Patent Publication Number: US-2020284937-A1

Title: System and method for displaying seismic events in distributed acoustic sensing data

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     TECHNICAL FIELD 
     The disclosed embodiments relate generally to techniques for displaying seismic events in subsurface reservoirs recorded by a Distributed Acoustic Sensing (DAS) system and, in particular, to a method of attenuating random noise in the DAS seismic data in order to make it possible to display the seismic events. 
     BACKGROUND 
     Seismic exploration involves surveying subterranean geological media for hydrocarbon deposits. A survey typically involves deploying seismic sources and seismic sensors at predetermined locations. The sources generate seismic waves, which propagate into the geological medium creating pressure changes and vibrations. Variations in physical properties of the geological medium give rise to changes in certain properties of the seismic waves, such as their direction of propagation and other properties. Alternatively, rather than having active seismic sources to generate seismic waves, a passive seismic survey may use ambient seismic sources such as but not limited to earthquakes, rock fracturing, and/or environmental sources (e.g., vehicle traffic, ocean waves, and the like). 
     Portions of the seismic waves reach the seismic sensors. Some seismic sensors are sensitive to pressure changes (e.g., hydrophones), others to particle motion (e.g., geophones), and industrial surveys may deploy one type of sensor or both. In response to the detected seismic waves, the sensors generate corresponding electrical signals, known as traces, and record them in storage media as seismic data. Seismic data will include a plurality of “shots” (individual instances of the seismic source being activated), each of which are associated with a plurality of traces recorded at the plurality of sensors. 
     An alternative seismic sensor may include fiber-optic cables. Fiber-optic cables may be deployed in a borehole drilled through the earth&#39;s subsurface, along the earth&#39;s surface, or on a seabed.  FIG. 1  illustrates a fiber-optic cable  12  attached to an interrogator  10 . A laser pulse  14  propagates through the fiber-optic cable  12 , shown as light stream  16 . The light stream  16  sends information to interrogator  10 . However, as observed in the enlarged view  11 , the fiber-optic cable  12  contains many impurities  13  which cause back-scattering  15 . This back-scattering  15  will be recorded as random noise. Meanwhile, if an acoustic signal  18  encounters the fiber-optic cable  12 , this may be recorded as a seismic event but the signal will be negatively impacted by the back-scattering  15 . 
     There exists a need for attenuating noise recorded by the DAS system so that recorded seismic events can be detected and displayed. 
     SUMMARY 
     In accordance with some embodiments, a method of improving distributed acoustic sensing (DAS) seismic data in order to identify seismic events including receiving a DAS seismic dataset recorded by a fiber-optic cable in a borehole drilled through a subsurface volume of interest; identifying a portion of the seismic dataset including random noise with no signal to generate a windowed noise dataset; transforming the windowed noise dataset into a noise power spectrum; training a machine-learning algorithm using the noise power spectrum; using the machine-learning algorithm to remove random noise from the DAS seismic dataset to generate a noise-attenuated seismic dataset; and identifying the seismic events in the noise-attenuated seismic dataset is disclosed. In an embodiment, the machine-learning algorithm may be a structured convolutional neural network. In an embodiment, the machine-learning algorithm may implement a Wiener filter. In an embodiment, the machine-learning algorithm may estimate a signal power spectrum for the DAS seismic dataset. 
     In another aspect of the present invention, to address the aforementioned problems, some embodiments provide a non-transitory computer readable storage medium storing one or more programs. The one or more programs comprise instructions, which when executed by a computer system with one or more processors and memory, cause the computer system to perform any of the methods provided herein. 
     In yet another aspect of the present invention, to address the aforementioned problems, some embodiments provide a computer system. The computer system includes one or more processors, memory, and one or more programs. The one or more programs are stored in memory and configured to be executed by the one or more processors. The one or more programs include an operating system and instructions that when executed by the one or more processors cause the computer system to perform any of the methods provided herein. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a distributed acoustic sensing (DAS) seismic recording system; 
         FIG. 2  illustrates a prior art method of attenuating random noise in a DAS seismic dataset; 
         FIG. 3  is an example of DAS seismic data; 
         FIG. 4  illustrates a basic embodiment of the present invention; 
         FIG. 5A  illustrates a particular embodiment of the present invention; 
         FIG. 5B  illustrates another embodiment of the present invention; 
         FIG. 6  illustrates the result of an embodiment of the present invention; and 
         FIG. 7  is a block diagram illustrating a seismic processing system, in accordance with some embodiments. 
     
    
    
     Like reference numerals refer to corresponding parts throughout the drawings. 
     DETAILED DESCRIPTION OF EMBODIMENTS 
     Described below are methods, systems, and computer readable storage media that provide a manner of DAS seismic processing. These embodiments are designed to be of particular use for attenuating random noise in DAS seismic datasets. 
     Reference will now be made in detail to various embodiments, examples of which are illustrated in the accompanying drawings. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the present disclosure and the embodiments described herein. However, embodiments described herein may be practiced without these specific details. In other instances, well-known methods, procedures, components, and mechanical apparatus have not been described in detail so as not to unnecessarily obscure aspects of the embodiments. 
     The present invention includes embodiments of a method and system for processing DAS seismic data. The DAS seismic data may contain seismic events that are caused by active seismic sources or by passive seismic sources. In practice, DAS seismic data contains a significant amount of random noise, likely due to impurities in the fiber-optic cable and/or interrogator. This random noise can obscure the seismic signal. For example, in  FIG. 2  the “Data” panel shows a shot gather containing seismic signal and random noise. Conventional methods for noise attenuation, such as FX-deconvolution, may reduce random noise, as seen in the “Signal” panel of  FIG. 2 , but are also likely to negatively impact the seismic signal. This can be seen in the “Noise” panel of  FIG. 2  in which a hyperbolic feature that is clearly part of the signal has been incorrectly identified as noise. This conventional method of noise attenuation has not removed all of the random noise from the “Signal” panel and has changed the amplitude of the seismic event by classifying part of the signal as noise (seen in the “Noise” panel). The present invention overcomes this problem. 
     The method for noise attenuation described herein takes DAS seismic data as input. DAS seismic data is recorded by a system such as that shown in  FIG. 1 . The fiber-optic cable may, in one embodiment, be located in a borehole that is drilled through a subsurface volume of interest, such as a rock formation containing a hydrocarbon reservoir. The borehole may be vertical, horizontal, or a combination of both. The DAS seismic data may be acquired as part of a passive seismic survey, such as microseismic data which records acoustic waves that are generated by rock fracturing, or as part of an active seismic survey, such as a walk-away vertical seismic profile (WVSP) using active seismic sources at the earth&#39;s surface or, for a marine survey, in the water column.  FIG. 3  is an example of a portion of a microseismic DAS seismic dataset. In this example, part of the fiber-optic cable was in the vertical section of a borehole (left of the vertical dashed line  30 ) and part of the fiber-optic cable was in the horizontal section of the cable (right of the vertical dashed line  30 ). As can be seen, the data on the left of vertical dashed line  30  consists only of random noise  32 . This random noise also exists right of the vertical dashed line  30  but here there is also a seismic event  34  which is partially obscured by the random noise. In this example, the seismic event is still visible to the human eye but it should be understood that in many cases there may be seismic signal in the data that is of a similar amplitude (i.e. strength) as the random noise so it will be almost indiscernible. 
     The DAS seismic data may be described as d(t, x) where t is time and x is the cable index (i.e. location along the fiber-optic cable): 
         d ( t,x )= s ( t,x )+ n ( t,x )   (1)
 
     where s(t, x) is the seismic signal and n(t, x) is the random noise. As is common in signal processing, it is helpful to deal with the data in the frequency domain. Given D(ω,k),S(cω,k), and N(ω,k) as the Fourier spectra of d(t, x), s(t, x), and n(t, x) respectively, with temporal frequency ω and wavenumber k, equation (1) becomes: 
         D (ω, k )= S (ω,k)+ N (ω, k )   (2)
 
     A means to separate the seismic signal s(t, x) from the seismic data d(t, x) is illustrated in  FIG. 4 . Here there is a linear filter f (t, x) that can be applied to d(t, x) that will produce an estimated seismic signal ŝ(t, x). The mean square error between the estimated seismic signal ŝ(t, x) and the seismic signal s(t, x) is e(t, x). It is desirable to find an optimal filter f opt (t, x) that minimizes the mean square error e(t, x). Note that e(t, x) is the mean square error between the estimated seismic signal ŝ(t, x) and the seismic signal s(t, x) rather than a simple difference due to the need to accommodate the positive and negative amplitude values recorded for the data. In the frequency domain, the optimal filter F opt (ω, k) is found by minimizing: 
       ∫ −∞   ∞   |E (ω, k )| 2   dω=∫   −∞   28   F   opt (ω, k ) D (ω, k )− S (ω, k )| 2   dω    (3)
 
     where E(ω, k) is the Fourier spectrum of e(t, x). 
     Many potential candidates for F opt (ω, k) exist. In the case of DAS seismic data, it may be assumed that the seismic signal is deterministic and varying along the time and space (i.e. cable index) axes. On the other hand, the random noise is stochastic and weakly stationary. This means that the seismic signal and the random noise are statistically independent. As such, the power spectrum of the seismic data d(t, x) is 
       Φ s (ω, k )=Φ s (ω, k )+Φ n (ω, k )   (4)
 
     where Φ s (ω, k) and Φ n (ω, k) are the power spectra of the seismic signal s(t, x) and random noise n(t, x) respectively. Based on this, it is possible to define the optimal filter F opt (ω, k) as a Wiener filter: 
     
       
         
           
             
               
                 
                   
                     
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     Since the random noise n(t, x) is weakly stationary, its power spectrum can be estimated by the spectra of moving windows of recorded noise: 
       Φ n (ω, k )≈ E (| N   i (ω, k )| 2 ),   (6)
 
     where i is window index and N i (ω, k) is the Fourier spectrum of windowed noise n i (t, x). On the other hand, the seismic signal s(t, x) is temporally and spatially varying so its power spectrum needs to be estimated from Fourier spectra of recorded data, 
       | S (ω, k )| 2   ≈|D (ω,k)| 2 −Φ n (ω, k ),   (7)
 
     where D(ω, k) is the Fourier spectrum of windowed data d(t, x). 
     Based on equation (7), it is possible to design a structured Convolutional Neural Network (CNN) to estimate the power spectrum of the signal, as shown in  FIG. 5A . For this structured CNN, it is necessary to train it on the power spectra of random noise N i (ω, k) as shown in  FIG. 5B  which is possible because, as shown in  FIG. 3 , DAS seismic data contains regions that contain only the random noise inherent in the system. Anything that the structured CNN does not identify as being random noise is assumed to be seismic signal. 
       FIG. 6  shows the result of an embodiment of the present invention. The “Data” panel in  FIG. 6  is the same as that in  FIG. 2 . The seismic signal is visible but partially obscured by the random noise. After performing the operations shown in  FIGS. 5A and 5B ,  FIG. 6  shows the results in the “Signal” panel and the “Noise” panel. Again comparing this with the results of a conventional noise attenuation process in  FIG. 2 , the “Signal” panel is much cleaner with no visible noise. In this example, the noise has been attenuated by 26 dB compared with the conventional method&#39;s noise attenuation of only 12 dB. Comparing the “Noise” panel of  FIG. 6  with that of  FIG. 2 , the noise identified by the present invention does not have any signal energy in it, as the conventional method erroneously did. The present invention attenuates the random noise much better than the conventional method without damaging the signal. 
       FIG. 7  is a block diagram illustrating a DAS seismic system  500 , in accordance with some embodiments. While certain specific features are illustrated, those skilled in the art will appreciate from the present disclosure that various other features have not been illustrated for the sake of brevity and so as not to obscure more pertinent aspects of the embodiments disclosed herein. 
     To that end, the DAS seismic system  500  includes one or more processing units (CPUs)  502 , one or more network interfaces  508  and/or other communications interfaces  503 , memory  506 , and one or more communication buses  504  for interconnecting these and various other components. The DAS seismic system  500  also includes a user interface  505  (e.g., a display  505 - 1  and an input device  505 - 2 ). The communication buses  504  may include circuitry (sometimes called a chipset) that interconnects and controls communications between system components. Memory  506  includes high-speed random access memory, such as DRAM, SRAM, DDR RAM or other random access solid state memory devices; and may include non-volatile memory, such as one or more magnetic disk storage devices, optical disk storage devices, flash memory devices, or other non-volatile solid state storage devices. Memory  506  may optionally include one or more storage devices remotely located from the CPUs  502 . Memory  506 , including the non-volatile and volatile memory devices within memory  506 , comprises a non-transitory computer readable storage medium and may store seismic data, velocity models, seismic images, and/or geologic structure information. 
     In some embodiments, memory  506  or the non-transitory computer readable storage medium of memory  506  stores the following programs, modules and data structures, or a subset thereof including an operating system  516 , a network communication module  518 , and a seismic processing module  520 . 
     The operating system  516  includes procedures for handling various basic system services and for performing hardware dependent tasks. 
     The network communication module  518  facilitates communication with other devices via the communication network interfaces  508  (wired or wireless) and one or more communication networks, such as the Internet, other wide area networks, local area networks, metropolitan area networks, and so on. 
     In some embodiments, the seismic processing module  520  executes the processes described herein. Seismic processing module  520  may include data sub-module  525 , which handles the seismic dataset including seismic gathers  525 - 1  through  525 -N. This seismic data is supplied by data sub-module  525  to other sub-modules. 
     ML filtering sub-module  522  contains a set of instructions  522 - 1  and accepts metadata and parameters  522 - 2  that will enable it to execute the machine-learning noise attenuation processes described herein. Although specific operations have been identified for the sub-modules discussed herein, this is not meant to be limiting. Each sub-module may be configured to execute operations identified as being a part of other sub-modules, and may contain other instructions, metadata, and parameters that allow it to execute other operations of use in processing seismic data and generate the seismic image. For example, any of the sub-modules may optionally be able to generate a display that would be sent to and shown on the user interface display  505 - 1 . In addition, any of the seismic data or processed seismic data products may be transmitted via the communication interface(s)  503  or the network interface  508  and may be stored in memory  506 . 
     The method is, optionally, governed by instructions that are stored in computer memory or a non-transitory computer readable storage medium (e.g., memory  506  in  FIG. 7 ) and are executed by one or more processors (e.g., processors  502 ) of one or more computer systems. The computer readable storage medium may include a magnetic or optical disk storage device, solid state storage devices such as flash memory, or other non-volatile memory device or devices. The computer readable instructions stored on the computer readable storage medium may include one or more of: source code, assembly language code, object code, or another instruction format that is interpreted by one or more processors. In various embodiments, some operations in each method may be combined and/or the order of some operations may be changed from the order shown in the figures. For ease of explanation, the method is described as being performed by a computer system, although in some embodiments, various operations of the method are distributed across separate computer systems. 
     While particular embodiments are described above, it will be understood it is not intended to limit the invention to these particular embodiments. On the contrary, the invention includes alternatives, modifications and equivalents that are within the spirit and scope of the appended claims. Numerous specific details are set forth in order to provide a thorough understanding of the subject matter presented herein. But it will be apparent to one of ordinary skill in the art that the subject matter may be practiced without these specific details. In other instances, well-known methods, procedures, components, and circuits have not been described in detail so as not to unnecessarily obscure aspects of the embodiments. 
     The terminology used in the description of the invention herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used in the description of the invention 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 also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises,” and/or “comprising,” when used in this specification, specify the presence of stated features, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, operations, elements, components, and/or groups thereof. 
     As used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in accordance with a determination” or “in response to detecting,” that a stated condition precedent is true, depending on the context. Similarly, the phrase “if it is determined [that a stated condition precedent is true]” or “if [a stated condition precedent is true]” or “when [a stated condition precedent is true]” may be construed to mean “upon determining” or “in response to determining” or “in accordance with a determination” or “upon detecting” or “in response to detecting” that the stated condition precedent is true, depending on the context. 
     Although some of the various drawings illustrate a number of logical stages in a particular order, stages that are not order dependent may be reordered and other stages may be combined or broken out. While some reordering or other groupings are specifically mentioned, others will be obvious to those of ordinary skill in the art and so do not present an exhaustive list of alternatives. Moreover, it should be recognized that the stages could be implemented in hardware, firmware, software or any combination thereof. 
     The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. The embodiments were chosen and described in order to best explain the principles of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.