Amplitude correction method and device for DAS-VSP seismic data

Abstract

The invention discloses a DAS-VSP seismic data amplitude correction method and device, and belongs to the field of oil exploration. The method comprises the following steps: performing ray tracing on a plurality of seismic waves excited by a plurality of shot points of a DAS-VSP system to determine imaging points respectively corresponding to the plurality of seismic waves and included angles between reflected waves of the plurality of seismic waves and an optical fiber survey line in a well where a detection point is located; determining amplitude correction coefficients of the plurality of seismic waves at respective imaging points based on the included angles between the reflected waves of the plurality of seismic waves and the optical fiber survey line in the well and the types of the plurality of seismic waves; dividing the plurality of seismic waves into a plurality of seismic wave groups, wherein the imaging points corresponding to the same seismic wave group are the same; and for each seismic wave group in the plurality of seismic wave groups, performing amplitude correction on the seismic data at the imaging point corresponding to the seismic wave group. According to the method, the DAS-VSP seismic data is corrected through the amplitude correction coefficient, so that the seismic data is more accurate.

Description

Technical Field

[0001] The present application relates to the field of oil exploration, and in particular to a method and device for amplitude correction of DAS-VSP seismic data. Background Art

[0002] In the process of oil and gas exploration, it is necessary to use in-well seismic technology to perform detailed imaging of complex underground structures. Currently, DAS (Distributed fiber Acoustic Sensing)-VSP (Vertical Seismic Profiling) technology has been widely studied and used due to its many advantages.

[0003] However, since the VSP observation system is asymmetric, this will inevitably cause the imaging profile to have the "arcing" phenomenon, which will reduce the profile quality and affect the interpretation accuracy. In addition, there will be differences between the data collected by the DAS-VSP technology and the data collected by conventional detectors. Therefore, it is very important to correct the data collected by the DAS-VSP technology and suppress or eliminate the factors that cause the "arcing" phenomenon. Summary of the invention

[0004] The present application provides a method and device for amplitude correction of DAS-VSP seismic data, which can correct the data collected by DAS-VSP technology and suppress or eliminate the factors causing the "arcing" phenomenon. The technical solution is as follows:

[0005] In one aspect, a method for amplitude correction of DAS-VSP seismic data is provided, the method comprising:

[0006] By performing ray tracing on multiple seismic waves excited by multiple shot points of the DAS-VSP system, imaging points corresponding to the multiple seismic waves and angles between reflected waves of the multiple seismic waves and the optical fiber measurement line in the well where the detection points are located are determined, wherein the imaging point refers to the intersection of the incident wave and the reflected wave of the seismic wave;

[0007] Determining amplitude correction coefficients of the multiple seismic waves at respective imaging points based on angles between the reflected waves of the multiple seismic waves and the optical fiber measuring line in the well and the types of the multiple seismic waves;

[0008] Dividing the multiple seismic waves into multiple seismic wave groups, wherein the imaging points corresponding to the same seismic wave group are the same;

[0009] For each of the multiple seismic wave groups, amplitude correction is performed on seismic data at an imaging point corresponding to the seismic wave group based on an amplitude correction coefficient of each seismic wave in the seismic wave group at a respective imaging point.

[0010] Optionally, the method of determining the imaging points respectively corresponding to the multiple seismic waves and the angles between the reflected waves of the multiple seismic waves and the optical fiber measurement line in the well where the detection points are located by performing ray tracing on the multiple seismic waves excited by the multiple shot points of the DAS-VSP system comprises:

[0011] For a target seismic wave among the multiple seismic waves, ray tracing is performed on the target seismic wave to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point, wherein the target detection point refers to a detection point on the optical fiber survey line in the well for detecting the reflected wave of the target seismic wave, and the first slowness vector refers to a slowness vector in a vertical direction;

[0012] Acquire the seismic wave velocity of the target detection point from a velocity grid model, wherein the velocity grid model is used to reflect the seismic wave velocity at different stratum positions in the exploration area;

[0013] Determine the angle between the reflected wave of the target seismic wave and the vertical direction based on the first slowness vector and the seismic wave velocity of the target detection point to obtain a first angle;

[0014] The target angle is subtracted from the first angle to obtain the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well, wherein the target angle is the angle between the optical fiber measuring line in the well and the vertical direction.

[0015] Optionally, performing ray tracing on the target seismic wave to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point includes:

[0016] Let i=1, take the shot point used to excite the target seismic wave as the i-th point on the incident wave of the target seismic wave, draw a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point, take the intersection point between the ray i and the boundary of the grid i as the i+1-th point on the incident wave of the target seismic wave, and the grid i refers to the first grid in the velocity grid model whose boundary intersects with the ray i;

[0017] If the i+1th point is not a point on the seismic wave reflection surface, determine the ray direction of the target seismic wave at the i+1th point, set i=i+1, and return to the step of drawing a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point;

[0018] If the i+1th point is a point on the seismic wave reflection surface, the i+1th point is determined as the imaging point of the target seismic wave, and j=1 is set. Based on the ray direction of the target seismic wave at the i-th point, the ray direction of the j-th point on the reflection wave of the target seismic wave is determined;

[0019] According to the ray direction of the target seismic wave at the j-th point, a ray j is drawn from the j-th point, and the intersection point between the ray j and the boundary of the grid j is taken as the j+1-th point on the reflection wave of the target seismic wave, and the grid j refers to the first grid in the velocity grid model whose boundary intersects with the ray j;

[0020] If the j+1th point is not the target detection point, determine the ray direction of the target seismic wave at the j+1th point, set j=j+1, and return to the step of drawing a ray j from the i-th point according to the ray direction of the target seismic wave at the j-th point;

[0021] If the j+1th point is the target detection point, the slowness vector of the jth point in the vertical direction is determined as the first slowness vector.

[0022] Optionally, determining the ray direction of the target seismic wave at the (i+1)th point includes:

[0023] Based on the travel time of the i-th point, determine the slowness change rate of the i-th point, where the slowness change rate refers to the change rate of the slowness vector of the i-th point in the horizontal direction in the vertical direction;

[0024] Determine a first distance vector and a second distance vector between the (i+1)th point and the (i)th point, wherein the first distance vector refers to a distance vector in a horizontal direction, and the second distance vector refers to a distance vector in a vertical direction;

[0025] Based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point and the second distance vector, determine the slowness vector of the i+1-th point in the horizontal direction; based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point and the first distance vector, determine the slowness vector of the i+1-th point in the vertical direction;

[0026] Based on the slowness vector of the i+1th point in the horizontal direction, the slowness vector of the i+1th point in the vertical direction and the seismic wave velocity indicated by the grid i, the ray direction of the target seismic wave at the i+1th point is determined.

[0027] Optionally, determining the amplitude correction coefficients of the multiple seismic waves at respective imaging points based on the angles between the reflected waves of the multiple seismic waves and the optical fiber measuring line in the well and the types of the multiple seismic waves includes:

[0028] For a target seismic wave among the multiple seismic waves, if the type of the target seismic wave is a longitudinal wave, the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point;

[0029] If the type of the target seismic wave is a converted wave, the reciprocal of the sine value of twice the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point.

[0030] In another aspect, a device for amplitude correction of DAS-VSP seismic data is provided, the device comprising:

[0031] A first determination module is used to determine imaging points corresponding to the multiple seismic waves and angles between the reflected waves of the multiple seismic waves and the optical fiber measurement line in the well where the detection point is located by performing ray tracing on the multiple seismic waves excited by the multiple shot points of the DAS-VSP system, wherein the imaging point refers to the intersection of the incident wave and the reflected wave of the seismic wave;

[0032] A second determination module is used to determine the amplitude correction coefficients of the multiple seismic waves at respective imaging points based on the angles between the reflection waves of the multiple seismic waves and the optical fiber measuring line in the well and the types of the multiple seismic waves;

[0033] A grouping module, used for dividing the plurality of seismic waves into a plurality of seismic wave groups, wherein the imaging points corresponding to the same seismic wave group are the same;

[0034] A correction module is used to perform amplitude correction on seismic data at an imaging point corresponding to each seismic wave group in the multiple seismic wave groups based on an amplitude correction coefficient of each seismic wave in the seismic wave group at its respective imaging point.

[0035] Optionally, the first determining module includes:

[0036] a tracking and determining submodule, configured to perform ray tracing on a target seismic wave among the multiple seismic waves to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point, wherein the target detection point refers to a detection point on the optical fiber survey line in the well for detecting the reflected wave of the target seismic wave, and the first slowness vector refers to a slowness vector in a vertical direction;

[0037] A velocity acquisition submodule, used to acquire the seismic wave velocity of the target detection point from a velocity grid model, wherein the velocity grid model is used to reflect the seismic wave velocity at different stratum positions in the exploration area;

[0038] A first angle determination submodule, configured to determine an angle between the reflected wave of the target seismic wave and a vertical direction based on the first slowness vector and the seismic wave velocity of the target detection point, to obtain a first angle;

[0039] The second angle determination submodule is used to subtract the target angle from the first angle to obtain the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well, wherein the target angle is the angle between the optical fiber measuring line in the well and the vertical direction.

[0040] Optionally, the tracking determination submodule is specifically used for:

[0041] Let i=1, take the shot point used to excite the target seismic wave as the i-th point on the incident wave of the target seismic wave, draw a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point, take the intersection point between the ray i and the boundary of the grid i as the i+1-th point on the incident wave of the target seismic wave, and the grid i refers to the first grid in the velocity grid model whose boundary intersects with the ray i;

[0042] If the i+1th point is not a point on the seismic wave reflection surface, determine the ray direction of the target seismic wave at the i+1th point, set i=i+1, and return to the step of drawing a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point;

[0043] If the i+1th point is a point on the seismic wave reflection surface, the i+1th point is determined as the imaging point of the target seismic wave, and j=1 is set. Based on the ray direction of the target seismic wave at the i-th point, the ray direction of the j-th point on the reflection wave of the target seismic wave is determined;

[0044] According to the ray direction of the target seismic wave at the j-th point, a ray j is drawn from the j-th point, and the intersection point between the ray j and the boundary of the grid j is taken as the j+1-th point on the reflection wave of the target seismic wave, and the grid j refers to the first grid in the velocity grid model whose boundary intersects with the ray j;

[0045] If the j+1th point is not the target detection point, determine the ray direction of the target seismic wave at the j+1th point, set j=j+1, and return to the step of drawing a ray j from the i-th point according to the ray direction of the target seismic wave at the j-th point;

[0046] If the j+1th point is the target detection point, the slowness vector of the jth point in the vertical direction is determined as the first slowness vector.

[0047] Optionally, the tracking determination submodule is specifically used for:

[0048] Based on the travel time of the i-th point, determine the slowness change rate of the i-th point, where the slowness change rate refers to the change rate of the slowness vector of the i-th point in the horizontal direction in the vertical direction;

[0049] Determine a first distance vector and a second distance vector between the (i+1)th point and the (i)th point, wherein the first distance vector refers to a distance vector in a horizontal direction, and the second distance vector refers to a distance vector in a vertical direction;

[0050] Based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point and the second distance vector, determine the slowness vector of the i+1-th point in the horizontal direction; based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point and the first distance vector, determine the slowness vector of the i+1-th point in the vertical direction;

[0051] Based on the slowness vector of the i+1th point in the horizontal direction, the slowness vector of the i+1th point in the vertical direction and the seismic wave velocity indicated by the grid i, the ray direction of the target seismic wave at the i+1th point is determined.

[0052] Optionally, the second determining module is specifically configured to:

[0053] For a target seismic wave among the multiple seismic waves, if the type of the target seismic wave is a longitudinal wave, the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point;

[0054] If the type of the target seismic wave is a converted wave, the reciprocal of the sine value of twice the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point.

[0055] On the other hand, a computer device is provided, comprising a memory and a processor, wherein the memory is used to store a computer program, and the processor is used to execute the computer program stored in the memory to implement the steps of the amplitude correction method of DAS-VSP seismic data described above.

[0056] On the other hand, a computer-readable storage medium is provided, wherein a computer program is stored in the storage medium, and when the computer program is executed by a processor, the steps of the amplitude correction method of DAS-VSP seismic data are implemented.

[0057] In another aspect, a computer program product is provided comprising instructions, which, when executed on a computer, cause the computer to perform the steps of the amplitude correction method for DAS-VSP seismic data described above.

[0058] The technical solution provided by this application can at least bring the following beneficial effects:

[0059] By tracking the direction of the seismic wave rays, the angle between the reflected wave and the optical fiber line in the well is obtained. The DAS-VSP seismic data of different seismic wave types are corrected by a custom amplitude correction coefficient based on the angle, making the amplitude of the seismic wave signal closer to the true value and the seismic data more accurate. At the same time, the amplitude of the corresponding noise can be closer or the same, thereby reducing the "arcing" phenomenon of the imaging section and facilitating the subsequent application and processing of seismic data. BRIEF DESCRIPTION OF THE DRAWINGS

[0060] In order to more clearly illustrate the technical solutions in the embodiments of the present application, the drawings required for use in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work.

[0061] Figure 1 is a flow chart of an amplitude correction method for DAS-VSP seismic data provided by an embodiment of the present application;

[0062] Figure 2 is a schematic diagram of a DAS-VSP seismic wave excitation-receiving system provided in an embodiment of the present application;

[0063] Figure 3 It is a flow chart of a method for determining an imaging point corresponding to a target seismic wave and an angle between a reflected wave of the target seismic wave and an optical fiber measuring line in a well where a detection point is located, provided in an embodiment of the present application;

[0064] Figure 4 is a schematic diagram of distance vectors in the horizontal and vertical directions provided in an embodiment of the present application;

[0065] Figure 5 It is a schematic diagram of tracing rays for target seismic waves provided in an embodiment of the present application;

[0066] Figure 6It is a schematic diagram of the result of using original DAS-VSP seismic data to perform in-phase stacking of seismic data received from imaging points at different depths, provided in an embodiment of the present application;

[0067] Figure 7 It is a schematic diagram of the result of using the corrected DAS-VSP seismic data to perform in-phase stacking of seismic data received from imaging points at different depths, provided in an embodiment of the present application;

[0068] Figure 8 It is a structural schematic diagram of an amplitude correction device for DAS-VSP seismic data provided in an embodiment of the present application;

[0069] Fig. 9 It is a structural diagram of a computer device provided in an embodiment of the present application. DETAILED DESCRIPTION

[0070] In order to make the objectives, technical solutions and advantages of the embodiments of the present application clearer, the implementation methods of the present application will be further described in detail below in conjunction with the accompanying drawings.

[0071] Before explaining in detail the amplitude correction method for DAS-VSP seismic data provided in the embodiment of the present application, the application scenario and implementation environment involved in the embodiment of the present application are first introduced.

[0072] In the process of oil and gas exploration, it is necessary to use borehole seismic technology to perform fine imaging of complex underground structures. Driven by the continuous application demand, DAS-related technologies, especially DAS-VSP technology, have gradually become an important development direction of borehole seismic technology due to its advantages of high density, high efficiency, good consistency, multiple repeated observations and low cost in data acquisition. However, there are differences between the data collected by DAS-VSP technology and the data collected by conventional detectors. In addition, since the VSP observation system is asymmetric, the imaging profile after migration has the phenomenon of "arcing", and the noise is very serious, which affects the final imaging quality. Therefore, it is very important to better correct the DAS acquisition data and suppress or eliminate the factors that cause the "arcing" phenomenon.

[0073] In the related technology, the traditional method needs to be repeated many times, but it can only basically eliminate the interference noise. The commonly used method is to stack the pre-stack CDP (Common Depth Point) gathers in phase so that the corresponding (the amplitudes in the same window segment are opposite in direction and the amplitudes are the same) noise signals cancel each other out. However, this method requires the amplitude of the seismic data to be as accurate as possible to be well implemented.

[0074] In view of the above situation, the present application uses a custom amplitude correction coefficient to perform amplitude correction on the seismic data collected by the DAS-VSP technology, correct the corresponding noise signal amplitude, make the amplitude difference of the corresponding noise signal as small as possible, and accurately correct the amplitude of the effective signal, so that when the pre-stack CDP gather is stacked in phase, the effective signal can be better enhanced and the noise can be reduced, thereby reducing the "arcing" phenomenon of the imaging section.

[0075] The executor of the amplitude correction method of DAS-VSP seismic data provided in the embodiment of the present application is a computer device, such as a PC (Personal Computer), a mobile phone, a smart phone, a PDA (Personal Digital Assistant), a PPC (Pocket PC), a tablet computer, a smart car machine, etc.

[0076] Those skilled in the art should understand that the above-mentioned computer devices are only examples, and other existing or future computer devices, if applicable to the embodiments of the present application, should also be included in the protection scope of the embodiments of the present application and are included here by reference.

[0077] It should be noted that the application scenarios and implementation environments described in the embodiments of the present application are intended to more clearly illustrate the technical solutions of the embodiments of the present application, and do not constitute a limitation on the technical solutions provided in the embodiments of the present application. Ordinary technicians in this field can know that with the emergence of new application scenarios and the evolution of the implementation environment, the technical solutions provided in the embodiments of the present application are also applicable to similar technical problems.

[0078] Next, the amplitude correction method for DAS-VSP seismic data provided in the embodiment of the present application is explained in detail.

[0079] Please refer to Figure 1 , Figure 1 It is a flow chart of an amplitude correction method for DAS-VSP seismic data provided in an embodiment of the present application. The method comprises the following steps.

[0080] Step 101: By performing ray tracing on multiple seismic waves excited by multiple shot points of the DAS-VSP system, imaging points corresponding to the multiple seismic waves and angles between reflected waves of the multiple seismic waves and the optical fiber survey line in the well where the detection points are located are determined. The imaging point refers to the intersection of the incident wave and the reflected wave of the seismic wave.

[0081] Among them, the shot point is the location where seismic waves are excited in the seismic field work; in order to realize the detection of seismic data, an optical fiber line is usually deployed in the well, which is called the well optical fiber line, and the well optical fiber line includes multiple detection points. The well optical fiber line is a fiber optic sensor arranged inside the well wall, which can be a Raman scattering fiber optic sensor, a Brillouin scattering fiber optic sensor, or other types of fiber optic sensors. In actual applications, the type of fiber optic sensor used can be selected according to application requirements, and the embodiments of the present application do not limit this.

[0082] It should be noted that the positions of the above-mentioned multiple shot points, detection points and light measurement lines in the well are all known data.

[0083] For example, please refer to Figure 2 , Figure 2 This is a schematic diagram of a seismic wave excitation-receiving system. Figure 2 Point S represents the shot point, ray P1 represents the incident wave of a seismic wave, ray P2 represents the reflected wave of the seismic wave, point M represents the imaging point corresponding to the seismic wave, that is, the intersection of ray P1 and ray P2, L represents the optical fiber survey line in the well, points R1, R2, and R3 represent the three detection points on the optical fiber survey line L in the well, R1 represents the detection point corresponding to the above seismic wave, and β represents the angle between the reflected wave P2 of the above seismic wave and the optical fiber survey line L in the well.

[0084] It should be noted that the propagation directions of the incident wave and the reflected wave in the figure are only for illustration. In the embodiments of the present application and in actual applications, due to the complex and changeable geological structure, the propagation medium and propagation speed at different locations may be different, so the propagation directions of the incident wave and the reflected wave are variable.

[0085] In some embodiments, please refer to Figure 3 , by performing ray tracing on multiple seismic waves excited by multiple shot points of the DAS-VSP system, the imaging points corresponding to the multiple seismic waves and the angles between the reflected waves of the multiple seismic waves and the optical fiber measurement line in the well where the detection points are located are determined, including the following steps (1)-(4):

[0086] (1) For a target seismic wave among multiple seismic waves, ray tracing is performed on the target seismic wave to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point, where the target detection point refers to a detection point on an optical fiber survey line in a well for detecting the reflected wave of the target seismic wave, and the first slowness vector refers to a slowness vector in a vertical direction.

[0087] Among them, the target seismic wave is a seismic wave being processed among multiple seismic waves; ray tracing is to track the propagation direction of the incident wave and the reflected wave of the target seismic wave; the slowness vector is an attribute of a segment of ray, which is composed of the slowness value of the medium in which the segment of ray is located and the direction of the segment of ray, wherein the slowness is the reciprocal of the propagation speed of the segment of ray in the medium in which it is located, and the slowness vector in the vertical direction includes the slowness value and the angle between the direction of the segment of ray and the vertical direction.

[0088] In some embodiments, ray tracing is performed on a target seismic wave to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point, including the following steps af:

[0089] a. Let i = 1, and take the shot point used to excite the target seismic wave as the i-th point on the incident wave of the target seismic wave. According to the ray direction of the target seismic wave at the i-th point, draw a ray i from the i-th point, and take the intersection of ray i and the boundary of grid i as the i+1-th point on the incident wave of the target seismic wave. Grid i refers to the first grid in the velocity grid model where the boundary intersects with ray i.

[0090] The velocity grid model is a velocity field model that grids the propagation velocity of seismic waves at different underground locations. The seismic waves have the same / different velocities when propagating in each grid, and the magnitudes of these velocities are known. The velocity grid model used can be selected according to actual application requirements, and the embodiments of the present application do not limit this.

[0091] It should also be noted that the ray direction of the target seismic wave at the shot point is also known data.

[0092] b. If the i+1th point is not a point on the seismic wave reflection surface, determine the ray direction of the target seismic wave at the i+1th point, set i=i+1, and return to the step of drawing a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point.

[0093] It should be noted that the position of the seismic wave reflection surface is known data.

[0094] In some embodiments, based on the travel time of the i-th point, the slowness change rate of the i-th point is determined. The slowness change rate refers to the change rate of the slowness vector of the i-th point in the horizontal direction in the vertical direction. The first distance vector and the second distance vector between the (i + 1)-th point and the i-th point are determined. The first distance vector refers to the distance vector in the horizontal direction, and the second distance vector refers to the distance vector in the vertical direction. Based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point, and the second distance vector, the slowness vector of the (i + 1)-th point in the horizontal direction is determined. Based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point, and the first distance vector, the slowness vector of the (i + 1)-th point in the vertical direction is determined. Based on the slowness vector of the (i + 1)-th point in the horizontal direction, the slowness vector of the (i + 1)-th point in the vertical direction, and the seismic wave velocity indicated by grid i, the ray direction of the target seismic wave at the (i + 1)-th point is determined.

[0095] Among them, the distance vector in the horizontal direction refers to the component of the distance between two adjacent points in the horizontal direction; the distance vector in the vertical direction refers to the component of the distance between two adjacent points in the vertical direction. Please refer to Figure 4 , assuming that the x-axis direction is the horizontal direction, the z-axis direction is the vertical direction, point A is the i-th point, and point B is the (i + 1)-th point, then q 1 is the distance vector in the horizontal direction between points A and B, and q 2 is the distance vector in the vertical direction between points A and B.

[0096] Among them, the travel time of the i-th point refers to the time taken for the seismic wave to travel from the shot point to the i-th point. When i = 1, the travel time is 0, that is, the travel time corresponding to the shot point is 0. In some embodiments, the travel time of the i-th (i≥2) point can be determined by the following formula (1):

[0097]

[0098] Among them, T(i) represents the travel time of the i-th point, T(i - 1) represents the travel time of the (i - 1)-th point, q I (i, i - 1) represents the first distance vector between the i-th point and the (i - 1)-th point, q J (i, i - 1) represents the second distance vector between the i-th point and the (i - 1)-th point, M IJ (i - 1) represents the slowness change rate corresponding to the (i - 1)-th point.

[0099] In some embodiments, a two-dimensional coordinate system is established with the shot point as the origin, the positive x-axis direction is horizontally to the right, and the positive z-axis direction is vertically downward. The position coordinates of the i-th point are (x i , z i ), and the position coordinates of the (i - 1)-th point are (x i-1 , zi-1 ), in which case q I (i, i-1) can be expressed as x i -x i-1 ,q J (i, i-1) can be expressed as z i -z i-1 .

[0100] It should be noted that the slowness change rate corresponding to the shot point is known data. In addition, based on the travel time of the i-1th point, the slowness change rate of the i-1th point can be determined, and then the travel time of the i-th point can be determined by the above formula (1), and then based on the travel time of the i-th point, the slowness change rate of the i-th point can be determined.

[0101] Among them, the embodiment of the present application does not limit the method of determining the slowness change rate of the i-th point based on the travel time of the i-th point.

[0102] The determination method of the first distance vector and the second distance vector between the i+1th point and the ith point can refer to the above-mentioned method for determining q I (i, i-1) and q J The determination process of (i, i-1) is simply to replace the i-th point and the i-1-th point with the i+1-th point and the i-th point; of course, it can also be determined by other methods, and the embodiments of the present application are not limited to this.

[0103] In some embodiments, based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point and the second distance vector, the slowness vector of the i+1-th point in the horizontal direction is determined by the following formula (2):

[0104]

[0105] Among them, P x (i+1) represents the slowness vector of the i+1th point in the horizontal direction, P x (i) represents the slowness vector of the i-th point in the horizontal direction, M IJ (i) represents the slowness change rate of the i-th point, q J (i+1, i) represents the second distance vector between the i+1th point and the ith point.

[0106] Similarly, in some embodiments, based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point and the first distance vector, the slowness vector of the i+1-th point in the vertical direction is determined by the following formula (3):

[0107]

[0108] Among them, P z(i+1) represents the vertical slowness vector of the i+1th point, P z (i) represents the slowness vector of the i-th point in the vertical direction, M IJ (i) represents the slowness change rate of the i-th point, q I (i+1, i) represents the first distance vector between the i+1th point and the ith point.

[0109] In some embodiments, based on the slowness vector of the i+1th point in the horizontal direction, the slowness vector of the i+1th point in the vertical direction and the seismic wave velocity indicated by the grid i, the ray direction of the i+1th point is determined by the following formula (4):

[0110]

[0111] in, represents the ray direction of the i+1th point, including the angle between the velocity direction of the i+1th point and the horizontal direction, and the angle between the velocity direction of the i+1th point and the vertical direction. v(i) represents the magnitude of the seismic wave velocity indicated by grid i. P x (i+1) represents the slowness vector of the i+1th point in the horizontal direction, P z (i+1) represents the slowness vector of the i+1th point in the vertical direction.

[0112] c. If the i+1th point is a point on the above-mentioned seismic wave reflection surface, then the i+1th point is determined as the imaging point of the target seismic wave, and j=1 is set. Based on the ray direction of the target seismic wave at the i-th point, the ray direction of the j-th point on the reflected wave of the target seismic wave is determined.

[0113] It should be noted that the first point on the reflected wave of the target seismic wave is the imaging point of the target seismic wave.

[0114] In some embodiments, if the i+1th point is a point on the above-mentioned seismic wave reflection surface, the ray direction of the first point on the reflected wave of the target seismic wave is determined based on the ray direction of the target seismic wave at the i-th point by Snell's theorem.

[0115] d. According to the ray direction of the target seismic wave at the jth point, a ray j is drawn from the jth point, and the intersection between the ray j and the boundary of the grid j is taken as the j+1th point on the reflection wave of the target seismic wave. The grid j refers to the first grid in the velocity grid model where the boundary intersects with the ray j.

[0116] The process is similar to that in step a above, except that the incident wave is replaced by the reflected wave.

[0117] e. If the j+1th point is not the target detection point, determine the ray direction of the target seismic wave at the j+1th point, set j=j+1, and return to the step of drawing a ray j from the i-th point according to the ray direction of the target seismic wave at the jth point.

[0118] The target detection point is a detection point among multiple detection points on the optical fiber survey line in the well, which receives the reflected wave of the target seismic wave. It should be noted that the position of the target detection point is known data.

[0119] In some embodiments, determining the ray direction of the j+1th point of the target seismic wave is the same as determining the ray direction of the i+1th point described above, except that i in the above description is replaced by j.

[0120] f. If the j+1th point is the target detection point, the slowness vector of the jth point in the vertical direction is determined as the first slowness vector.

[0121] (2) Obtaining the seismic wave velocity of the target detection point from the velocity grid model, where the velocity grid model is used to reflect the seismic wave velocity at different stratum positions in the exploration area.

[0122] (3) Based on the first slowness vector and the seismic wave velocity of the target detection point, determine the angle between the reflected wave of the target seismic wave and the vertical direction to obtain a first angle.

[0123] In some embodiments, based on the first slowness vector and the seismic wave velocity of the target detection point, the angle between the reflected wave of the target seismic wave and the vertical direction is determined by the following formula (5):

[0124]

[0125] in, represents the angle between the reflected wave of the target seismic wave and the vertical direction, V represents the seismic wave velocity of the target detection point, and P Z represents the first slowness vector.

[0126] (4) Subtracting the target angle from the first angle to obtain the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well. The target angle is the angle between the optical fiber measuring line in the well and the vertical direction.

[0127] It should be noted that the angle between the optical fiber measuring line in the well and the vertical direction is known.

[0128] In the same manner as steps (1) to (4) above, the imaging points corresponding to the multiple seismic waves and the angles between the reflected waves of the multiple seismic waves and the optical fiber measuring line in the well where the detection points are located can be determined.

[0129] Here is an example:

[0130] Please refer to Figure 5 , Figure 5 Point S represents the shot point, which is also the origin of the xz coordinate system. The x-axis is horizontal and the z-axis is vertical. The grid part represents the velocity grid model. L represents the fiber optic line in the well, R represents the target detection point, and Q represents the seismic wave reflection surface. The speed of seismic wave propagation in each grid and the positions of L, R, and Q in the xz coordinate system are all known. The angle of the fiber optic line L in the well relative to the positive direction of the z-axis, that is, the target angle θ, is also known. P1 represents the incident wave of the target seismic wave excited by point S, and P2 represents the corresponding reflected wave.

[0131] Since the ray direction of point S (shot point) corresponding to the target seismic wave is known, a ray is drawn from point S to obtain the first intersection point of the ray with the boundary of the velocity grid model, that is, Figure 5 In the middle point N1, naturally, we can get the position coordinates of point N1 (x N1 , z N1 ), and the position coordinates of point S are (0, 0), so the first distance vector between point N1 and point S is x N1 , the second distance vector is z N1 .

[0132] Since the slowness change rate of point S and the slowness vector of point S in the horizontal and vertical directions are known, the slowness vector of point N1 in the horizontal and vertical directions can be obtained through the above formulas (2) and (3). Since the seismic wave velocity indicated by grid n1 is known, the ray direction of point N1 can be obtained through the above formula (4).

[0133] After obtaining the ray direction of point N1, a ray is drawn from point N1 to obtain the first intersection point of the ray with the boundary of the velocity grid model, that is, Figure 4 The N2 point in the image can naturally obtain the position coordinates of the N2 point (x N2 , z N2 ), and the position coordinates of point N1 are (x N1 , z N1 ), so we can get the first distance vector between point N2 and point N1 as x N2 -x N1 , the second distance vector is z N2 -z N1 .

[0134] Since the travel time and slowness change rate corresponding to point S are known, the travel time of point N1 can be determined by formula (1), and the slowness change rate of point N1 can be obtained from the travel time of point N1. Then, the slowness vector of point N2 in the horizontal and vertical directions can be obtained by the above formulas (2) and (3). Since the seismic wave velocity indicated by grid n2 is known, the ray direction of point N2 can be obtained by the above formula (4).

[0135] Similarly, by continuously tracking the ray direction of the incident wave P1, the ray direction of point N6 can be determined. A ray is drawn from point N6, and the first intersection of the ray and the velocity grid model is the point M on the seismic wave reflection surface Q, so point M is the imaging point of the target seismic wave.

[0136] Next, based on the ray direction of point N6 and Snell's theorem, the ray direction of point N7 (M) can be determined. After that, the ray direction of the reflected wave P2 can be obtained by continuously tracking the ray direction of point N11 in the same way as the ray direction of the incident wave P1.

[0137] According to the ray direction of point N11, a ray is drawn from point N11. The first intersection of the ray and the boundary of the velocity grid model is point R, which is the target detection point. At this time, the slowness vector of point N11 in the vertical direction is determined as the first slowness vector. At the same time, the seismic wave velocity corresponding to the nr grid is obtained as the seismic wave velocity corresponding to the target detection point. Through the above formula (5), the angle between the reflection wave P2 of the target seismic wave and the positive direction of the z axis can be obtained: This angle is the first angle.

[0138] Since the angle θ of the optical fiber measuring line L in the well relative to the positive direction of the z-axis is known, the target angle is subtracted from the first angle, that is, The angle β between the reflected wave of the target seismic wave and the optical fiber measuring line in the well can be obtained.

[0139] Step 102: Based on the angles between the reflection waves of the multiple seismic waves and the optical fiber measuring line in the well, and the types of the multiple seismic waves, determine the amplitude correction coefficients of the multiple seismic waves at their respective imaging points.

[0140] In some embodiments, for a target seismic wave among multiple seismic waves, if the type of the target seismic wave is a longitudinal wave, the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the optical fiber survey line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point; if the type of the target seismic wave is a converted wave, the reciprocal of the sine value of the angle between twice the reflected wave of the target seismic wave and the optical fiber survey line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point.

[0141] For example, when the type of the target seismic wave is a longitudinal wave, the amplitude correction coefficient of the target seismic wave at its own imaging point can be expressed by the following formula (6):

[0142]

[0143] Among them, W DAS-P It represents the amplitude correction coefficient of the target seismic wave at its own imaging point when the target seismic wave is a longitudinal wave. β represents the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well.

[0144] For example, when the type of the target seismic wave is a converted wave, the amplitude correction coefficient of the target seismic wave at its own imaging point can be expressed by the following formula (7):

[0145]

[0146] Among them, W DAS-SV It represents the amplitude correction coefficient of the target seismic wave at its own imaging point when the target seismic wave is a converted wave. β represents the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well.

[0147] Step 103: Divide the multiple seismic waves into multiple seismic wave groups, and the imaging points corresponding to the same seismic wave group are the same.

[0148] It should be noted that the multiple seismic waves in the same seismic wave group may have the same or different corresponding shot points, and the same or different corresponding detection points. It is only necessary to ensure that the corresponding imaging points are the same.

[0149] Usually, different imaging points are located at different stratum depths. Therefore, it can be considered that each seismic wave group corresponds to imaging points at different depths.

[0150] Step 104: For each of the multiple seismic wave groups, based on the amplitude correction coefficient of each seismic wave in the seismic wave group at the respective imaging point, amplitude correction is performed on the seismic data at the imaging point corresponding to the seismic wave group.

[0151] In some embodiments, for each seismic wave group in a plurality of seismic wave groups, amplitude correction is performed on the seismic data at the imaging point corresponding to the seismic wave group based on the amplitude correction coefficient of each seismic wave in the seismic wave group at its respective imaging point, using the following formula (8).

[0152] m M =∫dW M ·u M (t) (8)

[0153] Among them, m Mrepresents the seismic data after amplitude correction of a seismic wave group corresponding to the imaging point M, W M Indicates the amplitude correction coefficient corresponding to each seismic wave in the seismic wave group, u M (t) represents the original amplitude of each seismic wave in the seismic wave group.

[0154] Through the above formula (8), for each seismic wave group, each seismic wave in the seismic wave group is multiplied by its own amplitude correction coefficient, so that the effective signal amplitude of each seismic wave is more accurate and the amplitude of the corresponding noise signal is closer; then these seismic waves are superimposed in phase so that the noise signals cancel each other out, and the effective signal corresponding to the same imaging point is enhanced.

[0155] The following is a verification of the effects of the embodiments of the present application:

[0156] There are multiple seismic data. First, the original seismic data is used to stack the seismic data received from imaging points at different depths in phase. The results are as follows: Figure 6 As shown, next, through the above steps 101-104, each original DAS-VSP seismic data is multiplied by the corresponding amplitude correction coefficient, and then the corrected DAS-VSP seismic data is used to stack the seismic data received at imaging points at different depths in phase, and the result is as shown in FIG. Figure 7 shown.

[0157] from Figure 6 It can be seen from the figure that after the DAS-VSP seismic data are stacked without amplitude correction, the stacking result has a lot of noise. Figure 7 It can be seen that after the amplitude-corrected DAS-VSP seismic data are stacked, the noise in the stacking result is significantly reduced. In the process of in-phase stacking of pre-stack CDP gathers, the corresponding noise (noise with the same amplitude and opposite amplitude direction in the window segment) should be offset after stacking, but due to the defects of DAS-VSP technology, the amplitude of the corresponding noise may not be the same, resulting in the noise not being completely offset. After amplitude correction, the amplitude of the corresponding noise is closer or the same, which makes the corresponding noise as completely offset as possible, so that the effective data in the imaging result will be clearer.

[0158] In an embodiment of the present application, the angle between the reflected wave and the optical fiber line in the well is obtained by tracking the ray direction of the seismic wave, and the DAS-VSP seismic data of different seismic wave types are corrected by a custom amplitude correction coefficient based on the angle, so that the amplitude of the seismic wave signal is closer to the true value, making the seismic data more accurate. At the same time, the amplitude of the corresponding noise can be closer or the same, so that after the seismic waves of the same depth imaging point are superimposed in phase, the noise in the superposition result is significantly reduced, thereby reducing the "arcing" phenomenon of the imaging section. In addition, the signal-to-noise ratio in the superposition result is greater, the effective data is clearer, and it is also convenient for the subsequent application and processing of seismic data.

[0159] Figure 8 This is a schematic diagram of the structure of an amplitude correction device for DAS-VSP seismic data provided in an embodiment of the present application. Please refer to Figure 8 The device includes: a first determination module 801, a second determination module 802, a grouping module 803 and a correction module 804.

[0160] The first determination module 801 is used to determine the imaging points corresponding to the multiple seismic waves and the angles between the reflected waves of the multiple seismic waves and the optical fiber measurement line in the well where the detection point is located by performing ray tracing on the multiple seismic waves excited by the multiple shot points of the DAS-VSP system. The imaging point refers to the intersection of the incident wave and the reflected wave of the seismic wave.

[0161] A second determination module 802 is used to determine the amplitude correction coefficients of the multiple seismic waves at their respective imaging points based on the angles between the reflection waves of the multiple seismic waves and the optical fiber measurement line in the well and the types of the multiple seismic waves;

[0162] A grouping module 803 is used to divide the multiple seismic waves into multiple seismic wave groups, and the imaging points corresponding to the same seismic wave group are the same;

[0163] The correction module 804 is used to perform amplitude correction on the seismic data at the imaging point corresponding to the seismic wave group for each seismic wave group in the multiple seismic wave groups based on the amplitude correction coefficient of each seismic wave in the seismic wave group at the respective imaging point.

[0164] Optionally, the first determining module 801 includes:

[0165] A tracking and determining submodule is used to perform ray tracing on a target seismic wave among multiple seismic waves to determine an imaging point corresponding to the target seismic wave and a first slowness vector of a reflected wave of the target seismic wave at a target detection point, wherein the target detection point refers to a detection point on an optical fiber survey line in a well for detecting a reflected wave of the target seismic wave, and the first slowness vector refers to a slowness vector in a vertical direction;

[0166] The velocity acquisition submodule is used to obtain the seismic wave velocity of the target detection point from the velocity grid model, and the velocity grid model is used to reflect the seismic wave velocity of different stratum positions in the exploration area;

[0167] A first angle determination submodule, used to determine the angle between the reflected wave of the target seismic wave and the vertical direction based on the first slowness vector and the seismic wave velocity of the target detection point, to obtain a first angle;

[0168] The second angle determination submodule is used to subtract the target angle from the first angle to obtain the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well, and the target angle is the angle between the optical fiber measuring line in the well and the vertical direction.

[0169] Optionally, the tracking determination submodule is specifically used for:

[0170] Let i = 1, take the shot point used to excite the target seismic wave as the i-th point on the incident wave of the target seismic wave, draw a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point, and take the intersection point between the ray i and the boundary of the grid i as the i+1-th point on the incident wave of the target seismic wave, where the grid i refers to the first grid in the velocity grid model where the boundary intersects with the ray i;

[0171] If the i+1th point is not a point on the seismic wave reflection surface, determine the ray direction of the target seismic wave at the i+1th point, set i=i+1, and return to the step of drawing a ray i from the i-th point according to the ray direction of the target seismic wave at the i-th point;

[0172] If the i+1th point is a point on the seismic wave reflection surface, the i+1th point is determined as the imaging point of the target seismic wave, and j=1. Based on the ray direction of the target seismic wave at the i-th point, the ray direction of the j-th point on the reflection wave of the target seismic wave is determined;

[0173] According to the ray direction of the target seismic wave at the jth point, a ray j is drawn from the jth point, and the intersection point between the ray j and the boundary of the grid j is taken as the j+1th point on the reflection wave of the target seismic wave. The grid j refers to the first grid in the velocity grid model where the boundary intersects with the ray j;

[0174] If the j+1th point is not the target detection point, determine the ray direction of the target seismic wave at the j+1th point, set j=j+1, and return to the step of drawing a ray j from the i-th point according to the ray direction of the target seismic wave at the jth point;

[0175] If the j+1th point is the target detection point, the slowness vector of the jth point in the vertical direction is determined as the first slowness vector.

[0176] Optionally, the tracking determination submodule is specifically used for:

[0177] Based on the travel time of the i-th point, determine the slowness change rate of the i-th point, where the slowness change rate refers to the change rate of the slowness vector of the i-th point in the horizontal direction in the vertical direction;

[0178] Determine a first distance vector and a second distance vector between the i+1th point and the ith point, wherein the first distance vector refers to a distance vector in the horizontal direction, and the second distance vector refers to a distance vector in the vertical direction;

[0179] Based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point and the second distance vector, determine the slowness vector of the i+1-th point in the horizontal direction; based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point and the first distance vector, determine the slowness vector of the i+1-th point in the vertical direction;

[0180] Based on the slowness vector of the i+1th point in the horizontal direction, the slowness vector of the i+1th point in the vertical direction and the seismic wave velocity indicated by the grid i, the ray direction of the target seismic wave at the i+1th point is determined.

[0181] Optionally, the second determining module is specifically configured to:

[0182] For a target seismic wave among the multiple seismic waves, if the type of the target seismic wave is a longitudinal wave, the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point;

[0183] If the type of the target seismic wave is a converted wave, the inverse of the sine value of the angle between the reflected wave of the twice target seismic wave and the optical fiber measuring line in the well is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point.

[0184] In the embodiment of the present application, the angle between the reflected wave and the optical fiber line in the well is obtained by tracking the ray direction of the seismic wave, and the DAS-VSP seismic data of different seismic wave types are corrected by a custom amplitude correction coefficient based on the angle, so that the amplitude of the seismic wave signal is closer to the true value, making the seismic data more accurate. At the same time, the amplitude of the corresponding noise can be closer or the same, thereby reducing the "arcing" phenomenon of the imaging section and facilitating the subsequent application and processing of the seismic data.

[0185] It should be noted that: the amplitude correction device for DAS-VSP seismic data provided in the above embodiment only uses the division of the above functional modules as an example when performing amplitude correction on DAS-VSP seismic data. In actual applications, the above functions can be assigned to different functional modules as needed, that is, the internal structure of the device is divided into different functional modules to complete all or part of the functions described above. In addition, the amplitude correction device for DAS-VSP seismic data provided in the above embodiment and the amplitude correction method embodiment of DAS-VSP seismic data belong to the same concept. The specific implementation process is detailed in the method embodiment and will not be repeated here.

[0186] Please refer to Fig. 9 , Fig. 9 90 is a block diagram of a computer device provided in an embodiment of the present application. The computer device includes at least one processor 901, a communication bus 902, a memory 903 and at least one communication interface 904.

[0187] The processor 901 may be a general-purpose central processing unit (CPU), a network processor (NP), a microprocessor, or may be one or more integrated circuits for implementing the solution of the present application, such as an application-specific integrated circuit (ASIC), a programmable logic device (PLD) or a combination thereof. The above-mentioned PLD may be a complex programmable logic device (CPLD), a field-programmable gate array (FPGA), a generic array logic (GAL) or any combination thereof.

[0188] The communication bus 902 is used to transmit information between the above components. The communication bus 902 can be divided into an address bus, a data bus, a control bus, etc. For ease of representation, only one thick line is used in the figure, but it does not mean that there is only one bus or one type of bus.

[0189] The memory 903 may be a read-only memory (ROM), a random access memory (RAM), an electrically erasable programmable read-only memory (EEPROM), an optical disc (including a compact disc read-only memory (CD-ROM), a compressed optical disc, a laser disc, a digital versatile disc, a Blu-ray disc, etc.), a magnetic disk storage medium or other magnetic storage device, or any other medium that can be used to carry or store the desired program code in the form of instructions or data structures and can be accessed by a computer, but is not limited thereto. The memory 903 may exist independently and be connected to the processor 901 via the communication bus 902. The memory 903 may also be integrated with the processor 901.

[0190] The communication interface 904 uses any transceiver-like device for communicating with other devices or communication networks. The communication interface 904 includes a wired communication interface and may also include a wireless communication interface. Among them, the wired communication interface may be, for example, an Ethernet interface. The Ethernet interface may be an optical interface, an electrical interface, or a combination thereof. The wireless communication interface may be a wireless local area network (WLAN) interface, a cellular network communication interface, or a combination thereof, etc.

[0191] In some embodiments, the memory 903 is used to store the program code 910 for executing the solution of the present application, and the processor 901 can execute the program code 910 stored in the memory 903. The program code 910 may include one or more software modules, and the computer device may implement the above by the processor 901 and the program code 910 in the memory 903. Figure 1 The embodiment provides an amplitude correction method for DAS-VSP seismic data.

[0192] Without loss of generality, computer readable media may include computer storage media and communication media. Computer storage media include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information such as computer readable instructions, data structures, program modules or other data. Computer storage media include RAM, ROM, EPROM, EEPROM, flash memory or other solid-state storage technology, CD-ROM, DVD or other optical storage, cassettes, magnetic tapes, disk storage or other magnetic storage devices. Of course, those skilled in the art will appreciate that computer storage media are not limited to the above.

[0193] In some embodiments, a computer-readable storage medium is further provided, wherein a computer program is stored in the storage medium, and when the computer program is executed by a processor, the steps of the amplitude correction method for DAS-VSP seismic data in the above embodiment are implemented. For example, the computer-readable storage medium may be a ROM, RAM, CD-ROM, magnetic tape, floppy disk, optical data storage device, etc.

[0194] It is worth noting that the computer-readable storage medium mentioned in the embodiments of the present application may be a non-volatile storage medium, in other words, a non-transitory storage medium.

[0195] It should be understood that all or part of the steps to implement the above embodiments can be implemented by software, hardware, firmware or any combination thereof. When implemented using software, it can be implemented in whole or in part in the form of a computer program product. The computer program product includes one or more computer instructions. The computer instructions can be stored in the above-mentioned computer readable storage medium.

[0196] That is, in some embodiments, a computer program product comprising instructions is also provided, which, when executed on a computer, enables the computer to execute the steps of the amplitude correction method for DAS-VSP seismic data described above.

[0197] It should be understood that the "at least one" mentioned herein refers to one or more, and "multiple" refers to two or more. In the description of the embodiments of the present application, unless otherwise specified, " / " means or, for example, A / B can mean A or B; "and / or" in this article is only a description of the association relationship of the associated objects, indicating that there can be three relationships, for example, A and / or B can mean: A exists alone, A and B exist at the same time, and B exists alone. In addition, in order to facilitate the clear description of the technical solutions of the embodiments of the present application, in the embodiments of the present application, the words "first", "second" and the like are used to distinguish the same items or similar items with basically the same functions and effects. Those skilled in the art can understand that the words "first", "second" and the like do not limit the quantity and execution order, and the words "first", "second" and the like do not limit them to be necessarily different.

[0198] It should be noted that the information (including but not limited to user device information, user personal information, etc.), data (including but not limited to data used for analysis, stored data, displayed data, etc.) and signals involved in the embodiments of the present application are all authorized by the user or fully authorized by all parties, and the collection, use and processing of relevant data need to comply with relevant laws, regulations and standards of relevant countries and regions.

[0199] The above-mentioned embodiments are provided for the present application and are not intended to limit the present application. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present application shall be included in the protection scope of the present application.

Claims

1. A method for amplitude correction of DAS-VSP seismic data, characterized in that, the method includes: By performing ray tracing on multiple seismic waves excited by multiple shot points of a distributed acoustic sensing vertical seismic profile (DAS-VSP) system, to determine the imaging points corresponding to the multiple seismic waves respectively, and the angles between the reflected waves of the multiple seismic waves and the downhole fiber optic cable where the geophones are located, the imaging point refers to the intersection point of the incident wave and the reflected wave of the seismic wave; Based on the angles between the reflected waves of the multiple seismic waves and the downhole fiber optic cable, and the types of the multiple seismic waves, determine the amplitude correction coefficients of the multiple seismic waves at their respective imaging points; Divide the multiple seismic waves into multiple seismic wave groups, and the imaging points corresponding to the same seismic wave group are the same; For each seismic wave group among the multiple seismic wave groups, based on the amplitude correction coefficients of each seismic wave in the seismic wave group at their respective imaging points, perform amplitude correction on the seismic data at the imaging points corresponding to the seismic wave group.

2. The method according to claim 1, characterized in that, the step of performing ray tracing on multiple seismic waves excited by multiple shot points of a DAS-VSP system to determine the imaging points corresponding to the multiple seismic waves respectively, and the angles between the reflected waves of the multiple seismic waves and the downhole fiber optic cable where the geophones are located, includes: For a target seismic wave among the multiple seismic waves, perform ray tracing on the target seismic wave to determine the imaging point corresponding to the target seismic wave, and the first slowness vector of the reflected wave of the target seismic wave at the target geophone, the target geophone refers to the geophone on the downhole fiber optic cable for detecting the reflected wave of the target seismic wave, and the first slowness vector refers to the slowness vector in the vertical direction; Obtain the seismic wave velocity of the target geophone from a velocity grid model, the velocity grid model is used to reflect the seismic wave velocities at different formation positions in the exploration area; Based on the first slowness vector and the seismic wave velocity of the target geophone, determine the angle between the reflected wave of the target seismic wave and the vertical direction, obtaining a first angle; Subtract the target angle from the first angle to obtain the angle between the reflected wave of the target seismic wave and the downhole fiber optic cable, the target angle is the angle between the downhole fiber optic cable and the vertical direction.

3. The method according to claim 2, characterized in that, the step of performing ray tracing on the target seismic wave to determine the imaging point corresponding to the target seismic wave, and the first slowness vector of the reflected wave of the target seismic wave at the target geophone, includes: Let i = 1, take the shot point for exciting the target seismic wave as the i-th point on the incident wave of the target seismic wave, draw a ray i starting from the i-th point in the ray direction of the target seismic wave at the i-th point, and take the intersection point between the ray i and the boundary of grid i as the (i + 1)-th point on the incident wave of the target seismic wave, grid i refers to the first grid in the velocity grid model whose boundary intersects with the ray i; If the (i + 1)-th point is not a point on the seismic wave reflection surface, determine the ray direction of the target seismic wave at the (i + 1)-th point, let i = i + 1, and return to the step of drawing a ray i starting from the i-th point according to the ray direction of the target seismic wave at the i-th point; If the (i + 1)-th point is a point on the seismic wave reflection surface, determine the (i + 1)-th point as the imaging point of the target seismic wave, let j = 1, and determine the ray direction of the j-th point on the reflected wave of the target seismic wave based on the ray direction of the target seismic wave at the i-th point; Draw a ray j starting from the j-th point according to the ray direction of the target seismic wave at the j-th point, and take the intersection point between the ray j and the boundary of grid j as the (j + 1)-th point on the reflected wave of the target seismic wave, where grid j refers to the first grid in the velocity grid model whose boundary intersects with the ray j; If the (j + 1)-th point is not the target geophone, determine the ray direction of the target seismic wave at the (j + 1)-th point, let j = j + 1, and return to the step of drawing a ray j starting from the i-th point according to the ray direction of the target seismic wave at the j-th point; If the (j + 1)-th point is the target geophone, determine the slowness vector of the j-th point in the vertical direction as the first slowness vector.

4. The method according to claim 3, wherein, the determining the ray direction of the target seismic wave at the (i + 1)-th point includes: Based on the travel time of the i-th point, determine the slowness change rate of the i-th point, where the slowness change rate refers to the change rate of the slowness vector of the i-th point in the horizontal direction in the vertical direction; Determine the first distance vector and the second distance vector between the (i + 1)-th point and the i-th point, where the first distance vector refers to the distance vector in the horizontal direction and the second distance vector refers to the distance vector in the vertical direction; Based on the slowness vector of the i-th point in the horizontal direction, the slowness change rate of the i-th point, and the second distance vector, determine the slowness vector of the (i + 1)-th point in the horizontal direction, and based on the slowness vector of the i-th point in the vertical direction, the slowness change rate of the i-th point, and the first distance vector, determine the slowness vector of the (i + 1)-th point in the vertical direction; Based on the slowness vector of the (i + 1)-th point in the horizontal direction, the slowness vector of the (i + 1)-th point in the vertical direction, and the seismic wave velocity indicated by grid i, determine the ray direction of the target seismic wave at the (i + 1)-th point.

5. The method according to claim 1, wherein, the determining the amplitude correction coefficients of the multiple seismic waves at their respective imaging points based on the angles between the reflected waves of the multiple seismic waves and the downhole optical fiber survey line, and the types of the multiple seismic waves includes: For the target seismic wave among the multiple seismic waves, if the type of the target seismic wave is a P-wave, then the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the downhole fiber optic survey line is determined as the amplitude correction coefficient of the target seismic wave at its imaging point; if the type of the target seismic wave is a converted wave, then the reciprocal of twice the sine value of the angle between the reflected wave of the target seismic wave and the downhole fiber optic survey line is determined as the amplitude correction coefficient of the target seismic wave at its imaging point.

6. An amplitude correction device for DAS-VSP seismic data, characterized in that, the device includes: A first determination module, configured to determine the imaging points corresponding to the multiple seismic waves respectively, and the angles between the reflected waves of the multiple seismic waves and the downhole fiber optic survey line where the geophones are located, by performing ray tracing on the multiple seismic waves excited by multiple shot points of a DAS-VSP system, where the imaging point refers to the intersection point of the incident wave and the reflected wave of the seismic wave; A second determination module, configured to determine the amplitude correction coefficients of the multiple seismic waves at their respective imaging points based on the angles between the reflected waves of the multiple seismic waves and the downhole fiber optic survey line, and the types of the multiple seismic waves; A grouping module, configured to divide the multiple seismic waves into multiple seismic wave groups, and the imaging points corresponding to the same seismic wave group are the same; A correction module, configured to, for each seismic wave group among the multiple seismic wave groups, perform amplitude correction on the seismic data at the imaging point corresponding to the seismic wave group based on the amplitude correction coefficients of each seismic wave in the seismic wave group at their respective imaging points.

7. The device according to claim 6, characterized in that, the first determination module includes: A tracing determination sub-module, configured to, for the target seismic wave among the multiple seismic waves, perform ray tracing on the target seismic wave to determine the imaging point corresponding to the target seismic wave, and the first slowness vector of the reflected wave of the target seismic wave at the target geophone, where the target geophone refers to the geophone on the downhole fiber optic survey line for detecting the reflected wave of the target seismic wave, and the first slowness vector refers to the slowness vector in the vertical direction; A velocity acquisition sub-module, configured to acquire the seismic wave velocity of the target geophone from a velocity grid model, where the velocity grid model is used to reflect the seismic wave velocities at different formation positions in the exploration area; A first angle determination sub-module, configured to determine the angle between the reflected wave of the target seismic wave and the vertical direction based on the first slowness vector and the seismic wave velocity of the target geophone, to obtain a first angle; A second angle determination sub-module, configured to subtract the target angle from the first angle to obtain the angle between the reflected wave of the target seismic wave and the downhole fiber optic survey line, where the target angle is the angle between the downhole fiber optic survey line and the vertical direction.

8. The device according to claim 6, characterized in that, the second determination module is specifically configured to: For the target seismic wave among the multiple seismic waves, if the type of the target seismic wave is a longitudinal wave, then the reciprocal of the square of the cosine value of the angle between the reflected wave of the target seismic wave and the downhole fiber optic survey line is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point; If the type of the target seismic wave is a converted wave, then the reciprocal of twice the sine value of the angle between the reflected wave of the target seismic wave and the downhole fiber optic survey line is determined as the amplitude correction coefficient of the target seismic wave at its own imaging point.

9. A computer device, characterized in that, the computer device includes a memory and a processor, the memory is used to store a computer program, and the processor is used to execute the computer program stored on the memory to implement the steps of the method according to any one of claims 1-5 above.

10. A computer-readable storage medium, characterized in that, the storage medium stores a computer program, and when the computer program is executed by a processor, the steps of the method according to any one of claims 1-5 are implemented.

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