Abstract:
A method includes receiving a seismic dataset from a survey, wherein the seismic dataset represents a portion of a subsurface geological formation and includes primary and multiple data. The method further includes the steps of conditioning the seismic dataset and estimating a model of the multiple data in the conditioned seismic dataset based on a user-defined parameter to derive a primary data set. Further, the method includes the steps of computing a velocity model from the primary data set using the user-defined parameter and updating the estimated multiple model based at least on a modification of the user-defined parameter. In addition, the method includes the steps of recomputing the primary data and the velocity model based on the modified user-defined parameter and generating an image of the primary data.

Description:
BACKGROUND 
       [0001]    Seismic surveying is a method for determining the structure of subterranean formations in the earth. Seismic surveying can utilize seismic energy sources that generate seismic waves, and seismic receivers that are positioned to detect the seismic waves. The seismic waves propagate into the formations in the earth, where a portion of the waves reflects from interfaces between subterranean formations. The reflected seismic waves are detected by the seismic receivers, which convert the reflected waves into representative seismic datasets. The datasets can be transmitted by electrical, optical, radio or other techniques to devices which record the datasets. Through analysis of the recorded datasets, the shape, position and composition of subterranean formations can be determined. 
         [0002]    Land seismic surveying is a method for determining the structure of subterranean formations beneath the surface of the earth. Seismic sources and seismic receivers for land seismic surveying can be placed on the surface of the earth. In different examples, the seismic source(s) or seismic receiver(s), or both, may be placed in a borehole for vertical seismic profiling. 
         [0003]    Marine seismic surveying is a method for determining the structure of subterranean formations underlying bodies of water. Marine seismic surveying can utilize seismic energy sources and seismic receivers located in the water and can be towed behind a vessel or positioned on the water bottom from a vessel. Marine seismic surveying can also employ seismic receivers deployed on a seabed cable. The energy source is typically an explosive device or compressed air system which generates seismic energy, which then propagates as seismic waves through the body of water and into the earth formations below seabed. As the seismic waves strike interfaces between subterranean formations, a portion of the seismic waves reflects back through the earth and water to the seismic receivers, to be detected, transmitted, and recorded. The seismic receivers typically used in marine seismic surveying are pressure sensors, such as hydrophones. Additionally, though, motion sensors, such as accelerometers may be used. Both the sources and receivers may be strategically repositioned to cover the survey area. 
         [0004]    Seismic waves, however, reflect from interfaces other than just those between subterranean formations, as would be desired. Seismic waves also reflect from the water bottom and the water surface, and the resulting reflected waves themselves continue to reflect. Waves which reflect multiple times are called “multiples”. Waves which reflect multiple times in the water layer between the water surface above and the water bottom below are called “water-bottom multiples”. Water-bottom multiples have long been recognized as a problem in marine seismic processing and interpretation, so multiple attenuation methods based on the wave equation have been developed to handle water-bottom multiples. 
         [0005]    In marine seismic surveying, seismic waves do not reflect just from the interfaces between subterranean formations. Seismic waves also reflect from the water bottom (e.g., seafloor) and the water surface (e.g., sea surface), and the resulting reflected waves themselves continue to reflect. Waves that reflect multiple times are called “multiples.” The presence of multiples data in recorded seismic data can adversely affect the accuracy of assumptions made during seismic processing and resulting interpretations made using interpretation techniques. 
       SUMMARY 
       [0006]    In some embodiments, a method includes receiving a seismic dataset from a survey, wherein the seismic dataset represents a portion of a subsurface geological formation and includes primary and multiple data. The method further includes the steps of conditioning the seismic dataset and estimating a model of the multiple data in the conditioned seismic dataset based on a user-defined parameter to derive a primary data set. Further, the method includes the steps of computing a velocity model from the primary data set using the user-defined parameter and updating the estimated multiple model based at least on a modification of the user-defined parameter. In addition, the method includes the steps of recomputing the primary data and the velocity model based on the modified user-defined parameter and generating an image of the primary data. 
         [0007]    Other or additional features will become apparent from the following description, from the drawings, or from the claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]    Some implementations are described with respect to the following figures. 
           [0009]      FIG. 1  is a diagrammatic view of an example survey arrangement. 
           [0010]      FIG. 2  illustrates a flow diagram of a seismic data processing technique, according to some implementations. 
           [0011]      FIG. 3  illustrates a plan view of a seismic data acquisition geometry according to one embodiment of the present disclosure. 
           [0012]      FIGS. 4 and 5  illustrate processing apertures according to one or more embodiments of the present disclosure. 
           [0013]      FIG. 6  is a block diagram of an example computing system in accordance with some implementations. 
       
    
    
     DETAILED DESCRIPTION 
       [0014]    Reference will now be made in detail to embodiments, examples of which are illustrated in the accompanying drawings and figures. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of some embodiments. However, it will be apparent to one of ordinary skill in the art that the embodiments may be practiced without these specific details. 
         [0015]    The terminology used in the description is for the purpose of describing example embodiments. As used in the description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this application, specify the presence of stated features, integers, tasks, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, tasks, operations, elements, components, and/or groups thereof. 
         [0016]    Although reference is made to subterranean structures or formations in the disclosure, it is contemplated that techniques or mechanisms according to some implementations can be applied to other types of target structures where data imaging and processing issues may occur, such as human tissue, mechanical structures, plant tissue, animal tissue, solid volumes, substantially solid volumes, volumes of liquid, volumes of gas, volumes of plasma, and volumes of space near and/or outside the atmosphere of a planet, asteroid, comet, moon, or other body, and so forth. 
         [0017]      FIG. 1  shows a schematic view of marine seismic surveying example  100 . Subterranean formations to be explored, such as  102  and  104 , lie below a body of water  106 . Seismic energy sources  108  and seismic receivers  110  are positioned in the body of water  106 , by one or more marine vessels (not shown). In other examples, seismic receivers can be deployed on a seabed cable. A seismic source  108 , such as an air gun, vibrator, or other type of source, creates seismic waves in the body of water  106  and a portion of the seismic waves travels downward through the body of water  106  toward the subterranean formations  102  and  104  beneath the body of water  106 . When the seismic waves reach a seismic reflector, a portion of the seismic waves reflects upward and a portion of the seismic waves continues downward. The seismic reflector can be the water bottom  112  or one of the interfaces between subterranean formations, such as an interface  114  between formations  102  and  104 . When the reflected waves traveling upward reach the water/air interface at the water surface  116 , a majority portion of the waves reflects downward. Continuing in this fashion, seismic waves can reflect multiple times between the water bottom  112  or formation interfaces below and the water surface  116  above. Each time the reflected waves propagate past the position of a seismic receiver  110 , the receiver  110  senses the reflected waves and generates representative signals. 
         [0018]    In other examples, the sources  108  can be referred to as survey sources that produce energy for propagation into a target structure, and the receivers  110  are referred to as survey receivers to measure signals representing the propagated energy affected by the target structure. In the ensuing discussion, reference is made to seismic data collected by seismic receivers. More generally, survey receivers can acquire survey data, which can include seismic wavefields, acoustic signals, or other signals. 
         [0019]    Primary reflections are those seismic waves that have reflected just once, from the water bottom  112  or an interface between subterranean formations, before being detected by a seismic receiver  110 . Primary reflections contain the desired information about the subterranean formations which marine seismic surveying seeks. An example of a primary reflection is shown in  FIG. 1  by ray paths  120  and  122 . Seismic waves are generated by a seismic source  108  and a portion of the waves travels downward through the body of water  106  and into the subterranean formation  102  along ray path  120 . A portion of the seismic waves reflects from the interface  114  between formations  102  and  104 . The reflected waves travel upward through the formation  102  and back into the body of water  106  along ray path  122 . The reflected waves travel past a receiver  110 , which detects the waves and generates a representative signal. 
         [0020]    Surface multiples are those waves that have been reflected multiple times between the water surface  116  and any upward reflectors such as the water bottom or formation interfaces, before being sensed by a receiver  110 . An example of a surface multiple is shown by ray paths  130 ,  132 , and  136 . 
         [0021]    Water layer multiples are those waves that have reflected multiple times between the water surface  116  and the water bottom  112  before being sensed by a receiver  110 . An example of a water layer multiple is shown starting at ray path  130 . Seismic waves are generated by a seismic source  108  and a portion of the waves travels downward through the body of water  106  along ray path  130 . A portion of the seismic waves reflects from the water bottom  112  and travels back upward through the body of water  106  along ray path  132 . A portion of the reflected waves reflects from the water surface  116  and travels back downward through the body of water  106  along ray path  134 . A portion of the twice-reflected waves reflects again from the water bottom  112  and travels back upward through the body of water  106  along ray path  136 . A portion of the thrice-reflected waves reflects again from the water surface  116  and travels back downward through the body of water  106  along ray path  138 . A portion of the four times reflected waves reflects again from the water bottom  112  and travels back upward through the body of water  106  along ray path  140 . A portion of the five times reflected waves reflects again from the water surface  116  and travels back downward through the body of water  106  along ray path  142 . A portion of the six times reflected waves reflects again from the water bottom  112  and travels back upward through the body of water  106  along ray path  144 . The seven times reflected waves then travel past a receiver  110 , which detects the waves and generates a representative signal. The water layer multiple starting at ray path  130  is an example of a simple water layer multiple since the seismic waves would not go below the water bottom  112 , i.e., the waves remain within the water layer or body of water  106 . The water layer multiple starting at ray path  130  is a multiple of order three, since the multiple contains three reflections from the water surface  116 . 
         [0022]    A water layer multiple that goes below the water bottom  112  can be referred to as a peg-leg water layer multiple.  FIG. 1  illustrates an example of a peg-leg water layer multiple starting at ray path  150 . Seismic waves are generated by a seismic source  108  and a portion of the waves travels downward through the body of water  106  and into the subterranean formation  102  along ray path  150 . A portion of the seismic waves reflects from the water bottom  112  and travels back upward through the body of water  106  along ray path  152 . A portion of the reflected waves reflects from the water surface  116  and travels back downward through the body of water  106  and into the subterranean formation  102  along ray path  154 . A portion of the twice-reflected waves reflects from the interface  114  and travels back upward through the formation  102  and the body of water  106  along ray path  156 . A portion of the thrice-reflected waves reflects again from the water surface  116  and travels back downward through the body of water  106  along ray path  158 . A portion of the four times reflected waves reflects again from the water bottom  112  and travels back upward through the body of water  106  along ray path  160 . A portion of the five times reflected waves reflects again from the water surface  116  and travels back downward through the body of water  106  along ray path  162 . A portion of the six times reflected waves reflects again from the water bottom  112  and travels back upward through the body of water  106  along ray path  164 . The seven times reflected waves then travel past a receiver  110 , which detects the waves and generates a representative signal. The peg-leg water layer multiple starting at ray path  150  is a multiple of order three, since the multiple contains three reflections from the water surface  116 . 
         [0023]    Multiples can be predicted, and the predicted multiples can be used to process recorded seismic data (such as by use of adaptive-match filtering and subtraction) to reduce the effect of multiples on processing and interpretation of recorded seismic data. In some examples, a desirable characteristic of a process that provides predicted multiples is that there is internal relative amplitude consistency of plural modes (e.g., a response mode that has a receiver-side round-trip of multiples, and a response mode that has a source-side round-trip of multiples) in the predicted multiples and the recorded seismic data. The internal relative amplitude consistency or inconsistency can reduce the likelihood of adaptive-match filtering and subtraction resulting in either or both over- and under-subtraction of different modes. 
         [0024]    One embodiment of the Generalized 3D surface multiple prediction disclosed in U.S. Pat. No. 7,796,467 to Bisley et al., which is hereby incorporated by reference in its entirety, includes (a) selecting a target trace; (b) selecting a potential downward reflection point for the selected target trace; (c) computing at least one of a desired shot-side midpoint, offset and azimuth, and at least one of a desired receiver-side midpoint, offset and azimuth using the selected potential downward reflection point and the selected target trace. The desired shot-side midpoint, offset and azimuth define a desired shot-side trace. The desired receiver-side midpoint, offset and azimuth define a desired receiver-side trace. The method further includes (d) determining a pair of recorded traces substantially closest to the desired shot-side trace and to the desired receiver-side trace; and (e) convolving the pair of recorded traces to generate a convolution. 
         [0025]    Wavefield extrapolation of recorded survey data through a model of the water layer can be used for creating water-layer-multiple model traces. A trace can refer to survey data acquired or predicted for a target structure in response to energy from one or more survey sources. A water-layer-multiple model trace can refer to a trace including predicted multiples that uses a model of a water layer. In accordance with some implementations, a general DWD technique disclosed in U.S. Patent Application Publication No. 20150006085 filed on Jun. 4, 2014, contents of which is hereby incorporated by reference in its entirety, employs a multidimensional (e.g., 2D, 3D, 4D, etc.) model of the water layer, subsurface, or other structure(s) through which multiples can propagate. With the general DWD technique, source and receiver side wavefield extrapolations cannot be performed in the same domain (unlike the 1D DWD techniques described above), because the wavefield extrapolation operators may differ between the source and receiver sides. In some examples, receiver-side extrapolation can be done on 3D (areal) shot gathers (a shot gather can refer to survey data collected by survey receivers for a particular shot), and source-side extrapolation can be done on 3D (areal) receiver gathers (a receiver gather can refer to survey data collected by a particular receiver in response to shots). 
         [0026]    An actual recording geometry may not result in well sampled 3D gathers (particularly receiver gathers). As a result, the actual recording geometry is constructed from the available survey data (e.g., recorded seismic data). 
         [0027]    One common theme in the typical GSMP and GDWD approaches to multiples prediction is the idea that discretization parameters for example, the extent of the aperture and the spacing of grid nodes within the aperture are typically user-selected prior to any multiple prediction or processing based on tests conducted on a limited amount of seismic data from the relevant survey. The selected aperture discretization parameters are then used to analyze or process large volumes of a survey. Those of ordinary skill in the art will appreciate that seismic data processing is compute power and time intensive. These costs constrain seismic processing jobs to adopt a user-defined parameter, for example, aperture extent, and use that parameter for an entire processing job. It is usually when the processing job is nearing completion that it may become apparent that the chosen parameter may be inadequate or inaccurate. For example, the selected aperture may be too small and more complex multiples may not be accounted for. Typically, it is then too late or costly to adjust the parameters and restart the processing job. Therefore, a need exists for a more efficient way of identifying accurate processing parameters before it is too costly to adjust processing parameters for a given processing job 
         [0028]      FIG. 2  illustrates one embodiment of the seismic data processing technique of present disclosure. Operation of the technique begins at a block  202  where the processing technique receives a seismic data set representing a subsurface region of interest. The data set may have been acquired from a seismic survey as discussed with respect to  FIG. 1  above. As would be understood to those of ordinary skill in the art, the seismic data set may include data that is representative of primary data as well as multiple data. 
         [0029]    The processing technique may condition the data set at a block  204 . In this context conditioning the data set includes any processing operation that is undertaken to refine the data set prior to further processing. For example, one such processing operation includes noise attenuation to remove unwanted signals that are identifiable in the data set. One of several noise attenuation methods known to those of ordinary skill in the art may be employed. One non-limiting example of such noise attenuation methods is a linear noise attenuation (LNA) technique. 
         [0030]    Next, the processing technique estimates a model of the multiples present in the conditioned or noise attenuated data set based on a user-defined parameter at a block  206 . Some examples of user-defined parameters that may be selected include the aperture extent and/or spacing of grid nodes within the aperture.  FIG. 3  illustrates the spatial aperture and its discretization for numerical computations in particular of free-surface multiples. shows an example of a selected aperture including potential downward reflection points of surface multiples as needed for computing the free-surface multiples with source location S and receiver location R. Typically, S and R coincide with the shot and receiver locations of a trace recorded in the survey, but in general S and R can be any locations. The aperture is the area selected for the computation of a certain integral providing the estimate of free-surface multiples for shot at S and receiver at R. Typically the aperture is a polygon that may be in one embodiment by location of corner points) or often and as a special case, a rectangle defined by its center (i.e., a midpoint of a source-receiver segment and the dimensions of its sides. A grid of nodes (downward reflection points, or DRPs) is defined within the aperture. The axis X and Y of the grid are orthogonal to each other, with X parallel to the source-receiver segment or to a survey grid axis when source and receiver location S, R are coincident. As an example,  FIG. 3  shows a uniform, cartesian grid of downward reflection points. To compute an estimate of multiples by integral multi-dimensional convolution methods, an integral of the form: 
         [0000]    
       
         
           
             
               
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         [0031]    Where T m =trace for which to predict multiple, 
         [0032]    T d =trace on detector side 
         [0033]    T s =trace on source side 
         [0034]    dx=sampling interval over x 
         [0035]    dy=sampling interval over y 
         [0036]    X s =Trace X coordinate at source 
         [0037]    Y s =Trace Y coordinate at source 
         [0038]    X d =Trace X coordinate at detector 
         [0039]    Y d =Trace Y coordinate at detector 
         [0040]    X drp =X coordinate of the downward reflecting point 
         [0041]    Y drp =Y coordinate of the downward reflecting point 
         [0042]    Equation (1) can then be evaluated as a Riemann sum. Similar to the approach disclosed in U.S. Pat. No. 7,796,467 contributions of additional grid points in the aperture may be accounted for. 
         [0043]    With continuing reference to  FIG. 2 , the processing technique of the present disclosure estimates a model the multiple data in the conditioned seismic data set based at least in part on a user-defined parameter at a block  206 . The estimated model of the multiple data may be subtracted from the seismic data set to derive a primary data set. Next, a velocity model may be computed at a block  208  from the primary data set using the user-defined parameter. Then the technique allows for a user to determine whether the computed velocity model is within a predetermined range of accuracy at a block  210 . This procedure and decision will typically require the computation of images (migration results) with the velocity model being evaluated. If the computed velocity model is not within the predetermined range of accuracy, the technique proceeds to a block  212  where the user modifies the user-defined parameter and the technique updates the estimated multiple model based on at least the user-defined parameter. Control then returns to the block  208 . 
         [0044]    In the event that a user determines at block  210  that the computed velocity model is within a selected range of accuracy, then control passes to a block  214  that updates the multiple data model based in part on the updated user-defined parameter. Next, a block  216  recomputes the primary data, the velocity, and generates an image of the recomputed primary data. Methods by which the primary data may be derived at any of the steps in the above-described technique are known to those of ordinary skill in the art and include, but are not limited to, an adaptive subtraction that uses adaptive match filtering, such as constrained adaptive match filtering (such as constrained adaptive match filtering described in U.S. Pat. No. 6,832,161). It is also contemplated that the technique  200  disclosed herein may be implemented where either the detector or source side terms (or both) i.e., T s , or T d  may be replaced with data computed from a subsurface geological model through simulation of seismic waves propagating in that model instead of actual data. 
         [0045]    Referring now to  FIG. 4 , equation 1 above may be used to derive the multiple data in aperture B that is bounded by integration aperture defined by M×N. A user may later determine that the area of interest is actually defined by integration aperture A. Considering that the integration aperture B lies wholly within aperture A, the user need only define non-intersecting areas B and (A−B). It follows then that A=B+(A−B). Therefore, the area A may be characterized by computing the integral of equation 1 for areas B and (A−B) separately and in the process, refining the integration aperture for the smaller areas before deriving the integral of area A. As such, a first user defined parameter may be used to process the seismic data for integration aperture B. Then, the user-defined parameter may be adjusted or refined for more accurate processing of integration aperture A, thereby improving the results derived from the processing operations. Both apertures B and A may be variable as a function of shot and receiver coordinates, or other related attributes such as midpoint, offset, azimuth etc.  FIG. 5  illustrates another example of an application of the technique of the present disclosure. As discussed above with respect to  FIG. 4 , multiples for the area  402  defined between area A and area B may be computed by first computing the multiples for area A and then computing the multiples for area B. The multiples for area  402  can then be defined by subtracting A-B. However, a taper  404  is applied around the edges of the areas A and B. This taper  404  may be compensated for by applying an appropriate scaling when solving equation 1. 
         [0046]    In some embodiments, any of the methods described herein may be executed by a computing system.  FIG. 6  illustrates an example of such a computing system  600 , in accordance with some embodiments. The computing system  600  may include a computer or computer system  601 A, which may be an individual computer system  601 A or an arrangement of distributed computer systems. The computer system  601 A includes one or more analysis module(s)  602  configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module  602  executes independently, or in coordination with, one or more processors  604 , which is (or are) connected to one or more storage media  606 . The processor(s)  604  is (or are) also connected to a network interface  607  to allow the computer system  601 A to communicate over a data network  609  with one or more additional computer systems and/or computing systems, such as  601 B,  601 C, and/or  601 D (note that computer systems  601 B,  601 C and/or  601 D may or may not share the same architecture as computer system  601 A, and may be located in different physical locations, e.g., computer systems  601 A and  601 B may be located in a processing facility, while in communication with one or more computer systems such as  601 C and/or  601 D that are located in one or more data centers, and/or located in varying countries on different continents). 
         [0047]    A processor can include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device. 
         [0048]    The storage media  606  can be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of  FIG. 6  storage media  606  is depicted as within computer system  601 A, in some embodiments, storage media  606  may be distributed within and/or across multiple internal and/or external enclosures of computing system  601 A and/or additional computing systems. Storage media  606  may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLUERAY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above can be provided on one computer-readable or machine-readable storage medium, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture can refer to any manufactured single component or multiple components. The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution. 
         [0049]    It should be appreciated that computing system  600  is only one example of a computing system, and that computing system  600  may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of  FIG. 6 , and/or computing system  600  may have a different configuration or arrangement of the components depicted in  FIG. 6 . The various components shown in  FIG. 6  may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits. 
         [0050]    Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of protection of the disclosure. In the foregoing description, numerous details are set forth to provide an understanding of the subject disclosed herein. However, implementations may be practiced without at least some of these details. Other implementations may include modifications and variations from the details discussed above. It is intended that the appended claims cover such modifications and variations.