Seismic migration imaging in a well

Abstract

The application provides a well seismic migration imaging method, comprising the following steps: step 1, acquiring well seismic common shot gathers for migration imaging, an initial velocity model and an initial quality factor model; step 2, determining a lateral grid interval for migration, an effective frequency band range and a main frequency of the common shot gathers; step 3, determining a migration velocity model and a migration quality factor model; step 4, acquiring observation parameters corresponding to each common shot gather, determining a migration aperture and an effective imaging range; step 5, solving a wave equation based on a numerical algorithm, acquiring imaging time and a corresponding source wave field of the shot; step 6, realizing migration imaging of the common shot gather by using an imaging condition; and step 7, superimposing single-shot migration profiles of all shots to obtain a final migration profile. The well seismic migration imaging method has high calculation efficiency, small storage capacity, high imaging profile resolution and high signal-to-noise ratio, and can be directly applied to seismic attribute inversion.

Description

Technical Field

[0001] This invention relates to the field of exploration seismic technology, and in particular to a well-drilled seismic migration imaging method. Background Technology

[0002] Seismic exploration technology, as an important means of finding oil and gas reservoirs, has been widely applied in production practice. However, with the increasing demand for seismic exploration, oil and gas reservoirs with simple structures and easy detection are gradually decreasing, replaced by complex and finely structured oil and gas reservoirs under some deep and special geological bodies, making exploration targets increasingly complex. Complex structural oil and gas reservoirs are characterized by thin reservoirs, wide distribution, and concealed occurrence states, creating a significant demand for high-precision imaging of small structures within the reservoir, which poses a challenge to surface seismic exploration technology. Downhole seismic exploration technology is a new technology developed based on traditional surface seismic exploration and VSP (Very Small Space) exploration. Unlike surface seismic technology and VSP technology, downhole seismic exploration uses a method of well excitation and surface reception. The source location is close to the target layer, and the wavefield passes through a shallow deceleration zone less than once, resulting in a high signal-to-noise ratio and strong reservoir identification ability. It can perform high-precision imaging of the well-perimeter structure, making up for the unsatisfactory imaging effect of conventional surface seismic exploration in deep complex oil and gas reservoirs and small structures around the well. It is a new type of geophysical exploration method. Therefore, developing well-drilled seismic data is crucial for the current exploration and development of deep and complex oil and gas reservoirs.

[0003] Well-drilled seismic technology employs a unique observation method. The arrangement of its source and detectors differs from that of surface seismic imaging, resulting in significant differences in seismic wave propagation paths. Therefore, the relatively mature surface seismic imaging procedures cannot be directly applied to well-drilled seismic imaging. Furthermore, the generation of seismic waves in wells requires consideration of practical considerations; to protect the wellbore, the source energy is relatively low, resulting in weak signal energy. The viscosity effect of the formation causes severe absorption of high-frequency components of the seismic signal. Compared to surface seismic imaging, the absorption and attenuation effects are more severe in well-drilled seismic imaging, leading to a weaker effective signal. Therefore, new targeted imaging methods are needed for well-drilled seismic imaging. The primary purpose of well-drilled seismic technology is to provide detailed imaging of the peri-well region in deep, complex structures. Reverse-time migration imaging of seismic data, based on two-way wave theory, is not limited by dip angle and lateral velocity variations, overcoming the limitations of traditional ray migration and one-way wave migration methods, and has significant advantages in imaging complex structural oil and gas reservoirs. For these reasons, a targeted well-drilled seismic migration imaging method needs to be developed.

[0004] Chinese patent application CN201610701979.4 discloses a seismic migration imaging method and apparatus. The method includes: acquiring seismic data; determining imaging velocity field data and quality factor field data based on the seismic data; calculating ray path compensation travel time based on the quality factor field data; acquiring a travel time table, a compensation travel time table, and pre-stack seismic trace data corresponding to the seismic data; compensating the pre-stack seismic trace data based on the travel time table and the compensation travel time table; and generating an imaging result based on the compensated pre-stack seismic trace data. The seismic migration imaging method and apparatus provided in this application can improve the accuracy of migration imaging results.

[0005] Chinese patent application CN201110029735.3 discloses a method for improving the imaging effect of wave equation pre-stack depth migration, applied to the processing of reflection seismic data in seismic exploration, thereby improving the application effect of wave equation pre-stack depth migration. By establishing a depth-angle domain residual dynamic correction relationship and a layer velocity inversion method, the migration velocity model of wave equation pre-stack depth migration is directly updated based on the residual dynamic correction of angle gathers, thus improving the imaging effect of wave equation pre-stack depth migration. Utilizing the depth-angle domain residual dynamic correction relationship, this method achieves residual dynamic correction and noise and stretching removal of migration gathers in wave equation pre-stack depth migration, improving the signal-to-noise ratio and resolution of the migration stacked profile; it improves the quality of angle gathers applied to pre-stack inversion, enabling better direct identification of oil, gas, or water-bearing subsurface structures; and it can be applied to two-dimensional and three-dimensional wave equation pre-stack depth migration of reflection seismic data, having significant application value for oil and gas and mineral resource exploration.

[0006] Chinese patent application CN201110112909.2 discloses a multi-component joint elastic reverse-time migration imaging method for seismic data, belonging to the field of exploration geophysics. Its key feature is the direct use of multi-component seismic data as input. Without wavefield separation of the input data, it performs forward and reverse-time extrapolation based on the elastic wave equation, jointly constructing a subsurface elastic vector seismic wavefield using multiple components. Applying illumination-compensated elastic wave cross-correlation imaging conditions, it obtains four types of elastic wave imaging results with clearly defined physical meanings: P-waves, S-waves, converted P-waves, and converted S-waves. Low-pass angular domain filtering is then applied to suppress low wavenumber noise in the elastic reverse-time migration, yielding the final elastic wave migration imaging result. This invention, by directly inputting multi-component seismic data and jointly using multiple components to construct a subsurface elastic vector seismic wavefield, is used for accurate imaging of complex Earth media.

[0007] The existing technologies described above are significantly different from the present invention and have failed to solve the technical problem we want to address. Therefore, we have invented a new well-drilled seismic migration imaging method. Summary of the Invention

[0008] The purpose of this invention is to provide a well seismic migration imaging method that can efficiently acquire high-quality pre-stack depth migration profiles of well seismic data.

[0009] The objective of this invention can be achieved through the following technical measures: a well-hole seismic migration imaging method, which includes:

[0010] Step 1: Obtain the common shot point gather, initial velocity model, and initial quality factor model for migration imaging from the borehole seismic data.

[0011] Step 2: Determine the lateral grid spacing used for offsetting and the effective frequency band and dominant frequency of the common shot point gather;

[0012] Step 3, determine the offset velocity model v p and the offset quality factor model Q p ;

[0013] Step 4: Obtain the observation parameters corresponding to each common shot point gather, and determine the offset aperture and effective imaging range;

[0014] Step 5: Solve the wave equation using a numerical algorithm to obtain the imaging time and corresponding source wave field of the shot.

[0015] Step 6: Utilize imaging conditions to perform offset imaging of the common shot point gather;

[0016] Step 7: Superimpose the single-gun offset profiles of all guns to obtain the final offset profile.

[0017] The objective of this invention can also be achieved through the following technical measures:

[0018] In step 1, based on the detection target and geological conditions of the exploration area, the borehole seismic shot gather D(x) stored in SEGY or SGY format for migration imaging is acquired. r ,t;x s ), initial velocity model v, initial quality factor model Q; where, x s =(x s ,y s ,z s ) represents the spatial location vector of the earthquake source, x r =(x r ,y r ,z r ) represents the spatial position vector of the detector point, and t represents the wave propagation time.

[0019] In step 2, based on the target surface size of this exploration area, the lateral grid intervals dx and dy used for offset are determined.

[0020] In step 2, the common shot point set D(x) is...r ,t;x s Perform spectrum analysis to determine its effective bandwidth and dominant frequency f. dom ; where x s =(x s ,y s ,z s ) represents the spatial location vector of the earthquake source, x r =(x r ,y r ,z r ) represents the spatial position vector of the detector point, and t represents the wave propagation time.

[0021] In step 3, the geodetic coordinates involved in the common shot point gather are scanned, a work area observation system is established, and the migration velocity model and migration quality factor model are determined.

[0022] In step 3, for the aforementioned borehole seismic common shot point gather D(x) r ,t;x s ), read the head parameters one by one, where x s =(x s ,y s ,z s ) represents the spatial location vector of the earthquake source, x r =(x r ,y r ,z r () represents the spatial position vector of the detector point, and t represents the wave propagation time; obtain the four trace header keywords Sx, Sy, Gx, Gy for each trace; by comparing the magnitudes of the four trace header keywords for all traces, obtain the following four parameters: Min x Min y Max x Max y Min x Max represents the minimum value of the two head keys Sx and Gx for all the channels mentioned. x Min represents the maximum value of the two head keys Sx and Gx for all the channels mentioned. y Max represents the minimum value of the two header keywords Sy and Gy for all the channels mentioned. y This represents the maximum value of the two header keywords Sy and Gy for all channels; expressed in Min... x and Min y Using the coordinate origin as the reference point, an observation system for the work area is established based on the aforementioned horizontal grid intervals dx and dy, and the number of horizontal spatial grid points Nx and Ny corresponding to the final imaging profile of the work area are determined.

[0023] In step 3, the number of horizontal spatial grid points Nx and Ny are specifically as follows:

[0024]

[0025] and

[0026]

[0027] In step 3, based on the geodetic coordinates of the initial velocity model v and the initial quality factor model Q, and the established work area observation system, the initial velocity model v and the initial quality factor model Q are projected onto the established work area observation system to determine the migration velocity model v used for migration. p and the offset quality factor model Q p The process involves projecting the initial velocity model v and the initial quality factor model Q onto the established work area observation system to determine the migration velocity model v used for migration. p and the offset quality factor model Q p .

[0028] In step 3, the initial velocity model v and the initial quality factor model Q covered by the work area observation system are extracted. Using the established work area observation system as the coordinate system, a regular velocity model and quality factor model are formed, which is the aforementioned offset velocity model v. p and the offset quality factor model Q p .

[0029] In step 4, the observation parameters corresponding to each common shot gather are obtained, including the spatial location of the shot point and the spatial location of the receiver point. The local migration velocity model and the local migration quality factor model corresponding to the common shot gather are extracted to determine the migration aperture and the effective imaging range.

[0030] In step 4, for each shot, the head parameters of the common shot gather for that shot are read to obtain the shot depth selev, shot spatial positions sx and sy, and the corresponding receiver depth gelev and receiver spatial positions gx and gy for each trace. The four head keywords sx, sy, gx, and gy for all traces of that shot are compared to obtain the following four parameters: min x min y ,max x max y , where min x The maximum value represents the minimum value of the two path keys sx and gx for all paths of the cannon. x This represents the maximum value of the two track head keywords sx and gx for all tracks of the cannon, min. y The maximum value represents the minimum value of the two key terms sy and gy for all paths of the cannon. yThe maximum values ​​of the two track head keywords sy and gy represent all tracks of the gun; determine the number of lateral space grid points nx and ny corresponding to the common shot point track set of the gun.

[0031] In step 4, the formulas for determining nx and ny are:

[0032]

[0033] and

[0034]

[0035] In step 4, based on the established work area observation system, the coverage area of ​​the common shot point gather of the shot within the established work area observation system is determined, and the lateral starting spatial grid coordinates (nx) of the shot are obtained. start ,ny start ),in

[0036]

[0037] and

[0038]

[0039] In step 4, based on the obtained lateral initial spatial grid coordinates (nx) start ,ny start The local migration velocity model corresponding to the common shot point gather is extracted by taking the horizontal spatial grid points nx and ny as inputs. and Local Misalignment Quality Factor Model Get the target offset depth z max And the model depth direction sampling interval dz, and the number of depth direction grid points nz=z used to calculate the offset. max / dz; Based on the determined number of lateral spatial grid points nx and ny, the determined lateral grid interval dx and dy for the offset, and the target offset depth z max The lateral spatial offset aperture Aper of the gun is calculated as follows:

[0040]

[0041] Based on the gun point depth selev, the effective imaging range Dist(z) at depth z of the gun is obtained, specifically:

[0042]

[0043] In step 5, for each shot, the local offset velocity model of that shot is searched. The maximum value v maxBased on the stability condition formula, the depth direction sampling interval dz, and the lateral grid intervals dx and dy, the wavefield extension time sampling interval dt used for the migration is determined. The stability condition formula is as follows:

[0044]

[0045] In the formula (9), critia represents the stability condition factor, which is usually taken as 0.4; min{·} represents the minimum value function.

[0046] In step 6, using the common shot point gather of the well as the boundary conditions, the wave equation is solved in reverse time based on the numerical algorithm, and the migration imaging of the common shot point gather is realized by using the imaging conditions based on the imaging time of the shot and the corresponding source wave field.

[0047] In step 6, for each shot, the local shot point grid coordinates (nx) in the established work area observation system are calculated. s ,ny s ,nz s At this gun emplacement location, the main frequency is set to f. dom Using the determined local migration velocity model, local migration quality factor model, spatial depth and interval dx, dy, and dz, and time sampling interval dt, the seismic wave equation is solved numerically to achieve forward modeling of the wavefield at the shot point, obtaining the imaging time T(x; x) of the shot at each spatial location x = (x, y, z). s ) and the corresponding source wave field S(x; x) at the time. s Based on numerical methods, the seismic wave equation is solved to achieve forward modeling of the wave field at the shot point.

[0048] In step 6, the seismic wave equation is:

[0049]

[0050] In the formula (10), u S (x,t;x s ) represents the seismic wave field, f(x,t; x s () represents the earthquake focal point, and the scalar X is specifically:

[0051]

[0052] Specifically, the scalar β is:

[0053]

[0054] In the formula (10), τ is specifically:

[0055]

[0056] The numerical solution method of partial differential equations is used to solve equation (10) to obtain the medium vibration at any spatial position x at each time t of the shot, i.e., the seismic wave field u. S (x,t;x s );

[0057] The method described above obtains the imaging time T(x; x) of the gun at each spatial location x = (x, y, z). s ) and the corresponding source wave field S(x; x) at the time. s Specifically, for each spatial location x = (x, y, z), calculate the reference imaging time T for that location. ref (x;x s The calculation method is as follows:

[0058]

[0059] This is the local offset velocity model corresponding to the common shot point gather of this gun;

[0060] The calculated reference imaging time T ref (x;x s ), the imaging time T(x; x) at each spatial location x = (x, y, z) s The source wave field S(x; x) at the corresponding time. s Specifically:

[0061]

[0062] The imaging time T(x; x) of the gun at each spatial position x = (x, y, z) is described. s Specifically:

[0063]

[0064] In step 7, for each shot, the obtained borehole seismic common shot point gather D(x) is used. r ,t;x s Using the boundary conditions, the seismic wave equation is solved in reverse time based on a numerical algorithm, and the imaging time T(x; x) of the shot is obtained. s ) and the corresponding source wave field S(x; x s Using imaging conditions, the migration imaging of the common shot point gather is achieved, and the single-shot migration imaging profile I(x; x) of the shot is obtained. s The single-shot migration imaging profiles of all shots are superimposed to obtain the final migration profile I(x); the obtained borehole seismic common shot gather D(x) is used as the basis for this process. r ,t;xs The boundary conditions are defined by the following equations: (equations are provided in the original text). The seismic wave equations are solved in reverse time using a numerical algorithm.

[0065]

[0066] The aforementioned method of using imaging conditions to achieve offset imaging of the common shot point gather specifically includes:

[0067]

[0068] Dist represents the effective offset aperture range;

[0069] The method of superimposing the single-shot offset imaging profiles of all guns to obtain the final offset profile I(x) is as follows:

[0070]

[0071] The borehole seismic migration imaging method of this invention relates to seismic data migration imaging processing and has the following advantages: 1) This invention is a borehole seismic migration imaging method. Compared with conventional surface seismic migration imaging methods, this invention can obtain high-precision, high-resolution, and high signal-to-noise ratio migration imaging profiles of complex subsurface structures; 2) This invention differs from conventional surface seismic migration imaging methods. This method does not require storing seismic wavefields, has low dependence on computer hardware, and has high computational efficiency; 3) This invention is designed for the special observation method of borehole seismic migration and has better imaging effects on deep steep-dip structures and even vertical structures. At the same time, due to the introduction of attenuation compensation, the amplitude of the imaging profile is more faithful, and the obtained migration profile can be directly applied to seismic attribute inversion, improving the accuracy of reservoir prediction and fluid identification. Attached Figure Description

[0072] Figure 1 This is a flowchart of a specific embodiment of the well-hole seismic migration imaging method of the present invention;

[0073] Figure 2 This is a schematic diagram of a typical two-dimensional thin inter-reservoir model provided in a specific embodiment of the present invention;

[0074] Figure 3 In a specific embodiment of the present invention Figure 2 The image shows a stacked offset profile of a typical two-dimensional thin inter-reservoir model.

[0075] Figure 4 This is a schematic diagram of a typical three-dimensional thin interbedded reservoir model provided in a specific embodiment of the present invention;

[0076] Figure 5 In a specific embodiment of the present invention Figure 4The image shows a stacked offset profile of a typical three-dimensional thin inter-reservoir model. Detailed Implementation

[0077] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0078] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments of the present invention. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, and / or combinations thereof.

[0079] This invention relates to a borehole seismic migration imaging method, comprising: acquiring borehole seismic common shot gathers, initial velocity models, and initial quality factor models for migration imaging; determining the lateral grid interval used for migration; determining the effective frequency band range and dominant frequency of the common shot gathers; scanning the geodetic coordinates involved in the common shot gathers, establishing a field observation system, and determining the migration velocity model and migration quality factor model; acquiring the observation parameters corresponding to each common shot gather, including the spatial location of the shot point and the spatial location of the receiver point, extracting the local migration velocity model and local migration quality factor model corresponding to the common shot gather, and determining the migration aperture and effective imaging range; solving the wave equation based on a numerical algorithm to obtain the imaging time and corresponding source wavefield of the shot; using the borehole seismic common shot gathers as boundary conditions, solving the wave equation in reverse time based on a numerical algorithm, and using the imaging conditions based on the imaging time and corresponding source wavefield of the shot to achieve migration imaging of the common shot gathers; and superimposing the single-shot migration profiles of all shots to obtain the final migration profile. This invention has high computational efficiency, small storage requirements, high imaging profile resolution and signal-to-noise ratio, and can be directly applied to seismic attribute inversion.

[0080] The following are several specific embodiments of the application of the present invention.

[0081] Example 1

[0082] In a specific embodiment 1 of the present invention, please refer to Figure 1 This is a schematic diagram of the well-hole seismic migration imaging method provided by the present invention. The well-hole seismic migration imaging method of the present invention includes the following steps:

[0083] Step S100: Based on the detection target and geological conditions of the exploration area, acquire the borehole seismic shot point gather D(x) stored in SEGY or SGY format for migration imaging. r,t;x s ), initial velocity model v, initial quality factor model Q; where, x s =(x s ,y s ,z s ) represents the spatial location vector of the earthquake source, x r =(x r ,y r ,z r ) represents the spatial position vector of the detector point, and t represents the wave propagation time;

[0084] Step S200: Based on the target surface size of this exploration area, determine the lateral grid intervals dx and dy used for offsetting;

[0085] Step S300, for the common shot point set D(x) r ,t;x s Perform spectrum analysis to determine its effective bandwidth and dominant frequency f. dom ;

[0086] Step S400, for the aforementioned well-hole seismic common shot point gather D(x) r ,t;x s The track header parameters are read one by one to obtain the four track header keywords Sx, Sy, Gx, and Gy for each track. By comparing the magnitudes of these four track header keywords for all tracks, the following four parameters are obtained: Min x Min y Max x Max y Min x Max represents the minimum value of the two head keys Sx and Gx for all the channels mentioned. x Min represents the maximum value of the two head keys Sx and Gx for all the channels mentioned. y Max represents the minimum value of the two header keywords Sy and Gy for all the channels mentioned. y This represents the maximum value of the two header keywords Sy and Gy for all channels; expressed in Min... x and Min y Using the coordinate origin as the reference point, an observation system for the work area is established based on the aforementioned horizontal grid intervals dx and dy. The number of horizontal spatial grid points Nx and Ny corresponding to the final imaging profile of the work area are determined, specifically as follows:

[0087]

[0088] and

[0089]

[0090] Based on the geodetic coordinates of the initial velocity model v and the initial quality factor model Q, and the established work area observation system, the initial velocity model v and the initial quality factor model Q are projected onto the established work area observation system to determine the migration velocity model v used for migration. p and the offset quality factor model Q p The process involves projecting the initial velocity model v and the initial quality factor model Q onto the established work area observation system to determine the migration velocity model v used for migration. p and the offset quality factor model Q p Specifically, this involves extracting the initial velocity model v and the initial quality factor model Q covered by the work area observation system, and using the established work area observation system as the coordinate system to form a regular velocity model and quality factor model, which is the aforementioned offset velocity model v. p and the offset quality factor model Q p ;

[0091] Step S500: For each shot, read the head parameters of the common shot point gather for that shot, and obtain the shot point depth selev, shot point spatial positions sx and sy, and the corresponding receiver point depth gelev and receiver point spatial positions gx and gy for each trace; compare the magnitudes of the four head keywords sx, sy, gx, and gy for all traces of that shot, and obtain the following four parameters: min x min y ,max x max y , where min x The maximum value represents the minimum value of the two path keys sx and gx for all paths of the cannon. x This represents the maximum value of the two track head keywords sx and gx for all tracks of the cannon, min. y The maximum value represents the minimum value of the two key terms sy and gy for all paths of the cannon. y The maximum values ​​of the two trackhead keywords sy and gy represent all tracks of the gun; the number of transverse spatial grid points nx and ny corresponding to the common shot point track set of the gun are determined as follows:

[0092]

[0093] and

[0094]

[0095] Based on the established work area observation system, the coverage area of ​​the common shot point gather of the shot within the established work area observation system is determined, and the lateral starting spatial grid coordinates (nx) of the shot are obtained. start ,ny start ),in

[0096]

[0097] and

[0098]

[0099] Based on the obtained lateral initial spatial grid coordinates (nx) start ,ny star t) and the number of horizontal spatial grid points nx and ny, extract the local migration velocity model corresponding to the common shot point gather of this shot. and Local Misalignment Quality Factor Model Get the target offset depth z max And the model depth direction sampling interval dz, and the number of depth direction grid points nz=z used to calculate the offset. max / dz; Based on the determined number of lateral spatial grid points nx and ny, the determined lateral grid interval dx and dy for the offset, and the target offset depth z max The lateral spatial offset aperture Aper of the gun is calculated as follows:

[0100]

[0101] Based on the gun point depth selev, the effective imaging range Dist(z) at depth z of the gun is obtained, specifically:

[0102]

[0103] Step S600: For each shot, search for the local offset velocity model of that shot. The maximum value v max Based on the stability condition formula, the depth direction sampling interval dz, and the lateral grid intervals dx and dy, the wavefield extension time sampling interval dt used for the migration is determined. The stability condition formula is as follows:

[0104]

[0105] In the above formula (9), critia represents the stability condition factor, which is usually taken as 0.4; min{·} represents the minimum value function;

[0106] Step S700: For each shot, calculate the local shot point grid coordinates (nx) in the established work area observation system. s ,ny s ,nz s At this gun emplacement location, the main frequency is set to f. domUsing the determined local migration velocity model, local migration quality factor model, spatial depth and interval dx, dy, and dz, and time sampling interval dt, the seismic wave equation is solved numerically to achieve forward modeling of the wavefield at the shot point, obtaining the imaging time T(x; x) of the shot at each spatial location x = (x, y, z). s ) and the corresponding source wave field S(x; x) at the time. s Based on numerical methods, the seismic wave equation is solved to achieve forward modeling of the wavefield at the shot point, specifically:

[0107] The earthquake wave equation is as follows:

[0108]

[0109] In the formula (10), u S (x,t;x s ) represents the seismic wave field, f(x,t; x s () represents the earthquake focal point, and the scalar X is specifically:

[0110]

[0111] Specifically, the scalar β is:

[0112]

[0113] In the formula (10), τ is specifically:

[0114]

[0115] The numerical solution method of partial differential equations is used to solve equation (10) to obtain the medium vibration at any spatial position x at each time t of the shot, i.e., the seismic wave field u. S (x,t;x s );

[0116] The method described above obtains the imaging time T(x; x) of the gun at each spatial location x = (x, y, z). s ) and the corresponding source wave field S(x; x) at the time. s Specifically, for each spatial location x = (x, y, z), calculate the reference imaging time T for that location. ref (x;x s The calculation method is as follows:

[0117]

[0118] Using the calculated reference imaging time T ref (x;x s), the imaging time T(x; x) at each spatial location x = (x, y, z) s The source wave field S(x; x) at the corresponding time. s Specifically:

[0119]

[0120] The imaging time T(x; x) of the gun at each spatial position x = (x, y, z) is described. s Specifically:

[0121]

[0122] Step S800: For each shot, use the obtained borehole seismic common shot point gather D(x) r ,t;x s Using the boundary conditions, the seismic wave equation is solved in reverse time based on a numerical algorithm, and the imaging time T(x; x) of the shot is obtained. s ) and the corresponding source wave field S(x; x s Using imaging conditions, the migration imaging of the common shot point gather is achieved, and the single-shot migration imaging profile I(x; x) of the shot is obtained. s The single-shot migration imaging profiles of all shots are superimposed to obtain the final migration profile I(x); the obtained borehole seismic common shot gather D(x) is used as the basis for this process. r ,t;x s The boundary conditions are defined by the following equations: (equations are provided in the original text). The seismic wave equations are solved in reverse time using a numerical algorithm.

[0123]

[0124] The aforementioned method of using imaging conditions to achieve offset imaging of the common shot point gather specifically includes:

[0125]

[0126] The method of superimposing the single-shot offset imaging profiles of all guns to obtain the final offset profile I(x) is as follows:

[0127]

[0128] Example 2

[0129] In a specific embodiment 2 of the present invention, the present invention is applied. Figure 2 This is a typical two-dimensional thin inter-reservoir model provided by the present invention, wherein, (a) the migration velocity model v p (b) Offset quality factor model Q pThe model has a lateral width of 2.42 km and a depth of 3 km. The spatial grid used for the migration is 10 m in size, with a total of 100 shots. There is a well in the middle of the model (1200 m), and the shot points are placed in the well. The initial shot point depth is 200 m, and the shot spacing is 15 m. The receiver points are placed on the ground. Shots are fired from the well and received on the ground. Each shot has 401 channels, with a channel spacing of 10 m, a recording time of 4 s, and a time step of 0.5 ms. The Ricker wavelet with a dominant frequency of 45 Hz is used as the source time function. Figure 3 yes Figure 2 The stacked offset profile of a typical two-dimensional thin inter-reservoir model is shown below: where, Figure 3 (a) is the superimposed offset profile obtained using the traditional method. Figure 3 (b) is the superimposed offset profile obtained using the method of the present invention. Figure 3 As shown in the comparison of the superimposed migration profiles, it can be seen that the migration imaging profiles obtained by the traditional method have uneven imaging amplitudes and unclear structural details in thin layers. Furthermore, the migration imaging profiles obtained by the traditional method are unable to eliminate the influence of medium absorption attenuation, and have weak characterization ability for deep well-side structures. In contrast, the superimposed migration profiles obtained by the method of this invention effectively image complex structures in thin layers, indicating that the superimposed migration profiles obtained by the method of this invention have better accuracy. The above results verify the effectiveness of the method of this invention in complex models.

[0130] Example 3

[0131] In a specific embodiment 3 of the present invention, the invention is applied. Figure 4 This is a typical three-dimensional thin inter-reservoir model provided by the present invention, wherein, (a) the migration velocity model v p (b) Offset quality factor model Q p The model has an inline length of 3190 km, a crossline length of 2410 m, and a depth of 2995 m. The spatial grid used for the migration is 10 m in size, with a total of 80 shots. The spatial coordinates of the initial shot point are (1600 m, 1210 m, 200 m). The shot points are placed in the well, with a shot spacing of 15 m. Detectors are evenly distributed on the surface, with a spacing of 10 m in both the x and y directions. The recording time is 2.3 s, with a time step of 0.5 ms. The Ricker wavelet with a dominant frequency of 45 Hz is used as the source time function. Figure 5 yes Figure 4 The stacked offset profile of a typical three-dimensional thin inter-reservoir model is shown below: where, Figure 5 (a) is the superimposed offset profile obtained using the traditional method. Figure 5 (b) is the superimposed offset profile obtained using the method of the present invention. Figure 5As can be seen from the comparison of the superimposed offset profiles, the superimposed offset profiles obtained using the method of this invention still have good imaging capabilities for complex three-dimensional structures. In summary, this invention has good feasibility and practicality in complex geological and geophysical models.

[0132] Finally, it should be noted that the above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

[0133] Except for the technical features described in the specification, all other technologies are known to those skilled in the art.

Claims

1. A well-drilled seismic migration imaging method, characterized in that, The well-hole seismic migration imaging method includes: Step 1: Obtain the common shot point gather, initial velocity model, and initial quality factor model for migration imaging from the borehole seismic data. Step 2: Determine the lateral grid spacing used for offsetting and the effective frequency band and dominant frequency of the common shot point gather; Step 3, Determine the offset velocity model and offset quality factor model ; Step 4: Obtain the observation parameters corresponding to each common shot point gather, and determine the offset aperture and effective imaging range; Step 5: Solve the wave equation using a numerical algorithm to obtain the imaging time and corresponding source wave field of the shot. This includes: In step 5, for each shot, search the local migration velocity model of that shot. maximum value Based on the stability condition formula and the depth direction sampling interval and horizontal grid spacing and Determine the wavefield extension time sampling interval used for the offset. The stability condition formula is as follows: （9） In the formula (9), The stability condition factor is typically set to 0.

4. Characterizes the function that takes the minimum value; Step 6: Migrate imaging of the common shot gather using imaging conditions, including: using the common shot gather from the borehole seismic test as boundary conditions, solving the wave equation in reverse time based on a numerical algorithm, and migrating the common shot gather based on the imaging time of the shot and the corresponding source wavefield; for each shot, calculating the local shot point grid coordinates in the established work area observation system. The main frequency was set at this gun emplacement location. The source wavelet, using the aforementioned determined local migration velocity model, local migration quality factor model, spatial depth, and interval... , and and time sampling interval By solving the seismic wave equation using numerical methods, a forward modeling simulation of the wavefield at the shot point was achieved, obtaining the wavefield of the shot at each spatial location. Imaging time at the location and the source wave field at the corresponding time. The seismic wave equation is solved using numerical methods to achieve forward modeling of the wavefield at the shot point. Step 7: Superimpose the single-gun offset profiles of all guns to obtain the final offset profile.

2. The well-drilled seismic migration imaging method according to claim 1, characterized in that, In step 1, based on the detection target and geological conditions of the exploration area, the borehole seismic shot gathers for migration imaging are acquired and stored in SEGY or SGY format. Initial velocity model Initial quality factor model ;in, Represents the spatial location vector of the earthquake source. Represents the spatial position vector of the detector point. This indicates the wave propagation time.

3. The well-drilled seismic migration imaging method according to claim 1, characterized in that, In step 2, the transverse grid interval used for offset is determined based on the target surface size of this exploration area. and .

4. The well-drilled seismic migration imaging method according to claim 1, characterized in that, In step 2, the common shot point gather is... Perform spectrum analysis to determine its effective bandwidth and dominant frequency. ;in, Represents the spatial location vector of the earthquake source. Represents the spatial position vector of the detector point. This indicates the wave propagation time.

5. The well-drilled seismic migration imaging method according to claim 1, characterized in that, In step 3, the geodetic coordinates involved in the common shot point gather are scanned, the work area observation system is established, and the migration velocity model and migration quality factor model are determined.

6. The well-drilled seismic migration imaging method according to claim 5, characterized in that, In step 3, for the well-hole seismic common shot point gather The track head parameters are read one by one, among which... Represents the spatial location vector of the earthquake source. Represents the spatial position vector of the detector point. Indicates wave propagation time; retrieves the four track header keywords for each track. , , , By comparing the four key headers of all channels, the following four parameters are obtained: , , , ,in Two key terms representing all channels and The minimum value, Two key terms representing all channels and The maximum value, Two key terms representing all channels and The minimum value, Two key terms representing all channels and The maximum value; with and The origin is the base, and the horizontal grid spacing is [missing information]. and Establish a work area observation system to determine the number of lateral spatial grid points corresponding to the final imaging profile of the work area. and .

7. The well-drilled seismic migration imaging method according to claim 6, characterized in that, In step 3, the number of horizontal spatial grid points and Specifically: （1） and （2）。 8. The well-hole seismic migration imaging method according to claim 7, characterized in that, In step 3, based on the initial velocity model and the initial quality factor model The geodetic coordinates and the established work area observation system will be used to determine the initial velocity model. Initial quality factor model Projecting onto the established work area observation system, the migration velocity model used for migration is determined. and offset quality factor model ; Initial velocity model Initial quality factor model Projecting onto the established work area observation system, the migration velocity model used for migration is determined. and offset quality factor model .

9. The well-hole seismic migration imaging method according to claim 8, characterized in that, In step 3, the initial velocity model covered by the work area observation system is... and the initial quality factor model Extracted and using the established work area observation system as the coordinate system, a regular velocity model and quality factor model are formed, which is the aforementioned migration velocity model. and offset quality factor model .

10. The well-hole seismic migration imaging method according to claim 1, characterized in that, In step 4, the observation parameters corresponding to each common shot gather are obtained, including the spatial location of the shot point and the spatial location of the receiver point. The local migration velocity model and the local migration quality factor model corresponding to the common shot gather are extracted to determine the migration aperture and the effective imaging range.

11. The well-hole seismic migration imaging method according to claim 10, characterized in that, In step 4, for each shot, the head parameters of the common shot point gather for that shot are read to obtain the shot point depth for that shot. Spatial location of the firing point and The depth of each corresponding detector point and the spatial location of the detector point and Keywords for the four trackheads of all tracks of this artillery. , , , Perform size comparisons separately and obtain the following four parameters: , , , ,in The two trackhead keywords represent all tracks of the cannon. and The minimum value, The two trackhead keywords represent all tracks of the cannon. and The maximum value, The two trackhead keywords represent all tracks of the cannon. and The minimum value, The two trackhead keywords represent all tracks of the cannon. and The maximum value; determine the number of lateral spatial grid points corresponding to the common shot point gather of this gun. and .

12. The well-drilled seismic migration imaging method according to claim 11, characterized in that, In step 4, determine and The formula is: （3） and （4）。 13. The well-drilled seismic migration imaging method according to claim 12, characterized in that, In step 4, based on the established work area observation system, the coverage area of ​​the common shot point gather of the shot within the established work area observation system is determined, and the lateral starting spatial grid coordinates of the shot are obtained. ,in （5） and （6）。 14. The well-hole seismic migration imaging method according to claim 13, characterized in that, In step 4, based on the obtained lateral starting spatial grid coordinates and the number of horizontal spatial grid points and Extract the local migration velocity model corresponding to the common shot point gather of the shot. and Local Misalignment Quality Factor Model ; Obtain target offset depth and the sampling interval in the depth direction of the model Number of depth-direction grid points used to calculate the offset Based on the determined number of horizontal spatial grid points and The lateral grid spacing used for the determined offset and and target offset depth Calculate the lateral spatial offset aperture of the gun. Specifically: （7） Based on the gun's firing point depth To obtain the depth of the cannon Effective imaging range at the location Specifically: （8）。 15. The well-hole seismic migration imaging method according to claim 1, characterized in that, In step 6, the seismic wave equation is: (10) In the formula (10), Represents the seismic wave field. Indicates the earthquake focal point, scalar Specifically: （11） Among them, scalar Specifically: （12） In the formula (10), Specifically: （13） The numerical solution method of partial differential equations is used to solve equation (10) to obtain the gun at each time step. any position in space The vibration of the medium at that location, i.e., the seismic wave field ; Obtain the cannon in every spatial location Imaging time at the location and the source wave field at the corresponding time. Specifically, for each spatial location At this location, calculate the reference imaging time. The calculation method is as follows: （14） This is the local offset velocity model corresponding to the common shot point gather of this gun; Using the calculated reference imaging time Each spatial location Imaging time The source wave field at the corresponding time Specifically: （15） The cannon is in every spatial position Imaging time at the location Specifically: （16）。 16. The well-drilled seismic migration imaging method according to claim 15, characterized in that, In step 7, for each shot, the obtained borehole seismic common shot point gather is used. As boundary conditions, the seismic wave equation is solved in reverse time using a numerical algorithm, and the resulting imaging time of the shot is used as the basis for the solution. and the corresponding source wave field By utilizing imaging conditions, migration imaging of the common shot point gather is achieved, resulting in a single-shot migration imaging profile of the shot. The single-shot offset imaging profiles of all guns are superimposed to obtain the final offset profile. ; using the obtained well-ground seismic co-shot point collection As boundary conditions, the seismic wave equations are solved in reverse time using a numerical algorithm, specifically by solving the following system of equations: （17） The migration imaging of this common shot point gather is achieved using imaging conditions, specifically as follows: （18） Dist represents the effective offset aperture range; The single-shot offset imaging profiles of all guns are superimposed to obtain the final offset profile. Specifically: （19）。

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