Seabed node seismic acquisition method with combined density

文档序号：1888094 发布日期：2021-11-26 浏览：20次中文

阅读说明：本技术 一种组合密度的海底节点地震采集方法 (Seabed node seismic acquisition method with combined density ) 是由张健男但志伟李三福孙雷鸣申跃勇孙博史芳徐克楠于 2021-08-27 设计创作，主要内容包括：本发明公开了一种组合密度的海底节点地震采集方法。根据本发明提供的技术方案,根据勘探目标的目的层深度,计算用于地震成像的第一区域的外扩孔径,并确定第一区域的第一炮点采样密度；计算用于全波形地震反演的第二区域的外扩孔径,并确定第二区域的第二炮点采集密度；组合所述第一区域和所述第二区域,针对重合区域采用所述第一炮点采样密度进行勘探观测,针对非重合区域采用所述第二炮点采样密度进行勘探观测。通过本发明可以通过对勘测区域分别设计高密炮点的内部区域和低密炮点的外部区域,同时满足地震成像和全波形反演的要求,极大地提升了勘测效率,并降低了勘测采集的成本。(The invention discloses a seabed node seismic acquisition method with combined density. According to the technical scheme provided by the invention, according to the target depth of a target layer of an exploration target, calculating the outward-expanding aperture of a first area for seismic imaging, and determining the first shot point sampling density of the first area; calculating the outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area; and combining the first area and the second area, and carrying out exploration observation by adopting the first shot point sampling density aiming at a coincident area and the second shot point sampling density aiming at a non-coincident area. By the method, the internal area of the high-density shot point and the external area of the low-density shot point can be respectively designed for the survey area, the requirements of seismic imaging and full waveform inversion are met, the survey efficiency is greatly improved, and the survey acquisition cost is reduced.)

1. A method for seismic acquisition of ocean bottom nodes with combined density, comprising:

calculating an outer expanding aperture of a first area for seismic imaging according to the target depth of a target layer of an exploration target, and determining a first shot sampling density of the first area;

calculating the outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area;

and combining the first area and the second area, and carrying out exploration observation by adopting the first shot point sampling density aiming at a coincident area and the second shot point sampling density aiming at a non-coincident area.

2. The method of claim 1, wherein calculating a flare aperture for the first region of the seismic imaging based on the depth of interest of the survey target and determining the first shot sampling density for the first region further comprises:

determining the longest offset distance according to the depth of the target layer, and further determining the outward-expanding aperture of the first region based on a first preset condition; wherein the first preset condition comprises: the dynamic correction stretching rate is lower than a first threshold value, the speed analysis precision error is lower than a second threshold value, the reflection coefficient accords with a stable condition, and the interference of direct waves and first-arrival refraction waves is avoided;

determining the first region according to the flaring aperture of the first region;

and determining a first shot sampling density of the first area according to the destination layer grid information.

3. The method of claim 2, wherein determining the longest offset distance according to the depth of the target layer and further determining the flare aperture of the first region based on a first preset condition further comprises:

when the first preset condition is met, the outward-expanding aperture of the first area is equal to the longest offset distance, and the longest offset distance is equal to the depth of the target layer.

4. The method of claim 2, wherein said determining the first region first shot sampling density from destination layer grid information further comprises:

determining the side lengths b1 and b2 of the mesh bins of the target layer according to the mesh information of the target layer and a second preset condition;

calculating the bin size of the target layer demonstration grid point according to the minimum value of the target layer grid bin sides b1 and b 2;

calculating the area of the first region according to the outward-expanding aperture of the first region;

and determining the distance between the shot points of the observation system according to the side length of the mesh surface element of the target layer.

And sampling density of the first shot according to the interval of the shots of the observation system.

5. The method according to claim 4, wherein the second preset condition comprises:

b1≤v_rms/(4×f_max×sinθ)

b2≤v_rms/(2×f_p)

where b1 is the bin edge length that satisfies the highest aliasing-free frequency requirement, v_rmsDemonstration for the purpose layerRoot mean square velocity, f, of overburden at a grid point_maxDemonstrating the highest aliasing-free frequency of the grid points for the destination layer; theta is the stratum inclination angle of the demonstration grid point of the target layer; b2 is the bin side length, f, which satisfies the lateral resolution requirement_pThe dominant frequency of the grid points is demonstrated for the destination layer.

6. The method of claim 4, wherein the observation system shots have a spacing of two times the side length of the mesh bin of the destination layer.

7. The method of claim 1, wherein calculating the flared aperture of the second region for full waveform seismic inversion further comprises:

and establishing a model velocity field, carrying out rotary wave ray analysis on the earth surface, confirming the main offset distribution range of rays passing through a target layer, and determining the main offset distribution range as the external expanding aperture of the second area for full waveform seismic inversion.

8. The method of claim 1, wherein determining a second shot point acquisition density for a second region further comprises:

calculating a first coefficient according to the full waveform inversion highest inversion frequency and the seismic imaging frequency;

and calculating to obtain the second shot point acquisition density according to the first shot point sampling density and the first coefficient.

9. The method of claim 1, wherein the combining the first region and the second region further comprises:

and overlapping the first region and the second region based on the positions and the area sizes of the first region and the second region to obtain the overlapped region and the non-overlapped region.

10. The method of claim 1, wherein after the survey observations are made with the first shot sampling density for coincident regions and the second shot sampling density for non-coincident regions, the method further comprises:

obtaining a first observation for the coincident region survey observation and a second observation for the non-coincident region survey observation; performing the full waveform seismic inversion together based on the first observation and the second observation.

Technical Field

The invention relates to the field of marine seismic exploration, in particular to a seabed node seismic acquisition method with combined density.

Background

With the development of marine oil exploration technology, in marine oil three-dimensional seismic exploration, in order to ensure the accuracy of seismic imaging, an observation system with high density and short arrangement for seismic imaging is generally adopted, and in order to perform velocity modeling, an observation system with long arrangement and low density is generally adopted to perform full waveform inversion.

In the prior art, due to the fact that the offset distance in an observation system aiming at seismic imaging is insufficient, the requirement of full waveform inversion on the offset distance cannot be met, the uncertainty of inversion is increased, and the convergence of subsequent inversion is influenced; and for the observation system of full waveform inversion, the offset distance is too large and the sampling density is insufficient, so that the requirement of seismic imaging cannot be met, and the imaging precision is influenced. Therefore, the prior art can only preferentially meet one direction for surveying at a time, greatly influences the surveying efficiency and greatly increases the surveying cost.

Disclosure of Invention

In view of the above, the present invention has been developed to provide a method of ocean bottom node seismic acquisition of a combined density that overcomes, or at least partially solves, the above-mentioned problems.

According to the invention there is provided a method of combined density ocean bottom node seismic acquisition, the method comprising:

calculating the outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area;

In the foregoing solution, the calculating an extended aperture of a first region for seismic imaging according to a depth of a target layer of an exploration target, and determining a first shot sampling density of the first region further includes:

determining the first region according to the flaring aperture of the first region;

and determining a first shot sampling density of the first area according to the destination layer grid information.

In the foregoing solution, the determining the longest offset distance according to the depth of the target layer, and further determining the outer expanded aperture of the first region based on a first preset condition further includes:

In the foregoing solution, the determining, according to the destination layer grid information, the first shot sampling density of the first area further includes:

determining the side lengths b1 and b2 of the mesh bins of the target layer according to the mesh information of the target layer and a second preset condition;

calculating the bin size of the target layer demonstration grid point according to the minimum value of the target layer grid bin sides b1 and b 2;

calculating the area of the first region according to the outward-expanding aperture of the first region;

determining the distance between the shot points of the observation system according to the side length of the mesh surface element of the target layer;

and determining the first shot sampling density according to the distance between the shots of the observation system.

In the foregoing scheme, the second preset condition includes:

b1≤v_rms/(4×f_max×sinθ)

b2≤v_rms/(2×f_p)

where b1 is the bin edge length that satisfies the highest aliasing-free frequency requirement, v_rmsDemonstrating the root mean square velocity, f, of the overburden at a grid point for the target layer_maxDemonstrating the highest aliasing-free frequency of the grid points for the destination layer; theta is the stratum inclination angle of the demonstration grid point of the target layer; b2 is the bin side length, f, which satisfies the lateral resolution requirement_pThe dominant frequency of the grid points is demonstrated for the destination layer.

In the above scheme, the distance between the shot points of the observation system is twice the side length of the mesh surface element of the target layer.

In the foregoing solution, the calculating the flaring aperture of the second region for full waveform seismic inversion further includes:

In the foregoing solution, the determining a second shot point acquisition density of the second region further includes:

calculating a first coefficient according to the full waveform inversion highest inversion frequency and the seismic imaging frequency;

and calculating to obtain the second shot point acquisition density according to the first shot point sampling density and the first coefficient.

In the foregoing aspect, the combining the first region and the second region further includes:

In the above scheme, after the performing exploration and observation by using the first shot point sampling density for the overlapped region and the performing exploration and observation by using the second shot point sampling density for the non-overlapped region, the method further includes:

According to the technical scheme provided by the invention, according to the target depth of a target layer of an exploration target, calculating the outward-expanding aperture of a first area for seismic imaging, and determining the first shot point sampling density of the first area; calculating the outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area; and combining the first area and the second area, and carrying out exploration observation by adopting the first shot point sampling density aiming at a coincident area and the second shot point sampling density aiming at a non-coincident area. Therefore, the problem that the prior art can only meet the observation requirement of one aspect of seismic imaging or full waveform inversion and complete survey can be completed only by acquiring for multiple times is solved, the submarine three-dimensional seismic exploration efficiency is improved, and meanwhile, the survey cost is greatly reduced.

The foregoing description is only an overview of the technical solutions of the present invention, and the embodiments of the present invention are described below in order to make the technical means of the present invention more clearly understood and to make the above and other objects, features, and advantages of the present invention more clearly understandable.

Drawings

Various other advantages and benefits will become apparent to those of ordinary skill in the art upon reading the following detailed description of the preferred embodiments. The drawings are only for purposes of illustrating the preferred embodiments and are not to be construed as limiting the invention. Also, like reference numerals are used to refer to like parts throughout the drawings. In the drawings:

FIG. 1 shows a flow diagram of a method of combined density ocean bottom node seismic acquisition according to one embodiment of the present invention;

FIG. 2 shows a flow diagram of a method of combined density ocean bottom node seismic acquisition according to another embodiment of the present invention;

FIG. 3a shows a schematic diagram of a conventional OBN (Ocean Bottom Node) observation system for seismic imaging based on the prior art;

FIG. 3b shows a schematic diagram of a conventional OBN observation system for full waveform inversion based on the prior art;

FIG. 3c shows a schematic view of an observation system according to an embodiment of the invention;

FIG. 3d shows a schematic view of an observation system according to an embodiment of the invention;

FIG. 4a shows a representation of the total shot count of the observation system as the survey area increases;

FIG. 4b is a diagram showing the proportional relationship between the total number of shots in the combined observation system and the total number of shots in the conventional density observation system.

Detailed Description

Exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be embodied in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

FIG. 1 shows a flow diagram of a method for combined density ocean bottom node seismic acquisition according to one embodiment of the present invention, as shown in FIG. 1, comprising the steps of:

step S101, calculating an external expanding aperture of a first area for seismic imaging according to the depth of a target layer of an exploration target, and determining a first shot point sampling density of the first area;

specifically, the longest offset distance is determined according to the depth of the target layer, and the outward-expanding aperture of the first area is further determined based on a first preset condition; wherein the first preset condition comprises: the dynamic correction stretching rate is lower than a first threshold value, the speed analysis precision error is lower than a second threshold value, the reflection coefficient is consistent and stable, and the interference of direct waves and first-arrival refraction waves is avoided;

determining the first region according to the flaring aperture of the first region;

and determining a first shot sampling density of the first area according to the destination layer grid information.

Since the first region is used for seismic imaging, the requirements of seismic imaging for the observation system need to be met. At present, seismic exploration basically adopts reflected waves to perform seismic imaging, the maximum offset distance of the reflected waves is required by velocity analysis precision, the larger offset distance is more beneficial to improving the velocity precision and the precision of anisotropic parameters, and the maximum offset distance meets the requirement of AVO (Amplitude variation with offset) analysis angle. The AVO analysis requires reflection angle data of more than 45 degrees, so that the maximum offset length is larger than the depth equal to the target layer, and the requirement of AVO parameter inversion can be met.

The length of the maximum offset is also affected by the degree of dynamic correction stretching, which empirically reduces the resolution of the superimposed section if the dynamic correction stretch exceeds 20%. Meanwhile, the effective maximum offset distance is also influenced by the stability of the reflection coefficient, and when the reflection angle is close to the critical angle and the offset distance is too large, the reflection coefficient is not stable any more, and the amplitude precision of the superposed section is reduced. When the reflected waves are adopted for seismic imaging, the maximum offset distance corresponds to the length of the cable used for observation, and the overlong length of the cable has very limited improvement on the seismic imaging, but the construction cost is greatly increased. Therefore, the longest offset distance is determined, it is required to satisfy that the dynamic correction stretching ratio is lower than a first threshold, the speed analysis precision error is lower than a second threshold, the reflection coefficient is stable, and the interference of the direct wave and the first-arrival refracted wave is avoided, that is, the first preset condition is satisfied.

Preferably, in the first preset condition, the first threshold may be 10%, and the second threshold may be 6%; namely, the dynamic correction elongation is lower than 10%, the speed analysis precision error is lower than 6%, the reflection coefficient is stable, and the interference of direct waves and first-arrival refraction waves is avoided.

When the first preset condition is met, the outward-expanding aperture of the first area is equal to the longest offset distance, and the longest offset distance is equal to the depth of the target layer.

Step S102, calculating an outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area;

specifically, the calculating the flaring aperture of the second region for full waveform seismic inversion further includes:

Preferably, the step of calculating the step.

Specifically, the determining the second shot point acquisition density of the second region further includes:

calculating a first coefficient according to the full waveform inversion highest inversion frequency and the seismic imaging frequency;

and calculating to obtain the second shot point acquisition density according to the first shot point sampling density and the first coefficient.

The highest inversion frequency of the current full waveform inversion does not exceed 20hz, while most seismic imaging frequencies are 60hz, i.e. the highest inversion frequency is 1/3 of the seismic imaging frequency. And calculating the second shot point acquisition density by the ratio of the frequencies.

Preferably, the first coefficient is 1/3, i.e. the second shot density is 1/3 of the first shot density.

And S103, combining the first area and the second area, carrying out exploration observation by adopting the first shot point sampling density aiming at a coincident area, and carrying out exploration observation by adopting the second shot point sampling density aiming at a non-coincident area.

Specifically, the combining the first region and the second region further includes:

The first region and the second region overlap in a center-aligned manner.

Specifically, after the survey observation is performed by using the first shot sampling density for the overlapped area and the survey observation is performed by using the second shot sampling density for the non-overlapped area, the method further includes:

After the first area and the second area are combined, the first shot point sampling density is adopted for carrying out exploration observation on the overlapped area, and the second shot point sampling density is adopted for carrying out exploration observation on the non-overlapped area; wherein the first shot sampling density is determined using bins calculated for seismic imaging at the coincidence zone; and determining the second shot sampling density by using the bin calculated for full waveform inversion in a non-coincident region.

Specifically, in the process of performing the full waveform seismic inversion based on the first observation result and the second observation result, at the initial stage of the full waveform inversion, the background velocity field of the model is inverted mainly by using the large offset distance low-density seismic data, that is, the second observation result; in the later stage of full waveform inversion, the high-frequency components of the model are inverted and the seismic data are subjected to migration imaging by mainly utilizing the seismic data with small migration distance and high density, namely the first observation result.

According to the seabed node seismic acquisition method with the combined density, the outward-expanding aperture of a first area for seismic imaging is calculated according to the target depth of a exploration target, and the first shot point sampling density of the first area is determined; calculating the outer expanding aperture of a second area for full-waveform seismic inversion, and determining a second shot point acquisition density of the second area; and combining the first area and the second area, and carrying out exploration observation by adopting the first shot point sampling density aiming at a coincident area and the second shot point sampling density aiming at a non-coincident area. By utilizing the technical scheme provided by the invention, two groups of different offset distances and sampling densities can be determined based on different requirements for seismic imaging and full waveform inversion, and sampling areas determined by the two groups of different offset distances and sampling densities are combined to finally generate a seismic acquisition mode capable of simultaneously meeting the requirements of the seismic imaging and the full waveform inversion. The scheme effectively solves the problem that seismic exploration can only be carried out in one mode of seismic imaging or full waveform inversion in the prior art, meets the requirements of seismic imaging and full waveform inversion simultaneously under the condition of ensuring low cost, simultaneously realizes the exploration advantages of migration imaging and full waveform inversion respectively, improves the precision of velocity precision and anisotropic parameters, ensures the convergence of subsequent inversion, greatly improves the efficiency of seismic exploration and reduces the exploration cost.

FIG. 2 shows a schematic flow diagram of a method of determining a first shot sampling density of a first region required for seismic imaging according to another embodiment of the invention, as shown in FIG. 2, the method comprising the steps of:

step S201, determining the side lengths b1 and b2 of the mesh bins of the destination layer according to the mesh information of the destination layer and a second preset condition.

Specifically, the second preset condition includes:

b1≤v_rms/(4×f_max×sinθ)

b2≤v_rms/(2×f_p)

Step S202, calculating the bin size of the target layer demonstration grid point according to the minimum value of the target layer grid bin sides b1 and b 2.

Specifically, according to the second preset condition in step S201, the minimum value of the side lengths b1 and b2 of the mesh bins of the target layer is determined, and the bin size of the demo grid point of the target layer is calculated according to the minimum value of the side lengths b1 and b 2.

Step S203, calculating an area of the first region according to the outward-expanding aperture of the first region.

Specifically, the expanded aperture of the first region is the side length of the first region, and the area of the first region is calculated through the expanded aperture of the first region.

And S204, determining the distance between the shot points of the observation system according to the side length of the mesh surface element of the target layer.

Specifically, the distance between the shots of the observation system is determined according to the side length of the mesh of the target layer determined in step S202 and the relationship between the distance between the shots of the observation system and the side length of the mesh of the target layer.

Preferably, the pitch of the observation system shots is twice as large as the mesh bin of the destination layer.

And S205, determining the first shot sampling density according to the distance between the shots of the observation system.

According to the seabed node seismic acquisition method with the combined density, the minimum value of the side length of the target layer grid surface element is determined according to the target layer grid information and the second preset condition about the side length of the target layer grid surface element; calculating the area of the first region according to the outward-expanding aperture of the first region; and determining the distance between shot points of the observation system according to the side length of the mesh surface element of the target layer, and further calculating the sampling density of the first shot point. By utilizing the technical scheme provided by the invention, the side length of the surface element can be ensured to meet the requirement of seismic imaging, so that seismic data has good transverse resolution in space; the sampling density of the first shot point calculated by the method can ensure the precision of seismic imaging.

FIGS. 3a, 3b, 3c, 3d show 4 pairs of 10km edge lengths with 100km areas²The OBN acquisition system designed for surveying targets, wherein a triangle is a seabed node, and a hexagram is a shot point; wherein the content of the first and second substances,

fig. 3a shows a schematic diagram of an OBN (Ocean Bottom Node) observation system for seismic imaging based on the conventional technology, as shown in fig. 3 a:

according to the speed analysis requirement required by seismic imaging, the maximum offset is usually the same as the depth of a target layer, so that the external expanding aperture is set to be 5km, and the total construction area of the shot ship is 400km²The interval of the shot points is 25m, and 64 ten thousand shots are needed in total.

Fig. 3b shows a schematic diagram of a conventional OBN observation system for full waveform inversion based on the prior art, as shown in fig. 3 b:

empirically, the maximum offset required for full waveform inversion is typically 3 times the depth of the target layer, so the flare aperture is set at 15km and the total shot-boat construction area is 1600km²The construction area is 4 times of that required by seismic imaging, the shot point interval is 25m, and 256 ten thousand shots are required.

FIG. 3c shows a schematic view of an observation system according to an embodiment of the invention, as shown in FIG. 3 c:

the observation system is used for the area of seismic imaging, namely the density of shot points within 5km of side length is consistent with the conventional mode; and the sparse shot point arrangement is adopted in the area with the offset distance of 5-15 km. If the interval between the shots is 1/2 and the density of the shots is 1/4, the seismic ship can have 2 times of the original optimal speed or charge a larger capacity of seismic sources. And at this time, the shot interval of the imaging area is 25m, the shot interval of the full waveform inversion area is 50m, and the total number of shots in the work area is 124 ten thousand. If the interval between the shots is 1/4 and the density of the shots is 1/16, the seismic ship can have the optimal navigational speed 4 times of the original navigational speed or can be inflated by a larger capacity of seismic sources. And at the moment, the shot point interval of the imaging area is 25m, the shot point interval of the full waveform inversion area is 100m, and the total number of shots in the work area is 76 ten thousand. Therefore, if the interval of the sparse fire points is 1/2, the construction cost of the gun ship is saved by 51%; if the interval of the rare blasting points is 1/4, the construction cost of the gun ship is saved by 70 percent.

FIG. 3d shows a schematic view of an observation system according to an embodiment of the invention, as shown in FIG. 3 d:

the seabed nodes of the observation system are randomly arranged by adopting Jeff sampling, the direction of the shot ship sailing line keeps a straight line, but the excitation positions are randomly distributed according to the Jeff sampling mode. Compared with the observation system shown in fig. 3c, the addition of the random sampling technique is beneficial to avoiding spatial aliasing and improving the recovery precision of signals, is beneficial to data interpolation recovery and improving the final imaging effect, and has the same cost as the observation system shown in fig. 3 c.

FIG. 4 is a schematic diagram showing shot data comparison of a combined vision system and an existing vision system in accordance with an embodiment of the present invention; wherein the content of the first and second substances,

FIG. 4a shows a representation of the total shot count of the observation system as the survey area increases, as shown in FIG. 4 a:

FIG. 4b is a diagram showing a proportional relationship between the total number of shots in the combined observation system and the total number of shots in the conventional density observation system, as shown in FIG. 4 b:

the oil and gas structure depth is preset to be 5km, the offset external expanding aperture is 5km, and a square observation system with the external expanding aperture of 15km is required for FWI (Full Waveform Inversion). In FIG. 4b, the abscissa is the area of the square work area and the ordinate is the total of different observation systemsThe number of shots is a percentage of the total number of shots conventionally used in FWI observation systems. As can be seen from FIG. 4b, when the area of the work area is 100km²When the combined observation system is used, the total number of the combined observation system accounts for about 44% of the total number of the FWI observation systems; when the area of the work area is 400km²When the combined observation system is used, the total number of the combined observation system accounts for about 52 percent of the total number of the FWI observation systems; when the area of the work area is 900km²And the total number of the combined observation system shots accounts for about 58% of the total number of the FWI observation system shots. Therefore, with the increase of the area of the work area, the low-cost advantage obtained by the combined observation system through sparse sampling is gradually reduced. Therefore, when designing a combined observation system for surveying, attention should be paid to the size of the area of the work area; the combined observation system in the embodiment of the application is also more suitable for exploration of medium and small work areas.

In the description provided herein, numerous specific details are set forth. It is understood, however, that embodiments of the invention may be practiced without these specific details. In some instances, well-known methods, structures and techniques have not been shown in detail in order not to obscure an understanding of this description.

Similarly, it should be appreciated that in the foregoing description of exemplary embodiments of the invention, various features of the invention are sometimes grouped together in a single embodiment, figure, or description thereof for the purpose of streamlining the disclosure and aiding in the understanding of one or more of the various inventive aspects. However, the disclosed method should not be interpreted as reflecting an intention that: that the invention as claimed requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive aspects lie in less than all features of a single foregoing disclosed embodiment. Thus, the claims following the detailed description are hereby expressly incorporated into this detailed description, with each claim standing on its own as a separate embodiment of this invention.

Those skilled in the art will appreciate that the modules in the device in an embodiment may be adaptively changed and disposed in one or more devices different from the embodiment. The modules or units or components of the embodiments may be combined into one module or unit or component, and furthermore they may be divided into a plurality of sub-modules or sub-units or sub-components. All of the features disclosed in this specification (including any accompanying claims, abstract and drawings), and all of the processes or elements of any method or apparatus so disclosed, may be combined in any combination, except combinations where at least some of such features and/or processes or elements are mutually exclusive. Each feature disclosed in this specification (including any accompanying claims, abstract and drawings) may be replaced by alternative features serving the same, equivalent or similar purpose, unless expressly stated otherwise.

Furthermore, those skilled in the art will appreciate that while some embodiments described herein include some features included in other embodiments, rather than other features, combinations of features of different embodiments are meant to be within the scope of the invention and form different embodiments. For example, in the claims, any of the claimed embodiments may be used in any combination.

The various component embodiments of the invention may be implemented in hardware, or in software modules running on one or more processors, or in a combination thereof. Those skilled in the art will appreciate that a microprocessor or Digital Signal Processor (DSP) may be used in practice to implement some or all of the functionality of some or all of the components in accordance with embodiments of the present invention. The present invention may also be embodied as apparatus or device programs (e.g., computer programs and computer program products) for performing a portion or all of the methods described herein. Such programs implementing the present invention may be stored on computer-readable media or may be in the form of one or more signals. Such a signal may be downloaded from an internet website or provided on a carrier signal or in any other form.

It should be noted that the above-mentioned embodiments illustrate rather than limit the invention, and that those skilled in the art will be able to design alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. The word "comprising" does not exclude the presence of elements or steps not listed in a claim. The word "a" or "an" preceding an element does not exclude the presence of a plurality of such elements. The invention may be implemented by means of hardware comprising several distinct elements, and by means of a suitably programmed computer. In the unit claims enumerating several means, several of these means may be embodied by one and the same item of hardware. The usage of the words first, second and third, etcetera do not indicate any ordering. These words may be interpreted as names.

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Seabed node seismic acquisition method with combined density

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