WO2009131619A2 - Procédé d’acquisition de données sismiques des fonds océaniques au moyen de multiples sources sismiques - Google Patents

Procédé d’acquisition de données sismiques des fonds océaniques au moyen de multiples sources sismiques Download PDF

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Publication number
WO2009131619A2
WO2009131619A2 PCT/US2009/002046 US2009002046W WO2009131619A2 WO 2009131619 A2 WO2009131619 A2 WO 2009131619A2 US 2009002046 W US2009002046 W US 2009002046W WO 2009131619 A2 WO2009131619 A2 WO 2009131619A2
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Prior art keywords
source
seismic
firing
shot
signals
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PCT/US2009/002046
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English (en)
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WO2009131619A3 (fr
Inventor
Eivind Fromyr
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Pgs Geophysical As
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Publication date
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Priority to GB1019881A priority Critical patent/GB2471982A/en
Publication of WO2009131619A2 publication Critical patent/WO2009131619A2/fr
Publication of WO2009131619A3 publication Critical patent/WO2009131619A3/fr

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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

Definitions

  • the invention relates generally to the field of seismic exploration. More particularly, the invention relates to methods for acquiring marine seismic data using selected arrangements of sources and receivers.
  • U.S. Patent No. 6,906,981 issued to Vaage and assigned to an affiliate of the assignee of the present invention describes a method for seismic surveying which includes towing a first seismic energy source and at least one seismic sensor system.
  • a second seismic energy source is towed at a selected distance from the first source.
  • the first seismic energy source and the second seismic energy source are actuated in a plurality of firing sequences.
  • Each of the firing sequences includes firing of the first source, waiting a selected time, firing the second source and recording signals generated by the seismic sensor system.
  • the selected time between firing the first source and the second source is varied between successive ones of the firing sequences.
  • the firing times of the first and second source are indexed so as to enable separate identification of seismic events -originating from the first source and seismic events originating from the second source in detected seismic signals.
  • Marine seismic data are also acquired using arrays of seismic sensors deployed on the water bottom.
  • sensor arrays may include both pressure (or l pressure gradient) responsive sensors and single or multiple direction component sensitive particle motion sensors.
  • the sensors are typically disposed in cables extended along the water bottom in a selected pattern. Such cables are referred to as ocean bottom cables ("OBCs").
  • OBCs ocean bottom cables
  • a seismic energy source is towed near the water surface by a vessel and is actuated at selected times as the towing vessel moves along the water surface. Signals detected by the sensors are recorded and are later processed and interpreted.
  • a method for seismic surveying includes towing a first seismic energy source in a body of water and a second seismic energy source at a selected distance from the first seismic energy source.
  • the first seismic energy source and the second seismic energy source are actuated in a plurality of firing sequences.
  • Each of the firing sequences includes firing the first source and the second source.
  • Signals generated by a seismic sensor system deployed on the bottom of the body of water in a selected pattern are recorded.
  • a time interval between firing the first source and the second source is varied between successive ones of the firing sequences.
  • the times of firing the first and second source are indexed so as to enable separate identification of seismic events originating from the first source and seismic events originating from the second source in detected seismic signals.
  • FIG. 1 shows a vertical section view of an example of an ocean bottom cable seismic survey being conducted using two source vessels.
  • FIG. 2 shows a plan view of an example of an ocean bottom cable seismic survey being conducted using two source vessels.
  • FIG. 3 shows a table indicating which components in recorded seismic signals have coherence in each of three "domains.”
  • the invention generally relates to acquiring seismic data using ocean bottom cables ("OBCs").
  • OBC acquisition includes deployment of one or more seismic sensor cables on the bottom of a body of water, and moving a seismic energy source through the water near the water surface.
  • the seismic energy source is actuated at selected times, and thus at different positions relative to the sensors in the one or more OBCs. Signals detected by the sensors are recorded for processing and interpretation.
  • two or more seismic energy sources are used. The sources are actuated at selected times in a manner to be further explained below.
  • FIG. 1 shows a vertical section view of an example OBC seismic survey being conducted using two different "source” vessels for towing seismic energy sources.
  • the source vessels move along the surface 16A of a body of water 16 such as a lake or the ocean.
  • a vessel referred to as a "primary source vessel” 10 may include equipment, shown generally at 14, that comprises components or subsystems (none of which is shown separately) for navigation of the primary source vessel 10, for actuation of seismic energy sources and for retrieving and processing seismic signal recordings.
  • the primary source vessel 10 is shown towing two, spaced apart seismic energy sources 18, 18A.
  • the equipment 14 on the primary source vessel 10 may be in signal communication with corresponding equipment 13 (including similar components to the equipment on the primary source vessel 10) disposed on a vessel referred to as a "secondary source vessel" 12.
  • the secondary source vessel 12 in the present example also tows spaced apart seismic energy sources 20, 2OA near the water surface 16A.
  • the equipment 14 on the primary source vessel 10 may, for example, send a control signal to the corresponding equipment 13 on the secondary source vessel 12, such as by radio telemetry, to indicate the time of firing of each of the sources 18, 18A towed by the primary source vessel 10.
  • the corresponding equipment 13 may, in response to such signal, actuate the seismic energy sources 20, 2OA towed by the secondary source vessel 12.
  • the seismic energy sources 18, 18A, 20, 2OA may be air guns, water guns, marine vibrators, or arrays of such devices.
  • the seismic energy sources are shown as discrete devices in FIG. 1 to illustrate the general principle of the invention.
  • the type of seismic energy sources that can be used in any example is not intended to limit the scope of the invention.
  • the two or more seismic energy sources may be towed by the same vessel or by different vessels. The manner of actuating the two or more seismic energy sources will be further explained below.
  • an OBC 22 is deployed on the bottom 16B of the water 16 such that a plurality of spaced apart seismic receiver modules 24 are disposed on the water bottom 16B in a preselected pattern.
  • the receiver modules 24 may include a pressure or pressure gradient responsive seismic sensor, and one or more seismic particle motion sensors, for example, one component or three-component geophones, or one or three component accelerometers (none of the sensors are shown separately).
  • the type of and the number of seismic sensors in each module 24 is not intended to limit the scope of the invention.
  • the seismic sensors in each module 24 generate electrical or optical signals (depending on the sensor type) in response to, in particular, detected seismic energy resulting from actuations of the seismic energy sources 18, 18A, 20, 2OA.
  • the signals may be conducted to a device near the water surface 16A such as a recording buoy 23, which may include a data recorder (not shown separately) for storing the signals for later retrieval and processing by the equipment 14 on the primary source vessel 10.
  • the data storage functions performed by the recording buoy 23 may be performed by different types of equipment, such as a data storage unit on a recording vessel (not shown) or a recording module (not shown) deployed on the water bottom 16B. Accordingly, the invention is not limited in scope to use with a recording buoy or any other specific recording device.
  • FIG. 2 shows a plan view of one example of an OBC survey according to the invention.
  • a plurality of OBCs 22 are deployed on the water bottom (16B in FIG. 1) in a preselected pattern.
  • One example is an array shown in FIG. 2 in which a plurality of OBCs are extended in substantially parallel lines on the water bottom.
  • the primary source vessel 10 may move, for example, along the direction of the OBCs 22 in a "swath" pattern, the direction of motion being indicated by arrow 1OA.
  • the secondary source vessel 12 may move transversely to the line array, such as shown at 12A in a "patch" pattern. Either or both vessels 10, 12 may move in swath or patch pattern.
  • FIG. 1 and FIG. 2 in which the two sources (e.g., 18 and 18A towed by the primary source vessel 10) are towed at different longitudinal distances from the vessel along the tow path is not a limit on the scope of the invention, nor is the number of source vessels a limit on the scope of the invention. In other examples, the sources may be towed at the same longitudinal distance from the vessel, but at different lateral positions from the centerline of the vessel and/or the vessel trajectory.
  • a first seismic energy source which may be any one of the sources shown in FIG. 1, for example, is actuated or "fired.”
  • a recording is made of the signals detected by the sensors (in the modules 24 in FIG. 1).
  • the signal recordings are indexed to the time of firing the first seismic energy source.
  • a second seismic energy source (any of the other sources shown in FIG. 1, for example other than the one fired as explained above) is then fired at a known, selected time delay after the firing of the first seismic energy source, while signal recording continues.
  • Firing the first seismic energy source, waiting the predetermined delay time and firing the second seismic energy source thereafter is referred to for purposes of explaining the invention as a "firing sequence.”
  • the previously explained firing sequence (including actuating the first source, waiting for a predetermined delay time and firing the second source and contemporaneous signal recording) are repeated in at least a second firing sequence.
  • the second firing sequence includes firing the first source, waiting a different predetermined time delay than in the first firing sequence, and then firing the second source, while contemporaneously recording seismic signals.
  • the known, selected time delay between firing the first source and firing the second source is different in each successive firing sequence.
  • seismic signals are recorded for a plurality of such firing sequences, typically hundred or more firing sequences, each having a different value of the time delay between firing the first source and firing the second source.
  • the time delay between firing the first source and the second source in each firing sequence is preferably selected to be at least as long as the "wavelet" time of the seismic energy generated by the first source to avoid interference between energy from the first source and the second source. For efficiency reasons a smaller minimum time delay can be chosen and for reasonable source separation will give desired attenuation of the interfering energy. Typically, however, the time delay is less than one second, but in some cases may be several seconds. In some examples, the time delay between successive firing sequences may vary in a known, but random manner. In other examples, the time delay may vary in a known, but quasi-random manner. In still other examples, the time delay may be varied systematically. In some examples, the difference between time delay in successive firing sequences changes in increments of about 1-100 milliseconds.
  • the recorded signals from the sensors in the OBS array will contain seismic response to actuations of both the first source and the second source.
  • a method for separating components in the signals originating from the first seismic energy source from those originating from the second seismic energy source is described in U.S. Patent No. 6,906,981 issued to Vaage, assigned to an affiliate of the assignee of the present invention and incorporated herein by reference.
  • a "true" seismic signal component corresponding to the firing of the first source can be identified in the signal recordings ("traces") by a two part procedure. The first part of the procedure includes determining coherence between the traces within an individual firing sequence.
  • Such determination can be performed by selecting closely spaced subsets of all the traces (such as a subset of between five and ten traces), and determining coherence between the selected traces within selected-length time windows. Coherence may be determined, for each subset of traces selected, by correlating the traces to each other over the selected-length time windows. A result of the correlation is a curve or trace, the amplitude of which represents degree of correspondence from trace to trace with respect to time. [0020]
  • the coherence between traces determined in the first part of the procedure includes components that are also coherent between firing sequences with respect to the firing time of the first source. These components represent the "true" signal corresponding to actuating the first source.
  • the trace correspondence determined in the first part of the procedure also includes coherent noise, such as would result from signals caused by actuation of the second source, or other coherent noise such as from a ship propeller. Random noise is substantially not present in the correspondence traces because random noise has substantially no correspondence from trace to trace.
  • the second part of the procedure includes separating the components of the signals which are caused by the first source from the coherent noise.
  • separation of the first source component can be performed by generating trace to trace coherence measures (traces), as described above, for each of a plurality of firing sequences. Corresponding ones of the coherence traces are then correlated to each other between firing sequences to generate coherence traces from shot to shot. The resulting coherence traces will substantially represent seismic signals resulting only from the source. Coherent noise from the second source and from other coherent noise sources will be substantially absent from the shot to shot coherence traces.
  • traces trace to trace coherence measures
  • the reason the second source component of the signal recordings is substantially removed by the shot to shot coherence determination can be explained as follows.
  • the arrival time of successive second source caused seismic signal events is very similar between individual traces, and so would show a high trace to trace coherence.
  • Difference in coherence in the second source caused signal events is substantially between firing sequences (in the case where recording time is indexed with respect to the firing time of the first source). This difference in coherence in the second source caused signal events is primarily because of the different time delay between firing the first source and the second source in each firing sequence. Therefore, while the second source caused signal events may show high coherence from trace to trace, they substantially will not have coherence from shot to shot when the recording time is indexed to the firing time of the first source.
  • determining shot to shot coherence to identify the signal events originating from the first source may be performed by generating a modified common-midpoint (CMP) trace gather with respect to the first source.
  • CMP common-midpoint
  • a modified CMP gather with respect to the first source comprises a subset of all the traces (signal recordings) corresponding to each of a plurality of first source firings, in which the position of the geodetic first source, and the corresponding sensor for which the trace is presented or processed in the gather, have the same "midpoint" between them adjusted for the vertical separation of source and receiver.
  • CMP gathers with respect to the first source will have a high coherence for events which correspond to firing of the source.
  • CMP gathers with respect to the first source by contrast, will have very low coherence for second source originating signal events, for coherent noise and for random noise.
  • one example of a method according to the invention further includes identifying the "true” seismic signals originating from the second source. Such identification can be performed by time-aligning the signals from each firing sequence with respect to the firing time of the second source. In some examples, this can be performed by applying a time delay to each trace such that the signals from the second source all represent a same time delay from the start of signal recording or from a selected time index related to the time of firing of the second source.
  • True seismic signal from the second source may then be identified by using trace-to-trace and shot-to-shot coherence determination, just as used to determine first source true seismic signals where the first source firings are time aligned from the start of recording, as previously explained.
  • Shot to shot coherence may be determined, in one example, by generating CMP trace gathers with respect to the second source. Events in the traces corresponding to the second source will have high coherence in a CMP gather with respect to the second source. First source induced events, other coherent noise, and random noise will have very little coherence in a CMP gather with respect to the second source.
  • the accuracy with which the signal components corresponding to the first source and to the second source may be checked by determining an amount of energy in each set of coherence traces which corresponds to an energy source other than the one the coherence traces correspond to. Energy in the coherence traces which does not correspond to the signals being identified indicates that the correlations may need to be performed again, using, for example, different length time windows.
  • FIG. 3 shows a table indicating which components in the recorded seismic signals have coherence in each of three "domains.” The first such domain is trace to trace within a single firing sequence or "shot.” Signals from the first source (source A) and from the second source (source B), as well as coherent noise, will have coherence from trace to trace. Random noise will not have any coherence in the trace to trace domain. A CMP gather with respect to source A will have coherence only for signals resulting from source A.
  • Source B signals, coherent noise and random noise will have substantially no coherence (i.e., they will be random).
  • a CMP gather with respect to source B will show coherence for signals originating from source B.
  • Source A signals, coherent noise and random noise will have substantially no coherence in a source B CMP gather.
  • the signals identified to source A may be removed from the total signal. Then, the source A identified signals can be time aligned with respect to the firing time of source B, gathered in a CMP gather with respect to source B and checked to see if there is any coherence. As shown in FIG. 3, source A signals should be random (have substantially zero mean value) in a CMP gather with respect to source B. Correspondingly, the signals identified to source B can be time aligned with respect to the firing time of source A, and CMP gathered with respect to source A. Source B signals should have substantially zero energy (be random) in a CMP gather with respect to source A, as indicated in the table of FIG. 3.
  • the signals corresponding to source A and source B may be removed from the originally recorded signals. Trace to trace correlation may show some energy if there is coherent noise in the remainder, as shown in FIG. 3. However, CMP gathers of the remainder with respect to either source A or source B should have substantially zero mean value (they will be random) as indicated in FIG. 3.
  • the foregoing examples of the invention are described in terms of having two seismic energy sources at spaced apart positions.
  • the invention is not limited in scope to having only two sources and identifying two trace to trace and shot to shot components.
  • three, four or more sources may be used.
  • the third, fourth and any additional sources are each fired sequentially in each firing sequence.
  • the time delay between firing the second source and the third source is different than the delay between firing the first source and the second source.
  • the delay between firing the second source and the third source is also different in each firing sequence.
  • determining coherent signal components identified to the third, fourth and any additional sources includes time aligning the recorded signals with respect to the source for which reflective events are desired to be identified, and determining trace to trace and shot to shot coherent components of the time-aligned signals. Determining the shot to shot coherent components may be performed, in some embodiments, by generating a common mid point gather with respect to the source for which signal components are to be identified.
  • Methods according to the invention may provide the benefit of reducing a waiting time between firing the sources in firing sequences because signals from each of the plurality of sources may be uniquely identified in a shot sequence. Therefore, embodiments of a method according to the invention may increase the efficiency with which OBC seismic surveying is performed. While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Abstract

La présente invention concerne un procédé d’étude sismique comportant l’étape consistant à traîner une première source d’énergie sismique dans une masse d’eau et une seconde source d’énergie sismique à une distance sélectionnée de la première source d’énergie sismique. La première source d’énergie sismique et la seconde source d’énergie sismique sont actionnées au cours d’une pluralité de séquences d’allumage. Chacune des séquences d’allumage comporte l’étape consistant à allumer la première source et la seconde source. Les signaux générés par un système de capteur sismique déployé sur le fond de la masse d’eau suivant une configuration sélectionnée sont enregistrés. Un intervalle de temps entre l’allumage de la première source et celui de la seconde source varie entre les séquences d’allumage successives parmi les séquences d’allumage. Les moments d’allumage des première et seconde sources sont indexés de manière à permettre une identification séparée des événements sismiques provenant de la première source et des événements sismiques provenant de la seconde source dans les signaux sismiques détectés.
PCT/US2009/002046 2008-04-24 2009-04-01 Procédé d’acquisition de données sismiques des fonds océaniques au moyen de multiples sources sismiques WO2009131619A2 (fr)

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GB1019881A GB2471982A (en) 2008-04-24 2009-04-01 Method for acquiring marine ocean bottom seismic data using multiple seismic sources

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US14898208A 2008-04-24 2008-04-24
US12/148,982 2008-04-24

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GB2473418A (en) * 2009-06-25 2011-03-16 Statoilhydro Asa Re-deploying seismic receiver cables while carrying out a marine seismic survey
WO2012145113A1 (fr) * 2011-04-18 2012-10-26 Siemens Corporation Systèmes et procédés pour séparer des groupements de tirs sismiques
WO2013087871A3 (fr) * 2011-12-15 2013-10-03 Cgg Services Sa Procédé et dispositif de séparation de signaux sismiques provenant de sources sismiques
GB2512209A (en) * 2013-03-12 2014-09-24 Pgs Geophysical As Systems and methods for removing acquisition related effects from seismic data
US20150331125A1 (en) * 2014-05-14 2015-11-19 Sercel Method for calculating a seismic survey
EP2802900A4 (fr) * 2012-01-12 2016-01-27 Geco Technology Bv Atténuation de bruit acquis dans une mesure d'énergie
US9874646B2 (en) 2014-04-14 2018-01-23 Pgs Geophysical As Seismic data processing
US10267936B2 (en) 2016-04-19 2019-04-23 Pgs Geophysical As Estimating an earth response
US10598807B2 (en) 2014-02-18 2020-03-24 Pgs Geophysical As Correction of sea surface state
GB2584124A (en) * 2019-05-22 2020-11-25 Equinor Energy As System for acquiring seismic data
GB2606450A (en) * 2017-08-29 2022-11-09 Pgs Geophysical As Seismic data acquisition for velocity modeling and imaging
NO346705B1 (no) * 2013-09-03 2022-11-28 Pgs Geophysical As Dempning av støy ved skuddgjentakelse ved marin seismisk kartlegging av undergrunnen

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Cited By (26)

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GB2473418A (en) * 2009-06-25 2011-03-16 Statoilhydro Asa Re-deploying seismic receiver cables while carrying out a marine seismic survey
WO2012145113A1 (fr) * 2011-04-18 2012-10-26 Siemens Corporation Systèmes et procédés pour séparer des groupements de tirs sismiques
US9602781B2 (en) 2011-04-18 2017-03-21 Siemens Aktiengesellschaft Methods for deblending of seismic shot gathers
WO2013087871A3 (fr) * 2011-12-15 2013-10-03 Cgg Services Sa Procédé et dispositif de séparation de signaux sismiques provenant de sources sismiques
US9128209B2 (en) 2011-12-15 2015-09-08 Cggveritas Services Sa Method and device for separating seismic signals from seismic sources
US9405027B2 (en) 2012-01-12 2016-08-02 Westerngeco L.L.C. Attentuating noise acquired in an energy measurement
EP2802900A4 (fr) * 2012-01-12 2016-01-27 Geco Technology Bv Atténuation de bruit acquis dans une mesure d'énergie
GB2512209B (en) * 2013-03-12 2018-04-11 Pgs Geophysical As Systems and methods for removing acquisition related effects from seismic data
AU2018220021B2 (en) * 2013-03-12 2019-11-28 Pgs Geophysical As Systems and methods for removing acquisition related effects from seismic data
US9329293B2 (en) 2013-03-12 2016-05-03 Pgs Geophysical, As Systems and methods for removing acquisition related effects from seismic data
NO345989B1 (no) * 2013-03-12 2021-12-13 Pgs Geophysical As System og fremgangsmåte for å fjerne innsamlingsrelatert støy fra seismiske data
GB2512209A (en) * 2013-03-12 2014-09-24 Pgs Geophysical As Systems and methods for removing acquisition related effects from seismic data
NO346705B1 (no) * 2013-09-03 2022-11-28 Pgs Geophysical As Dempning av støy ved skuddgjentakelse ved marin seismisk kartlegging av undergrunnen
US10598807B2 (en) 2014-02-18 2020-03-24 Pgs Geophysical As Correction of sea surface state
US9903966B2 (en) 2014-04-14 2018-02-27 Pgs Geophysical As Seismic data acquisition
US11099287B2 (en) 2014-04-14 2021-08-24 Pgs Geophysical As Seismic data processing
US9874646B2 (en) 2014-04-14 2018-01-23 Pgs Geophysical As Seismic data processing
NO347113B1 (en) * 2014-05-14 2023-05-15 Sercel Rech Const Elect Method for calculating a multi-source seismic survey
US20150331125A1 (en) * 2014-05-14 2015-11-19 Sercel Method for calculating a seismic survey
US10267936B2 (en) 2016-04-19 2019-04-23 Pgs Geophysical As Estimating an earth response
US11125900B2 (en) 2016-04-19 2021-09-21 Pgs Geophysical As Estimating an earth response
GB2606450A (en) * 2017-08-29 2022-11-09 Pgs Geophysical As Seismic data acquisition for velocity modeling and imaging
GB2606450B (en) * 2017-08-29 2023-02-08 Pgs Geophysical As Seismic data acquisition for velocity modeling and imaging
US11747500B2 (en) 2017-08-29 2023-09-05 Pgs Geophysical As Seismic data acquisition for velocity modeling and imaging
GB2584124B (en) * 2019-05-22 2023-01-04 Equinor Energy As System for acquiring seismic data
GB2584124A (en) * 2019-05-22 2020-11-25 Equinor Energy As System for acquiring seismic data

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GB201019881D0 (en) 2011-01-05
GB2471982A (en) 2011-01-19

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