GB1583042A - Method of seismic exploration - Google Patents
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- GB1583042A GB1583042A GB31568/77A GB3156877A GB1583042A GB 1583042 A GB1583042 A GB 1583042A GB 31568/77 A GB31568/77 A GB 31568/77A GB 3156877 A GB3156877 A GB 3156877A GB 1583042 A GB1583042 A GB 1583042A
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- 238000000034 method Methods 0.000 title claims description 70
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 76
- 238000002310 reflectometry Methods 0.000 claims description 43
- 238000010304 firing Methods 0.000 claims description 38
- 230000015572 biosynthetic process Effects 0.000 claims description 31
- 238000005311 autocorrelation function Methods 0.000 claims description 16
- 238000005259 measurement Methods 0.000 claims description 6
- 230000004044 response Effects 0.000 claims description 3
- 238000005755 formation reaction Methods 0.000 description 26
- 238000007598 dipping method Methods 0.000 description 11
- 230000003111 delayed effect Effects 0.000 description 9
- 230000006870 function Effects 0.000 description 6
- 230000008569 process Effects 0.000 description 6
- 238000005314 correlation function Methods 0.000 description 5
- 230000001934 delay Effects 0.000 description 3
- 230000008901 benefit Effects 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 238000005070 sampling Methods 0.000 description 2
- 238000001228 spectrum Methods 0.000 description 2
- 229910008355 Si-Sn Inorganic materials 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/003—Seismic data acquisition in general, e.g. survey design
- G01V1/006—Seismic data acquisition in general, e.g. survey design generating single signals by using more than one generator, e.g. beam steering or focusing arrays
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/38—Seismology; Seismic or acoustic prospecting or detecting specially adapted for water-covered areas
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/38—Seismology; Seismic or acoustic prospecting or detecting specially adapted for water-covered areas
- G01V1/3808—Seismic data acquisition, e.g. survey design
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- G—PHYSICS
- G11—INFORMATION STORAGE
- G11C—STATIC STORES
- G11C27/00—Electric analogue stores, e.g. for storing instantaneous values
- G11C27/005—Electric analogue stores, e.g. for storing instantaneous values with non-volatile charge storage, e.g. on floating gate or MNOS
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Description
(54) METHOD OF SEISMIC EXPLORATION
(71) We, MOBIL OIL CORPORATION, a Corporation organised under the laws of the
State of New York, United States of America, of 150 East 42nd Street, New York, New York 10017, United States of America, do hereby declare the invention for which we pray that a patent may be granted to us, and the method by which it is to be performed, to be particularly described in and by the following statement:
This invention relates to a method of seismic exploration.
U.S. Patent 3,689,874 describes a method for removing the reverberation distortion which is present in seismic data. The method involves an operation which separates the reverberation distortion component of the data from the component representing the characteristics of the subsurface formation. This operation is known as dereverberation and involves obtaining a dereverberation operator in the form of an inverse filter. This filter is applied to the seismic data to produce a signal which approximates the signal which would have been produced by a desired shot pulse interacting with the reflectivity of the subsurface formation in the absence of the reverberation distortion.
While dereverberation has been successfully used on many marine seismograms, it is not effective in many areas.
There is also known a technique of firing an array of sources in a time sequence which produces a resultant acoustic pressure wave having a time domain operator characteristic which is the inverse of the distortion of the reverberation. Because the generation of the seismic pulses, the reflection and the recording of them are a linear system, generating the seismic pulse as an inverse distortion operator has the same desirable effect as inverse filtering technique. This known technique has the added advantage of reducing the dynamic range of the recording system occupied solely with reverberations.
In order to fire an array of sources in a time sequence producing an inverse operator it is, however, necessary to determine the reflectivity of the water bottom and the water depth or the two-way travel time of seismic energy through this water depth.
According to the present invention there is provided a method of seismic exploration comprising:
generating seismic pulses from a source towed by a marine vessel,
recording seismograms representing the reflected seismic pulses,
measuring from the seismograms the characteristics of the medium through which the seismic pulses travel,
converting the measurements of the characteristics into control parameters for controlling an array of seismic sources, and
generating further pulses from the array of seismic sources towed by the marine vessel in accordance with the control parameters.
The characteristics which may be measured include the water bottom reflectivity and the water depth. Another characteristic which is of interest is the dip of the reflecting subsurface formations. The array of seismic sources is preferably controlled so that the energy from the sources reflects from the dipping formation approximately vertically and so that it intersects the array of hydrophones orthogonally.
The present invention also provides a simplified process for determining the values of reflection coefficients and two-way travel times on board the ship.
In one embodiment of the invention the reflectivity of the water bottom and the two-way travel time Tw are measured directly from seismograms produced by conventional shooting of a linear array of sources. Then the measured reflectivity and travel time Tw are converted to a three point inverse distortion operator. The array of sources is then fired in a time sequence which produces this three point operator.
The sources in the array may be fired simultaneously to produce conventional seismograms with reverberations. From these conventional seismograms, the reflectivity and the two-way travel time can be determined. The sources are then fired in groups. Firing of a second group of sources is delayed from the firing of the first group by the measured two-way travel time and the firing of the third group of sources is delayed by twice the two-way travel time. The number of sources in each group is controlled by the measured reflectivity.
Further features and advantages of the invention will be better understood from the drawings and the following detailed description.
In the accompanying drawings:
Fig. 1 depicts water bottom multiples;
Figs. 2 and 3 depict water reverberations;
Figs. 4 and 5 show a marine seismic exploration system;
Figs. 6-9 illustrate two and three point time domain inverse operators;
Fig. 10 depicts a conventionally produced seismogram combined with assumed values of R and Tw;
Fig. 11 depicts an example of a system for carrying out this invention;
Fig. 12 shows the correlation function of a selected window;
Fig. 13 depicts conversion from an estimated reflectivity to actual reflectivity.
Figs. 14 and 15 show a system for carrying out exploration over dipping formations.
Fig. 16 depicts a conventionally recorded seismogram; and
Fig. 17 shows an alternative embodiment in which the seismic source array is tilted.
The seismic energy can be generated from a towed array of sources. The resultant acoustic pressure waves are reflected from the subsurface formations and recorded as seismograms.
Unfortunately, the seismograms include distortion which obscures the characteristics of the subsurface formations. In marine exploration, this distortion is often severe. It includes water bottom multiples as depicted in Fig. 1 and reverberations as depicted in Figs. 2 and 3.
As the initial shot pulse travels to the bottom of the water, it is partially transmitted and partially reflected by this boundary. This transmitted part is reflected by the discontinuity beneath the water to become a primary reflection. The reflected part bounces back to the surface where it is again reflected to the water bottom. Once more, part of this pulse passes through the boundary and part is reflected. The process continues indefinitely. Each time a pulse bounces between the surface and the bottom of the water, a pulse emerges from the boundary at the bottom to follow the initial pulse into the section. These multiple pulses are delayed equal time intervals relative to each other, and their amplitudes are successively reduced by the reflection coefficient at the bottom of the water. The net result of this is to produce a seismogram consisting of a single primary followed by a train of equally spaced multiples or reverberations.
As previously mentioned a dereverberation technique is disclosed in U.S. patent 3,689,874. This technique uses an inverse filter which is applied to the seismic data to produce a signal which approximates the signal which would have been produced by a desired shot pulse interacting with the reflectivity of the subsurface formation in the absence of the reverberation distortion.
While dereverberation has been successfully used on many marine seismograms, it is not effective in all areas. Particularly where the water bottom is hard, the reverberations are so severe that the complete dynamic range of the recording system is required just to faithfully record the reverberations. Accordingly. it is desirable to suppress the reverberations before recording.
Figs. 4 and 5 show a marine seismic exploration system. A vessel 11 traverses a seismic exploration path in surveying the subsurface formation 12 below the water layer 13. A linear horizontal array of seismic sources 14. 15. 16 and others is towed behind the boat by the cable 17. Surface floats help to maintain the equal spacing between the sources.
A hydrophone streamer 18 is also towed behind the boat. A surface support buoy 19 helps to maintain the proper relationship between the hydrophone streamer and the source array.
A seismic trace which is generated during seismic marine exploration by this system may be described mathematically as follows:
S(t) = B(t) *H(t) *R(t) + N(t) (1) where,
S(t) = seismic trace.
B(t) = shot pulse.
H(t) = reverberation distortion.
R(t) = reflectivity function. and
N(t) = noise.
Equation (1) states that the seismic trace is produced by the shot pulse convolved with the reverberation distortion convolved with the reflectivity, plus coherent and random noise.
[Convolution is denoted by an asterisk (*)j. Convolution is the process of filtering. Consequently, the seismic trace is the result of the shot pulse being filtered by the reflectivity of the earth and by the reverberation distortion.
Basically, the reverberation distortion is a function of both the magnitudes and signs of the reflection coefficients, R, at the bottom of the water and at the water surface. The reverberations of the shot pulse are delayed equal time intervals relative to each other, and their amplitudes are successively reduced by these reflection coefficients. The reflection coefficient at the water bottom can be either positive (+) or negative (-) in sign depending on the nature of the water bottom, while the reflection coefficient at the water surface is always negative (-) and is assumed to be unity (-1). Further, each multiple pulse is reduced in amplitude from the previous one by the magnitude of the water bottom reflectivity R.
Accordingly, a dereverberation operator can be described by the two point operator i(t):
i(t) = 8(t) + R 8(t+Tw) (2)
This operator, consisting of a first impulse of unity magnitude at t = 0 and a second impulse of magnitude R at Tw, can be illustrated in two forms. The first is shown in Fig. 6 for a positive water bottom reflection coefficient, + R. The second is shown in Fig. 7 for a negative water bottom coefficient, -R,
In those circumstances wherein the water bottom is relatively flat, the downward-going reverberation distortion at the shotpoint, and the upward-going reverberation distortion at the detector are approximately the same. Consequently, for a flat water bottom, a total dereverberation operator I(t) can be represented by the convolution of the two point operator at the shotpoint, is(t), with the two point operator, id(t), at the detector.
1(t) = is(t) * id(t) (3)
= [ (t) + R8(t +Tw)] * [8(t) + R8(t+Tw)] (4)
= 8(t) + 2R8(t+T) + R28(t+Tw) (5)
For the case of a positive water bottom reflectivity, + R, the dereverberation operator can be illustrated as in Fig. 8; while for a negative water bottom reflectivity, -R, the derverberation operator can be illustrated as in Fig. 9. It can therefore be seen that the total dereverberation operator I(t) for a flat water bottom is a three point operator consisting of three impulses - the first of unity magnitude at t = 0, the second of magnitude 2R at t = Tu, and the third of magnitude R2 at t = 2Tw.
By firing the sources in various groups with different firing times for each group, the resultant acoustic pressure wave has the time domain characteristics depicted in Figs. 8 and 9.
As an example, the operator of Fig. 8 is generated by firing a first group of pulses at time t = 0. The amplitude of the pulse generated by this group is arbitrarily designated unity. A second group of pulses is fired at time T. The amplitude of the pulse produced by the second group is related to that of the first group by a factor 2R, where R is the reflectivity of the water bottom.
A third group of pulses is fired at time 2Tw. The amplitude of the pulse produced by the third group is related to the amplitude of the first pulse by a factor R2. It can be shown that firing the sources in a sequence such as the foregoing produces suppressed reverberations.
In order to fire the array of sources in such a sequence, it is necessary to determine the reflection coefficient R and the two-way travel time Tw of acoustic energy through the water depth. R and Tw are obtained from a conventional seismogram produced by firing all of the sources 14-16 simultaneously. The sources are fired simultaneously to determine R and Tw and then the sources are fired in groups which produce a three point inverse distortion operator. The seismic energy of this inverse operator produces seismograms which are substantially free of reverberations.
As one example of the manner in which R and Tu can be determined from a conventional seismogram. consider Fig. 10. Fig. 10 depicts a conventional seismogram which has been combined, or stacked. in accordance with: t, 2R, R2 at t = 0. T, 2TA for different assumed values of R and Tu. The seismic sections under the lines 21 . . 22 represent reflections detected by the geophones 18 as a function of time (ordinate) after the shot. The seismic sections under the lines 23-'5 represent the same seismic sections stacked with an assumed reflectivity R = .1 and for various assumed values of T. The seismic section under the line 24 is the sum of the conventionally produced section plus the conventionally produced section weighted by a factor of 2(.1) delayed by 96 msecs., plus the conventionally produced trace weighted by a factor of (.1) delayed by 192 msecs. The section under the line 25 is the sum of the conventionally produced trace weighted by the same factors but delayed by 98 msecs. and twice 98 msecs. The last section in this set under the line 26 is the sum of the conventionally produced trace weighted in the same manner but delayed by 120 msecs. and twice 120 msecs.
The sections under the lines 27-29 are combined. or stacked. sections with the same time delays, 94. 96... 120 msecs. but with an assumed reflectivity of R = .2. The sections under the lines 30, 31 and 32 are stacked sections with an assumed reflectivity of R = .5. and with the same time delays. The values of R and T can be determined from such an analysis by selecting the values of R and Tu which produce the minimum energy in a section. Visual analysis of Fig. 10 shows that the section 33 has the minimum energy therein. This indicates that a correct value of R is .5. and the correct value of T is 114 msecs.
The values of R and T can be automatically determined in this manner but a very large number of computer operations is required, and generally it is not practical to make such an
analysis on shipboard. However. a simplified process for determining R and TA on board the
ship may be adopted. Fig. 10 shows that the correct value of T can be determined for any
assumed value of R. That is. the section 34 has the minimum energy in its set and this indicates
a value of T of 114 msecs. even though an incorrect value of R = .2 was used in the stacking.
Similarly. the section 35 has the minimum energy in its set and this indicates a correct value of = = 114 msecs. even though an incorrect value of R = .1 was used in the stacking. This phenomena is utilized by assuming a value of reflectivity in determining TN. Then. reflectivity
can be determined from the known value of Ta.
Fig. 11 depicts one system for determining R and T on board ship. A seismogram from a
conventionally produced shot is recorded on magnetic tape 40 as is standard. A portion. or
window of this seismogram is played back as indicated at 41. This window is auto-correlated
by the auto-correlator 42.
The auto-correlation function is shown in Fig. 12. As is well known, auto-correlation
requires the point-by-point multiplicationof the samples in the window bv themselves to produce a set of auto-correlation coefficients which are then summed to produce one point on .the auto-correlation function of Fig. 12. Then. the window is time shifted. the samples are again multiplied one by the other and summed to form another point on the auto-correlation
function. The process is repeated for various time shifts.
As an example. with zero time shift. the samples in the window are multiplied by them
selves to produce the zero lag auto-correlation coefficients. These are summed to produce the
value So on the curve of Fig. 12. Then. the samples of the window are shifted by one time
sample. multiplied one by the other to produce the coefficients at one time sample lag. These
are summed to form another point on the correlation function of Fig. 17. In general. the
window is shifted with respect to itself by a number of time samples designated n.
The zero lag auto-correlation coefficients S are combined with the auto-correlation
coefficients for a lag of n and for a lag of 'n for various values of n. The change in the value of
n is indicated at 43 in Fig. 11. The combination takes place in the multipliers 44. The zero lag
value S(, is multiplied by 2.0625. The value of the correlation function at a lag of n is
multiplied by 2.5 and the value at a lag of 2n is multiplied by .5. These products are summed at
45. The minimum power. that is. the least sum. in the combined auto-correlation functions is
selected at 46. The minimum power sum specifies the correct n which is designated NI.
Since M is in sample times. this can be directly converted toT because the time per sample
is known. For example. the sections of Fig. 10 have a sample interval of 2 msecs. Assuming
that a minimum power in the combined auto-correlation coefficients is detected when n = 57. then the output of 47 is a T of 114 msecs.
The determination of reflectivitv is an improvement on the technique described in Pfluever. "SPECTRA OF WATER REVERBERATIONS FOR PRIMARY AND MUL- TIPLE REFLECTIONS." GEOPHYSICS. Vol. 37. No. 5 (October 1972). pp. 788-796. In
that prior art technique. reflectivity is related to the ratio of the amplitude of the side lobes of
the auto-correlation function occurring at multiples of TX, This procedure provides a good
estimate of reflectivitv when the auto-correlation window is quite long. However. the use of a
lone auto-correlation window introduces other problems. notably the introduction of noise.
It is for this reason that the window selected at 41 is a relatively short multiple of T.
The determination of reflectivity as illustrated in Fig. 11 makes use of the Pflueger
technique to determine a first estimate R. The divider 48 forms the ratio:
2 S2M
3 SIM where SIM is the determined value of the correlation function at Tw and S2M is the value of the auto-correlation function at 2 Tw.
The auto-correlation function is interpolated to get a finer sampling rate. As an example, the auto-correlation coefficients may be produced at 4 msec. intervals, and it is desired to convert this to a 1 msec. sampling rate. In order to do this, it is assumed that the autocorrelation function is a sin x/x function. Using this interpolation technique preserves the amplitude spectrum of the data and introduces no new frequencies.
It can be shown that the estimate R is related to true reflectivity R in the manner depicted in
Fig. 13. F is the length of the correlation window in terms of the number of Tw's which are included in the window. As an example, suppose the auto-correlation window extends from 3Tw to 7Tw and R is determined to be .4 from Pflueger's technique. Then, F = 4 and Fig. 13 shows that R is approximately .425. In actual practice, reference is not made to a graph like
Fig. 13. Rather coefficients are stored in memory which are applied to the estimate R to convert it to the true value of R. The coefficients are Ao, A1 and A2 which are applied to R as indicated at 49.
The coefficients are a least squares fits to a surface described by plotting the true value of R as a function of N and the first estimate of R. Specifically, the coefficients are determined as indicated at 50. The value of F for this procedure is found by dividing the length of the window by Tw as indicated at 51.
The length of the auto-correlation window, selected at 41, is a function of the two-way travel time as determined from the fathometer 52. The auto-correlation lag M is determined by dividing twice the fathometer reading by the velocity of sound in water, assumed to be 4800 feet per second. This ration is determined at 52A. The length of the auto-correlation window is a multiple of the auto-correlation lag M. Generally, a window extending from 5M to 15M for each trace will be suitable.
A better understanding of these operations may be obtained from the following description of the underlying theory:
A seismic trace with a reverberation operator applied can be represented as:
si = Si + 2RSi.n + R2SI-2n (6) where Si is the ith sample of the seismogram and Sin is a sample with time shift n.
In accordance with this embodiment, we assume any reasonable value of R. For example, assume R = .5. Then, equation (6) becomes:
si = Si + Sin + .25Sin (7)
In accordance with least square theory, the correct value of R and n is obtained when the sum of the squares of the foregoing is a minimum. That is, the correct n occurs where the following is a minimum: S2i = ZS2i + 4R .S2in + R SSi-2n iii + 4R ESiSi-n + 2R ESiSi-2n i i + 4R3 SSi nSi-2n (8) To carry out the foregoing requires a very large number of computer operations. To determine the correct n in this manner would require approximately 200,000 operations. To make the determination for ten different values of n would require approximately 2,000,000 operations. In accordance with an embodiment of this invention, certain simplifying assumptions are made. If the length of the window is long compared to the time shift n, the samples in two windows which are shifted with respect to each other by n are the same. Therefore. we can assume the following: #Si2 #Si-n2 = #Si-2n2 = So (9) and S~SiSi-n = #Si-nSi-2n = SM (10)
i i and #SiSi-2 = S2M (ill) i
Using these assumptions, equation (7) becomes: S2i = (1 +4R2+R4)So + (4R+4R3)SM + 2R2S2M (12)
i
Using an assumed value of R = .5, this becomes: SS2j = 2.0625 So + 2.5 SM + .5 S2M (13)
It is in this manner that the simplifying multipliers used at 44 are obtained.
In carrying out this invention, it is necessary to find the correlation function only once. As previously mentioned, this might require approximately 200,000 operations. In order to do this for ten different values of n, it is necessary to repeat the multiplication of SM and S2M by 2.5 and .5 only nine further times. This adds eighteen operations for a total of 200,018 operations. This is approximately a ten fold decrease over the number of operations required without the simplifying assumptions.
Having determined TW and R, the sources are fired in groups which produce the desired three point operator. The sources are fired in three groups designated a, b and c. The a group is fired at time t = 0. Group b is fired at t = Tw, and group c is fired at t = 2Tw. The firing circuits 53 for accomplishing this may be of the type shown in U.S. patent 3.687,218 - Ritter.
The number of sources in each group is determined by the value of R. If a, b and c denote the number of sources in each group, these numbers are related to the determined reflectivity by the following:
a + b' + c = total number of sources
b - = 2R
a
c - = R2
a
A typical array which has been used in practice includes forty sources which are designated by the numerals " I" through '40". In this example, four sources are used as spares and the sources are fired in the following groups: if R = .3 (a.b.c) = (20.28.39) a = 40.39.37 36.33.32.30.29.27. 23,22,19,18,13,12,10,9,7,4,3,1 b = 39.34.31:28.24.21 .20. 16. 14. 11.8.5.2 c = 25.17 if R = .4 (a.b.c) = (23.26,38) a = 40.38.36.33.3l.29.27.23.22.l9,t8,l3.l 1,9.7.4,3,1
b = 39.37.34.32.30.28.24.20.16.14.12.10.8.5,2 c = 25.21.17 if R = .5 (a.b.c) = (25.25.37) a = 40.38.36.33.31.29.25.29.18.14.12.10 895z3 1 b = 39.37.34.31.30.77.23.71.18.17.13.1 13,11,7,4.2 c = 28.24.20.16 if R = .6 (a,b,b) = (27,24,36)
a = 39,37,34,32,28,24,23,19,12,11,9,7,4,2
b = 40,38,36,33,31,30,27,22,20, 18,16,14,10,8,5,3,1 c = 29,25,21,17,13 if R = .7 (a,b,c) = (29,23,35)
a = 39,37,34,30,27,22,18,14,11,8,4,2
b = 40,38,36,33,3 1,29,25,23,21,19,17,13,10,9,7,5,3,1 c = 32,28,24,20,16,12 if R = .8 (a,b,c) = (30,23,34)
a = 39,37,32,3 1,28,23,19,16,11,7,3, b = 40,38,36,34,30,27,24,22,20,18,14,12,10,8,5,4,2,1 c = 33,29,25,21,17,13,9
The firing procedure is as follows. As the vessel makes a traverse, the sources are alternately fired conventionally with all sources firing simultaneously and in three groups to produce the three point operator. Traces from the last five hydrophones in the streamer, produced by the conventional shot, are used to determine Tw. This value of Tw is used as the delay time for the next three point operator shot. For each three point operator shot, the value of Tw as determined from the immediately preceding conventional shot is used.
The value of reflectivity R is also determined from the traces of the last five hydrophones in the streamer. Because R changes slowly as the vessel moves, R is not recomputed for each shot. Rather, an optimum value of R occurring over the subsurface length of the cable is used to control the number of sources in each group for the three point operator shots.
As previously mentioned, the directivity of the source array can also be controlled in response to measurements of dip. In this technique the array of sources is preferably controlled so that energy from the sources reflects from the dipping formation approximately vertically and so that it intersects the array of hydrophones orthogonally.
First, a conventional survey is performed to identify the subsurface formation of interest.
From the seismic reflection signals produced in this survey, the dip of the formation can be determined. A survey is then run to produce seismograms having enhanced reflections from that formation. During this part of the survey, the firing of each source in the array is delayed so that the resulting seismic wave is directional. That is, the seismic wave does not travel vertically towards the dipping formation, but rather, travels at an angle. This angle is such that as the seismic energy strikes the dipping formation it is reflected in a vertical direction. This directivity can alternatively be obtained by changing the length of the cable between each surface buoy and its source. By towing succeeding sources at differing depths, the array of sources produces a seismic wave which travels at the desired angle.
FIG. 14 illustrates a system for carrying out a marine seismic exploration over dipping formations. A vessel 60 traverses a seismic exploration line in surveying the subsurface formation beneath a water layer. A linear horizontal array of seismic sources Sl-Sn is towed behind vessel 60. Also towed behind the vessel at a greater distance than the sources is a horizontal array of acoustic receivers R l-Rn. As vessel 60 traverses a desired exploration line, the seismic sources S1-SII are fired simultaneously to produce a seismic pressure wave in the water later. The acoustic receivers R1-Rn generate electrical signals in response to the reception of seismic reflections from the subsurface formations caused by the generation of the seismic pressure
particular seismic trace; and
V is the acoustic velocity characteristic of the layer through which the seismic energy
travels.
However, when there is a dipping subsurface formation having the angle a between the horizontal and the formation itself, the times Tx of the seismic reflections from such dipping formation are changed by the amount of the dip angle a so that the arrival time curve H hpcnm'
(Positive signs illustrate a receiver array down dip from a source array.)
U.S. Pat. No. 3,696,331 is an example of a process for determining and storing values of the subsurface dip and acoustic velocity in accordance with the expression of Equation (2).
A second traverse is made by the vessel 60 along the exploration line, and the values of dip and acoustic velocity determined during the first traverse are now used to control the sequential firing of the array of seismic sources so that the resultant seismic pressure wave is directed into the water at a desired angle 8 along the line of exploration. This desired angle 0 is such that the seismic pressure wave as illustrated at 65a in FIG. 16 strikes the dipping formation 62 and is reflected vertically toward the line of seismic receivers Rl-Rn. Such directivity may be obtained by delaying the time of firing of the successive sources Si-Sn, the time delay being given by the expression: AX 7 = - Sin tl (3) V where,
AX is the spacing between sources.
Vw is the velocity of the seismic energy in water, and
8 is the directivity angle.
It is a preferred aspect of this invention that the directivity angle (t be such that the reflected seismic pressure wave from the dipping formation 62 travel vertically toward the water surface. In this manner. the refected seismic pressure wave, illustrated at 65b in FIG. 16 will strike the horizontal array of receivers Rl-Rn orthogonally, thereby permitting the production of seismograms having enhanced reflections from the dipping formation.
As can be noted from the expression of Equation (2), the moveout of the recorded reflection signals from the array of receivers R l-Rn is related to twice the Sin of the dip angle a. Accordingly. applicant delays the firings of the successive seismic sources S l-Sn so that the directivity angle 8 for the downwardly traveling seismic pressure wave deviates from the vertical by twice the amount of the dip angle a of the formation 62. The timing sequence of the firings of the seismic sources to generate each seismic pressure wave may be continually changed during the second traverse along the line of exploration in accordance with the determined values of dip and velocity from the first traverse along the line of exploration.
In an alternative method. the foregoing-described marine seismic exploration operation may be carried out during a single traverse along the line of exploration by alternating the firings of the seismic sources between a first simultaneous firing of all the sources and a second sequential firing of all the sources. Following the first simultaneous firing, the value of dip and velocity is determined as described above and a second sequential firing of all the sources is then carried out so as to direct the resultant seismic pressure wave at the angle 8 which is twice the amount of the angle of dip a determined from the first simultaneous firing of all the seismic sources. This sequence of first and second firings is repeated along the entire line of exploration. Suitable firing circuits are used to fire the sources in a time sequence with the time delay T between each source. One example of such a firing circuit is shown in U.S.
Pat. No. 3.687.218 - Ritter.
An alternative way of obtaining a directive array of sources is shown in FIG. 17. The linear array of sources is towed at an angle (t from the horizontal so that the seismic wave produced by a simultaneous firing of the sources has the directivity angle 6' with respect to the vertical.
This is achieved by successively changing the length of the cables between the surface buoys and the sources. That is. cable 66 is longer than cable 67 and the cable 67 is longer than cable 68 so that source S, is deeper than source S2 and source S2 is deeper than source S3 and soon.
Conventional analog or hard wired digital circuits may be used in implementing the invention. However, it is preferred to use a small general purpose digital computer which is carried on board the vessel. One example of such a computer which has been successfully used is the Texas Instruments 980A computer.
WHAT WE CLAIM IS:
1. A method of seismic exploration comprising:
generating seismic pulses from a source towed by a marine vessel,
recording seismograms representing the reflected seismic pulses,
measuring from the seismograms the characteristics of the medium through which the seismic pulses travel,
converting the measurements of the characteristics into control parameters for controlling an array of seismic sources, and
generating further pulses from the array of seismic sources towed by the marine vessel in accordance with the control parameters.
2. A method according to claim 1 in which the step of measuring includes measuring the water bottom reflectivity and the water depth from the recorded seismograms.
3. A method according to claim 2 in which the measurements of reflectivity and water depth are converted into a time domain operator representative of the inverse of the reverberation distortion in the water layer between the water bottom and the water surface.
4. A method according to claim 3 in which the array of sources is fired in groups such that the acoustic pulses from the sources combine to produce a resultant acoustic pressure wave having a time domain operator characteristic in its travel to and from the subsurface formation.
5. A method according to claim 4 in which the source comprises an array of sources fired simultaneously to generate the seismic pulses from which the seismograms are recorded to enable the characteristics to be measured.
6. A method according to claim 5 in which the sources are alternately fired simultaneously and thereafter fired in groups. the group firing producing the acoustic pressure wave having the time domain operator.
7. A method according to any of claims 4 to 6 in which the steps of firing said array of sources in groups comprises:
firing first, second and third groups so that the leading edges of the pressure waves therefrom enhance each other to generate first, second and third acoustic impulses into the water.
8. A method according to claim 7 in which the energy produced by the second and third groups of sources is controlled in proportion to energy produced by the first group multiplied by factors related to the measured reflectivity of the water bottom.
9. A method according to claim 8 in which the energy produced by the second group is related to the energy produced by the first group of sources by a factor of twice the measured water bottom reflectivity, and in which the energy produced by the third group is related to the energy produced by the first group of sources by the square of the measured reflectivity.
10. A method according to any of claims 7 to 9 further comprising:
delaying the second group of pulses after the first group of pulses by a time Tu relating to the measured water depth. and
delaying the firing of the third group of sources from the firing of the first group by an amount 2Tw.
11. A method according to any of claims 4 to 10 in which the number of sources fired in each group is controlled in accordance with the measured reflectivity.
12. A method according to claim 4 in which the resultant acoustic pressure wave has a time domain characteristic representative of the inverse of the reverberation distortion in the water layer between the water bottom and the water surface.
13. A method according to claim 12 in which the water bottom reflectivity and water depth are measured by generating the zero lag auto-correlation coefficients of a window of the seismogram. generating the auto-correlation coefficients of said window with a lag of n time samples. generating the auto-correlation coefficients of the window with a lag of 2n time samples. repeating the foregoing for various values of n, combining the auto-correlation coefficients generated for each value of n. and selecting the n producing the minimum in the combined auto-correlation functions as being representative of water depth.
14. A method according to claim 13 which includes generating the values So. Sl and S2 of the auto-correlation function of the window at the sample times of o. n and 2n respectively.
15. A method according to claim 13 or 14 in which the auto-correlation functions are combined by summing the values of the auto-correlation function in accordance with the following: 2.0625 So + 2.5 S, + .5 S2.
16. A method according to any of claims 13 to 15 which includes converting the number
**WARNING** end of DESC field may overlap start of CLMS **.
Claims (27)
1. A method of seismic exploration comprising:
generating seismic pulses from a source towed by a marine vessel,
recording seismograms representing the reflected seismic pulses,
measuring from the seismograms the characteristics of the medium through which the seismic pulses travel,
converting the measurements of the characteristics into control parameters for controlling an array of seismic sources, and
generating further pulses from the array of seismic sources towed by the marine vessel in accordance with the control parameters.
2. A method according to claim 1 in which the step of measuring includes measuring the water bottom reflectivity and the water depth from the recorded seismograms.
3. A method according to claim 2 in which the measurements of reflectivity and water depth are converted into a time domain operator representative of the inverse of the reverberation distortion in the water layer between the water bottom and the water surface.
4. A method according to claim 3 in which the array of sources is fired in groups such that the acoustic pulses from the sources combine to produce a resultant acoustic pressure wave having a time domain operator characteristic in its travel to and from the subsurface formation.
5. A method according to claim 4 in which the source comprises an array of sources fired simultaneously to generate the seismic pulses from which the seismograms are recorded to enable the characteristics to be measured.
6. A method according to claim 5 in which the sources are alternately fired simultaneously and thereafter fired in groups. the group firing producing the acoustic pressure wave having the time domain operator.
7. A method according to any of claims 4 to 6 in which the steps of firing said array of sources in groups comprises:
firing first, second and third groups so that the leading edges of the pressure waves therefrom enhance each other to generate first, second and third acoustic impulses into the water.
8. A method according to claim 7 in which the energy produced by the second and third groups of sources is controlled in proportion to energy produced by the first group multiplied by factors related to the measured reflectivity of the water bottom.
9. A method according to claim 8 in which the energy produced by the second group is related to the energy produced by the first group of sources by a factor of twice the measured water bottom reflectivity, and in which the energy produced by the third group is related to the energy produced by the first group of sources by the square of the measured reflectivity.
10. A method according to any of claims 7 to 9 further comprising:
delaying the second group of pulses after the first group of pulses by a time Tu relating to the measured water depth. and
delaying the firing of the third group of sources from the firing of the first group by an amount 2Tw.
11. A method according to any of claims 4 to 10 in which the number of sources fired in each group is controlled in accordance with the measured reflectivity.
12. A method according to claim 4 in which the resultant acoustic pressure wave has a time domain characteristic representative of the inverse of the reverberation distortion in the water layer between the water bottom and the water surface.
13. A method according to claim 12 in which the water bottom reflectivity and water depth are measured by generating the zero lag auto-correlation coefficients of a window of the seismogram. generating the auto-correlation coefficients of said window with a lag of n time samples. generating the auto-correlation coefficients of the window with a lag of 2n time samples. repeating the foregoing for various values of n, combining the auto-correlation coefficients generated for each value of n. and selecting the n producing the minimum in the combined auto-correlation functions as being representative of water depth.
14. A method according to claim 13 which includes generating the values So. Sl and S2 of the auto-correlation function of the window at the sample times of o. n and 2n respectively.
15. A method according to claim 13 or 14 in which the auto-correlation functions are combined by summing the values of the auto-correlation function in accordance with the following: 2.0625 So + 2.5 S, + .5 S2.
16. A method according to any of claims 13 to 15 which includes converting the number
of time samples n into Tw, two way travel time of acoustic energy through said water depth.
17. A method according to any of claims 13 to 16 in which the water bottom reflection coefficients are measured by generating an estimate of reflectivity from
2S2
R = 3S, determining the length of said window in terms of the number n of two way travel times Tw in the window by
time length of
window (msecs.) N Tw (msecs.)
determining the value of the coefficients Ao, A,, A2 from A = .0048 ( ' - .0174( ') 2 A1 = -.0006 + .0786(n) - .0022(n)2
A2 = .0023 + 17.055(') - 25.691(22, and
determining the reflectivity R from R = A" A11 + A,R + A2R2.
18. A method according to any of claims 1 to 17 in which the water depth is measured with a fathometer and the window of the seismogram selected with a length equal to twice the fathometer reading divided by the velocity of seismic energy in water.
19. A method according to claim 1 in which the dip of a subsurface formation of interest is determined from the seismograms and the array of seismic sources is controlled in response to the measured dip such that the seismic pulses from the sources are directed at an angle such that the resultant seismic wave reflected from the formation of interest travels vertically towards the surface of the water.
20. A method according to claim 19 in which a linear array of seismic sources is used to produce the directed seismic pulses.
21. A method according to claim 20 in which the seismic pulses are directed by delaying the seismic pulses produced by each source in the array by a time delay between the sources to direct seismic energy at the desired angle.
22. A method according to claim 21 in which the time delay is given by 7 = AX Sin 8 V# where 7 is the time delay. AX is the spacing between the sources, Vw is the velocity of the seismic pulses in water, and t} is the angle.
23. A method according to claim 22 in which the angle f is related to twice the dip of the formation of interest.
24. A method according to claim 20 in which the seismic pulses are directed by towing the linear array of sources at an angle from the horizontal and firing the sources in the array simultaneously.
25. A method according to claim 20 in which the seismic pulses are directed at an angle from the vertical which is twice the value of the measured dip of the subsurface formation.
26. A method according to any of claims 20 to 25 in which the seismic pulses are produced at spaced points along the line of exploration that are down dip from the array of hydrophones.
27. A method of seismic exploration substantially as herein described with reference to the accompanying drawings.
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US70948576A | 1976-07-28 | 1976-07-28 | |
US70948476A | 1976-07-28 | 1976-07-28 | |
US70948676A | 1976-07-28 | 1976-07-28 | |
US05/793,680 US4146870A (en) | 1976-07-28 | 1977-05-04 | Seismic exploration for dipping formations |
Publications (1)
Publication Number | Publication Date |
---|---|
GB1583042A true GB1583042A (en) | 1981-01-21 |
Family
ID=27505513
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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GB31568/77A Expired GB1583042A (en) | 1976-07-28 | 1977-07-27 | Method of seismic exploration |
Country Status (10)
Country | Link |
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JP (1) | JPS5319901A (en) |
AU (1) | AU510036B2 (en) |
BR (1) | BR7704936A (en) |
DE (1) | DE2734091A1 (en) |
DK (1) | DK338777A (en) |
FR (1) | FR2360087A1 (en) |
GB (1) | GB1583042A (en) |
NL (1) | NL7708214A (en) |
NO (2) | NO146924C (en) |
NZ (1) | NZ184749A (en) |
Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB2148503A (en) * | 1983-10-21 | 1985-05-30 | Siesmograph Service | Underwater seismic sources |
WO2014198865A2 (en) * | 2013-06-13 | 2014-12-18 | Cgg Services Sa | Adaptable seismic source for seismic surveys and method |
WO2014198806A2 (en) * | 2013-06-13 | 2014-12-18 | Cgg Services Sa | Stationary marine vibratory source for seismic surveys |
WO2015036468A3 (en) * | 2013-09-12 | 2015-06-04 | Cgg Services Sa | Methods and systems for seismic imaging using coded directivity |
Families Citing this family (7)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
DE2905635C2 (en) * | 1979-02-14 | 1987-01-22 | Perkin-Elmer Censor Anstalt, Vaduz | Device for positioning a workpiece in the Z direction during projection copying |
DE3017818C2 (en) * | 1980-05-07 | 1983-01-27 | Mannesmann AG, 4000 Düsseldorf | Process for generating arbitrarily selectable echo pulse shapes as reflected signals in ultrasonic testing systems |
JPS5830128A (en) * | 1981-08-17 | 1983-02-22 | Hitachi Ltd | Waffer chuck device |
JPS5885904U (en) * | 1981-12-04 | 1983-06-10 | 富士ロビン株式会社 | Fumarole type soil improvement machine |
JPS58175631U (en) * | 1982-05-18 | 1983-11-24 | 株式会社東芝 | parallelization device |
JPS5917247A (en) * | 1982-07-21 | 1984-01-28 | Hitachi Ltd | Exposure method and its device |
NO164138C (en) * | 1986-01-13 | 1990-08-29 | Dag T Gjessing | SYSTEM OF MARINE SEISM INVESTIGATIONS. |
Family Cites Families (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
NO144253C (en) * | 1975-02-28 | 1981-07-22 | Mobil Oil Corp | PROCEDURE AND SYSTEM FOR SEISMIC INVESTIGATIONS |
-
1977
- 1977-07-19 NO NO772567A patent/NO146924C/en unknown
- 1977-07-22 NL NL7708214A patent/NL7708214A/en not_active Application Discontinuation
- 1977-07-26 NZ NZ184749A patent/NZ184749A/en unknown
- 1977-07-27 DK DK338777A patent/DK338777A/en unknown
- 1977-07-27 BR BR7704936A patent/BR7704936A/en unknown
- 1977-07-27 AU AU27360/77A patent/AU510036B2/en not_active Expired
- 1977-07-27 GB GB31568/77A patent/GB1583042A/en not_active Expired
- 1977-07-28 FR FR7723296A patent/FR2360087A1/en not_active Withdrawn
- 1977-07-28 JP JP8986377A patent/JPS5319901A/en active Pending
- 1977-07-28 DE DE19772734091 patent/DE2734091A1/en not_active Withdrawn
-
1982
- 1982-04-21 NO NO821289A patent/NO821289L/en unknown
Cited By (10)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB2148503A (en) * | 1983-10-21 | 1985-05-30 | Siesmograph Service | Underwater seismic sources |
WO2014198865A2 (en) * | 2013-06-13 | 2014-12-18 | Cgg Services Sa | Adaptable seismic source for seismic surveys and method |
WO2014198806A2 (en) * | 2013-06-13 | 2014-12-18 | Cgg Services Sa | Stationary marine vibratory source for seismic surveys |
US20140369163A1 (en) * | 2013-06-13 | 2014-12-18 | Cgg Services Sa | Stationary marine vibratory source for seismic surveys |
WO2014198865A3 (en) * | 2013-06-13 | 2015-02-26 | Cgg Services Sa | Adaptable seismic source for seismic surveys and method |
WO2014198806A3 (en) * | 2013-06-13 | 2015-02-26 | Cgg Services Sa | Stationary marine vibratory source for seismic surveys |
US9746569B2 (en) | 2013-06-13 | 2017-08-29 | Cgg Services Sas | Stationary marine vibratory source for seismic surveys |
US9921328B2 (en) | 2013-06-13 | 2018-03-20 | Cgg Services Sas | Adaptable seismic source for seismic surveys and method |
WO2015036468A3 (en) * | 2013-09-12 | 2015-06-04 | Cgg Services Sa | Methods and systems for seismic imaging using coded directivity |
US9874650B2 (en) | 2013-09-12 | 2018-01-23 | Cgg Services Sas | Methods and systems for seismic imaging using coded directivity |
Also Published As
Publication number | Publication date |
---|---|
DE2734091A1 (en) | 1978-02-02 |
AU510036B2 (en) | 1980-06-05 |
NZ184749A (en) | 1981-10-19 |
NO146924C (en) | 1982-12-29 |
NO772567L (en) | 1978-01-31 |
AU2736077A (en) | 1979-02-01 |
NL7708214A (en) | 1978-01-31 |
DK338777A (en) | 1978-01-29 |
BR7704936A (en) | 1978-04-25 |
NO146924B (en) | 1982-09-20 |
FR2360087A1 (en) | 1978-02-24 |
NO821289L (en) | 1978-01-31 |
JPS5319901A (en) | 1978-02-23 |
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PCNP | Patent ceased through non-payment of renewal fee |