Method and system for reducing effects of sea surface ghost contamination in seismic data

Abstract

An improved de-ghosting method and system that utilizes multi-component marine seismic data recorded in a fluid medium. The method makes use of two types of data: pressure data that represents the pressure in the fluid medium, such as sea water, at a number of locations; and vertical particle motion data that represents the vertical particle motion of the acoustic energy propagating in the fluid medium at a number of locations within the same spatial area as the pressure data. The vertical particle motion data can be in various forms, for example, velocity, pressure gradient, displacement, or acceleration. A spatial filter is designed so as to be effective at separating up and down propagating acoustic energy over substantially the entire range of non-horizontal incidence angles in the fluid medium. The spatial filter is applied to either the vertical particle motion data or to the pressure data, and then combined with the other data to generate pressure data that has its up and down propagating components separated.

Description

By comparison to equation (1), we see that this is a normal incidence approximation, which occurs when k_x is zero. This is implemented as a simple scaling of the vertical velocity trace followed by its addition to the pressure trace.

Equation (1) can also be formulated in terms of the vertical pressure gradient (dp(x)/dz). The vertical pressure gradient is proportional to the vertical acceleration:
dp(x)/dz=ρdv_z(x)/dt  (3)

Integrating in the frequency domain through division of iω, and substituting in equation (1) gives:

$\begin{array}{cc}{p}^u\left(x\right)=0.5\left[p\left(x\right)+\frac{1}{i{k}_z}*dp\left(x\right)/dz\right]& \left(4\right)\end{array}$

FIGS. 6a-6f show various embodiments for data acquisition set-ups and streamer configurations according to preferred embodiments of the invention. FIG. 6a shows a seismic vessel 120 towing a seismic source 110 and a seismic streamer 118. The sea surface is shown by reference number 112. In this example, the depth of streamer 118 is about 60 meters, however those of skill in the art will recognise that a much shallower depth would ordinarily be used such as 6-10 meters. The dashed arrows 122a-d show paths of seismic energy from source 110. Arrow 122a shows the initial down-going seismic energy. Arrow 122b shows a portion of the seismic energy that is transmitted through the sea floor 114. Arrow 122c shows an up-going reflection. Arrow 122d shows a clown-going ghost reflected from the surface. According to the invention, the down-going rough sea receiver ghost 122d can be removed from the seismic data.

FIGS. 6b-6f show greater detail of acquisition set-ups and streamer configurations, according to the invention. FIG. 6b shows a multi-component streamer 124. The streamer 124 comprises multiple hydrophones (measuring pressure) 126a, 126b, and 126c, and multiple 3C geophones (measuring particle velocity in three directions x, y, and z) 128a, 128b, and 128c. The spacing between the hydrophones 126a and 126b, and between geophones 128a and 128b is shown to be less than 12 meters. Additionally, the preferred spacing in relation to the frequencies of interest is discussed in greater detail below.

FIG. 6c shows a streamer 130 that comprises multiple hyrdophones 132a, 132b, and 132c, and multiple pressure gradient measuring devices 134a, 134b, and 134c. The spacing between the hydrophones 132a and 132b, and between pressure gradient measuring devices 134a and 134b is shown to be less than 12 meters.

FIG. 6d shows a multi-streamer configuration that comprises hydrophone streamers 140a and 140b. The streamers comprise multiple hyrdophones 142a, 142b, and 142c in the case of streamer 140a, and 142d, 142e, and 142f in the case of streamer 140b. The spacing between the hydrophones is shown to be less than 12 meters. The separation between steamers 140a and 140b in the example shown in FIG. 6d is less then 2 meters. Although the preferred separation is less than 2 meters, greater separations are contemplated as being within the scope of the invention. FIG. 6e shows a cross sectional view of a dual streamer arrangement. FIG. 6f shows a multi-streamer configuration comprising three hydrophone streamers 140a, 140b, and 140c.

Adequate spatial sampling of the wavefield is highly preferred for the successful application of the de-ghosting filters. For typical towed streamer marine data, a spatial sampling interval of 12 m is adequate for all incidence angles. However, to accurately spatially sample all frequencies up to 125 Hz (for all incidence angles), a spatial sampling interval of 6.25 meters is preferred. These spacings are determined according to the Nyquist spatial sampling criterion. Note that if all incidence angles are not required, a coarser spacing than described above can be used. The filters can be applied equally to both group formed or point receiver data.

FIG. 8 is a flow chart illustrating some of the steps of the de-ghosting method for the combination of pressure and vertical velocity data to achieve separated pressure data, according to a preferred embodiment of the invention. In step 202, spatial filter coefficients are calculated. The coefficients are preferably dependent on the cbaracteristics of the acquisition parameters 203 (such as the temporal sample interval of the pressure and particle motion data, the spatial separation of the vertical particle motion measuring devices, and the spatial aperture of the filter), the density of the fluid medium 206, and the speed of the compressional wave in the fluid medium (or velocity of sound) 204. Vertical particle motion data 208 and pressure data 212 are received, typically stored as time domain traces on a magnetic tape or disk. In step 210, the vertical particle motion data 208 are convolved in with the spatial filter to yield filtered vertical particle motion data. In step 214 the filtered vertical particle motion data are added to pressure data 212 to give the downward propagating component of the separated pressure data. Alternatively, in step 216 the filtered vertical particle motion data are subtracted from pressure data 212 to give the upward propagating component of the separated pressure data. Finally, in step 218 the upward component is further processes and analysed.

The processing described herein is preferably performed on a data processor configured to process large amounts of data. For example, FIG. 9 illustrates one possible configuration for such a data processor. The data processor typically consists of one or more central processing units 350, main memory 352, communications or I/O modules 354, graphics devices 356, a floating point accelerator 358, and mass storage devices such as tapes and discs 360. It will be understood by those skilled in the art that tapes and discs 360 are computer-readable media that can contain programs used to direct the data processor to carry out the processing described herein.

FIG. 10 shows a shot record example, computed under a 4 m Significant Wave Height (SWH) sea and using the finite-difference method described by Robertsson, J. O. A., Blanch, J. O. and Symes, W. W., 1994 ‘Viscoelastic finite-difference modelling’ Geophysics, 59, 1444-1456 (hereinafter “Robertsson et al. (1994)”) and Robertsson, J. O. A., 1996 ‘A Numerical Fret-Surface Condition for Elastic/Viscoelastic Finite-difference modelling in the Presence of Topography’, Geophysics, 61, 6, 1921-1934 (hereinafter “Robertsson (1996)”). The streamer depth in this example is 60 m. The left panel shows the pressure response and the right panel shows the vertical velocity response scaled by the water density and the compressional wave speed in water. A paint source 50 Hz Ricker wavelet was used and the streamer depth was 60 m in this example. The choice of streamer depth allows a clear separation of the downward travelling ghost from the upward travelling reflection energy for visual clarity of the de-ghosting results. The trace spacing on the plot is 24 m. A single reflection and its associated ghost are shown, along with the direct wave travelling in the water layer. Perturbations in the ghost wavelet and scattering noise from the rough sea surface are evident.

FIG. 11 shows the results of de-ghosting the shot record shown in FIG. 10. The left panel shows the result using the normal incidence approximation and the right panel shows the result using the exact solution. The exact solution shows a consistent response over all offsets, whereas the normal incidence approximation starts to break down at incident angles greater than about 20 degrees, and shows a poorer result at the near offsets. Note that the direct wave is not amplified by the exact filter application even though the poles of the filter lie close to its apparent velocity. The exact filter is tapered before application such that it is has near unity response for frequencies and wavenumbers corresponding to apparent velocities of 1500 m/s and greater. The weak event just below the signal reflection is a reflection from the side absorbing boundary of the model. It is upward travelling and hence untouched by the filter.

FIG. 12 shows details of the de-ghosted results for a single trace from FIG. 11. The trace offset is 330 m corresponding to a 37 degree incidence angle. The upper panel shows the normal incidence approximation, and the lower panel shows the exact solution. Not only does the exact solution provide a superior result in terms of the de-ghosting, but also in terms of amplitude preservation of the signal reflection—the upper panel shows loss of signal amplitude after the de-ghosting.

The filters described herein are applicable to, for example, measurements of both pressure and vertical velocity along the streamer. Currently, however, only pressure measurements are commercially available. Therefore, engineering of streamer sections that are capable of commercially measuring vertical velocity is preferred in order to implement the filters.

FIGS. 13a-b illustrate two possible examples of multi-component streamer design. FIG. 13a shows a coincident pressure and single 3-component geophone. In this design, the 3-component geophone is perfectly decoupled from the streamer. FIG. 13b shows a coincident pressure and twin 3-component geophones. In this design, one of the 3-component geophones is decoupled from the streamer, the other is coupled to the streamer; measurements from both are combined to remove streamer motion from the data.

In an alternative formulation, the filters make use of vertical pressure gradient measurements. An estimate of vertical pressure gradient can be obtained from over/under twin streamers (such as shown in FIGS. 6d and 6e) and multiple streamers (such as shown in FIG. 6f) deployed in configurations analogous to that described in Robertsson (1998), allowing the filters to be directly applied to such data. However, for the results to remain sufficiently accurate, the streamers should not be vertically separated by more than 2 m for seismic frequencies below approximately 80 Hz.

An important advantage of multiple streamer configurations such as shown in FIG. 6f is that their relative locations are less crucial than for over/under twin streamer geometries, where the two streamers are preferably directly above one another.

The filters described here are applied in 2D (along the streamer) to data modelled in 2D. The application to towed streamer configurations naturally lends itself to this implementation, the cross-line (streamer) sampling of the wavefield being usually insufficient for a full 3D implementation. Application of these filters to real data (with ghost reflections from 3D sea surfaces) will give rise to residual Coors caused by scattering of the wavefield from the cross-line direction. This error increases with frequency though is less than 0.5 dB in amplitude and 3.6° in phase for frequencies up to 150 Hz, for a 4 m SWH sea. These small residual noise levels are acceptable when time-lapse seismic surveys are to be conducted.

Invoking the principle of reciprocity, the filters can be applied in the common receiver domain to remove the downward travelling source ghost. Reciprocity simply means that the locations of source and receiver pairs can be interchanged, (the ray path remaining the same) without altering the seismic response. FIG. 1 can also be used to define the source ghost if the stars are now regarded as receivers and the direction of the arrows is reversed, with the source now being located at the arrow. This application is particularly relevant for data acquired using vertical cables, which may be tethered, for example, to the sea floor, or suspended from buoys. In the case of FIG. 6a, those of skill in the art will understand that as the seismic vessel 120 travels though the water, the firing position of source 110 will change. The different positions of source 110 can be then be used to construct data in the common receiver domain as is well known in the art.

While preferred embodiments of the invention have been described, the descriptions and figures are merely illustrative and are not intended to limit the present invention.

Claims

1. A method of reducing the effects in seismic data of downward propagating reflected and scattered acoustic energy travelling in a fluid medium comprising the steps of:

receiving pressure data representing at least the pressure in the fluid medium at a first location and a second location, the first location being in close proximity to the second location;

receiving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a third location and a fourth location, the third location being in close proximity to the fourth location, and the first, second, third and fourth locations being within a spatial area;

2. The method of claim 1 wherein the acquisition parameters include the temporal sampling interval, the spatial sampling interval, and the number of independent locations at which the pressure and vertical particle motion data are measured.

3. The method of claim 1 wherein the vertical particle motion data is measured using one or more multi-component streamers.

4. The method of claim 1 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy.

5. The method of claim 1 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical pressure gradient of the acoustic energy.

6. The method of claim 5 wherein the pressure gradient is measured using at least two parallel streamer cables in close proximity and vertically offset from one another.

7. The method of claim 1 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical displacement of the acoustic energy.

8. The method of claim 1 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical acceleration of the acoustic energy.

9. The method of claim 1 wherein the distance between the first location and the second location and the distance between the third location and the fourth location is less than the Nyquist spatial sampling criterion.

10. The method of claim 9 wherein the spatial area is substantially a portion of a line, and the range of non-vertical incidence angles includes substantially all non-horizontal incidence angles within a vertical plane that passes through the portion of line.

11. The method of claim 9 wherein the spatial area is a portion of a substantially planar region, and the range of non-vertical incidence angles include substantially all non-horizontal incidence angles.

12. A method of reducing the effects in seismic data of downward propagating reflected and scattered acoustic energy travelling in a fluid medium comprising the steps of:

receiving pressure data representing at least the pressure in the fluid medium at a first location and a second location, the first location being in close proximity to the second location;

receiving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a third location and a fourth location, the third location being in close proximity to the fourth location, and the first, second, third and fourth locations being within a spatial area;

calculating a plurality of spatial filter coefficients based in part on the velocity of sound in the fluid medium and the density of the fluid medium, thereby creating a spatial filter which is designed so as to be effective at separating up and down propagating acoustic energy over a range of non-horizontal incidence angles in the fluid medium;

applying the spatial filter to the pressure data to generate filtered pressure data;

combining the filtered pressure data with the vertical particle motion data to generate separated pressure data, the separated pressure data having up and down propagating components separated; and

analysing at least part of the up or down propagating component of the separated pressure data, and

13. The method of claim 12 wherein the distance between the first location and the second location and the distance between the third location and the fourth location is less than the Nyquist spatial sampling criterion.

14. The method of claim 12 wherein the vertical particle motion data is measured using one or more multi-component streamers.

15. The method of claim 12 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy.

16. The method of claim 12 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical pressure gradient of the acoustic energy.

17. The method of claim 16 wherein the pressure gradient is measured using at least two parallel streamer cables in close proximity and vertically offset from one another.

18. A method of reducing the effects in seismic data of downward propagating reflected and scattered acoustic energy travelling in a fluid medium comprising the steps of:

receiving pressure data representing at least variations in pressure in the fluid medium at a first location, the variations caused in part by a first source event and a second source event, the first source event and the second source event being within a spatial area;

receiving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a second location, the acoustic energy being caused in part by the first source event and the second source event;

calculating a plurality of spatial filter coefficients based in part on the velocity of sound in the fluid medium and the density of the fluid medium, thereby creating a spatial filter which is designed so as to be effective at separating up and down propagating acoustic energy from the first source event and second source event over a range of non-horizontal incidence angles in the fluid medium;

applying the spatial filter to the vertical particle motion data to generate filtered particle motion data;

combining the filtered particle motion data with the pressure data to generate separated pressure data, the separated pressure data having up and down propagating components separated; and

analysing at least part of the up or down propagating component of the separated pressure data, and

19. The method of claim 18 wherein the first source event and the second source event are generated by firing a seismic source at different locations at different times, and the distance between the location of the first source event and the location of the second source event is less than the Nyquist spatial sampling criterion.

20. The method of claim 18 wherein the vertical particle motion data is measured using one or more multi-component streamers.

21. The method of claim 18 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy.

22. The method of claim 18 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical pressure gradient of the acoustic energy.

23. The method of claim 22 wherein the pressure gradient is measured using at least two parallel streamer cables in close proximity and vertically offset from one another.

24. A computer-readable medium which can be used for directing an apparatus to reduce the effects in seismic data of downward propagating reflected and scattered acoustic energy travelling in a fluid medium comprising:

means for retrieving pressure data representing at least the pressure in the fluid medium at a first location and a second location, the first location being in close proximity to the second location;

means for retrieving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a third location and a fourth location, the third location being in close proximity to the fourth location, and the first, second, third and fourth locations being within a spatial area;

means for calculating a plurality of spatial filter coefficients based in part on the velocity of sound in the fluid medium, the density of the fluid medium and a plurality of acquisition parameters, thereby creating a spatial fiber which is designed so as to be effective at separating up and down propagating acoustic energy over a range of non-vertical incidence angles in the fluid medium;

means for applying the spatial filter to the vertical particle motion data to generate filtered particle motion data;

means for combining the filtered particle motion data with the pressure data to generate separated pressure data, the separated pressure data having up and down propagating components separated; and

means for analysing at least part of the up or down propagating component of the separated pressure data, and

25. The computer-readable medium of claim 24 wherein the distance between the first location and the second location and the distance between the third location and the fourth location is less than the Nyquist spatial sampling criterion.

26. The computer-readable medium of claim 24 wherein the vertical particle motion data is measured using one or more multi-component streamers.

27. The computer-readable medium of claim 24 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy.

28. The computer-readable medium of claim 24 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical pressure gradient of the acoustic energy.

29. The computer-readable medium of claim 28 wherein the pressure gradient is measured using at least two parallel streamer cables in close proximity and vertically offset from one another.

30. A method of reducing the effects in seismic data of downward propagating reflected and scattered acoustic energy travelling in a fluid medium comprising the steps of:

receiving pressure data representing at least the pressure in the fluid medium at a first location and a second location, the first location being in close proximity to the second location;

receiving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a third location, and the first, second, and third locations being within a spatial area;

calculating a plurality of spatial filter coefficients based in part on the velocity of sound in the fluid medium and the density of the fluid medium, thereby creating a spatial filter which is designed so as to be effective at separating up and down propagating acoustic energy over a range of non-horizontal incidence angles in the fluid medium;

applying the spatial filter to the pressure data to generate filtered pressure data;

combining the filtered pressure data with the vertical particle motion data to generate separated vertical particle motion data, the separated vertical particle motion data having up and down propagating components separated; and

analysing at least part of the up or down propagating component of the separated pressure data, and

wherein said vertical particle motion data is measured using one or more multi-component streamers, or over and under twin streamers, or vertical cables having receivers located substantially above the sea floor.

31. The method of claim 30 wherein the distance between the first location and the second location is less than the Nyquist spatial sampling criterion.

32. The method of claim 30 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy.

33. The method of claim 30 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the vertical pressure gradient of the acoustic energy.

34. The method of claim 33 wherein the pressure gradient is measured using at least two parallel streamer cables in close proximity and vertically offset from one another.

35. A data processor, comprising:

a central processing unit;

a memory;

a program residing on the memory that, when executed by the central processing unit, performs a method including:

receiving pressure data representing at least the pressure in the fluid medium at a first location and a second location, the first location being in close proximity to the second location;

receiving vertical particle motion data representing at least the vertical particle motion of acoustic energy propagating in the fluid medium at a third location, and the first, second, and third locations being within a spatial area;

calculating a plurality of spatial filter coefficients based in part on the velocity of sound in the fluid medium and the density of the fluid medium, thereby creating a spatial filter which is designed so as to be effective at separating up and down propagating acoustic energy over a range of non-horizontal incidence angles in the fluid medium;

applying the spatial filter to the pressure data to generate filtered pressure data;

combining the filtered pressure data with the vertical particle motion data to generate separated vertical particle motion data, the separated vertical particle motion data having up and down propagating components separated; and

analysing at least part of the up or down propagating component of the separated pressure data, and

wherein said vertical particle motion data is measured using one or more multi-component streamers, or over and under twin streamers, or vertical cables having receivers located substantially above the sea floor.

36. The data processor of claim 35 wherein the distance between the first location and the second location is less than the Nyquist spatial sampling criterion.

37. The data processor of claim 35 wherein the vertical particle motion of the acoustic energy represented in said vertical particle motion data is the particle velocity of the acoustic energy or the vertical pressure gradient of the acoustic energy.