A VSP up-down wave joint imaging method based on distributed optical fiber acoustic sensing

Abstract

This invention discloses a VSP (Vibration Spectroscopic Spatial) uplink and downlink wave joint imaging method based on distributed fiber optic acoustic sensing, belonging to the field of exploration geophysics. The invention first separates the wavefield of DAS VSP data to obtain uplink and downlink wave data; then, it mirrors the downlink wave data along the time axis at the wellhead location and stitches it with the uplink wave data to construct a super gather; finally, it mirrors the original subsurface velocity model and stitches it with the original velocity model to construct an extended velocity model; based on the extended velocity model, it performs direct reverse-time migration imaging of DAS data, and incorporates subsurface strata dip constraints during single-shot imaging to reduce migration artifacts; finally, it superimposes the single-shot migration imaging results corresponding to all sources to obtain the final imaging result. This invention can utilize the uplink and downlink wavefields simply and efficiently without additional complex processing, and can significantly improve the imaging accuracy and imaging range of subsurface structures from DAS VSP data.

Description

Technical Field

[0001] This invention relates to the field of exploration geophysics, and in particular to a VSP uplink and downlink combined imaging method based on distributed fiber optic acoustic sensing. Background Technology

[0002] Vertical seismic profiling (VSP) is a seismic exploration technique that uses receivers deployed in a borehole and ground-based seismic sources to generate seismic waves to obtain information about subsurface structures. Because the acquired reflected waves only pass through the near-surface low-velocity layer once, VSP offers a higher signal-to-noise ratio and vertical resolution compared to surface seismic exploration. Traditional VSP observations typically use borehole geophone arrays for data acquisition, but the limited number of geophones results in low spatial sampling density and high instrument deployment costs, limiting its suitability for large-scale monitoring and long-term observation. In recent years, distributed optical fiber acoustic sensing (DAS) technology has provided a new solution for borehole seismic observation. This technology uses optical fiber as a continuous sensing medium, measuring strain or strain rate signals along the fiber direction by analyzing the phase change of Rayleigh scattered light, thereby achieving continuous spatial sampling of the seismic wavefield. Compared to traditional borehole geophone systems, DAS offers advantages such as high spatial sampling density, low cost, convenient deployment, and suitability for long-term monitoring, thus gradually becoming an important means of VSP data acquisition. Seismic wavefields recorded by VSP typically contain two types of wavefields: ascending waves and descending waves. Downward waves mainly consist of direct waves generated by the seismic source and their multiple reflections, while ascending waves are primarily composed of reflections generated by subsurface strata. These two types of wavefields have different propagation paths and wavefield characteristics, and carry complementary subsurface structural information, thus being of great significance for subsurface imaging. However, traditional VSP imaging usually only utilizes the separated ascending waves for migration imaging, while the effective information carried by the descending waves is often unused, which to some extent limits the coverage and imaging quality of VSP imaging. How to fully utilize the ascending and descending wavefield information in DAS VSP records is a key problem that urgently needs to be solved in current seismic imaging research.

[0003] Currently, VSP imaging methods mainly rely on uplink primary reflections. While offering good vertical resolution, they are limited by the acquisition geometry, imaging only a narrow triangular region below the receiver array, resulting in limited illumination. Downlink multiples have been shown to extend VSP illumination, but their utilization is complex, typically requiring the reconstruction of VSP records into synthetic virtual ground seismic gathers or the separation of specific downlink reflections or multiples of a specified order from complex mixed wavefields, which is challenging to implement. Existing combined uplink and downlink strategies usually involve imaging the uplink and downlink waves separately and then using matched filters or weighted mixing to combine the results. This not only significantly increases computational costs but also introduces subjective factors into the stitching process, affecting the reliability and repeatability of the imaging results.

[0004] Existing VSP imaging methods still face problems such as low wavefield utilization efficiency, small imaging range, and insufficient imaging accuracy under DAS observation conditions. There is an urgent need for an efficient and simple joint imaging method to improve the imaging quality of DAS-VSP data. Summary of the Invention

[0005] To address the aforementioned issues, this invention discloses a VSP (Vibration-Slippery-Particle) uplink and downlink wave joint imaging method based on distributed fiber acoustic sensing. This method simultaneously utilizes uplink and downlink wave information to improve wavefield information utilization; it expands the coverage of subsurface structure imaging by constructing an extended aperture dataset; it improves the illumination conditions of subsurface structures by utilizing multiple wave information, thereby increasing imaging resolution; and it suppresses migration artifacts by introducing structural tilt constraints, improving the structural continuity and stability of the imaging results. Specifically, this invention first separates the wavefield of DAS VSP data to obtain uplink and downlink wavefield data. Then, the downlink wave is mirrored along the time axis at the wellhead location and stitched together with the uplink wave to construct a super gather. Further, the velocity model is mirrored and stitched together with the original velocity model to construct an observation system matching the super gather data. Based on this, direct reverse-time migration imaging of DAS data is performed based on the pressure-strain rate equation, and structural tilt constraints are added during the imaging process to reduce migration artifacts. Through the above technical solution, this invention enables simple and efficient utilization of uplink and downlink wavefields without additional complex processing, and significantly improves the imaging accuracy and range of subsurface structures from DAS VSP data. The DAS VSP uplink and downlink wave joint imaging technology framework proposed in this invention provides an effective and feasible technical approach for achieving large-scale, high-resolution well-hole seismic imaging, and has good application prospects and promotional value.

[0006] To achieve the above objectives, the present invention adopts the following technical solution:

[0007] A VSP uplink and downlink joint imaging method based on distributed optical fiber acoustic sensing (DAS) includes the following steps:

[0008] s1. Acquire DAS VSP seismic record data, perform preprocessing, and then separate the wavefield to obtain upgoing wave data and downgoing wave data;

[0009] s2. Mirror the down-wave data along the time axis at the wellhead position and stitch it with the up-wave data to form a super gather with an expanded aperture, thereby increasing the effective observation angle and expanding the imaging aperture;

[0010] s3. To maintain geometric consistency with the constructed super gather data, the original subsurface velocity model is vertically mirrored with the surface as the symmetrical interface, and then stitched together with the original velocity model at the surface location to form an extended velocity model. The area above the surface is the virtual velocity model region formed by the mirror, corresponding to the virtual well location, while the area below the surface is the real subsurface model region. Therefore, the downlink wavefield after mirroring can be equivalently represented by the uplink reflected wave received by the virtual well, thus achieving equivalent representation of the uplink and downlink wavefields in the unified model, and can be used for subsequent wavefield propagation and migration imaging.

[0011] s4. Based on the extended velocity model, the direct reverse time migration method using DAS data is used to simulate wavefield propagation. The forward propagation wavefield is obtained by forward propagation; the DAS VSP seismic records acquired in step s1 are used as boundary conditions to obtain the reverse propagation wavefield by backward propagation.

[0012] s5. Using cross-correlation imaging conditions for forward propagation wavefields With reverse propagation wave field Perform imaging to obtain imaging results;

[0013] s6. The local structural dip angle of the underground strata is estimated using the structural tensor method, the spatial gradient of the seismic imaging results is calculated and the structural tensor matrix is ​​constructed, and then the dip angle information of the underground strata is obtained through eigenvalue decomposition.

[0014] s7. Subsurface strata dip information is introduced as a structural constraint into the migration imaging process. By constructing a dip consistency weighting function, energy that does not conform to the structural dip angle is attenuated, thereby reducing migration artifacts and improving structural continuity.

[0015] s8. Superimpose the single-shot migration imaging results corresponding to all seismic sources to obtain the final imaging result.

[0016] Optionally, in step s1, a distributed optical fiber sensing acquisition system is laid in the well, seismic waves are excited by a ground source, and the seismic strain rate wave field signal is continuously recorded along the wellbore through the DAS system to obtain DAS VSP seismic record data.

[0017] Optionally, in step s4, the forward propagation wavefield is:

[0018] ;

[0019] in, For the density of the medium, For the model's longitudinal wave velocity, For strain rate, The source time function, For time, , , Spatial direction;

[0020] The reverse propagation wave field is:

[0021] ;

[0022] in, This is the actual DAS VSP data collected.

[0023] Optionally, in step s5, the imaging results Represented as:

[0024] ;

[0025] in, and These represent summation over all cannons and time, respectively.

[0026] Optionally, in step s6, the structure tensor for a point on the cross-section is represented as:

[0027] ;

[0028] in, Represents the gradient structure tensor matrix. Represents the gradient vector matrix in the unit direction. and This represents the gradient component in the corresponding direction;

[0029] matrix For a real symmetric positive semi-definite matrix, its eigenvalue decomposition yields:

[0030] ;

[0031] in, For two eigenvalues, and These are the two corresponding feature vectors;

[0032] The solution yields two eigenvectors, expressed as follows:

[0033] ;

[0034] The two corresponding feature values ​​are:

[0035] ;

[0036] inclination Represented as:

[0037] .

[0038] Optionally, in step s7, the weight function is expressed as:

[0039] ;

[0040] in, This represents the tilt angle consistency weighting coefficient. and These represent the dip angle values ​​of the VSP single-shot offset profile and the reference profile, respectively. This indicates the permissible tilt angle error.

[0041] The beneficial effects of this invention are as follows: By jointly utilizing the up-going and down-going waves in DAS VSP data, this invention effectively transforms the down-going multiples, which are not fully utilized in traditional methods, into equivalent reflection information, thereby significantly improving the utilization rate of wavefield information. Based on this, by constructing a mirror wavefield and an extended velocity model, the observation aperture is effectively expanded, significantly increasing the illumination range of underground structures, especially enhancing the imaging capability in areas far from the wellbore and shallow areas, thus improving the overall imaging coverage and resolution. Simultaneously, this invention utilizes the supplementary propagation path provided by the multiples to improve the illumination conditions of the underground medium, making the imaging of complex structural areas clearer and more reliable. The introduction of a structural tilt constraint mechanism during the imaging process suppresses imaging energy that does not conform to the geological structural characteristics, effectively reducing offset artifacts and improving the structural continuity and stability of the imaging results, thereby improving interpretation accuracy. Furthermore, this invention does not require additional acquisition equipment or changes to existing acquisition methods; it only requires processing existing DAS VSP data to improve imaging quality. It has advantages such as simple implementation process, clear computational framework, and ease of engineering implementation, improving data processing efficiency while ensuring imaging quality, and has good application and promotion value. Attached Figure Description

[0042] Figure 1 This is a schematic diagram of combined uplink and downlink wave field imaging according to an embodiment of the present invention;

[0043] Figure 2 This is an example of an extended velocity model for joint imaging according to an embodiment of the present invention;

[0044] Figure 3 This is a DAS VSP super gather spliced ​​from a mirrored downlink and uplink wave, as shown in an embodiment of the present invention.

[0045] Figure 4 This is an example of an up-flowing wave imaging result from an embodiment of the present invention;

[0046] Figure 5 This is an example of uplink and downlink combined imaging results shown in one embodiment of the present invention;

[0047] Figure 6 This is an example of tilt-constrained uplink and downlink wave joint imaging results shown in an embodiment of the present invention. Detailed Implementation

[0048] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of the present invention, not all of them. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention. Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to represent selected embodiments of the invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0049] s1. A distributed fiber optic sensing acquisition system is laid in the well. Seismic waves are excited by ground seismic sources. The seismic strain rate wave field signal is continuously recorded along the wellbore through the DAS system to obtain DAS VSP seismic record data. After preprocessing these data, wave field separation is performed to obtain up-wave data and down-wave data. The preprocessing includes noise removal, direct wave removal, amplitude correction, data equalization, etc.

[0050] s2. Mirror the down-wave data along the time axis at the wellhead position and stitch it with the up-wave data to form a super gather with an expanded aperture, thereby increasing the effective observation angle and expanding the imaging aperture.

[0051] s3. To maintain geometric consistency with the constructed super gather data, the original subsurface velocity model is vertically mirrored with the surface as the symmetrical interface, and then stitched together with the original velocity model at the surface location to form an extended velocity model. The area above the surface is the virtual velocity model region formed by the mirror, corresponding to the virtual well location, while the area below the surface is the real subsurface model region. Based on this extended relationship, the downlink wavefield after mirroring can be equivalently represented by the uplink reflected wave received by the virtual well, thereby achieving equivalent representation of the uplink and downlink wavefields in the unified model, and used for subsequent wavefield propagation and migration imaging.

[0052] s4. Based on the extended velocity model, the direct reverse time migration method using DAS data is used to simulate wavefield propagation. The forward propagation wavefield is obtained by forward propagation; the DAS VSP seismic records acquired in step s1 are used as boundary conditions to obtain the reverse propagation wavefield by backward propagation.

[0053] The forward wave field is:

[0054] ;

[0055] in, For forward propagation wave field, For the density of the medium, For the model's longitudinal wave velocity, For strain rate, The source time function, For time, , , Spatial direction;

[0056] The reverse propagation wave field is:

[0057] ;

[0058] in, For the reverse propagation wave field, This is the actual DAS VSP data collected.

[0059] s5. Using cross-correlation imaging conditions for forward propagation wavefields With reverse propagation wave field Imaging was performed, and the imaging results were obtained. Represented as:

[0060] ;

[0061] in, and These represent summation over all cannons and time, respectively.

[0062] s6. The local structural dip angle of the subsurface strata is estimated using the structural tensor method. The spatial gradient of the seismic imaging results is calculated and a structural tensor matrix is ​​constructed. Then, the dip angle information of the subsurface strata is obtained through eigenvalue decomposition. The structural tensor representation of a point on the profile is as follows:

[0063] ;

[0064] in, Represents the gradient structure tensor matrix. Represents the gradient vector matrix in the unit direction. and This represents the gradient component in the corresponding direction;

[0065] matrix For a real symmetric positive semi-definite matrix, its eigenvalue decomposition yields:

[0066] ;

[0067] in, For two eigenvalues, and These are the two corresponding feature vectors;

[0068] The solution yields two eigenvectors, expressed as follows:

[0069] ;

[0070] The two corresponding feature values ​​are:

[0071] ;

[0072] inclination Represented as:

[0073] .

[0074] s7. Subsurface strata dip angle information is introduced as a structural constraint into the migration imaging process. By constructing a dip angle consistency weighting function, energy that does not conform to the structural dip angle is attenuated, thereby reducing migration artifacts and improving structural continuity; the weighting function is expressed as:

[0075] ;

[0076] in, This represents the tilt angle consistency weighting coefficient. and These represent the dip angle values ​​of the VSP single-shot offset profile and the reference profile, respectively. This indicates the permissible tilt angle error.

[0077] s8. Superimpose the single-shot migration imaging results corresponding to all seismic sources to obtain the final imaging result.

[0078] To more clearly illustrate the technical solutions in the embodiments of the present invention, the technical methods and implementation process adopted by the present invention will be further described in detail with reference to the accompanying drawings. A schematic diagram of the overall uplink and downlink combined imaging based on DAS VSP data proposed in this invention is shown below. Figure 1 As shown. Traditional VSP imaging mainly relies on the upward reflected waves recorded by the receiver in the well. In contrast, this invention also utilizes the information carried by the downward multiples. Specifically, this invention uses a vertical mirror extension through a well and velocity model, interpreting the downward multiples received in the actual well as equivalent upward reflected waves recorded by the corresponding virtual receiver in the mirror velocity model. This allows the mirrored downward multiples to have the same propagation properties as the upward reflected waves, and they are used as effective reflection information in conjunction with the original upward wave data for migration imaging. This effectively expands the acquisition aperture and enhances the subsurface illumination effect, enabling both the main reflected wave and the downward multiples to contribute to the final migration imaging results. Figure 2 As shown, the original underground velocity model is vertically mirrored and extended with the surface as the symmetrical interface, and then spliced ​​with the original velocity model to form the extended velocity model. The solid yellow line represents the location of the real well, and the dashed yellow line represents the location of the mirrored virtual well. Figure 3 The image shows DAS VSP super gather data formed by stitching down-going and up-going waves after mirroring. This super gather effectively expands the observation aperture, improves the illumination range of subsurface structures, and provides richer wavefield information for subsequent migration imaging. Figure 4 The image shows the results of reverse time migration imaging of the underground structure using only the ascending wave field. It can be seen that the illumination range is mainly concentrated in the area near the well. At the same time, due to the limited observation angle, there are migration artifacts and structural discontinuities in the imaging results. Figure 5 The results of joint imaging of uplink and downlink wave fields using the method of the present invention are shown. It can be seen that the joint imaging results significantly expand the lateral coverage. At the same time, due to the introduction of downlink wave and its multiple wave information, some originally under-illuminated areas are effectively compensated, thereby improving the overall imaging resolution. Figure 6 The imaging results are shown after further introducing structural tilt constraints on the basis of combined uplink and downlink imaging. It can be seen that the offset artifacts are significantly reduced, the continuity of the underground strata is significantly improved, and the structural boundaries are clearer.

[0079] Of course, the above description is not intended to limit the present invention, and the present invention is not limited to the examples given above. Any changes, modifications, additions or substitutions made by those skilled in the art within the scope of the present invention should also fall within the protection scope of the present invention.

Claims

1. A VSP uplink and downlink joint imaging method based on distributed fiber optic acoustic sensing, characterized in that, Includes the following steps: s1. Acquire DAS VSP seismic record data, perform preprocessing, and then separate the wavefield to obtain upgoing wave data and downgoing wave data; s2. Mirror the downflow wave data along the time axis at the wellhead location and stitch it with the upflow wave data to form an extended aperture super gather; s3. Vertically mirror the original underground velocity model and stitch it together with the original velocity model to construct an extended velocity model; s4. Based on the extended velocity model, the direct reverse time migration method using DAS data is used to simulate wavefield propagation. The forward propagation wavefield is obtained by forward propagation; the DAS VSP seismic records acquired in step s1 are used as boundary conditions to obtain the reverse propagation wavefield by backward propagation. s5. Using cross-correlation imaging conditions for forward propagation wavefields With reverse propagation wave field Perform imaging to obtain imaging results; s6. Calculate the spatial gradient of the seismic imaging results and construct the structural tensor matrix, and then obtain the dip angle information of the subsurface strata through eigenvalue decomposition; s7. Subsurface strata dip angle information is introduced as a structural constraint into the migration imaging process. By constructing a dip angle consistency weighting function, energy that does not conform to the structural dip angle is attenuated. s8. Superimpose the single-shot migration imaging results corresponding to all seismic sources to obtain the final imaging result.

2. The VSP uplink and downlink joint imaging method based on distributed fiber optic acoustic sensing as described in claim 1, characterized in that, In step s4, the propagating wave field is: ； in, For the density of the medium, For the model's longitudinal wave velocity, For strain rate, The source time function, For time, , , Spatial direction; The reverse propagation wave field is: ； in, This is the actual DAS VSP data collected.

3. The VSP uplink and downlink joint imaging method based on distributed fiber optic acoustic sensing as described in claim 1, characterized in that, In step s5, the imaging results Represented as: ；· in, and These represent summation over all cannons and time, respectively.

4. The VSP uplink and downlink joint imaging method based on distributed fiber optic acoustic sensing as described in claim 1, characterized in that, In step s6, the structure tensor for a point on the cross-section is represented as: ； in, Represents the gradient structure tensor matrix. Represents the gradient vector matrix in the unit direction. and This represents the gradient component in the corresponding direction; matrix For a real symmetric positive semi-definite matrix, its eigenvalue decomposition yields: ； in, For two eigenvalues, and These are the two corresponding feature vectors; The solution yields two eigenvectors, expressed as follows: ； The two corresponding feature values ​​are: ； inclination Represented as: 。 5. The VSP uplink and downlink joint imaging method based on distributed fiber optic acoustic sensing as described in claim 1, characterized in that, In step s7, the weighting function is expressed as: ； in, This represents the tilt angle consistency weighting coefficient. and These represent the dip angle values ​​of the VSP single-shot offset profile and the reference profile, respectively. This indicates the permissible tilt angle error.

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