GB2576736A - Seismic data acquisition system - Google Patents
Seismic data acquisition system Download PDFInfo
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- GB2576736A GB2576736A GB1814032.7A GB201814032A GB2576736A GB 2576736 A GB2576736 A GB 2576736A GB 201814032 A GB201814032 A GB 201814032A GB 2576736 A GB2576736 A GB 2576736A
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- seismic
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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
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/12—Signal generation
- G01V2210/127—Cooperating multiple sources
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/12—Signal generation
- G01V2210/129—Source location
- G01V2210/1293—Sea
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- Physics & Mathematics (AREA)
- Oceanography (AREA)
- Engineering & Computer Science (AREA)
- Acoustics & Sound (AREA)
- Environmental & Geological Engineering (AREA)
- Geology (AREA)
- Remote Sensing (AREA)
- General Life Sciences & Earth Sciences (AREA)
- General Physics & Mathematics (AREA)
- Geophysics (AREA)
- Geophysics And Detection Of Objects (AREA)
Abstract
A system for obtaining seismic data comprises at least one seismic receiver array 3 and at least one electric seismic source 7 located within an end region of, or a distance behind, the seismic receiver array. A vessel 1 may tow the streamer 3 and the electric source 7, and also a second seismic source 2. The second source is an impulsive source, such as an airgun. The electric source 7 and airgun 2 may operate at different frequencies, which may overlap, and may emit seismic waves simultaneously. The end region 10 may be the rearmost third of the seismic receiver array. The electric source may be on a tailbuoy 8, or an the streamer 3. Data from the multiple sources may be separated based on opposing moveouts, a separational effect during deconvolution, or time shifts.
Description
The present invention relates to the field of seismic data acquisition. In particular, it relates to a system for acquiring geophysical data in a marine or other such watercovered environment.
In order to determine details of the subsurface of the Earth, geophysical methods may be applied. One of these methods, and currently the main geophysical method used in the oil and gas industry, records active seismic data. In this technique, a downward-propagating seismic wavefield is generated by a source, such as an airgun. Subsurface inhomogeneities in the region being studied cause part of the seismic waves of the wavefield to be reflected back up towards the surface. The energy in these waves (e.g. represented by their amplitude) is then recorded by receivers at a location (or locations) distant from the source.
Such seismic reflection data obtained in this way are then processed to obtain an image of subsurface structures. This image is often in three dimensions (3D), which refer to the three spatial dimensions illuminated by the seismic data.
A typical arrangement for performing such studies in a marine or other such watercovered environment comprises a vessel towing an array of air gun sources and an array of streamers, each streamer holding a number of seismic receivers. The array of streamers is typically towed such that its front end is several tens of metres and up to several hundred metres (e.g. around 300 m) behind the vessel. The array of air gun sources is in most cases towed closer to the vessel than the streamers, between the vessel’s stern and the front end of the streamers. Thus, there is a horizontal offset typically of several tens of metres, between the array of air gun sources and the front of the array of streamers. This means that so-called “zero offset” seismic data cannot be obtained from such an arrangement. “Zero offset” seismic data is data that would be obtained where the seismic wave from the source travels straight down and straight back up again to a receiver, i.e. with zero horizontal offset (displacement) between the source and the receiver. However, in the prior art arrangement just described, as no receiver is located at the same horizontal position as the source, it is not possible to obtain such zero offset data.
-2Zero offset data is important because it allows regions shallow beneath the sea bed to be studied. This is necessary for several reasons, even though such regions do not typically contain economically significant amounts of hydrocarbons. One important reason to image the shallow seabed in detail is to detect hazards such as gas (e.g. methane) which could be problematic for any future drilling in that region. Other reasons could be to determine the presence of any unknown natural or artificial structures and bodies, or just for the improvement of the deeper seismic imaging. Thus, it is important to obtain an understanding of the structure of shallow regions beneath the sea bed and so zero offset data is required.
In the above case, the array of streamers cannot be towed any closer to the vessel, i.e. such that at least part of the array of streamers has the same horizontal position as the air gun array, due to mechanical reasons. It is also not possible to locate the air gun array more distant from the vessel, i.e. with the same horizontal location as at least part of the array of streamers. This is because the air guns require the supply of high pressure air for them to operate. In the conventional system described above, increasing the distance from the vessel to the air gun array would make it impossible (or at least highly impractical and/or costly) to provide the required air pressure to the air guns.
For these reasons, zero offset data is typically obtained by performing a second survey and/or using a second vessel. However, these solutions are highly inefficient and costly.
“Shooting over the seismic spread”, Vetle Vinje etal, First Break, Vol. 35, June 2017 discloses a system for obtaining zero offset data wherein the seismic sources are towed from a first (source) vessel, and receiver streamers are towed from a second (streamer) vessel, such that the receiver streamers are in a deep-water location and the sources are positioned directly above the streamers. Thus, there is zero horizontal offset between them. However, two vessels are required for this system to work.
“A new look at simultaneous sources”, Craig J. Beasley, Ronald E. Chambers, and Zerong Jiang (1998),. SEG Technical Program Expanded Abstracts 1998: pp. 133
- 3135 discloses a system in which airguns and pressure generators are towed from two separate vessels.
US 2012/0275264 A1 discloses a single vessel towing an air gun and an array of receiver streamers, wherein the air gun is located above the array of streamers.
“Near-zero offset acquisition for 3D marine surveys utilizing Cable Head Sources”, Michael Norris et al, SEG International Exposition and 87th Annual Meeting, 2007, pp 116-120, discloses a vessel towing an air gun array and a streamer array, wherein the air gun array is towed in front of the streamer array, and an electrically powered acoustic source is provided on the cable head buoy (i.e. at the front end) of each streamer.
According to the present invention, there is provided a system for obtaining seismic data, the system comprising:
at least one seismic receiver array; and at least one electric seismic source;
wherein the at least one electric seismic source is arranged to emit seismic waves that can be detected by the seismic receiver array; and the at least one electric seismic source is located within an end region of, or a distance behind, the seismic receiver array.
Thus, the present invention provides a system for obtaining seismic data in which an electric seismic source is provided within an end region of, or a distance behind, the seismic receiver array. By providing an electric seismic source within an end region of, or a distance behind, the seismic receiver array, this allows zero-offset seismic data to be obtained.
In addition, by locating an electric seismic source within an end region of, or a distance behind, the seismic receiver array, this means that seismic waves can be generated in an opposite direction to any waves generated from in front of the seismic receiver array (e.g. from conventional air gun sources). Furthermore, such sources may be shot simultaneously, or quasi-simultaneously, such that their recordings overlap and blend in time, but are still separable, e.g. by performing a frequency-wavenumber (“f-k”) analysis of data obtained from both sources.
- 4The system preferably comprises a towing vessel for towing (at least) the at least one seismic receiver array. The towing vessel may also tow the at least one electric seismic source. Alternatively, the at least one electric seismic source may be towed by a different vessel to that which tows the at least one seismic receiver array.
The towing vessel (or vessels) could be any vessel, such as a boat, capable of towing a seismic receiver array (at least), and/or the at least one electric seismic source. It may comprise or carry, for example, a controller and/or processing means for obtaining and/or processing the seismic data (corresponding to seismic waves) detected by the seismic receiver array.
The system comprises at least one electric seismic source. In a preferred embodiment, the system comprises more than one electric seismic source. For example, the system may comprise 2, 3, 4 or more electric seismic sources.
The system comprises a seismic receiver array. The array may, for example, comprise one or more, and preferably more than one, streamers, each streamer comprising or holding one or more receivers (preferably a plurality of receivers) for detecting seismic waves.
In a preferred embodiment, the seismic receiver array may comprise up to 30 streamers or, more preferably, 10-20 streamers. However, more or fewer may alternatively be provided. The streamers are preferably spaced apart from each other in the array. For example, the streamers may be spaced around 10 - 75 m apart from each other in the array. The spacing distance between adjacent streamers in the array may be up to 200 m and may vary inside the array. The streamers (or the seismic receiver array) may be up to or more than around 2 km long and up to 16 km long.
The seismic receiver array may be towed along the surface of the water or it may be towed beneath the surface of the water, e.g. at any depth. For example, the seismic receiver array may be towed between up to 6 and 15 m deep, or deeper
- 5such as up to 50 or 100 m deep. The seismic receiver array may have a varying depth (e.g. between 6 and 25 m) along its length, for example.
The at least one electric seismic source is arranged to emit seismic waves that can be detected by the seismic receiver array. As described below, the seismic receiver array may comprise or hold a plurality of receivers. Thus, the at least one electric seismic source is arranged to emit seismic waves that can be detected by at least part of, or at least one receiver in, the seismic receiver array.
Preferably, the end region (or the at least one electric seismic source) is arranged or positioned such that at least one receiver (and preferably a plurality of receivers and/or a majority of the receivers) of the seismic receiver array is (are) located between a front end of the seismic receiver array (e.g. in a towing direction) and the at least one electric seismic source.
One or more receivers of the seismic receiver array may additionally or alternatively be located behind (e.g. in a towing direction) the at least one electric seismic source.
The system comprises at least one electric seismic source. The at least one electric seismic source may be any seismic source which is or can be powered, at least partly or mainly, by electricity. For example, the at least one electric seismic source may be a vibrating source (a vibrator), a boomer or a sparker. The at least one electric seismic source could be or comprise a source which is arranged to operate by moving a volume of water by pushing an interface (e.g. a straight/flat plate, a steel dome, or other member), or by discharging electricity between electrodes in the water thereby producing a plasma, for example.
Electrical power for the at least one electric seismic source could be provided from any suitable source of electrical power. For example, electrical power for the at least one electric seismic source could be provided from a battery, solar panels, an electrical generator or any other kind of source of electrical power. The source of electrical power could be located on a vessel (e.g. to which the seismic receiver array and/or at least one electric seismic source are connected), a float (e.g. connected to the seismic receiver array and/or the at least one electric seismic
- 6source), or a further vessel (e.g. to which the seismic receiver array is not connected), for example.
The at least one electric seismic source is located within an end region of, or a distance behind, the seismic receiver array.
The end region of the seismic receiver array could be a region around at least 1.5 2 km from a front end (in a towing direction) of the seismic receiver array (or from a towing vessel to which the seismic receiver array is attached). For example, the end region could be at least 1.5 km, 1.6 km, 1.7 km, 1.8 km, 1.9 km or 2 km from a front end of the seismic receiver array (or from a towing vessel to which the seismic receiver array is attached). Preferably, the end region is at least 2 km from a front end of the seismic receiver array, or from a towing vessel to which the seismic receiver array is attached.
The end region of the seismic receiver array could be a region covering the rearmost 50%, 45%, 40%, 35%, 30%, 25%, 20%, 15%, 10% or 5% of the length of the seismic receiver array.
The size of the end region, or the fraction of the seismic receiver array covered by the end region (i.e. comprising or containing one or more electric seismic receivers), may depend on the geological setting.
The length of the receiver array (or streamers) is usually defined by the maximum target depth that is desired to be imaged. The deeper the target, the longer the receiver array (or streamer(s)) required. This means that if the target is deep the end region is located further from the vessel and/or a smaller fraction of the seismic receiver array is covered by the end region.
Having the end region more distant from the vessel may also help with the inversion calculation to be performed and in cases where the geology is not simply horizontally layered but may even have vertical structures which could reflect waves sideways, for example.
- 7The size of the end region may be dependent on the geology or the region being studied. In particular, the size of the end region may depend more on the shallow part of the geology, e.g. when the seabed is rugose, for example. In such cases, the waves get scattered more, thereby creating multiple scattered waves. In order to remove such “multiples” (multiple scattered waves), a split-spread recording would be beneficial.
Split-spread is when a shot is recorded in two directions. This simply means that the wave spreads in two opposite directions away from the source (e.g. forwards and backwards with respect to a towing direction).
In the prior art, the source is usually located behind the vessel with the receiver array located even further behind the vessel than the source. In such cases, the the waves from the source only travel from the front towards the end (back) of the receiver array.
However, if, as in the present invention, the (a) source is located somewhere along the streamer or receiver array (as opposed to being in front of it), then the waves travel from the source towards the end of the receiver array and also from the source towards the front of the receiver array (or vessel). Both such waves may then be recorded by the same receiver array (streamer).
The end region of the seismic receiver array could be a region which does not extend (horizontally) beyond a horizontal end-point of the seismic receiver array.
Alternatively, the at least one electric seismic source may be located a distance behind the seismic receiver array, e.g. up to 50 m, 75 m, 100 m, 150 m, 200 m or more behind the seismic receiver array.
Preferably, the towing vessel is a common towing vessel to which the at least one electric seismic source and the seismic receiver array are directly or indirectly connected, e.g. via one or more cables. Since both the at least one electric seismic source and the seismic receiver array are connected to a single towing vessel, only one towing vessel is needed, providing an improvement in cost and efficiency compared to systems in which two or more towing vessels are used or required.
- 8The at least one electric seismic source and the seismic receiver array may be directly or indirectly connected to the towing vessel. For example, a single connecting means (e.g. one or more cables) may connect each of the at least one electric seismic source and/or the seismic receiver array to the towing vessel. Alternatively, the at least one electric seismic source and/or the seismic receiver array may be connected to the towing vessel via another component. For example, and preferably, the at least one electric seismic source may be connected to the towing vessel via the seismic receiver array.
The system preferably further comprises at least one second seismic source. The at least one second seismic source is preferably arranged to emit seismic waves that can be detected by the seismic receiver array (e.g. at least part of, or a receiver within, the seismic receiver array).
The at least one electric seismic source and the at least one second seismic source are preferably located at different horizontal positions, e.g. a different horizontal distances from a (e.g. common) towing vessel. For example, the at least one second seismic source may be located closer to the towing vessel than the at least one electric seismic source and/or the seismic receiver array. This can allow for greater coverage of the subsurface region of interest and the collection of more detailed seismic data.
The at least one second seismic source could be any kind of seismic source such as an impulsive seismic source and/or a vibrational seismic source. For example, the at least one second seismic source may comprise an air gun source. As the at least one second seismic source may be located closer to the vessel than the at least one electric seismic source, the at least one second seismic source may comprise air gun sources. Furthermore, as the at least one second seismic source may be located further from the seismic receiver array that the at least one electric seismic source, a more powerful source, such as an air gun source, may be desirable or necessary in order for its wavefield to be detected by the seismic receiver array.
- 9The towing vessel is preferably a common towing vessel to which the at least one electric seismic source, the at least one second seismic source, and the seismic receiver array are directly or indirectly connected. As all of the at least one electric seismic source, the at least one second seismic source, and the seismic receiver array are directly or indirectly connected to a common towing vessel, only a single vessel may be used, thereby providing an improvement in cost and efficiency compared to systems in which two or more towing vessels are used or required.
In a preferred embodiment, the at least one electric seismic source and the at least one second seismic source are arranged to operate at different frequencies. However, this is not mandatory.
For example, the at least one electric seismic source may be arranged to operate at a higher centre frequency (or frequency band) (e.g. >100 Hz, up to a few thousand Hz) than the at least one second seismic source. The use of a high frequency source, e.g. for obtaining zero offset data, can allow the near surface subsurface region of the region of interest to be studied, e.g. at a higher resolution, to detect shallow hazards or shallow targets for example.
The at least one second seismic source is preferably arranged to operate at a lower centre frequency (or frequency band) (e.g. 1-100 Hz) than the at least one electric seismic source. This can allow the seismic waves generated by the at least one second seismic source to penetrate deeper into the subsurface region, e.g. to find hydrocarbon target layers.
The at least one electric seismic source and the at least one second seismic source may be arranged to operate at overlapping frequencies (frequency bands). For example, airguns may typically emit seismic waves whose frequencies cover a wide spectrum, so their frequencies may overlap anyway with those (that) of the at least one electric source. However, the centre frequencies of the at least one electric source and the at least one second seismic source are preferably different.
In one embodiment, the at least one electric source may (also) be arranged to operate at (lower) frequencies, e.g. corresponding to that/those of the at least one second seismic source.
- 10The at least one electric seismic source and the at least one second seismic source are preferably arranged to simultaneously (or substantially simultaneously) emit seismic waves that can be detected by the seismic receiver array. Arranging the at least one electric seismic source and the at least one second seismic source to simultaneously (or substantially simultaneously) emit seismic waves provides a more efficient method of data collection compared with systems in which such data cannot be (or is not) obtained simultaneously.
The provision of a system comprising two different kinds of seismic sources is viewed as a further inventive concept.
Thus, viewed from a further aspect, there is provided a system for obtaining seismic data, the system comprising:
at least one first seismic source;
at least one second seismic source; and a seismic receiver array;
wherein the at least one first seismic source and the at least one second seismic source are arranged to emit seismic waves that can be detected by the seismic receiver array; and the at least one first seismic source is a different kind of seismic source to the at least one second seismic source and is located within an end region of, or a distance behind, the seismic receiver array.
By providing a system with at least one first seismic source and at least one second seismic source, wherein the at least one first seismic source is a different kind of seismic source to the at least one second seismic source and is located within an end region of, or a distance behind, the seismic receiver array, this allows the generation of more detailed seismic data from a single system.
The system preferably comprises a towing vessel for towing (at least) the at least one seismic receiver array. The towing vessel may also tow the at least one first and/or second seismic source(s).
- 11 The at least one first seismic source preferably comprises or is an electric seismic source. As described above, this can allow it to be located more distant from the vessel than other kinds of sources.
Such a system, and indeed any aspect of the invention, may comprise any of the further features discussed above or below.
The seismic receiver array preferably comprises an array of one or more streamers, each streamer comprising a plurality of seismic receivers.
The at least one first/electric seismic source may be located, for example, at the same horizontal position as a rearmost seismic receiver in the seismic receiver array. This means that it can emit seismic waves in an opposite direction to waves emitted from the second seismic source(s) located in front of the seismic receiver array.
Alternatively, the at least one first/electric seismic source may be located at a horizontal position between a rearmost seismic receiver in the seismic receiver array and a towing vessel. This can allow for the generation of “split-spread” data, i.e. the source signal may be detected in receivers located between the vessel and the at least one first/electric seismic source, as usual, but the signal now may also be recorded in a (small) tail region of the receiver array towards the end of the array, behind the at least one first/electric seismic source. This means that the detected source signal spreads in two directions with respect to the at least one first/electric seismic source and is thereby “split”.
The at least one first/electric seismic source may be located behind the seismic receiver array, e.g. up to 100 m behind the seismic receiver array. For example, the at least one first/electric seismic source may be provided on a tail buoy of the seismic receiver array. This can be a convenient way of locating the at least one first/electric seismic source in an end region of the system.
The at least one first/electric seismic source may be located a horizontal distance away from a towing vessel that is equal to or greater than a distance between the
- 12towing vessel and a receiver (e.g. a front-most receiver, in a towing direction) in the seismic receiver array.
The at least one first/electric seismic source may be provided on a streamer of the seismic receiver array.
Alternatively, the at least one first/electric seismic source may be provided in a region covered by, or behind, the seismic receiver array, but not, for example, actually on a streamer or the seismic receiver array. For example, the at least one first/electric seismic source could be connected to the seismic receiver array (e.g. a streamer of the seismic receiver array) via a connecting cable. Alternatively, the at least one first/electric seismic source could be connected to the vessel via a further cable, e.g. not via the seismic receiver array.
In an example, a float could be provided which is connected, e.g. via a cable, to the streamer. The at least one first/electric source, could then be connected to the float, e.g. via a further cable, at a location below the float, for example.
In another example, two connections (e.g. cables) could be provided, e.g. from adjacent streamers, the two connections both being connected to the at least one first/electric source. This could allow the at least one first/electric source to be towed between two streamers, for example.
The at least one first/electric seismic source may be located at the same vertical position as the seismic receiver array, a higher vertical position than the seismic receiver array, or a lower vertical position than the seismic receiver array. Locating the at least one first/electric seismic source at, e.g. various, vertical positions in this way may have benefits concerning the frequency content to be targeted or for removing undesired ghost notches from frequency recordings, for example.
The system may comprise a plurality of first/electric seismic sources, the plurality of first/electric seismic sources being located in one or any number of the various locations described above. Preferably, a plurality of first/electric seismic sources are provided, e.g. more than 5, 10, 15 or 20 first/electric seismic sources may be
- 13provided. If more first/electric seismic sources are provided, this can improve the data received.
The system may further comprise a processing system. The processing system being arranged, for example, to perform a method comprising processing geophysical data detected by the seismic receiver array. The processing system could, for example, be provided on a towing vessel or it could be provided, for example, on a shore based location, or on another vessel, and be in communication with, e.g., the seismic receiver array.
Processing geophysical data detected by the seismic receiver array preferably comprises separating data received from multiple (e.g. first/electric and/or second) seismic sources. This could be performed, for example, by performing a frequencywavenumber (“f-k”) analysis.
Separating data from multiple seismic sources may be based on: opposing moveouts (e.g. as described in Craig J. Beasley, Ronald E. Chambers, and Zerong Jiang (1998) A new look at simultaneous sources. SEG Technical Program Expanded Abstracts 1998: pp. 133-135); a separational effect during deconvolution; and/or time shifts.
As described above, the multiple seismic sources may comprise vibrational and/or impulsive seismic sources.
The at least one first/electric seismic source is preferably located at least 2 km horizontally away from a towing vessel e.g. at the end of the seismic receiver array.
The system may further comprise means for transferring or supplying electricity (electrical power) to the at least one first/electric seismic source. For example, cables for transferring electricity to the at least one first/electric seismic source may be provided, e.g. from a generator or other electricity supply source, e.g. on board the vessel, to the at least one first seismic source. Alternatively or additionally, electricity may be provided by a float/vessel with a power generator located, for example, near the end of the seismic receiver array. Such a float/vessel with a
- 14power generator may be towed by the main vessel or by its own propulsion, for example.
According to a further aspect, there is provided a method of generating seismic data comprising:
providing at least one electric seismic source and a seismic receiver array; causing the at least one electric seismic source to emit seismic waves; and detecting the seismic waves with the seismic receiver array;
wherein the at least one electric seismic source is located within an end region of, or a distance behind, the seismic receiver array.
According to a further aspect, there is provided a method of generating seismic data comprising:
providing at least one first seismic source, at least one second seismic source and a seismic receiver array;
causing the at least one first seismic source and the at least one second seismic source to emit seismic waves; and detecting the seismic waves with the seismic receiver array;
wherein the at least one first seismic source is a different kind of seismic source to the at least one second seismic source and is located within an end region of, or a distance behind, the seismic receiver array.
Either method may further comprise processing geophysical data detected by the seismic receiver array.
Either method may comprise performing a frequency sweep, e.g. a sweep of frequencies emitted by the at least one electric source. For example, a frequency sweep could cover any range from as low as 1 Hz and up to several thousands of Hz.
Processing geophysical data detected by the seismic receiver array may comprise separating data received from multiple seismic sources.
- 15Separating data from multiple seismic sources may be based on: opposing moveouts; a separational effect during deconvolution; and/or time shifts, e.g. as described above.
Such methods may be performed using a system such as described above.
Preferred embodiments of the invention are now described, by way of example only, with reference to the accompanying drawings, in which:
Fig. 1 (a) is a schematic drawing showing a side view of a system according to the present invention; and
Fig. 1 (b) is a schematic drawing showing a top view of a system according to the present invention.
As shown in Figs. 1(a) and (b), a system 20 for obtaining seismic data comprises a vessel 1 to which is connected a seismic source array 2 of seismic sources 2a. This seismic source array 2 is usually located a few hundred metres from the vessel 1.
A seismic receiver array 11 comprising a number of streamers 3 is also connected to the vessel via cables 5. Each streamer 3 comprises a number of seismic receivers (not shown) for detecting seismic waves.
In a region 10 (indicated by a dashed line), electric seismic sources 7 are provided in a number of locations. Fig. 1 shows possible locations at which the electric seismic sources 7 may be located. Electric seismic sources 7 may be located at one, some or all of these locations. As shown in Fig. 1, two electric seismic sources 7 are carried by the streamers 3 themselves. Two electric seismic sources 7 are provided between the streamers 3 and are connected to the streamers 3 via cables 9.One electric seismic source 7 is provided on a tail buoy 8. Two of the electric seismic sources 7 are located at positions lower than the streamers 3. Two of the electric seismic sources 7 are located at positions at the same depth as the streamers 3. One of electric seismic sources 7 is located at a position higher than the streamers 3. In alternative embodiments, the electric seismic sources 7 are
- 16located at different vertical positions to those shown in Fig. 1, e.g. at different combinations of horizontal and vertical positions.
The sources 2a, which are those closest to the vessel 1, might be of any type. For example, they could be electric seismic sources like the electric seismic sources 7, or they could be air gun seismic sources. Other kinds of sources are also possible.
The towing vessel 1 is a boat capable of towing the seismic receiver array 11, the seismic source array 2 and the electric seismic sources 7. The vessel 1 holds a controller and a processor for obtaining and possibly processing the seismic data (corresponding to seismic waves) detected by the seismic receiver array 11. For example, the processor can perform data quality checks to check the quality of the data obtained.
Although in Fig. 1 only three streamers 3 are shown, this is for illustrative purposes and typically the seismic receiver array 11 will contain 1-16 streamers 3. However, in other embodiments, the seismic receiver array 11 may contain more streamers 3 than that. The streamers 3 are usually equally spaced apart in the array 11. There is around 50 - 75 m between adjacent streamers 3 in the array 11. The streamers 3 are (or the seismic receiver array 11 is) usually several kilometres long, e.g. around 15 km.
Each streamer 3 holds thousands of receivers (not shown). The receivers are arranged in groups along each streamer 3. The groups of receivers are usually spaced around 6.25 or12.5 m apart along each streamer 3.
The receivers comprise hydrophones and/or accelerometers, for example, for detecting the seismic waves, e.g. in three spatial dimension.
The seismic receiver array 11 may be towed, by the vessel 1, beneath the surface of the water. The seismic receiver array 11 is towed at a depth E below the water surface. The depth E is typically between 6 and 15 m.
The electric seismic sources 7 are electrically driven seismic sources, like marine vibrators, boomers or sparkers.
- 17Electric cables (not shown) are provided in the system 20 to transfer electricity from an electrical power source on the vessel, e.g. a generator, to the electric seismic sources 7 via (or along) the streamers 3.
The electric seismic sources 7 are located within a region 10 which consists of an end region of the seismic receiver array 11 and a distance D behind it.
There is an offset A of a few 100 m between the seismic source array 2 and the seismic receiver array 11. The region 10, in which the electric seismic sources 7 are located, is a distance B from a front end of the seismic receiver array 11. In one embodiment, B is 2 km.
The length C of the region 10 depends on the geologically optimal setting. For example, and as described above, the deeper the target, the longer the receiver array (or streamer(s)) required. This means that if the target is deep the end region is located further from the vessel and/or a smaller fraction of the seismic receiver array is covered by the end region.
In addition, the size of the end region may depend more on the shallow part of the geology, e.g. when the seabed is rugose, for example. In such cases, the waves get scattered more, thereby creating multiple scattered waves. In order to remove such “multiples” (multiple scattered waves), a split-spread recording (i.e. recording waves in two directions, in front and behind the source, would be beneficial.
The distance D is the horizontal distance of the tail buoy 8 from the end of the seismic receiver array 11.
The region 10 should protrude the end of the seismic receiver array 11 only marginally, to allow for zero-offset data collection. Therefore, the distance D should be far less than A and it is usually below or around 100 m.
As well as carrying an electric seismic source 7, the tail buoy 8 also carries means for detecting the position of the end of the streamer 3 to which it is attached. Each streamer 3 has its own tail buoy 8 although only one tail buoy 8 is shown in Fig. 1,
- 18for illustrative purposes. The streamers 3 are slightly steered, by their respective tail buoys 8 and also possibly by fins (not shown) provided along the streamers 3, both to keep the streamers 3 in line with the trajectory of the vessel 1 and to keep the streamers 3 the same distance(s) from each other. This is necessary due to water currents which are not ‘in line’ with the survey design, which can cause feathering of the streamers 3 behind the vessel 1. The tail buoys 8 can be used for depth control of the streamers 3, as well as for steering of the ends of the streamers
3. The tail buoys 8 can also be used for data recording and data transmission.
Diverters or vanes 4 are provided on the cables 5 connecting the seismic receiver array 11 to the vessel 1. The diverters or vanes 4 are wings which span up the spread of the streamers 3 behind the vessel 1. In Fig. 1, the vessel 1 moves to the left and typically it has between 1 and 16 streamers 3 being towed along behind the vessel 1. Each streamer 3 is up to 15km (most often 8km) long. These streamers 3 need to be spread out behind the vessel 1 with, usually, a constant distance between them. In order to drag them out and away from the travel path of the vessel 1, the diverters or vanes 4 are provided to push the streamers 3 out by several hundred metres on each side of the vessel 1.
In use, seismic waves are emitted simultaneously from the seismic source array 2 and the electric seismic sources 7. These seismic waves travel downwards and are then (partially) reflected back upwards from subsurface impedance contrasts. The reflected seismic waves are then detected by the receivers in the receiver array 11.
The electric seismic sources 7 may operate at a higher centre frequency than the sources 2a of the seismic source array 2. As an example, a source 2a would usually operate at around a centre frequency of 25 Hz, whereas the electric seismic sources 7 would mostly emit frequencies greater than 100 Hz.
Utilizing marine vibrators as the electric sources 7, frequency sweeps may be performed. For example, a frequency sweep could cover any range from as low as 1 Hz and up to several thousands of Hz.
The sources 2a and the electric seismic sources 7 may be independently operated or they may be operated dependently in the frequency or time domain.
- 19In some embodiments, the electric seismic sources 7 and the seismic sources 2a operate at overlapping frequencies. Seismic sources are usually able to emit a certain frequency band of seismic waves. It is envisioned that the sources 2a emit a lower frequency band than the sources 7. It is beneficial but not necessary if the bandwidths of the sources overlap. In an embodiment, the sources 2a operate over a frequency band of 1-100 Hz, and the electric sources 7 operate over a frequency band from above 100 Hz up to a few thousand Hz. Operating over both low and high frequency bands in this way can allow the scanning of deep and shallow regions at the same time.
After geophysical data has been obtained in this way, it is processed. Processing geophysical data detected by the seismic receiver array comprises separating data received from the multiple seismic sources 2a, 7.
Separating the data from the multiple seismic sources 2a, 7 can be based on various methods, including opposing moveouts (e.g. as described in Craig J. Beasley, Ronald E. Chambers, and Zerong Jiang (1998) A new look at simultaneous sources. SEG Technical Program Expanded Abstracts 1998: pp. 133135), separation during deconvolution, and/or time shifts. Other methods may alternatively be used.
Claims (43)
1. A system for obtaining seismic data, the system comprising:
at least one seismic receiver array; and at least one electric seismic source;
wherein the at least one electric seismic source is arranged to emit seismic waves that can be detected by the seismic receiver array; and the at least one electric seismic source is located within an end region of, or a distance behind, the seismic receiver array.
2. A system as claimed in claim 1, further comprising a towing vessel for towing the at least one seismic receiver array.
3. A system as claimed in claim 2, wherein the towing vessel is a common towing vessel to which the at least one electric seismic source and the seismic receiver array are directly or indirectly connected.
4. A system as claimed in claim 1, 2 or 3, further comprising at least one second seismic source, and wherein the at least one second seismic source is arranged to emit seismic waves that can be detected by the seismic receiver array, and the at least one electric seismic source and the at least one second seismic source are located at different horizontal positions.
5. A system as claimed in claim 4, wherein the at least one second seismic source is located closer to a towing vessel than the at least one electric seismic source and/or the seismic receiver array.
6. A system as claimed in claim 4 or 5, wherein the at least one second seismic source comprises an impulsive seismic source and/or a vibrational seismic source.
7. A system as claimed in claim 6, wherein the at least one second seismic source comprises an air gun source.
8. A system as claimed in any of claims 4 to 7, comprising a common towing vessel to which the at least one electric seismic source, the at least one second seismic source, and the seismic receiver array are directly or indirectly connected.
9. A system as claimed in any of claims 4 to 8, wherein the at least one electric seismic source and the at least one second seismic source are arranged to operate at different frequencies.
10. A system as claimed in claim 9, wherein the at least one electric seismic source is arranged to operate at a higher frequency than the at least one second seismic source.
11. A system as claimed in any of claims 4 to 8, wherein the at least one electric seismic source and the at least one second seismic source are arranged to operate at overlapping frequencies.
12. A system as claimed in any of claims 4 to 11, wherein the at least one electric seismic source and the at least one second seismic source are arranged to simultaneously emit seismic waves that can be detected by the seismic receiver array.
13. A system for obtaining seismic data, the system comprising:
at least one first seismic source;
at least one second seismic source; and a seismic receiver array;
wherein the at least one first seismic source and the at least one second seismic source are arranged to emit seismic waves that can be detected by the seismic receiver array; and the at least one first seismic source is a different kind of seismic source to the at least one second seismic source and is located within an end region of, or a distance behind, the seismic receiver array.
14. A system as claimed in claim 13, wherein the at least one first seismic source comprises an electric seismic source.
15. A system as claimed in claim 13 or 14, wherein the at least one second seismic source comprises an impulsive and/or a vibrational seismic source.
16. A system as claimed in claim 15, wherein the at least one second seismic source comprises an air gun source.
17. A system as claimed in any of claims 13 to 16, wherein the at least one first seismic source and the at least one second seismic source are arranged to operate at different frequencies.
18. A system as claimed in claim 17, wherein the at least one first seismic source is arranged to operate at a higher frequency than the at least one second seismic source.
19. A system as claimed in any of claims 13 to 16, wherein the at least one first seismic source and the at least one second seismic source are arranged to operate at overlapping frequencies.
20. A system as claimed in any of claims 13 to 19, wherein the at least one first seismic source and the at least one second seismic source are arranged to simultaneously emit seismic waves that can be detected by the seismic receiver array.
21. A system as claimed in any of claims 13 to 20, comprising a towing vessel for towing the seismic receiver array.
22. A system as claimed in claim 21, wherein the towing vessel is a common towing vessel to which the at least one first seismic source, the at least one second seismic source and the seismic receiver array are directly or indirectly connected.
23. A system as claimed in any preceding claim, wherein the end region of the seismic receiver array is at most a rearmost third of the seismic receiver array.
24. A system as claimed in any preceding claim, wherein the seismic receiver array comprises an array of one or more streamers, each streamer comprising a plurality of seismic receivers, and the at least one first or
- 23electric seismic source is located at the same horizontal position as a rearmost seismic receiver in the seismic receiver array.
25. A system as claimed in any of claims 1 to 23, wherein the seismic receiver array comprises an array of one or more streamers, each streamer comprising a plurality of seismic receivers, and the at least one first or electric seismic source is located at a horizontal position between a rearmost seismic receiver in the seismic receiver array and a towing vessel.
26. A system as claimed in any of claims 1 to 23, wherein the at least one first or electric seismic source is located up to 100 m behind the seismic receiver array.
27. A system as claimed in claim 26, wherein the at least one first or electric seismic source is provided on a tail buoy.
28. A system as claimed in any preceding claim, wherein the at least one first or electric seismic source is located a horizontal distance away from a towing vessel that is equal to or greater than a distance between the towing vessel and a receiver in the seismic receiver array.
29. A system as claimed in any preceding claim, wherein the at least one first or electric seismic source is provided on a streamer of the seismic receiver array.
30. A system as claimed in any preceding claim, wherein the at least one first or electric seismic source is located at the same vertical position as the seismic receiver array, a higher vertical position than the seismic receiver array, or a lower vertical position than the seismic receiver array.
31. A system as claimed in any preceding claim, further comprising a processing system, the processing system being arranged to perform a method comprising processing geophysical data detected by the seismic receiver array.
32. A system as claimed in claim 31, wherein processing geophysical data detected by the seismic receiver array comprises separating data received from multiple seismic sources.
33. A system as claimed in claim 32, wherein separating data from multiple seismic sources is based on:
opposing moveouts; and/or a separational effect during deconvolution; and/or time shifts.
34. A system as claimed in claim 32 or 33, wherein the multiple seismic sources comprise vibrational and/or impulsive seismic sources.
35. A system as claimed in any preceding claim, wherein the receiver array is at least 2 km long.
36. A system as claimed in any preceding claim, wherein the at least one first or electric seismic source is located at least 2 km horizontally from a towing vessel.
37. A system as claimed in any preceding claim, further comprising means for supplying electricity to the at least one first or electric seismic source.
38. A method of generating seismic data comprising:
providing a seismic receiver array and at least one electric seismic source;
causing the at least one electric seismic source to emit seismic waves; and detecting the seismic waves with the seismic receiver array; wherein the at least one electric seismic source is located within an end region of, or a distance behind, the seismic receiver array.
39. A method of generating seismic data comprising:
providing at least one first seismic source, at least one second seismic source and a seismic receiver array;
- 25causing the at least one first seismic source and the at least one second seismic source to emit seismic waves; and detecting the seismic waves with the seismic receiver array;
wherein the at least one first seismic source is a different kind of seismic source to the at least one second seismic source and is located within an end region of, or a distance behind, the seismic receiver array.
40. A method as claimed in claim 38 or 39, further comprising processing geophysical data detected by the seismic receiver array.
41. A system as claimed in claim 40, wherein processing geophysical data detected by the seismic receiver array comprises separating data received from multiple seismic sources.
42. A method as claimed in claim 41, wherein separating data from multiple seismic sources is based on:
opposing moveouts; and/or a separational effect during deconvolution; and/or time shifts.
43. A method as claimed in any of claims 38 to 42 performed using a system as claimed in any of claims 1 to 37.
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| GB1814032.7A GB2576736A (en) | 2018-08-29 | 2018-08-29 | Seismic data acquisition system |
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| GB2576736A true GB2576736A (en) | 2020-03-04 |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| NO20220985A1 (en) * | 2022-09-15 | 2024-03-18 | Neomare As | Negative Offset Interleaved High Resolution System for Seismic Surveys |
Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2014152125A1 (en) * | 2013-03-15 | 2014-09-25 | Westerngeco Llc | Methods and systems for marine survey acquisition |
| WO2016062710A1 (en) * | 2014-10-20 | 2016-04-28 | Pgs Geophysical As | Methods and systems to separate seismic data associated with impulsive and non-impulsive sources |
| WO2016105576A1 (en) * | 2014-12-23 | 2016-06-30 | Ion Geophysical Corporation | Real-time infill in marine seismic surveys using an independent seimic source |
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2018
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Patent Citations (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2014152125A1 (en) * | 2013-03-15 | 2014-09-25 | Westerngeco Llc | Methods and systems for marine survey acquisition |
| WO2016062710A1 (en) * | 2014-10-20 | 2016-04-28 | Pgs Geophysical As | Methods and systems to separate seismic data associated with impulsive and non-impulsive sources |
| WO2016105576A1 (en) * | 2014-12-23 | 2016-06-30 | Ion Geophysical Corporation | Real-time infill in marine seismic surveys using an independent seimic source |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| NO20220985A1 (en) * | 2022-09-15 | 2024-03-18 | Neomare As | Negative Offset Interleaved High Resolution System for Seismic Surveys |
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