Patent Application
20090168600
The invention generally relates to separating seismic signals produced by interfering seismic sources.
Seismic exploration involves surveying subterranean geological formations for hydrocarbon deposits. A survey typically involves deploying seismic source(s) and seismic sensors at predetermined locations. The sources generate seismic waves, which propagate into the geological formations creating pressure changes and vibrations along their way. Changes in elastic properties of the geological formation scatter the seismic waves, changing their direction of propagation and other properties. Part of the energy emitted by the sources reaches the seismic sensors. Some seismic sensors are sensitive to pressure changes (hydrophones), others to particle motion (e.g., geophones), and industrial surveys may deploy only one type of sensors or both. In response to the detected seismic events, the sensors generate electrical signals to produce seismic data. Analysis of the seismic data can then indicate the presence or absence of probable locations of hydrocarbon deposits.
Some surveys are known as “marine” surveys because they are conducted in marine environments. However, “marine” surveys may be conducted not only in saltwater environments, but also in fresh and brackish waters. In one type of marine survey, called a “towed-array” survey, an array of seismic sensor-containing streamers and sources is towed behind a survey vessel.
In an embodiment of the invention, a technique includes obtaining seismic data indicative of measurements acquired by seismic sensors of a composite seismic signal produced by the firings of multiple seismic sources. The technique includes associating models that describe geology associated with the composite seismic signal with linear operators and characterizing the seismic data as a function of the models and the associated linear operators. The technique includes simultaneously determining the models based on the function and based on the determined models, generating datasets. Each dataset is indicative of a component of the composite seismic signal and is attributable to a different one of the seismic sources.
In another embodiment of the invention, a system includes an interface and a processor. The interface receives seismic data indicative of measurements acquired by seismic sensors of a composite seismic signal produced by the firings of multiple seismic sources. The processor processes the seismic data to associate linear operators with models that describe geology associated with the composite seismic signal; characterize the seismic data as a function of the models and the associated linear operators; simultaneously determine the models based on the function; and based on the determined models, generate datasets. Each dataset is indicative of a component of the composite seismic signal and is attributable to a different one of the seismic sources.
In yet another embodiment of the invention, an article includes a computer accessible storage medium containing instructions that when executed by a processor-based system cause the processor-based system to receive seismic data indicative of measurements acquired by seismic sensors of a composite seismic signal produced by the firings of multiple seismic sources. The instructions when executed cause the processor-based system to process the seismic data to associate linear operators with models that describe geology associated with the composite seismic signal; characterize the seismic data as a function of the models and the associated linear operators; simultaneously determine the models based on the function; and based on the determined models, generate datasets. Each dataset is indicative of a component of the composite seismic signal and is attributable to a different one of the seismic sources.
Advantages and other features of the invention will become apparent from the following drawing, description and claims.
The seismic streamers 30 may be several thousand meters long and may contain various support cables (not shown), as well as wiring and/or circuitry (not shown) that may be used to support communication along the streamers 30. In general, each streamer 30 includes a primary cable into which is mounted seismic sensors that record seismic signals. The streamers 30 contain seismic sensors 58, which may be, depending on the particular embodiment of the invention, hydrophones (as one non-limiting example) to acquire pressure data or multi-component sensors. For embodiments of the invention in which the sensors 58 are multi-component sensors (as another non-limiting example), each sensor is capable of detecting a pressure wavefield and at least one component of a particle motion that is associated with acoustic signals that are proximate to the sensor. Examples of particle motions include one or more components of a particle displacement, one or more components (inline (x), crossline (y) and vertical (z) components (see axes 59, for example)) of a particle velocity and one or more components of a particle acceleration.
Depending on the particular embodiment of the invention, the multi-component seismic sensor may include one or more hydrophones, geophones, particle displacement sensors, particle velocity sensors, accelerometers, pressure gradient sensors, or combinations thereof.
For example, in accordance with some embodiments of the invention, a particular multi-component seismic sensor may include a hydrophone for measuring pressure and three orthogonally-aligned accelerometers to measure three corresponding orthogonal components of particle velocity and/or acceleration near the sensor. It is noted that the multi-component seismic sensor may be implemented as a single device (as depicted in
The marine seismic data acquisition system 10 includes one or more seismic sources 40 (two exemplary seismic sources 40 being depicted in
As the seismic streamers 30 are towed behind the survey vessel 20, acoustic signals 42 (an exemplary acoustic signal 42 being depicted in
The incident acoustic signals 42 that are acquired by the sources 40 produce corresponding reflected acoustic signals, or pressure waves 60, which are sensed by the seismic sensors 58. It is noted that the pressure waves that are received and sensed by the seismic sensors 58 include “up going” pressure waves that propagate to the sensors 58 without reflection, as well as “down going” pressure waves that are produced by reflections of the pressure waves 60 from an air-water boundary 31.
The seismic sensors 58 generate signals (digital signals, for example), called “traces,” which indicate the acquired measurements of the pressure wavefield and particle motion. The traces are recorded and may be at least partially processed by a signal processing unit 23 that is deployed on the survey vessel 20, in accordance with some embodiments of the invention. For example, a particular seismic sensor 58 may provide a trace, which corresponds to a measure of a pressure wavefield by its hydrophone 55; and the sensor 58 may provide (depending on the particular embodiment of the invention) one or more traces that correspond to one or more components of particle motion.
The goal of the seismic acquisition is to build up an image of a survey area for purposes of identifying subterranean geological formations, such as the exemplary geological formation 65. Subsequent analysis of the representation may reveal probable locations of hydrocarbon deposits in subterranean geological formations. Depending on the particular embodiment of the invention, portions of the analysis of the representation may be performed on the seismic survey vessel 20, such as by the signal processing unit 23. In accordance with other embodiments of the invention, the representation may be processed by a seismic data processing system (such as an exemplary seismic data processing system 320 that is depicted in
A particular seismic source 40 may be formed from an array of seismic source elements (such as air guns, for example) that may be arranged in strings (gun strings, for example) of the array. Alternatively, a particular seismic source 40 may be formed from one or a predetermined number of air guns of an array, may be formed from multiple arrays, etc. Regardless of the particular composition of the seismic sources, the sources may be fired in a particular time sequence during the survey.
As described in more detail below, the seismic sources 40 may be fired in a sequence such that multiple seismic sources 40 may be fired simultaneously or near simultaneously in a short interval of time so that a composite energy signal that is sensed by the seismic sensors 58 contain a significant amount of energy from more than one seismic source 40. In other words, the seismic sources interfere with each other such that the composite energy signal is not easily separable into signals that are attributed to the specific sources. The data this is acquired by the seismic sensors 58 is separated, as described below, into datasets that are each associated with one of the seismic sources 40 so that each dataset indicates the component of the composite seismic energy signal that is attributable to the associated seismic source 40.
In a conventional towed marine survey, a delay is introduced between the firing of one seismic source and the firing of the next seismic source, and the delay is sufficient to permit the energy that is created by the firing of one seismic source to decay to an acceptable level before the energy that is associated with the next seismic source firing arrives. The use of such delays, however, imposes constraints on the rate at which the seismic data may be acquired. For a towed marine survey, these delays also imply a minimum inline shot interval because the minimum speed of the survey vessel is limited.
Thus, the use of simultaneously-fired or near-simultaneously-fired seismic sources in which signals from the sources interfere for at least part of each record, has benefits in terms of acquisition efficiency and inline source sampling. For this technique to be useful, however, the acquired seismic data must be separated into the datasets that are each uniquely associated with one of the seismic sources.
One conventional technique for enabling the separation for interfering seismic sources makes use of relatively small delays (random delays, for example) between the firings of seismic sources (i.e., involves the use of source dithering). The resulting seismic traces are collected into a domain that includes many firings of each source. The traces are aligned such that time zero corresponds to the firing time for a specific source so that the signal acquired due to the specific seismic source appears coherent while the signal acquired due to the other seismic sources appear incoherent. The acquired signals are separated based on coherency.
It has been observed that the apparently incoherent signal may not be mathematically incoherent, because the time delays between seismic source firings that make the signal appear to be incoherent are known. Therefore, in accordance with embodiments of the invention described herein, all of the energy that is acquired due to interfering seismic source firings is treated as a single composite energy signal; and linear operator transforms are used for purposes of decomposing the composite energy signal into signals that are each uniquely associated with a particular seismic source.
More specifically,
As a more specific example, assume that the seismic data vector d is acquired due to the near simultaneous firing of two seismic sources called “S1” and “S2” For this example, the seismic sources S1 and S2 are fired pursuant to a timing sequence, which may be based on a predetermined timing pattern or may be based on random or pseudo-random times. Regardless of the particular timing scheme, it is assumed for this example that the seismic source S1 is fired before the seismic source S2 for all traces, and it is further assumed that the zero times of the traces correspond to the firing times for S1. Thus, the zero times of the traces are in “S1 time.” The offsets, or vectors, to the seismic sources S1 and S2 are called “x1” and “x2,” respectively. The timing delays, denoted by “t” for the seismic source S2 are known for each trace.
It is assumed for this example that the collection of traces are such that the values of t are random. In practice, this is the case for a CMP, receiver or common offset gather. For purposes of simplifying this discussion, it is assumed that the trace in each gather may be located with respect to the seismic source S1 and seismic source S2 using scalar quantities called “x1i” and “x2i,” respectively. In this notation, the subscript “i” denotes the trace number in the gather. As a more specific example, for a CMP gather, “x1i” may be the scalar offset to the seismic source S1, and these quantities are referred to as offsets below. Similarly, “ti” denotes the timing delay for the ith trace.
The recorded energy for the seismic source S1 may be modeled by applying a linear operator called “L1” (which represents the physics of the seismic source S1, the wave propagation associated with the source S1 and the survey geometry associated with the seismic source S1) to an unknown model called “m1,” which describes the geology that affects the energy that propagates from the seismic source S1. The model m1 contains one element for each parameter in the model space. Typically the model space may be parameterized by slowness or its square, corresponding to linear or hyperbolic/parabolic Radon transforms, respectively. The linear operator L1 is a function of the offsets to the source S1, the parameters that characterize the model space, and time or frequency. A seismic data vector d1 contains one element for each trace (at each time or frequency) and is the component of the seismic data d, which is associated with the seismic source S1. In other words, the seismic data vector d1 represents the dataset attributable to the seismic source S1. The seismic data vector d1 may be described as follows:
d1=L1m1. Eq. 1
The energy that is associated with the seismic source S2 appears incoherent in the seismic data vector d. However, the energy is related to a coherent dataset in which the firing times for the seismic source S2 are at time zero (i.e., seismic source S2 time) by the application of time shifts ti to the traces. A diagonal linear operator called “D2” may be used for purposes of describing these time shifts, such that the component of the seismic data vector d, which is associated with the seismic source S2 and which is called “d2” may be described as follows:
d2=D2L2m2. Eq. 2
In Eq. 2, a linear operator called “L2” represents the physics of the seismic source S2, the wave propagation associated with the seismic source S2 and the survey geometry associated with the seismic source S2. Also in Eq. 2, a model called “m2” describes the geology that affects the energy that propagates from the seismic source S2.
The composite seismic energy signal that is recorded by the seismic sensors is attributable to both seismic sources S1 and S2. Thus, the seismic data vector d (i.e., the recorded data) is a combination of the seismic data vectors d1 and d2, as described below:
d=d
1
+d
2. Eq. 3
Due to the relationships in Eqs. 1, 2 and 3, the seismic data vector d may be represented as the following linear system:
Thus, Eq. 4 may be solved (i.e., jointly inverted) for the model vector m (i.e., (m1; m2)) using standard techniques, such as the least squares algorithm; and after the model vector m is known, Eqs. 1 and 2 may be applied with the models m1 and m2 for purposes of separating the seismic data vector d into the seismic data vectors d1 and d2, i.e., into the datasets that indicate the measurements attributable to each seismic source.
Thus, referring to
Eq. 4 may be inverted in the frequency (ω) domain. In that case, (D2)jk=exp(−iωtj)δjk and (Ls)jk=exp(−iωtsjk), where tsjk is the time shift associated with offset xsj and the parameter for the kth trace in the model space associated with Ss. For a linear Radon transform parameterized by slowness, psk, tsjk=xsjpsk. For a parabolic Radon transform parameterized by curvature, qsk, tsjk=(xsj)2 qsk.
The success of the source separation technique described above depends on the ability of the transform to separate the energy associated with the two sources. Unlike most applications of Radon transforms, success does not depend on the ability to focus energy at the correct model parameter within m1 or m2. When random or pseudo time delays are used between source firings, the basis functions for the two model domains (t1jk and tj+t2jk) are very different, and this enables extremely effective separation of the sources.
Details of the parameterization of the model domain are not important, provided it is possible to model the recorded data using that domain. For example, for a linear Radon transform, the slowness range must cover the range observed in the data, and the sampling must be adequate to avoid aliasing. The use of high-resolution transforms to improve focusing is not expected to be necessary in general. However, high-resolution transforms can be used if required, for instance because of poor sampling in offset created by offset windowing or acquisition geometry issues.
The separation process is directed at recovering the S1 input signals 206 (
Although the examples that are described above use source dithering, or non-simultaneous firing of the seismic sources, the seismic sources may be fired simultaneously, in accordance with other embodiments of the invention. In this regard, if the linear operators are made more unique predictors of the seismic data, then the requirement for the dithering of the source firings becomes less important. In other words, source dithering may be less important if there is less overlap of the basis functions for the seismic source locations.
As a more specific example, the techniques that are described herein may be combined with other techniques for source separation for purposes of causing the linear operators to be more unique predictors of the seismic data. For example, some parts of the wavefields (such as the direct arrivals, for example) may be estimated deterministically and subtracted as a pre-processing step. In addition, methods such as dip-filtering may be used in combination with the techniques that are described herein.
As a more specific example, the energy that is recorded from the seismic source S1 may be viewed as a combination of energy produced by direct arrivals and energy that is produced by reflections. As such, the seismic data vector d1 may be effectively represented as follows:
d
1
=d
1l
+d
1h
=L
1
m
l
+H
1
m
h, Eq. 5
where “d1l” represents the seismic data attributable to direct arrivals from the seismic source S1; “d1h” represents the seismic data attributable to reflections produced due to the seismic source S1; “L1” represents a linear Radon operator associated with the direct arrivals from the seismic source S1; “ml” represents a model describing the geology that affects the direct arrivals; “H1” represents a hyperbolic Radon transform operator associated with the reflections produced due to energy from the seismic source S1; and “mh” represents a model that describes the geology that affects the reflections produced by the seismic sources.
Similarly, the seismic data vector, which is d2 attributable to energy that is recorded from the seismic source S2, may be described as follows:
d
2
=d
2l
+d
2h
=L
2
m
l
+H
2
m
h, Eq. 6
where “d2l” represents the component of the seismic data vector d2 attributable to direct arrivals; “d2h” represents the seismic data d2 attributable to reflections; “L2” represents a linear Radon transform operator associated with the direct arrivals from the seismic source S2; and “H2” represents the hyperbolic Radon transform associated with the reflections produced due to the energy from the seismic source S2.
Due to the relationships that are set forth in Eqs. 5 and 6, the seismic data vector d, which represents the actual data recorded by the seismic sensors, may be represented as follows:
d=d
1l
+d
1h
+d
2l
+d
2h, Eq. 7
Thus, the seismic data vector d may be represented by the following function, which may be inverted for the models m1 and mh:
Eqs. 5 and 6 may then be applied to derive the data vectors d1 and d2.
Although linear and hyperbolic Radon transforms have been described above, it is noted that other linear operators may be used, in accordance with other embodiments of the invention. For example, parabolic or migration operators may be used in accordance with other embodiments of the invention, as just a few other non-limiting examples.
Thus, referring to
Although the example that is set forth herein is for two seismic sources S1 and S2, the techniques may be extended to more than two sources.
Referring to
The processor 350 may be coupled to a communication interface 360 for purposes of receiving seismic data that corresponds to pressure and/or particle motion measurements from the seismic sensors 58. Thus, in accordance with embodiments of the invention described herein, the processor 350, when executing instructions stored in a memory of the seismic data processing system 320, may receive multi-component data and/or pressure sensor data that are acquired by seismic sensors while in tow. It is noted that, depending on the particular embodiment of the invention, the data may be data that are directly received from the sensors as the data are being acquired (for the case in which the processor 350 is part of the survey system, such as part of the vessel or streamer) or may be sensor data that were previously acquired by seismic sensors while in tow and stored and communicated to the processor 350, which may be in a land-based facility, for example.
As examples, the interface 360 may be a USB serial bus interface, a network interface, a removable media (such as a flash card, CD-ROM, etc.) interface or a magnetic storage interface (IDE or SCSI interfaces, as examples). Thus, the interface 360 may take on numerous forms, depending on the particular embodiment of the invention.
In accordance with some embodiments of the invention, the interface 360 may be coupled to a memory 340 of the seismic data processing system 320 and may store, for example, various input and/or output datasets involved with processing the seismic data in connection with the techniques 110, 150 and/or 200, as indicated by reference numeral 348. The memory 340 may store program instructions 344, which when executed by the processor 350, may cause the processor 350 to perform various tasks of or more of the techniques that are disclosed herein, such as the techniques 110, 150 and/or 200 and display results obtained via the technique(s) on a display (not shown in
Other embodiments are within the scope of the appended claims. For example, in accordance with other embodiments of the invention, “amplitude dithering” may be used to aid separation. Although control of the amplitude of a towed seismic source may, in general, be challenging, in accordance with embodiments of the invention, the seismic sources may be controlled by deliberately not firing selected seismic sources according to some random or regular pattern. As another example, the amplitude dithering may includes selectively firing some source elements (such as guns, for example) of a particular source while not firing other elements of the source to vary the amplitude.
Information regarding the amplitude dithering may be incorporated into the above-described linear operators.
In practice, occasionally one of the seismic sources may fail to fire. When this occurs, the information regarding the failed seismic source may be included into the associated linear operator by forcing the operator to have zero output for the corresponding trace. These misfires, in turn, may make the different seismic sources easier to separate.
Other embodiments are within the scope of the appended claims. For example, although a towed marine-based seismic acquisition system has been described above, the techniques and systems described herein for separating seismic signals produced by interfering seismic sources may likewise be applied to other types of seismic acquisition systems. As non-limiting examples, the techniques and system that are described herein may be applied to seabed, borehole and land-based seismic acquisition systems. Thus, the seismic sensors and sources may be stationary or may be towed, depending on the particular embodiment of the invention. As other examples of other embodiments of the invention, the seismic sensors may be multi-component sensors that acquire measurements of particle motion and pressure, or alternatively the seismic sensors may be hydrophones only, which acquire pressure measurements. Thus, many variations are contemplated and are within the scope of the appended claims.
While the present invention has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention.
