviation of the sub-azimuth angle, wherein the seismic pre-stack gather corresponding to different h is superposed to represent a high-resolution deviation profile I of the sub-azimuth angleS(x, y, T, θ), N represents the initial co-offset prestack data set, the weight function
Figure FDA0002945194610000042
Denotes the offset aperture as a function of azimuth, d ζ denotes the attenuation band length, ζθRepresenting the corresponding inclination angle of the mth pre-stack seismic channel in the direction of the azimuth angle theta, wherein the inclination angle zeta of the mth pre-stack seismic channel in the direction of the azimuth angle thetaθThe calculation method is as follows:
Figure FDA0002945194610000043
Figure FDA0002945194610000044
indicating the left and right boundaries of the offset aperture in the azimuth theta direction,
Figure FDA0002945194610000045
is set by the second offset aperture
Figure FDA0002945194610000046
The element(s) of (a) is calculated as:
Figure FDA0002945194610000047
Figure FDA0002945194610000048
Figure FDA0002945194610000049
weight function
Figure FDA0002945194610000051
The expression of (a) is:
Figure FDA0002945194610000052
wherein ω represents the initial co-offset pre-stack data angular frequency of the input, ω0Representing the input initial common offset pre-stack data main frequency, F (omega) representing the m channel pre-stack seismic channel data to be transformed into a frequency domain through Fourier transform processing, j representing an imaginary unit, QeffRepresenting the value of the equivalent Q value model at the imaging point (x, y, T),
Figure FDA0002945194610000053
representing the travel time from shot to imaging point taking into account the effect of medium absorption on the group velocity of seismic wave propagation,
Figure FDA0002945194610000054
the travel time from the imaging point to the geophone point, which takes into account the effects of medium absorption on the group velocity of seismic wave propagation, is expressed as:
Figure FDA0002945194610000055
wherein (x)s,ys) Representing the shot point coordinate corresponding to the mth seismic channel, (x)g,yg) Representing the coordinate of the detection point, V, corresponding to the mth seismic tracermsRepresenting the root mean square velocity at the imaging point (x, y, T),
Figure FDA0002945194610000056
indicating the left boundary of the corrected inline direction shift aperture,
Figure FDA0002945194610000057
a right boundary representing the corrected inline direction offset aperture;
Figure FDA0002945194610000058
indicating the left boundary of the corrected crossline direction shift aperture,
Figure FDA0002945194610000059
indicating the right boundary, Q, of the corrected crossline direction offset apertureeffAnd representing the value of the equivalent Q value model at the imaging point.
7. A seismic profiling imaging apparatus, comprising:
the processing module is used for processing the initial common offset prestack data set to obtain an inclination angle gather;
the first obtaining module is used for obtaining a first offset aperture set of each imaging point of the imaging space according to the dip angle gather;
a second obtaining module, configured to obtain a constant Q scan gather according to the initial common offset prestack data set;
the generating module is used for generating an equivalent Q value model according to the constant Q scanning gather;
a third obtaining module, configured to correct the first offset aperture set of each imaging point in the imaging space based on the equivalent Q-value model, so as to obtain a second offset aperture set of each imaging point in the imaging space;
a fourth obtaining module, configured to perform high-precision attenuation imaging processing on the initial common-offset prestack data set based on a preset offset velocity model, the equivalent Q-value model, and the second offset aperture set, so as to obtain an offset profile and a prestack gather;
the second set of offset apertures is represented as:
Figure FDA0002945194610000061
the first set of offset apertures is represented as:
Figure FDA0002945194610000062
wherein the second set of offset apertures ApertureQThe correspondence with the first set of offset apertures Aperture is expressed as:
Figure FDA0002945194610000063
Figure FDA0002945194610000064
Figure FDA0002945194610000065
Figure FDA0002945194610000066
Figure FDA0002945194610000071
wherein (x, y, T) represents coordinates of an imaging point,
Figure FDA0002945194610000072
indicating that the inline direction is offset from the left boundary of the aperture,
Figure FDA0002945194610000073
indicating main survey line directionThe right boundary of the offset aperture,
Figure FDA0002945194610000074
indicating that the crossline direction is offset from the left boundary of the aperture,
Figure FDA0002945194610000075
representing the right boundary of the crossline direction-shifted aperture, f representing the dominant frequency of the initial common-offset prestack dataset, fQRepresenting a preset co-offset pre-stack data dominant frequency, Q, after resolution enhancement processingeffRepresenting the value of the equivalent Q value model at the imaging point,
Figure FDA0002945194610000076
indicating the left boundary of the corrected inline direction shift aperture,
Figure FDA0002945194610000077
a right boundary representing the corrected inline direction offset aperture;
Figure FDA0002945194610000078
indicating the left boundary of the corrected crossline direction shift aperture,
Figure FDA0002945194610000079
indicating the corrected crossline direction shifted right boundary of the aperture.
8. An electronic device, comprising: a processor, a memory storing machine-readable instructions executable by the processor, the machine-readable instructions when executed by the processor performing the steps of the method of any of claims 1 to 6 when the electronic device is run.
9. A computer-readable storage medium, having stored thereon a computer program which, when being executed by a processor, is adapted to carry out the steps of the method according to any one of claims 1 to 6.
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