CN112433246A - Method and system for acquiring earth surface offset gathers - Google Patents

Method and system for acquiring earth surface offset gathers Download PDF

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CN112433246A
CN112433246A CN202011215004.3A CN202011215004A CN112433246A CN 112433246 A CN112433246 A CN 112433246A CN 202011215004 A CN202011215004 A CN 202011215004A CN 112433246 A CN112433246 A CN 112433246A
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wave field
source
offset
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郝新源
赵杨
陈海潮
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
    • G01V1/30—Analysis
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
    • G01V1/30—Analysis
    • G01V1/307—Analysis for determining seismic attributes, e.g. amplitude, instantaneous phase or frequency, reflection strength or polarity

Abstract

The invention relates to a surface offset gather obtaining method and a system, wherein a seismic source wave field and a back propagation wave field are obtained, the seismic source wave field is separated into a source longitudinal wave field and a source transverse wave field, and a receiving wave field is separated into a receiving longitudinal wave field and a receiving transverse wave field; obtaining a PP surface offset trace set and a PS surface offset trace set according to the longitudinal wave field, the source transverse wave field, the receiving longitudinal wave field and the receiving transverse wave field; superposing the acquired PP earth surface offset gather to obtain a PP common offset gather; and the obtained PS surface offset gathers are superposed to obtain the PS common offset gather, and the acquisition of the PP and PS surface offset gathers is independent of the angle, so that the calculation cost is reduced, and the acquisition efficiency of the surface offset gathers is improved.

Description

Method and system for acquiring earth surface offset gathers
Technical Field
The invention relates to the technical field of seismic waves, in particular to a method and a system for acquiring earth surface offset gathers.
Background
Traditional sonic reverse-time migration approaches approximate subsurface materials as fluid media, considering only the propagation of longitudinal waves. Although this approximation is useful and effective in practice, acoustic reverse time migration (acoustic time migration) ignores the S-wave and excludes the associated additional information. Elastic wave reverse time migration ERTM, in contrast to ARTM, has shown a unique ability to estimate lithologic information and specially constructed imaging (Crase et al, 1990; Stewart et al, 2003).
There are a number of ways to implement ERTM. One method is to directly extrapolate the source forward, extrapolate the received data backward into the ground, and then perform the wave decomposition by solving the elastic wave equation. The first step of the method is to compute the subsurface source and receive wavefields using the acquired multi-component data as boundary conditions. Then, the seismic longitudinal waves (P-waves) and the seismic transverse waves (S-waves) are separated by a wave decomposition method. Finally, parallel calculations are performed on the P and S components of the extrapolated wavefield using imaging conditions to obtain PP and PS images or images of the gather.
As a concept of the subsurface horizon, angle domain common image point gathers (ADCIGs) of common shot ERTM have been widely developed over the past decades. Similar to ARTM, ADCIGs may be calculated from extended images (Yan and Sava, 2008) or using Poynting vectors (Yoon and Marfurt, 2006; Tang and McMechan, 2017), and the like.
Ehinger et al (1996) initially performed common offset wave equation shifts by computing green's functions from the surface and then using them to perform frequency dependent one-way shifts. Etgen (2012) extends this approach to 3D and optimizes efficiency by reusing one-way green's functions (extrapolating from the surface multiple times) to save computational cost. Based on the two-way wave equation, Giboli et al (2012) generate SOGs by stable phase extraction of the encoded attributes, shift the attributes into common shot, arm, restore surface attributes, and redistribute common shot images. Yang et al (2015) proposes to divide the co-shot gathers into offset groups (duquetantd Lailly, 2006), to separately backpropagate the wavefields of each group, and then to generate one SOG per source-receive group.
ADCIGs has become one of the common methods for calculating velocity in offset velocity analysis. For example, Biondiand Symes (2004) have developed a residual time difference (RMO) equation based on ADCIGs assuming a smooth ray path and constant velocity error. However, there are also problems with standard cosumption ERTM ADCIGs. First, in a complex geological environment, a multicomponent wave packet in a particular region cannot always be estimated to the correct angle. Recent studies (Yang et al, 2017) have greatly improved accuracy, but also required significant computational costs (Tang and McMechan, 2017). Deep targets associated with complex geological conditions can only be observed to a very small extent. The speed of the offset tends to be in error and thus can cause disturbances in the propagation of the wavefront surface caused by different surface offsets.
Disclosure of Invention
Based on the above, the invention aims to provide a method and a system for acquiring a surface offset gather, which improve the acquisition efficiency of the surface offset gather.
In order to achieve the purpose, the invention provides the following scheme:
a surface offset gather acquisition method is applied to a surface offset gather acquisition system, the system comprises a seismic source, a first detector and a second detector, the second detector is positioned at the position of the seismic source, and a plurality of the first detectors are different in distance from the seismic source;
the method comprises the following steps:
collecting a plurality of wavelets by the first detector; the plurality of wavelets are a plurality of wavelets under different offset conditions, and the offset is the distance from the first detector to the seismic source;
performing double integration on the wavelets to obtain a seismic source wave field;
separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield;
transmitting a counter wave to a corresponding seismic source through the first detector;
receiving the counter-propagating wave by the second detector;
performing double integration on the backward wave to obtain a backward wave field;
separating the backward wave field into a backward longitudinal wave field and a backward transverse wave field;
obtaining a PP surface offset trace set and a PS surface offset trace set according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field;
superposing the acquired PP earth surface offset gather to obtain a PP common offset gather;
and superposing the obtained PS surface offset gather to obtain a PS common offset gather.
Optionally, the wave equation of the wavelet is:
Figure BDA0002760070610000031
where v denotes the velocity of the particle at the propagation time t, ρ is the medium density, λ is the first Lame coefficient, and μ is the second Lame coefficient.
Optionally, the formula for separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield is:
Figure BDA0002760070610000032
Figure BDA0002760070610000033
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure BDA0002760070610000034
a local P-wave representing said wavelet,
Figure BDA0002760070610000035
a local S-wave representing the wavelet in question,
Figure BDA0002760070610000036
a source longitudinal wave field is represented,
Figure BDA0002760070610000037
representing the source transverse wavefield.
Optionally, the formula for obtaining the PP surface offset trace gather and the PS surface offset trace gather according to the longitudinal wave field, the source transverse wave field, the back-propagation longitudinal wave field, and the back-propagation transverse wave field is as follows:
Figure BDA0002760070610000038
Figure BDA0002760070610000039
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure BDA00027600706100000310
a source longitudinal wavefield is represented,
Figure BDA00027600706100000311
representing the source transverse wave field, sgnPPSymbols representing gathers of PP images, sgnPSA symbol representing a PS image gather, d represents the wavelet multi-component record,
Figure BDA00027600706100000312
representing the counter-propagating longitudinal wave field,
Figure BDA00027600706100000313
representing the backward transverse wavefield.
The invention discloses a surface offset gather acquisition system, which comprises: the seismic source comprises a seismic source, a first detector and a second detector, wherein the second detector is located at the position of the seismic source, and the first detectors are different in distance from the seismic source;
the system further comprises:
the wavelet acquisition module is used for acquiring a plurality of wavelets through the first detector; the plurality of wavelets are a plurality of wavelets under different offset conditions, and the offset is the distance from the first detector to the seismic source;
the seismic source wave field acquisition module is used for carrying out double integration on the wavelets to obtain a seismic source wave field;
the seismic source wave field separation module is used for separating the seismic source wave field into a seismic source longitudinal wave field and a seismic source transverse wave field;
the counter propagation wave transmitting module is used for transmitting counter propagation waves to the corresponding seismic source through the first detector;
the backward wave receiving module is used for receiving the backward wave through the second detector;
the device comprises a back wave field acquisition module, a back wave field acquisition module and a back wave detection module, wherein the back wave field acquisition module is used for carrying out double integration on the back waves to obtain a back wave field;
the backward wave field separation module is used for separating the backward wave field into a backward longitudinal wave field and a backward transverse wave field;
the earth surface offset gather acquisition module is used for acquiring a PP earth surface offset gather and a PS earth surface offset gather according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field;
the PP common offset distance offset gather acquisition module is used for superposing the acquired PP earth surface offset distance gathers to obtain a PP common offset distance offset gather;
and the PS common offset distance offset gather acquisition module is used for superposing the acquired PS surface offset distance gathers to obtain the PS common offset distance offset gathers.
Optionally, the wave equation of the wavelet is:
Figure BDA0002760070610000041
where v denotes the velocity of the particle at the propagation time t, ρ is the medium density, λ is the first Lame coefficient, and μ is the second Lame coefficient.
Optionally, the formula for separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield is:
Figure BDA0002760070610000042
Figure BDA0002760070610000043
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure BDA0002760070610000044
a local P-wave representing said wavelet,
Figure BDA0002760070610000051
a local S-wave representing the wavelet in question,
Figure BDA0002760070610000052
a source longitudinal wave field is represented,
Figure BDA0002760070610000053
representing the source transverse wavefield.
Optionally, the formula for obtaining the PP surface offset trace gather and the PS surface offset trace gather according to the longitudinal wave field, the source transverse wave field, the back-propagation longitudinal wave field, and the back-propagation transverse wave field is as follows:
Figure BDA0002760070610000054
Figure BDA0002760070610000055
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure BDA0002760070610000056
a source longitudinal wavefield is represented,
Figure BDA0002760070610000057
representing the source transverse wave field, sgnPPSymbols representing gathers of PP images, sgnPSA symbol representing a PS image gather, d represents the wavelet multi-component record,
Figure BDA0002760070610000058
representing the counter-propagating longitudinal wave field,
Figure BDA0002760070610000059
representing the backward transverse wavefield.
According to the specific embodiment provided by the invention, the invention discloses the following technical effects:
the invention discloses a surface offset gather acquisition method and a system, wherein a seismic source wave field and a back propagation wave field are obtained, the seismic source wave field is separated into a seismic source longitudinal wave field and a seismic source transverse wave field, and the back propagation wave field is separated into a back propagation longitudinal wave field and a back propagation transverse wave field; obtaining a PP surface offset trace set and a PS surface offset trace set according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field; superposing the acquired PP earth surface offset gather to obtain a PP common offset gather; and the obtained PS surface offset gathers are superposed to obtain the PS common offset gather, and the acquisition of the PP and PS surface offset gathers is independent of the angle, so that the calculation cost is reduced, and the acquisition efficiency of the surface offset gathers is improved.
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In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required to be used in the embodiments will be briefly described below, and it is obvious that the drawings in the following description are only some embodiments of the present invention, and it is obvious for those skilled in the art that other drawings can be obtained according to the drawings without inventive labor.
FIG. 1 illustrates the common offset imaging principle of the present invention;
FIG. 2 is a common shot point principle of the present invention;
FIG. 3 is a schematic diagram of RMO comparison of a PP surface offset trace set and a PS surface offset trace set under first parameters of the present invention;
FIG. 4 is a schematic diagram of RMO comparison of a PP surface offset trace set and a PS surface offset trace set under second parameters of the present invention;
FIG. 5 is a schematic diagram of RMO comparison of a PP surface offset trace set and a PS surface offset trace set under a third parameter condition according to the present invention;
FIG. 6 is a schematic diagram of RMO comparison of a PP surface offset trace set and a PS surface offset trace set under fourth parameters according to the present invention;
FIG. 7 is a schematic diagram of RMO comparison between a PP surface offset trace set and a PS surface offset trace set under the fifth parameter condition of the present invention;
FIG. 8 is a schematic diagram of RMO comparison of a PP surface offset trace set and a PS surface offset trace set under sixth parameters in accordance with the present invention;
FIG. 9 is a schematic view of the BP2004 model of the present invention;
FIG. 10 is a BP model schematic diagram of a received wavefield snapshot according to the present invention;
FIG. 11 is a graph showing a comparison of offset velocity models for PP SOG and PS SOG and PP ADCIGs and PS ADCIGs in accordance with the present invention;
FIG. 12 is a schematic diagram showing the comparison between the zero offset PP image slices of SOGs of the invention and the zero angle PP ADCIGs image slices of the BP2004 model;
FIG. 13 is a schematic representation of a comparison of models of coal seams in accordance with the present invention;
FIG. 14 is a schematic diagram of an experimental wave field decomposition performed on a land model according to the present invention;
FIG. 15 is a comparison of the present invention using an offset velocity model;
FIG. 16 is a schematic diagram comparing zero offset PP image slices of SOGs of the invention with zero angle PP ADCIGs image slices of a dry coal seam model;
FIG. 17 is a schematic flow chart of a method for surface offset gather acquisition according to the present invention;
FIG. 18 is a schematic diagram of a surface offset gather acquisition system according to the present invention.
Detailed Description
The technical solutions in the embodiments of the present invention will be described clearly and completely with reference to the accompanying drawings in the embodiments of the present invention, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The invention aims to provide a method and a system for acquiring a surface offset gather, which improve the acquisition efficiency of the surface offset gather.
In order to make the aforementioned objects, features and advantages of the present invention comprehensible, embodiments accompanied with figures are described in further detail below.
ADCIGs has become one of the common methods for calculating velocity in offset velocity analysis. For example, Biondiande and Symes (2004) have developed a residual time difference (RMO) equation based on ADCIGs assuming a smooth ray path and constant velocity error. However, there are also problems with standard cosumption ERTM ADCIGs. First, in a complex geological environment, a multicomponent wave packet in a particular region cannot always be estimated to the correct angle. Recent studies (Yang et al, 2017) have greatly improved accuracy, but also required significant computational costs (Tang and McMechan, 2017). Deep targets associated with complex geological conditions can only be observed to a very small extent. The speed of the offset tends to be in error and thus can cause disturbances in the propagation of the wavefront surface caused by different surface offsets. Thus, there is often a performance degradation in RMO of ADCIGs. Finally, shot-common offsets may introduce aperture-induced artifacts, and during velocity update it is often not possible to locate the same Common Depth Point (CDP). In contrast to common offset shifts, co-shot based ADCIGs are not the first choice for conventional MVA (shift velocity analysis) techniques (Ehinger et al 1996) and conventional amplitude analysis (Dellinger and Etgen, 1990; Etgen, 2012).
Surface Offset Gathers (SOGs) constructed from common shot wave equation (one-way and two-way) offsets may be used as a substitute for ADCIGs for velocity analysis and imaging. However, all previous work was limited to acoustic media, requiring significant computational costs. More importantly, the kinematic relationship between SOGs and ADICGs has not been quantitatively addressed in prior studies. When performing MVA, the lack of corresponding understanding may generate errors; therefore, when inverting these time differences for chromatographic velocity correction, a quantitative formulation of RMO is required.
The present invention extends the previous work to the case of elastic wave isotropy, providing a theoretical kinematic basis between these two offset domains (two gathers). We consider it simpler to measure the kinematic correctness with a common surface offset gather in the case of incorrect velocities. In order to make a sufficient comparison with ADCIGs, we first construct a cost-effective workflow to generate surface offset gathers of PP and PS; existing wavefield separation techniques and imaging conditions are also reviewed. Specifically, on the basis of the second-order elastic isotropic wave equation, we only need the selected spatial gradient to approximate the vector P-wave and S-wave decompositions. The modified dot-product imaging conditions (Zhao et al, 2018a) are then adjusted to accommodate the separated input records of the independent offset groups. To the best of our knowledge, these two techniques are the least computationally expensive, and we therefore discuss and select them. The motion characteristics between elastic SOGs and ADCIGs are then analyzed, revealing their relationship to the co-offset and co-shot domain offsets, respectively. In particular, we use an analytical expression of the image misalignment between the two domains as a function of the disturbance in travel caused by the velocity error. This led us to the RMO definition using common offset and common shot offset in an elastic MVA environment. The RMO definition indicates that as an alternative to co-shot offsets, co-offset offsets (SOGs) may be more direct and linear, with two synthetic (sea and land) examples demonstrating their advantages. PP and PS were described and compared as a combined numerical evaluation method and compared with ADCIGs.
Fig. 17 is a schematic flow chart of a method for acquiring a surface offset gather according to the present invention, and as shown in fig. 17, the present invention discloses a method for acquiring a surface offset gather, which is applied to a system for acquiring a surface offset gather, the system including a seismic source, a first detector and a second detector, the second detector being located at the position of the seismic source, and a plurality of the first detectors being located at different distances from the seismic source. The method comprises the following steps:
step 101: collecting a plurality of wavelets by the first detector; the plurality of wavelets are a plurality of wavelets under different shot-geophone distances, and the shot-geophone distance is the distance from the first detector to the seismic source.
In step 101, the wavelet is a wave obtained by stabilizing a pulse signal emitted from the seismic source, and the wavelet is a multi-component wave.
Step 102: and performing double integration on the wavelets to obtain a source wave field.
In step 102, the double integration is performed as two integrations over time.
The wave equation for wavelets is:
Figure BDA0002760070610000081
where v represents the velocity of the particle in the x and z directions at the propagation time t, ρ is the medium density, λ is the first Lame number, and μ is the second Lame coefficient. The symbols · and × represent the divergence and curl, respectively.
The wave equation of a wavelet is a second-order wave equation expressed by a vector in a two-dimensional isotropic elastic medium.
The time derivative in the second order wave equation, in which v, i.e. v, is added to v, can be removedP(p-wave field) + vS(s wavefield) twice integration, divergence operator from vPThe S wave is removed, and the rotation operator is from vsThe P-wave is removed. Using local P-waves (χ)p) And S wave (χ)s) Rewriting the second order wave equation to obtain the wavefield separation formula:
Figure BDA0002760070610000091
wherein v ispRepresenting the longitudinal wave field, vsRepresenting a transverse wave field.
Step 103: separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield.
In step 103, the formula for separating the seismic source wavefield into a seismic source longitudinal wavefield and a seismic source transverse wavefield is:
Figure BDA0002760070610000092
Figure BDA0002760070610000093
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure BDA0002760070610000094
a local P-wave representing said wavelet,
Figure BDA0002760070610000095
a local S-wave representing the wavelet in question,
Figure BDA0002760070610000096
a source longitudinal wavefield is represented,
Figure BDA0002760070610000097
representing the source transverse wavefield.
Step 104: and transmitting the counter waves to the corresponding seismic source through the first detector. Specifically, the counter-propagating waves are emitted to the corresponding seismic source through the velocity model of the position of the first detector.
Step 105: receiving the counter-propagating wave by the second detector;
step 106: and carrying out double integration on the backward wave to obtain a backward wave field.
In step 106, the principle and the calculation method for obtaining the backward wave field by performing double integration on the backward wave are the same as those for obtaining the seismic source wave field.
Step 107: separating the backward propagating wavefield into a backward propagating longitudinal wavefield and a backward propagating transverse wavefield.
In step 107, the formulas for separating the backward propagation wave field into the backward propagation longitudinal wave field and the backward propagation transverse wave field are respectively as follows:
Figure BDA0002760070610000101
Figure BDA0002760070610000102
wherein v isrec' denotes the back-propagation field, p is the density of the medium,
Figure BDA0002760070610000103
a local P-wave representing the counter-propagating wave,
Figure BDA0002760070610000104
a local S-wave representing the counter-propagating wave,
Figure BDA0002760070610000105
a counter-propagating longitudinal wave field is represented,
Figure BDA0002760070610000106
representing the backward transverse wavefield.
Step 108: and obtaining a PP surface offset trace set and a PS surface offset trace set according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field.
In step 108, the formula for obtaining the PP surface offset trace gather and the PS surface offset trace gather according to the longitudinal wave field, the source transverse wave field, the back-propagation longitudinal wave field, and the back-propagation transverse wave field is as follows:
Figure BDA0002760070610000107
Figure BDA0002760070610000108
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure BDA0002760070610000109
a source longitudinal wavefield is represented,
Figure BDA00027600706100001010
representing the source transverse wave field, sgnPPSymbols representing gathers of PP images, sgnPSA symbol representing a PS image gather, d represents the wavelet multi-component record,
Figure BDA00027600706100001011
representing the counter-propagating longitudinal wave field,
Figure BDA00027600706100001012
representing the backward transverse wavefield. Namely, it is
Figure BDA00027600706100001013
Where the multicomponent recording is a recording that receives both shear and longitudinal wave information from the subsurface medium, PP refers to longitudinal wave transmit and longitudinal wave receive, and PS refers to longitudinal wave transmit and transverse wave receive.
Obtaining the imaging conditions for the PP surface offset trace set and the PS surface offset trace set reduces the angular dependence of ERTM imaging conditions, preserves the dot product sign, and recalculates the amplitude by multiplying the absolute values of the separated source wavefield and the return wavefield. PP denotes P-wave transmission P-wave reception and PS denotes P-wave transmission S-wave reception.
Step 109: and superposing the acquired PP earth surface offset gather to obtain a PP common offset gather.
Step 110: and superposing the obtained PS surface offset gather to obtain a PS common offset gather.
In the invention, the motion relation between ERTM SOGs and ADCIGs is utilized. The difference between the two is their implementation in different domains. All calculations are first performed in the co-offset domain and then expanded into the co-shot domain. For simplicity and clarity, we fix the horizontal position and the shift speed of the reflected imaging spot. Similar to the elastic kirchhoff-shifted MVA, this ray-based analysis is effective at high frequency approximations and small contrast velocity anomalies.
1) Imaging in common offset range and SOG
The imaging conditions for SOG calculation in equation 3 need to be performed in the common offset domain. For local events Tobs(src; rec) to a two-dimensional position (x; z; h) the following travel time requirements need to be met:
Tobs(src，rec)＝Tcaic(src，x，z，χ)+Tcalc(rec，x，z，χ) (4)
wherein T isobs(src, rec) is the observed two-way travel time (independent of χ) for a given event in the seismic recording. Similarly, Tcalc(src, x, z, χ) and Tcalc(rec, x, z, χ) is the one-way travel time (dependent on χ) from the source and receive locations to image locations x and z, respectively. In the case of common offset, the source and receiver positions can be represented by midpoint m and surface offset h by the relationships of m-src/2 + rec/2 and h-src/2-rec/2. Equation 4 can be rewritten with m, h, and for fixed x and χ, we take the total differential of T with respect to m, h, and z:
Figure BDA0002760070610000111
equation 5 is as defined above, but only a differential calculation is performed.
Using the chain rule, as shown in equation 6:
Figure BDA0002760070610000112
to simplify the notation, x and χ are discarded during differentiation. Can use the observed Tobs(src, rec) or calculated Tcalc(src, rec) travel time function instead of term T. With respect to the spatial variables in equation 5, the derivative of T is the in-phase axis slope or horizontal slowness in the data domain. We can easily select by slant stacking transformation of common shot gathers
Figure BDA0002760070610000113
(ray parameters on the receiving side) and vice versaVice versa, and are available in common receiving point trace sets
Figure BDA0002760070610000114
(ray parameters on the source side). Likewise, the computed ray parameters may be retrieved by ray tracing from bottom to top in the depth domain
Figure BDA0002760070610000115
And
Figure BDA0002760070610000116
mathematically, these four ray parameters can be expressed as:
Figure BDA0002760070610000121
obviously, in the case of a surface location independent of the speed of the offset
Figure BDA0002760070610000122
Then, equations 6 and 7 and the m-relationship are inserted into equation 5, giving the following equation after some algebraic operations:
Figure BDA0002760070610000123
FIG. 1 summarizes the definition of parameters related to events, ray trajectories, and SOGs. In acoustic reflection tomography, the travel-time perturbation is converted into a depth-deviation relationship, i.e.
Figure BDA0002760070610000124
Figure BDA0002760070610000125
We can easily extend this to the elastic case by including the converted wave PS case:
Figure BDA0002760070610000126
wherein theta isSHexix-sRespectively representing the reflection opening angle and the local slowness of the S-wave.
Figure BDA0002760070610000127
Is the one-way travel time of the source to image locations x and z,
Figure BDA0002760070610000128
is the one-way travel time of the S-wave from the receive position to image positions x and z. FIG. 1 illustrates the ERTMOGs geometry of the offset in-phase axis of a horizontal reflector with small slowness (χ) correction due to the travel time perturbations caused by the deviation in path length that the ray must travel due to the depth perturbations. Inserting equation 9 into equation 8, and considering the reflections of PP and PS, respectively, we can write the RMO perturbation equation for PP and PS images as follows:
Figure BDA0002760070610000129
wherein
Figure BDA0002760070610000131
And
Figure BDA0002760070610000132
respectively representing the slopes of the observed PP and PS events,
Figure BDA0002760070610000133
representing the perturbation deviation of the PP image,
Figure BDA0002760070610000134
representing the perturbation bias of the PS image.
To better understand equation 10, we introduce an ideal scheme in which the local offset slowness χp/sNear the local true slowness ε χp/sAnd the constant scaling epsilon is close to 1. Here, we follow Stork and at qcalcAnd q isobsApproximately a constant theta between ray segmentsp. Snell's law requires that the horizontal slowness component must be constant in any subsurface medium. Therefore, we can follow the ray path
Figure BDA0002760070610000135
Back projected to the imaging point (dashed line in fig. 1). Then, the numerator of equation 10 becomes
Figure BDA0002760070610000136
ε is a scaling constant that makes the local offset slowness xp/sNear the local true slowness ε χp/s。
Figure BDA0002760070610000137
And
Figure BDA0002760070610000138
representing the slopes of the observed PP and PS in-phase axes, respectively.
Figure BDA0002760070610000139
And
Figure BDA00027600706100001310
the slopes of the SS and SP in-phase axes, respectively. ThetapIs the angle of reflection of the P wave, thetasIs the S-wave reflection angle.
We further simplify this elastic analysis by introducing γ, which is the local slowness ratio between shear and compressional velocities at the image point. Inserting equation 11 into equation 10, we have
Figure BDA00027600706100001311
Wherein
Figure BDA00027600706100001312
Equation 12 applies to any heterogeneous medium. To fairly compare the two gathers, we need to pass the assumption in the context of a constant velocityConverting surface offset h into incidence angle thetaP. A simple trigonometric function may connect h to the depth of the reflection point z as h ═ z (tan (θ)p)+tan(θp/s)). Finally, the common offset RMO can be expressed as:
Figure BDA00027600706100001313
wherein z isppResidual time difference of PP wave at common offset, zpsIs the residual time difference of the PS waves at the common offset.
Biondi and Symes (2004) and Zhangetal (2014) in homogeneous media give δ zPPSimilar expressions of (a). But our solution (equation 12) is also valid in laterally inhomogeneous media and is simplified to the homogeneous case.
2) Co-shot and angle domain trace-centric imaging
Ertmadigs are typically generated in shot-to-shot offsets. We repeat the analysis for common offset offsets before and extend it to the common shot case. Since the travel times are the same (equation 4), equation 5 can be re-expressed as
Figure BDA0002760070610000141
Tobs(src, rec) is the observed two-way travel time (independent of χ) for a given event in the seismic recording. T iscalc(src, z) and Tcalc(rec, z) is the one-way travel time (in χ) from the source and receive locations, respectively, to the image location z.
Figure BDA0002760070610000142
And
Figure BDA0002760070610000143
are respectively Tobs(src, rec) differentiation of the source and recipient points,
Figure BDA0002760070610000144
is Tcalc(src, z) differential to the source,
Figure BDA0002760070610000145
is Tcalc(rec, z) the differential of the position of the reception point.
Figure BDA0002760070610000146
Is Tcalc(src, z) on the image position z,
Figure BDA0002760070610000147
is Tcalc(rec, z) the differential of the image position z.
Where χ and x are constants, but this assumption does not necessarily hold if the perturbations are large. In contrast to the common offset, the common shot offset propagates all receivers backwards in the offset process, where the ADCIG is built solely on the source ray to reflection angle mapping. In other words, EERTM ADCIG consists of a shot offset image mapped into ADCIG that is kinematically free of receiver slope (horizontal slowness) errors. Plotted in the same manner as in FIG. 1, FIG. 2 illustrates the above function, and FIG. 2 is a common shot point principle-the geometric configuration of ERTM ADCIGs for a migration event in a small slowness x-corrected horizontal reflector, where the receiver horizontal slowness
Figure BDA0002760070610000148
The equivalence needs to be maintained. Again, the depth perturbation is trivial, but is shown exaggerated for illustrative purposes. Because of the different slope of the earth's surface, we can observe imprecise overlap between receiver ray segments during the cine update of the imaging (as shown in FIG. 2). Mathematically, we can write as
Figure BDA0002760070610000149
The disturbance while traveling can be approximated as
Figure BDA00027600706100001410
Use of thisFor some information, we insert equation 15 into equation 14 to obtain:
Figure BDA0002760070610000151
wherein the content of the first and second substances,
Figure BDA0002760070610000152
and
Figure BDA0002760070610000153
RMO perturbation formulas for PP and PS images in the co-shot situation are respectively shown.
Figure BDA0002760070610000154
The slope of the P-wave at the source when traveling in both passes,
Figure BDA0002760070610000155
is the slope of the P-wave at the source during a single trip travel.
Equation 16 applies to any laterally inhomogeneous medium. Unlike the process in the case of the common offset in equation 11, we cannot assume θ because the source ray undergoes a large correction (FIG. 2)PIs constant. Therefore, δ θ (fig. 2) is introduced to quantify the change in the angle of incidence, giving the numerator of equation 16:
Figure BDA0002760070610000156
where the + sign represents a higher migration velocity and the-sign represents a lower migration velocity. δ θ represents the change in angle. Since δ θ is very small, it can be approximated as sin (θ)p±δθ)＝sin(θp)±δθcos(θp). Assuming that the background is a constant velocity, δ θ is easily obtained as-sin (θ) cos (θ) δ z/z. Using this relation 16 can be written as:
Figure BDA0002760070610000157
wherein the symbols
Figure BDA0002760070610000159
Depending on the magnitude of the offset velocity. (the remaining parameters are illustrated in the above formula). With these algebras, the common shot RMO can be finally expressed as
Figure BDA0002760070610000158
Wherein, δ zppResidual time difference of PP wave in common shot point condition, delta zpsThe residual time difference of the PS wave under the common shot point condition.
3) Comparison and analysis of RMO
It should be noted that the conventional ADCIGMVA is built on a common offset domain, and the implementation mode is mainly in a common shot point domain. This discrepancy may result in a series of errors associated with the velocity and amplitude analysis. In contrast to equation 13, equation 19 provides a kinematic insight into three main functions of these misalignments: ε, θ and γ.
It is clear that when the offset speed is correct (e ═ 1) and normal incidence angle (θ ═ 0), the two offsets show good agreement. However, as shown on the right side of the denominator (equation 19), the difference between the two RMO curvatures grows as theta (θ) and epsilon (ε) increase. Small angles and small speed errors result in less curvature; large angles with large velocity anomalies can produce large inconsistencies in depth or large curvatures. Secondly, equation 19 also shows that the common shot RMO exhibits a different curvature with respect to lower or higher offset velocities; that is, at higher offset speeds (. epsilon.)>1) In the case of (3), the RMO in the common offset case is greater than the RMO in the common shot case; in contrast, with a lower offset velocity (ε)<1) In contrast, the common offset provides a smaller RMO curvature. The RMO relationship in terms of speed error for equation 13 is more linear than for equation 19. Third, in a general sense, because θS<θPThe curvature of PS RMO is much smaller than PP RMO. Due to thetaSControlled by gammaThe PS RMO gradually approaches the PP RMO where γ approaches 1. For most hard rock materials, γ is typically between 1.5 and 2.0. Thus, δ z of these two domainsPSIn close proximity to each other.
To validate the above observations, we scanned a series of values of ε, θ, and γ in equations 13 and 19. In previous studies, there are many ERTMADCIG methods available. To be more direct, we have adopted the method of subsurface offset extended imaging (Yan and Sava, 2008). Analysis was performed using a simple horizontal reflector in a homogeneous medium background of z 500 m. The common offset SOGs and common shot points ADCIGs are created by a newly proposed ERTM and an original standard ERTM, respectively. With a uniform medium model we can easily convert the SOGs into the angular domain and vice versa. For fair comparison, fig. 3, 4, 5, 6, 7, and 7 illustrate the comparison in this group in the angle (top row) and surface offset field (bottom row). In fig. 3, parameters z is 500m, ∈ is 1.03, and γ is 1.22, and two lines in fig. 3 represent the analytical solutions of the common offset (equation 13) and the common shot (equation 19), respectively. Converting the SOGs into an angular domain (e-a, c-g); similarly, the ADCIGs are transformed to the surface offset field (b-f, d-h) for equivalent comparison. RMO comparison plots for parameters z 500m, e 1.05 and y 1.22 in fig. 4 and for parameters z 500m, e 1.05 and y 1.73 in fig. 5. Parameters in fig. 6: at lower deflection speeds z is 500m, e is 0.97 and y is 1.22. Parameters in fig. 7: at lower deflection speeds z is 500m, e is 0.95 and y is 1.22. In FIG. 8, reference numerals: at lower deflection speeds z is 500m, e is 0.97 and y is 1.71.
The comparison between the two RMOs is performed by predicting the real RMOs in the offset image obtained by equation 13 and equation 19, respectively. Note that for purposes of illustration, we normalize the amplitude traces from trace to trace; therefore, these contrasted gathers do not represent true amplitudes. As discussed, at faster offset speeds (fig. 3-5), the co-offset is made by a higher RMO than the co-shot ADCIGs (fig. 3-5), while for slower speeds the slope is smaller (fig. 6-8). Both mismatches increase with the angle of incidence and with the speed error. PS RMO consistently exhibited less curvature than the expected PP RMO. In contrast to PP RMO, the difference between common shot and common offset for PS RMO is negligible in the presence of reasonable gamma values (fig. 5 and 8).
As is well known, RMO plays a crucial role in the establishment of velocity models. The RMO system description between the two domains is in fact a basis. First, our analysis is based on the Stork (1992) standard, which has strong assumptions about the temporal dip and reflection angles at which the offset operator keeps constant during the fault velocity correction. In fact, the offset operation using the velocity model cannot guarantee a vertical offset other than a flat tilt angle (van Trier, 1989). Secondly, for practical problems, our zero tilt formula is applicable to a wide range of tilt angles for PP modes. The zero tilt angle approximation of PS is not very reliable due to the loss of the up-down symmetry. Finally, most importantly, the correct RMO information in anisotropic media (VTI and TTI) is more important than in the isotropic case, because the error information of the anisotropic parameters is mainly contained in large offset track sets (Tsvankin, 1996). Thus, the common shot offset distance may underestimate the velocity and anisotropy parameter corrections at higher offset velocities, but overestimate the velocity and anisotropy parameter corrections at lower offset velocities.
The embodiment of the invention is as follows: in an embodiment, we compare two gathers using two synthetic examples (ocean and land). The ocean example is the correct part of the BP2004 model, the BP2004 model is shown in FIG. 9, and FIGS. 9a and 9b are true and smooth compressional velocity models. Fig. 9c and 9d are true and smooth shear velocity models. The units of 9a to 9d are meters/second. FIG. 9e is a density model in kg/cm 3. This acquisition included 500 surface explosive sources and 500 equally spaced subsea nodes (OBNs). In the smooth velocity model, we use linearly increasing VP(FIG. 9b) instead of the exact VPModel (fig. 9 a). The smoothed VS (fig. 9d) was similarly obtained from the exact S-wave model (fig. 9 c). The exact density ρ (fig. 9e) and velocity are used to model the multicomponent recording of the OBN location. Using equation 2, fig. 10 shows the isolated P and S wavefields propagated by the receiver side at 3.0S for the exact model. A receiving wavefield using the proposed decomposition methodBP model of snapshot. (FIGS. 10a and 10b) coupling the horizontal and vertical wavefields. (FIG. 10c and FIG. 10d) separated horizontal and vertical p-type wavefields. (FIGS. 10e and 10f) horizontal and vertical s-wave fields. All gray scales have a unit of m/s. For the sake of detail we put the receiver position in the middle of the model. As described in our proposed workflow, a small fraction of the offsets of the multi-component records are propagated backwards. The phase and amplitude in the six panels are consistent with the expected reference results. This indicates that the proposed wavefield decomposition strategy has good accuracy. Notably, because the S-wave energy is contributed by the wave mode conversion of the explosive source, it is relatively weak. FIG. 11 shows a comparison of PP and PS between SOGs and ADCIGs on the same CDPs using the smoothed velocity model (FIGS. 9b and 9d, respectively), with CDP positions distributed horizontally along the surface. The reflection of the mark (yellow arrow) is bent upwards due to the lower speed of the shift. As shown in fig. 9, the offset model is typically lower than the exact model. Band pass filters (1-2-12-14 Hz) were applied to eliminate ERTM backscatter noise. The PP and PS gathers result in a close resolution and amplitude of the depth in-phase axis.
This example cannot accurately convert the two domains to each other, so we cannot make a completely fair comparison like the previous homogeneous example. But for these curve-up events we can observe from ADCIGs (fig. 11b and 11d) a larger RMO curvature than SOG (fig. 11a and 11c), while the error between PS gathers is smaller than PP gathers. These results support the results of fig. 8 and equation 19, since the tilt angle of most reflectors is small (fig. 9e), i.e., at lower speeds, the common offset domain produces less RMO than the common shot domain. Fig. 12 shows the zero offset and zero angle PP image portions, and the arrows in fig. 12 indicate that the zero offset section produces less offset wobble noise than the zero angle section. In contrast to fig. 11, we do nothing amplitude correction. If the offset is at true speed, the zero offset image portion should be very close to the zero angle portion if these planar reflectors are used. Since our migration velocity is very far from the true velocity, the zero offset PP (fig. 12a) produces less offset wobble noise than the zero angle PP, as highlighted by the yellow arrows. These observations indicate that velocity errors produce significant disturbances caused by wavefront propagation from different surface offsets, while SOGs are less affected by velocity errors (RMO functions).
Next, the land example (ZHao and Li, 2018a, 2018 b; ZHao et al, 2018b) is selected as a supplementary case to the previous sea example. It is a 2D slice from a 3D coal seam drought model. The acquisition includes 330 surface sources and 1300 equally spaced detectors. The dense pitch (5m) is used to effectively remove linear and dispersive noise. Near-surface scattering ranges from a few meters to tens of meters. Below the near surface, there is simple stratigraphic geology with associated dip angles typically less than 5 °. Several layers covering the target reflector with a large velocity contrast at a depth of about 2200 m. We use precision VPThe reservoir velocity (black arrow) is reduced for the model ∈ 0.85 (fig. 13a), forming an offset velocity model (fig. 13b) instead of using the linear initial model (previous example). FIG. 13: and (4) a coal bed model. Fig. 13a and 13b are true smoothed longitudinal velocity models. Fig. 13c and 13d are true smooth shear velocity models. FIGS. 13a to 13d are in m/s, and FIG. 13e is a density model in kg/cm3. The offset V is obtained from the exact S-wave model (FIG. 13c) approximationS(FIG. 13 d). The exact density ρ (fig. 13e) and velocity are used to simulate a multicomponent recording in the presence of a free surface. FIG. 14: and performing a wave field decomposition experiment on the land model by using the proposed decomposition method. FIGS. 14a and 14b are coupled horizontal and vertical wavefields. FIGS. 14c and 14d are separate horizontal and vertical p-type wavefields. FIGS. 14e and 14f are horizontal and vertical s-wavefields. All units are m/s. FIG. 14 shows the separate P-wave and S-wave fields propagated on the source side using equation 2. Compared to fig. 10, the S-wave energy is relatively strong due to the use of the vibroseis.
As with the marine case, fig. 15 compares fig. 15aPP and 15c PS SOG and fig. 15bPP and 15d PS ADCIGs of ERTM using an offset velocity model. CDP locations are distributed horizontally along the surface. The reflection of the marker (arrow) curves upwards due to the low migration velocity (target reservoir). Fig. 15 shows a comparison of PP and PS at selected CDPs using the offset velocity model. Since these are land data, the signal-to-noise ratio of the reflections is typically lower than in the marine case, and therefore the energy of the in-phase axis of all gathers is reduced. Because the migration velocity is very close to the true velocity, we only observe the isophase axis of the target reservoir (yellow arrow) reflection with greater curvature due to lower velocity. Also, a larger RMO curvature was observed across the angle compared to the offset domain (fig. 15). FIG. 16: the zero offset PP image slices of the SOGs of fig. 16a are compared to the zero angle PP ADCIGs image slices of the dry coal seam model of fig. 16 b. The arrows indicate the energy reduction for the zero angle section compared to the zero offset section. The same process as the previous example is repeated and fig. 16 shows the original amplitudes of the zero offset and zero angle image portions of fig. 15. In comparison with fig. 12, the PP and PS fractions show comparable quality in addition to the target reservoir. As indicated by the yellow arrows, PP ADCIGs (FIG. 16c) have less focal energy than SOGs (FIG. 16 a). These observations support the conclusion that velocity errors wrongly map surface offset energy to reflection angles, because surface regions are less affected by velocity errors than subsurface regions.
According to the method, the obtained PS surface offset gathers are superposed to obtain the PS common offset, and the acquisition of the PP and PS surface offset gathers is independent of the angle, so that the calculation cost is reduced, and the acquisition efficiency of the surface offset gathers is improved.
The invention also discloses a surface offset gather acquisition system, as shown in fig. 18, the surface offset gather acquisition system comprises: the seismic source comprises a seismic source, a first detector and a second detector, wherein the second detector is located at the position of the seismic source, and the first detectors are different in distance from the seismic source.
A surface offset gather acquisition system further comprises:
a wavelet collecting module 201, configured to collect a plurality of wavelets by the first detector; the wavelets are wavelets under different offset conditions, and the offset is the distance from the first detector to the seismic source.
And a source wavefield acquisition module 202, configured to perform double integration on the wavelets to obtain a source wavefield.
A seismic source wavefield separation module 203 for separating the seismic source wavefield into a seismic source longitudinal wavefield and a seismic source transverse wavefield.
And the backward propagation wave transmitting module 204 is used for transmitting the backward propagation wave to the corresponding seismic source through the first detector.
The backward propagation wave transmitting module 204 specifically includes a module for transmitting a backward propagation wave to a corresponding seismic source through the velocity model of the position of the first detector.
And a backward wave receiving module 205, configured to receive the backward wave through the second detector.
And the back propagation wave field acquisition module 206 is configured to perform double integration on the back propagation waves to obtain a back propagation wave field.
A backward wave field separation module 207 for separating the backward wave field into a backward longitudinal wave field and a backward transverse wave field.
And the surface offset gather acquisition module 208 is configured to acquire a PP surface offset gather and a PS surface offset gather according to the seismic source longitudinal wave field, the seismic source shear wave field, the back-propagation longitudinal wave field, and the back-propagation shear wave field.
And a PP common offset gather obtaining module 209, configured to superimpose the obtained PP surface offset gathers to obtain a PP common offset gather.
And a PS common offset gather obtaining module 210, configured to superimpose the obtained PS surface offset gathers to obtain a PS common offset gather.
The wave equation of the wavelet is:
Figure BDA0002760070610000211
where v represents the velocity of the particle at the propagation time t, ρ is the density of the medium, λ is the first Lame coefficient, and μ is the second Lame coefficient.
The formula for separating the seismic source wavefield into a seismic source longitudinal wavefield and a seismic source transverse wavefield is:
Figure BDA0002760070610000212
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure BDA0002760070610000213
a local P-wave representing the wavelet,
Figure BDA0002760070610000214
a local S-wave representing the wavelet in question,
Figure BDA0002760070610000215
a source longitudinal wave field is represented,
Figure BDA0002760070610000216
the source transverse wavefield is represented.
The formula for obtaining the PP surface offset trace set and the PS surface offset trace set according to the longitudinal wave field, the source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field is as follows:
Figure BDA0002760070610000217
Figure BDA0002760070610000218
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure BDA0002760070610000219
a source longitudinal wavefield is represented,
Figure BDA00027600706100002110
representing the source transverse wave field, sgnPPSign, sgn, representing a gather of PP picturesPSSymbols representing PS image gathers, d represents the wavelet multi-componentThe information is recorded and recorded in a recording medium,
Figure BDA00027600706100002111
a counter-propagating longitudinal wave field is represented,
Figure BDA00027600706100002112
representing the backward transverse wavefield.
The embodiments in the present description are described in a progressive manner, each embodiment focuses on differences from other embodiments, and the same and similar parts among the embodiments are referred to each other. For the system disclosed by the embodiment, the description is relatively simple because the system corresponds to the method disclosed by the embodiment, and the relevant points can be referred to the method part for description.
The principles and embodiments of the present invention have been described herein using specific examples, which are provided only to help understand the method and the core concept of the present invention; meanwhile, for a person skilled in the art, according to the idea of the present invention, the specific embodiments and the application range may be changed. In view of the above, the present disclosure should not be construed as limiting the invention.

Claims (8)

1. A surface offset gather acquisition method is applied to a surface offset gather acquisition system, and the system comprises a seismic source, a first detector and a second detector, wherein the second detector is positioned at the position of the seismic source, and a plurality of the first detectors are different in distance from the seismic source;
the method comprises the following steps:
collecting a plurality of wavelets by the first detector; the plurality of wavelets are a plurality of wavelets under different offset conditions, and the offset is the distance from the first detector to the seismic source;
performing double integration on the wavelets to obtain a seismic source wave field;
separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield;
transmitting a counter wave to a corresponding seismic source through the first detector;
receiving the counter-propagating wave by the second detector;
performing double integration on the backward wave to obtain a backward wave field;
separating the backward wave field into a backward longitudinal wave field and a backward transverse wave field;
obtaining a PP surface offset trace set and a PS surface offset trace set according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field;
superposing the acquired PP earth surface offset gather to obtain a PP common offset gather;
and superposing the obtained PS surface offset gather to obtain a PS common offset gather.
2. The surface offset gather acquisition method of claim 1, wherein the wave equation of the wavelet is:
Figure FDA0002760070600000011
where v represents the velocity of the particle at the propagation time t, ρ is the density of the medium, λ is the first Lame coefficient, and μ is the second Lame coefficient.
3. The surface offset gather acquisition method of claim 1, wherein the formula for separating the source wavefield into a source longitudinal wavefield and a source transverse wavefield is:
Figure FDA0002760070600000012
Figure FDA0002760070600000013
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure FDA0002760070600000014
a local P-wave representing the wavelet,
Figure FDA0002760070600000015
a local S-wave representing the wavelet in question,
Figure FDA0002760070600000016
a source longitudinal wave field is represented,
Figure FDA0002760070600000017
the source transverse wavefield is represented.
4. The surface offset gather acquisition method of claim 1 wherein the formula for obtaining a PP surface offset gather and a PS surface offset gather from the compressional field, the source transverse wavefield, the back-propagation compressional field, and the back-propagation transverse wavefield is:
Figure FDA0002760070600000021
Figure FDA0002760070600000022
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure FDA0002760070600000023
a source longitudinal wavefield is represented,
Figure FDA0002760070600000024
representing the source transverse wave field, sgnPPSymbols representing gathers of PP images, sgnPSA symbol representing a PS image gather, d represents the wavelet multi-component record,
Figure FDA0002760070600000025
a counter-propagating longitudinal wave field is represented,
Figure FDA0002760070600000026
representing the backward transverse wavefield.
5. A surface offset gather acquisition system, the system comprising: the seismic source comprises a seismic source, a first detector and a second detector, wherein the second detector is positioned at the position of the seismic source, and the first detectors are different in distance from the seismic source;
the system further comprises:
the wavelet acquisition module is used for acquiring a plurality of wavelets through the first detector; the plurality of wavelets are a plurality of wavelets under different offset conditions, and the offset is the distance from the first detector to the seismic source;
the seismic source wave field acquisition module is used for carrying out double integration on the wavelets to obtain a seismic source wave field;
the seismic source wave field separation module is used for separating the seismic source wave field into a seismic source longitudinal wave field and a seismic source transverse wave field;
the counter propagation wave transmitting module is used for transmitting counter propagation waves to the corresponding seismic source through the first detector;
the backward wave receiving module is used for receiving the backward wave through the second detector;
the device comprises a back wave field acquisition module, a back wave field acquisition module and a back wave detection module, wherein the back wave field acquisition module is used for carrying out double integration on the back waves to obtain a back wave field;
the backward wave field separation module is used for separating the backward wave field into a backward longitudinal wave field and a backward transverse wave field;
the earth surface offset gather acquisition module is used for acquiring a PP earth surface offset gather and a PS earth surface offset gather according to the seismic source longitudinal wave field, the seismic source transverse wave field, the back-propagation longitudinal wave field and the back-propagation transverse wave field;
the PP common offset distance offset gather acquisition module is used for superposing the acquired PP earth surface offset distance gathers to obtain a PP common offset distance offset gather;
and the PS common offset distance offset gather acquisition module is used for superposing the acquired PS surface offset distance gathers to obtain the PS common offset distance offset gathers.
6. The surface offset gather acquisition system of claim 5 wherein the wave equation of the wavelet is:
Figure FDA0002760070600000031
where v represents the velocity of the particle at the propagation time t, ρ is the density of the medium, λ is the first Lame coefficient, and μ is the second Lame coefficient.
7. The surface offset gather acquisition system of claim 5 wherein the formula that separates the source wavefield into a source longitudinal wavefield and a source transverse wavefield is:
Figure FDA0002760070600000032
Figure FDA0002760070600000033
wherein v issrc' denotes the source wavefield, p is the medium density,
Figure FDA0002760070600000034
a local P-wave representing the wavelet,
Figure FDA0002760070600000035
a local S-wave representing the wavelet in question,
Figure FDA0002760070600000036
a source longitudinal wave field is represented,
Figure FDA0002760070600000037
the source transverse wavefield is represented.
8. The surface offset gather acquisition system of claim 5 wherein the formula for obtaining a PP surface offset gather and a PS surface offset gather from the P-wave field, the source wavefield, the back-propagation P-wave field, and the back-propagation P-wave field is:
Figure FDA0002760070600000038
Figure FDA0002760070600000039
wherein, IppRepresenting PP image gathers corresponding to PP surface offset gathers, IpsRepresents a PS image gather corresponding to the PS surface offset gather, x and z respectively represent coordinates of an x axis and a y axis of an image point, h represents offset, t represents time,
Figure FDA0002760070600000041
a source longitudinal wavefield is represented,
Figure FDA0002760070600000042
representing the source transverse wave field, sgnPPSymbols representing gathers of PP images, sgnPSA symbol representing a PS image gather, d represents the wavelet multi-component record,
Figure FDA0002760070600000043
a counter-propagating longitudinal wave field is represented,
Figure FDA0002760070600000044
representing the backward transverse wavefield.
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