Patent Publication Number: US-2021190984-A1

Title: Attenuation of Guided Waves Using Polarization Filtering

Description:
BACKGROUND 
     Field of the Disclosure 
     The present disclosure generally relates to geophysical exploration using seismic surveying. More specifically, embodiments of the disclosure relate to the attenuation of noise from guided waves. 
     Description of the Related Art 
     In geophysical exploration, such as the exploration for hydrocarbons, seismic surveys are performed to produce images of the various rock formations in the earth (“subsurface”) or underwater (“subsea”). The seismic surveys obtain seismic data indicating the response of the rock formations to the travel of elastic wave seismic energy. Various types of seismic waves may be generated as the seismic data, and such seismic waves include interface waves produced at the interface between different waves. These interface waves include Rayleigh waves and Scholte waves. Various techniques may be used to filter these interface waves from the seismic data. However, existing filtering techniques may be unable to filter other types of waves that are a source of noise in the seismic data. 
     SUMMARY 
     In a marine environment, guided waves are generated as a consequence of constructive interference of plane waves undergoing multiple reflections between the free surface and water bottom at angles of incidence beyond the critical angle. Polarization filtering is typically used to filter interface waves such as Rayleigh waves (in land environments) and Scholte waves (in marine environments) from multicomponent seismic data. Interface waves such as Rayleigh and Scholte waves exhibit a distinctive characteristic—elliptical polarization—that may be exploited to filter these waves from body waves that are typically linearly polarized. However, guided waves do not exhibit such distinctive elliptical polarization characteristics relative to body waves. Consequently, guided waves may be difficult or impossible to filter from multicomponent seismic data, resulting in excessive noise in seismic images that affects accurate characterization of rock formations and hydrocarbon reservoirs in such formations. 
     In one embodiment, a computer-implemented method for producing attenuated seismic data from raw seismic data generated from seismic receiver station configured to sense seismic signals originating from a seismic source station. The seismic receiver station includes a geophone and a hydrophone. The method includes obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component, and scaling the raw seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component. The method further includes applying polarization filtering within a frequency band defined by a first velocity and a second velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. The method also includes producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the method includes generating a seismic image from the attenuated seismic data. In some embodiments, the method includes removing the scaling from the attenuated seismic data. In some embodiments, the scaling is performed using a constant scalar. In some embodiments, the method includes applying polarization filtering to the raw seismic data before the scaling, such that polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the method includes applying a polarization filtering to the attenuated seismic data within a frequency band defined by a third velocity and a fourth velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the attenuated seismic data. 
     In another embodiment, a transitory computer-readable storage medium having executable code stored thereon for producing attenuated seismic data from seismic data generated from a seismic receiver station configured to sense seismic signals originating from a seismic source station is provided. The seismic receiver station includes a geophone and a hydrophone. The executable code includes a set of instructions that causes a processor to perform operations that include obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component, and scaling the raw seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component. The operations further include applying polarization filtering within a frequency band defined by a first velocity and a second velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. The operations also include producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the operations include generating a seismic image from the attenuated seismic data. In some embodiments, the operations include removing the scaling from the attenuated seismic data. In some embodiments, the scaling is performed using a constant scalar. In some embodiments, the operations include applying polarization filtering to the raw seismic data before the scaling, such that polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the operations include applying a polarization filtering to the attenuated seismic data within a frequency band defined by a third velocity and a fourth velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the attenuated seismic data. 
     In another embodiment, a system is provided that includes a seismic source station and a seismic receiver station configured to sense seismic signals originating from the seismic source station, the seismic receiver station having a geophone and a hydrophone. The system further includes a seismic data processor and a non-transitory computer-readable storage memory accessible by the seismic data processor and having executable code stored thereon for producing attenuated seismic data from seismic data generated from the seismic receiver station. The executable code includes a set of instructions that causes a processor to perform operations that include obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component, and scaling the raw seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component. The operations further include applying polarization filtering within a frequency band defined by a first velocity and a second velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. The operations also include producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the operations include generating a seismic image from the attenuated seismic data. In some embodiments, the operations include removing the scaling from the attenuated seismic data. In some embodiments, the scaling is performed using a constant scalar. In some embodiments, the operations include applying polarization filtering to the raw seismic data before the scaling, such that polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the operations include applying a polarization filtering to the raw seismic data within a frequency band defined by a third velocity and a fourth velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the attenuated seismic data. 
     In one embodiment, a computer-implemented method for producing attenuated seismic data from raw seismic data generated from seismic receiver station configured to sense seismic signals originating from a seismic source station. The seismic receiver station includes a geophone and a hydrophone. The method includes obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component and applying a polarization filtering to the raw seismic data within a frequency band defined by a first velocity and a second velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the scaled seismic data. The method further includes producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the method includes generating a seismic image from the attenuated seismic data. In some embodiments, the polarization filtering is a first polarization filtering and the method includes applying a second polarization filtering to the raw seismic data before the first polarization filtering, such that the second polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the method includes scaling the attenuated seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component and applying polarization filtering within a frequency band defined by a third velocity and a fourth velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. 
     In another embodiment, a transitory computer-readable storage medium having executable code stored thereon for producing attenuated seismic data from seismic data generated from a seismic receiver station configured to sense seismic signals originating from a seismic source station is provided. The seismic receiver station includes a geophone and a hydrophone. The executable code includes a set of instructions that causes a processor to perform operations that include obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component, and applying a polarization filtering to the raw seismic data within a frequency band defined by a first velocity and a second velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the scaled seismic data. The operations further include producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the operations include generating a seismic image from the attenuated seismic data. In some embodiments, the polarization filtering is a first polarization filtering and the operations include applying a second polarization filtering to the raw seismic data before the first polarization filtering, such that the second polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the operations include scaling the attenuated seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component and applying polarization filtering within a frequency band defined by a third velocity and a fourth velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. 
     In another embodiment, a system is provided that includes a seismic source station and a seismic receiver station configured to sense seismic signals originating from the seismic source station, the seismic receiver station having a geophone and a hydrophone. The system further includes a seismic data processor and a non-transitory computer-readable storage memory accessible by the seismic data processor and having executable code stored thereon for producing attenuated seismic data from seismic data generated from the seismic receiver station. The executable code includes a set of instructions that causes a processor to perform operations that include obtaining raw seismic data from the seismic receiver station, the raw seismic data having a hydrophone component and a vertical geophone component, and applying a polarization filtering to the raw seismic data within a frequency band defined by a first velocity and a second velocity and based on a tilt angle, such that the polarization filtering attenuates guided waves in the scaled seismic data. The operations further include producing attenuated seismic data from the application of polarization filtering, such that the attenuated seismic data has attenuated guided waves as compared to the raw seismic data. 
     In some embodiments, the operations include generating a seismic image from the attenuated seismic data. In some embodiments, the polarization filtering is a first polarization filtering and the operations include applying a second polarization filtering to the raw seismic data before the first polarization filtering, such that the second polarization filtering attenuates Scholte waves in the raw seismic data. In some embodiments, the operations include scaling the attenuated seismic data to produce scaled seismic data having a scaled hydrophone component and a scaled vertical geophone component and applying polarization filtering within a frequency band defined by a third velocity and a fourth velocity to the scaled seismic data, the polarization filtering based on an ellipticity ratio, such that the polarization filtering attenuates guided waves in the scaled seismic data. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  depicts example raw receiver gathers for a hydrophone component and a vertical geophone component of multicomponent seismic data obtained in a seismic exploration operation using an ocean bottom cable (OBC) in a marine environment in accordance with an embodiment of the disclosure; 
         FIG. 2  depicts determined ellipticity ratios from the raw hydrophone component and the raw vertical geophone component of  FIG. 1  in accordance with an embodiment of the disclosure; 
         FIG. 3  depicts determined tilt angles from the raw hydrophone component and the raw vertical geophone component of  FIG. 1  in accordance with an embodiment of the disclosure; 
         FIG. 4  depicts a hydrophone component and vertical geophone component of multicomponent seismic data after attenuation of the Scholte waves from the raw hydrophone and geophone components of  FIG. 1  using polarization filtering in accordance with an embodiment of the disclosure; 
         FIG. 5  depicts the hydrophone component and vertical geophone component of the multicomponent seismic data generated by subtracting the attenuated seismic data depicted in  FIG. 4  from the raw seismic data depicted in  FIG. 1  in accordance with an embodiment of the disclosure; 
         FIGS. 6A, 6B, 6C, and 6D  are block diagrams of processes for attenuating guided waves in multicomponent seismic data in accordance with an embodiment of the disclosure; 
         FIG. 7  depicts example raw receiver gathers for a hydrophone component and a vertical geophone component of multicomponent seismic data in accordance with an embodiment of the disclosure; 
         FIG. 8  depicts the ellipticity ratio derived from hydrophone data and geophone data after using a constant scaling on the hydrophone data in accordance with an embodiment of the disclosure; 
         FIG. 9  depicts the tilt angles in example raw receiver gathers for a hydrophone component and a vertical geophone component of multicomponent seismic data in accordance with an embodiment of the disclosure; 
         FIG. 10  depicts example raw receiver gathers for a hydrophone component and a vertical geophone component of multicomponent seismic data before the application of polarization filtering to attenuate the guided waves in the data in accordance with an embodiment of the disclosure; 
         FIG. 11  depicts an example hydrophone component and vertical geophone component of multicomponent seismic data after the application of polarization filtering to attenuate the guided waves in accordance with an embodiment of the disclosure; 
         FIG. 12  depicts the differences in a hydrophone component and vertical geophone component generated by subtracting the raw hydrophone component and raw vertical geophone component shown in  FIG. 10  from the attenuated hydrophone component and vertical geophone component shown in  FIG. 11 ; 
         FIG. 13  depicts example raw receiver gathers for a hydrophone component and a vertical geophone component of multicomponent seismic data illustrating Scholte waves in accordance with an embodiment of the disclosure; 
         FIG. 14  depicts an example hydrophone component and vertical geophone component of multicomponent seismic data after the attenuation of Scholte waves using polarization filtering in accordance with an embodiment of the disclosure; 
         FIG. 15  depicts an example hydrophone component and vertical geophone component of multicomponent seismic data after attenuation of guided waves using polarization filtering in accordance with an embodiment of the disclosure; 
         FIG. 16  is a schematic diagram of a simplified example seismic surveying system in a marine environment in accordance with an embodiment of the present disclosure; and 
         FIG. 17  is a block diagram of a seismic data processing system in accordance with an embodiment of the disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure will be described more fully with reference to the accompanying drawings, which illustrate embodiments of the disclosure. This disclosure may, however, be embodied in many different forms and should not be construed as limited to the illustrated embodiments. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art. 
     Embodiments of the disclosure include systems, methods, and computer-readable media for attenuating guided waves in seismic data using polarization filtering. In some embodiments, a raw hydrophone component and raw geophone component of seismic data may be scaled using a constant scalar to enhance the ellipticity ratio of the guided waves and the contrast between the reflection arrivals and the guided waves. After scaling, polarization filtering based on the ellipticity ratio may be applied within a velocity constraint to the scaled hydrophone and vertical geophone components to attenuate the guided waves. The polarization filtering may produce multicomponent seismic data with reduced or removed noise from the guided waves. 
     In some embodiments, polarization filtering may be applied to a raw hydrophone component and raw vertical geophone component of seismic data to attenuate Scholte waves before attenuation of the guided waves. 
     In some embodiments, polarization filtering based on the tilt angle may be applied within a velocity constraint to the raw (unscaled) hydrophone and vertical geophone components to attenuate the guided waves. Here again, the polarization filtering may produce multicomponent seismic data with reduced or removed noise from the guided waves. 
     In some embodiments the guided waves in the multicomponent seismic data may be attenuated using a sequential combination of polarization filtering based on the tilt angle applied to the raw hydrophone and vertical geophone components and polarization filtering based on the ellipticity ratio applied to the scaled hydrophone and vertical geophone components. For example, in some embodiments, the guided waves in the multicomponent seismic data may first be attenuated using polarization filtering based on the ellipticity ratio applied to the scaled hydrophone and vertical geophone components. In this example, the attenuated seismic data may then be attenuated in a second pass of polarization filtering based on the tilt angle applied to the attenuated hydrophone and vertical geophone components. In another example, the guided waves in the multicomponent seismic data may first be attenuated using polarization filtering based on the tilt angle applied to the raw hydrophone and vertical geophone components. In this example, 
     As mentioned in the disclosure, interface waves (that is, Scholte waves in marine environments) may be filtered using polarization filtering due to the distinctive elliptical polarization characteristics relative to desired signal waves. For example,  FIGS. 1-5  illustrate an application of polarization filtering to seismic data to attenuate Scholte waves.  FIG. 1  depicts an example raw receiver gathers for a hydrophone component ( 100 ) and a vertical geophone component ( 102 ) of multicomponent seismic data obtained from an ocean bottom cable in a seismic exploration operation in a marine environment. The raw receiver gathers shown in  FIG. 1  includes guided waves  104  and Scholte waves  106 . 
       FIG. 2  depicts determined ellipticity ratios from the hydrophone component ( 200 ) and the vertical geophone component ( 202 ) respectively of the raw receiver gathers depicted in  FIG. 1 .  FIG. 2  depicts the ellipticity ratio  204  of the guided waves and the ellipticity ratio  206  of the Scholte waves. As shown in  FIG. 2 , the ellipticity ratio  204  of the guided waves is relatively small (that is, the guided waves exhibit a linear polarization) and the ellipticity ratio  206  of the Scholte waves is relatively large (that is, the Scholte waves exhibit an elliptical polarization). 
       FIG. 3  depicts determined tilt angles from the hydrophone component ( 300 ) and the vertical geophone component ( 302 ) respectively of the raw receiver gathers depicted in  FIG. 1 .  FIG. 3  depicts the tilt angle  304  of the guided waves and the tilt angle  306  of the Scholte waves. As shown in  FIG. 3 , the tilt angle  304  of the guided waves is relatively small and is in a horizontal polarization direction. In contrast, the tilt angle  306  of the Scholte waves is relatively large and is in a vertical polarization direction. 
     Polarization filtering may be applied to the hydrophone component and the vertical geophone component to attenuate Scholte waves based on the ellipticity ratio  206  shown in  FIG. 2 .  FIG. 4  depicts the hydrophone component ( 400 ) and vertical geophone component ( 402 ) of the multicomponent seismic data after attenuation of the Scholte waves in the raw receiver gathers depicted in  FIG. 1  using polarization filtering. As shown in  FIG. 4 , the guided waves  404  are not attenuated by the polarization filtering applied to the multicomponent seismic data, as the linear polarization exhibited by the guided waves is unsuitable for polarization filtering. 
       FIG. 5  depicts the hydrophone component ( 500 ) and vertical geophone component ( 502 ) of the multicomponent seismic data generated by subtracting the attenuated seismic data depicted in  FIG. 4  from the raw receiver gathers depicted in  FIG. 1 . As shown in  FIG. 5 , the attenuated noise is dominated by the Scholte waves, whereas the attenuated noise does not include the relatively large amplitude guided waves. The amplitude of the guided waves is relatively large in the hydrophone component of the seismic data and relatively small in the geophone (directional) component. The hydrophone component shows the very significant component of the guided waves in the water column along with other wave types. Because the guided waves are confined within the water layer of the seismic exploration, only minute fractions of the guides waves&#39; energy enters (leaks into) the solid medium recorded in the geophone (directional) components, resulting in the relatively small amplitude in this component. 
     As described above, conventional polarization filtering based on ellipticity ratio does not attenuate guided waves in the seismic data. Accordingly, embodiments of the disclosure include the attenuation of guided waves using polarization filtering based on ellipticity ratio (as applied to scaled seismic data) or tilt angle. The phase difference between the guided waves in the water column (recorded in the hydrophone component) and the attenuated “leaky” portion of the guided waves (recorded in the geophone component) may be used in the application of polarization filtering. As discussed below, the seismic data may be scaled to enhance the “leaky” portion of the guided waves in the geophone component to a comparable amplitude, and the phase difference may then be used to perform polarization filtering. Additionally or alternatively, polarization filtering may be applied based on a tilt angle of the guided waves. 
       FIGS. 6A, 6B, 6C, and 6D  depict processes for attenuating guided waves in multicomponent seismic data in accordance with embodiments of the disclosure.  FIG. 6A  depicts a process for attenuating guided waves in multicomponent seismic data using polarization filtering based on the ellipticity ratio.  FIG. 6B  depicts a process for attenuating guided waves in multicomponent seismic data using polarization filtering based on the tilt angle.  FIG. 6C  depicts a process for attenuating guided waves in multicomponent seismic data using a first pass of polarization filtering based on the ellipticity ratio and a second pass of polarization filtering based on the tilt angle.  FIG. 6D  depicts a process for attenuating guided waves in multicomponent seismic data using a first pass of polarization filtering based on the tilt angle and a second pass of polarization filtering based on the ellipticity ratio. 
       FIG. 6A  depicts a process  600  for attenuating guided waves in multicomponent seismic data using polarization filtering based on the ellipticity ratio in accordance with an embodiment of the disclosure. The process  600  is also described with reference to  FIGS. 7-12 . Initially, raw multicomponent seismic data (for example, raw receiver gathers or traces) is obtained (block  602 ). The multicomponent seismic data may include a hydrophone component and a vertical geophone component.  FIG. 7  depicts example raw receiver gathers for a hydrophone component ( 700 ) and a vertical geophone component ( 702 ) of multicomponent seismic data.  FIG. 7  also depicts the guided waves  704  in the hydrophone component ( 700 ) and vertical geophone component ( 702 ) that are attenuated according to the techniques described in the disclosure. 
     In some embodiments, polarization filtering may be applied to attenuate Scholte waves in the multicomponent seismic data (block  604 ) before the attenuation of guided waves. As discussed supra, polarization filtering using the ellipticity ratio may be applied to the raw hydrophone component and vertical geophone component to attenuation the Scholte waves. In other embodiments, the process  600  for attenuating guided waves may not include the attenuation of Scholte waves. 
     Next, the raw hydrophone component and raw vertical geophone component of the multicomponent seismic data may be scaled (block  606 ).  FIG. 8  depicts the scaling of the example multicomponent seismic data of  FIG. 7  using a constant scaling.  FIG. 8  depicts the ellipticity ratio derived from hydrophone data ( 800 ) and geophone data ( 802 ) after applying a constant scaling on the hydrophone data. As will be appreciated, although the scale of ellipticity ratio in  FIG. 8  includes negative values, the negative values are an artifact of the illustration. The actual values of the ellipticity ratio are positive and within the range of 0 to 0.02537 in the example shown in  FIG. 8 . 
     As shown in  FIG. 8 , the guided waves  804  in the scaled hydrophone data ( 800 ) and scaled vertical geophone data ( 802 ) exhibit a relatively large ellipticity ratio. As also shown in  FIG. 8 , the reflections arrivals  806  (that is, desired signal waves) in the scaled hydrophone data ( 800 ) and scaled vertical geophone data ( 802 ) exhibit a relatively small ellipticity ratio. The scaling may be removed after the application of polarization filtering to avoid any effect on the amplitude of the seismic signal in subsequent processing. 
     In some embodiments, a constant scaling is applied to both the hydrophone component data and the vertical geophone component data to enhance the ellipticity ratio of the guided waves and improve the contrast between the polarization attributes of desired signal waves (that is, reflection arrivals) and noise (guided waves). As will be appreciated, in other embodiments the scaling may depend on space and frequency. Such dependent scaling is associated with the relationship between the pressure gradient and velocity, as shown in Equation 1: 
       ∇ P=iρωV   (1)
 
     where ∇P is the pressure gradient, V is a vector of the particle velocity components, ω the circular frequency, ρ is the water density, and i is the imaginary number unit. As will be appreciated, scaling of the hydrophone component and vertical geophone component may use the space-frequency dependent scalars shown in Equation 1 and is related to the impedance of the medium (as defined by the ratio between stress and particle velocity). 
     Next, polarization filtering based on the ellipticity ratio and within a specific frequency band defined by a velocity constraint may be applied to the scaled hydrophone component and vertical geophone component to attenuate the guided waves (block  608 ). In contrast to Scholte waves that are confined in a relatively narrow and low frequency band, guided waves are characterized by broadband frequency content. As the application of polarization filtering (performed in the time-frequency domain) may cover a frequency band where signal waves and guided waves overlap, the polarization filtering is applied within specific frequency band defined by minimum and maximum velocities. As guided waves are dispersive, the minimum velocity (v 1 ) and maximum velocity (v 2 ) may be estimated from the low and high frequency limits from the phase velocity dispersion curve of the fundamental mode. This velocity constraint ensures that the polarization filtering is applied only within the region of the seismic data where guided waves are predominant. The minimum velocity (v 1 ) is equal to the velocity of sound in water (about 1500 meters/second (m/s)) and may vary with water temperature and salinity. The maximum velocity (v 2 ) may be the maximum phase velocity of the first mode dispersion curve towards low frequency. This maximum velocity (v 2 ) may about 90% of the shear wave velocity of the water bottom layer. In some embodiments, the minimum velocity (v 1 ) and maximum velocity (v 2 ) may be estimated by measuring the apparent slopes of the lower and upper ends of the guided wave cone (for example, the cones  1004  shown in  FIG. 10  and discussed infra). 
       FIGS. 10-12  depict an example attenuation of guided waves in multicomponent seismic data using polarization filtering based on the ellipticity ratio.  FIG. 10  depicts example raw receiver gathers for a hydrophone component ( 1000 ) and a vertical geophone component ( 1002 ) of multicomponent seismic data before application of polarization filtering to attenuate the guided waves in accordance with an embodiment of the disclosure. As shown in  FIG. 10 , the domain of application of the polarization filtering may be delimited by cones  1004  as defined by a minimum velocity  1006  (v 1 ) and a maximum velocity  1008  (v 2 ). The cones  1004  may delimit the application of polarization filtering in both the hydrophone component ( 1000 ) and vertical geophone component ( 1002 ). 
       FIG. 11  depicts the attenuated hydrophone component ( 1100 ) and vertical geophone ( 1102 ) after application of polarization filtering to attenuate the guided waves in accordance with an embodiment of the disclosure. As compared to the raw receiver gathers shown in  FIG. 10 , the guided waves are significantly attenuated resulting in a reduction of noise in the desired signal waves. 
       FIG. 12  depicts the differences in the hydrophone component ( 1200 ) and vertical geophone component ( 1202 ) generated by subtracting the raw hydrophone component ( 1000 ) and raw vertical geophone component ( 1002 ) shown in  FIG. 10  from the attenuated hydrophone component ( 1100 ) and vertical geophone component ( 1102 ) shown in  FIG. 11 .  FIG. 12  thus specifically depicts the noise attenuated via application of polarization filtering to the raw hydrophone component ( 1000 ) and raw vertical geophone component ( 1002 ) shown in  FIG. 10 . 
     After the polarization filtering, seismic data having a hydrophone component and vertical geophone component may be produced with attenuated noise from the guided waves (block  610 ). The attenuated seismic data may be used to generate a seismic image of a region of interest (for example, a subsea rock formation). 
       FIG. 6B  depicts a process  612  for attenuating guided waves in multicomponent seismic data using polarization filtering based on the ellipticity ratio in accordance with an embodiment of the disclosure. Initially, raw multicomponent seismic data (for example, raw receiver gathers or traces) is obtained (block  614 ). The multicomponent seismic data may include a hydrophone component and a vertical geophone component, such as shown in  FIG. 7  as discussed supra. 
     In some embodiments, polarization filtering may be applied to attenuate Scholte waves in the multicomponent seismic data (block  616 ) before the attenuation of guided waves. As discussed supra, polarization filtering using the ellipticity ratio may be applied to the raw hydrophone component and vertical geophone component to attenuation the Scholte waves. In other embodiments, the process  612  for attenuating guided waves may not include the attenuation of Scholte waves. 
     In the embodiment shown in  FIG. 6B , the tilt angle is be used as the basis for polarization filtering. Thus, in some embodiments, polarization filtering based on the tilt angle and within a specific frequency band defined by a velocity constraint may be applied to the raw hydrophone component and raw vertical geophone component to attenuate the guided waves (block  618 ). Tilt angle may be a suitable attribute because it is predominantly recorded in the hydrophone while the signal waves are recorded in both the hydrophone and geophone components. Consequently, the range of tilt angles derived from the raw multicomponent seismic data (that is, hydrophone (pressure sensor) and vertical geophone) will cluster around extreme values (for example, 0° or) 90° for the guided waves and away from these extreme values for the compressional waves.  FIG. 9  depicts the tilt angles in example raw receiver gathers for a hydrophone component ( 900 ) and a vertical geophone component ( 902 ) of multicomponent seismic data. 
     After the polarization filtering, seismic data having a hydrophone component and vertical geophone component may be produced with attenuated noise from the guided waves (block  620 ). As noted in the disclosure, the attenuated seismic data may be used to generate a seismic image of a region of interest (for example, a subsea rock formation). 
     In some embodiments the guided waves in the multicomponent seismic data may be attenuated using a sequential combination of polarization filtering based on the ellipticity ratio applied to the scaled hydrophone and vertical geophone components and polarization filtering based on the tilt angle.  FIG. 6C  depicts a process  622  for attenuating guided waves in multicomponent seismic data using a first pass of polarization filtering based on the ellipticity ratio and a second pass of polarization filtering based on the tilt angle in accordance with an embodiment of the disclosure. Initially, raw multicomponent seismic data (for example, raw receiver gathers or traces) is obtained (block  624 ). The multicomponent seismic data may include a hydrophone component and a vertical geophone component, such as shown in  FIG. 7  as discussed supra. 
     Here again, in some embodiments, polarization filtering may be applied to attenuate Scholte waves in the multicomponent seismic data (block  626 ) before the attenuation of guided waves. As discussed supra, polarization filtering using the ellipticity ratio may be applied to the raw hydrophone component and vertical geophone component to attenuation the Scholte waves. In other embodiments, the process  622  for attenuating guided waves may not include the attenuation of Scholte waves. 
     Next, the raw hydrophone component and raw vertical geophone component of the multicomponent seismic data may be scaled (block  628 ), such as shown in  FIG. 8  and as discussed supra. After scaling the multicomponent seismic data, polarization filtering based on the ellipticity ratio and within a specific frequency band defined by a velocity constraint may be applied to the scaled hydrophone component and vertical geophone component to attenuate the guided waves (block  632 ), as shown in  FIGS. 10-12  and as discussed with respect to the process  600 . 
     After the application of polarization filtering based on the ellipticity ratio, a second pass of polarization filtering may be applied to the attenuated seismic data, such as to attenuate residual guided wave noise. As shown in  FIG. 6C , polarization filtering based on the tilt angle and within a specific frequency band defined by a velocity constraint may be applied to the attenuated hydrophone component and raw vertical geophone component to attenuate residual guided waves (block  632 ) 
     After the two passes of polarization filtering, seismic data having a hydrophone component and vertical geophone component may be produced with attenuated noise from the guided waves (block  634 ). As noted in the disclosure, the attenuated seismic data may be used to generate a seismic image of a region of interest (for example, a subsea rock formation). 
     In some embodiments the guided waves in the multicomponent seismic data may be attenuated using a sequential combination of polarization filtering based on the tilt angle applied to the raw hydrophone and vertical geophone components and polarization filtering based on the ellipticity ratio.  FIG. 6D  depicts a process  636  for attenuating guided waves in multicomponent seismic data using a first pass of polarization filtering based on the ellipticity ratio and a second pass of polarization filtering based on the tilt angle in accordance with an embodiment of the disclosure. Initially, raw multicomponent seismic data (for example, raw receiver gathers or traces) is obtained (block  638 ). The multicomponent seismic data may include a hydrophone component and a vertical geophone component, such as shown in  FIG. 7  as discussed supra. 
     In some embodiments, polarization filtering may be applied to attenuate Scholte waves in the multicomponent seismic data (block  640 ) before the attenuation of guided waves. As discussed supra, polarization filtering using the ellipticity ratio may be applied to the raw hydrophone component and vertical geophone component to attenuation the Scholte waves. In other embodiments, the process  636  for attenuating guided waves may not include the attenuation of Scholte waves. 
     Next, polarization filtering based on the tilt angle and within a specific frequency band defined by a velocity constraint may be applied to the raw hydrophone component and raw vertical geophone component to attenuate the guided waves (block  642 ), as discussed with regard to the process  612 . After the application of polarization filtering based on the tilt angle, a second pass of polarization filtering may be applied to the attenuated seismic data, such as to attenuate residual guided wave noise. As shown in  FIG. 6D , the attenuated hydrophone component and raw vertical geophone component of the multicomponent seismic data may be scaled (block  644 ), such as by using a constant scalar as discussed in the disclosure and similar to that illustrated in  FIG. 8 . After scaling the attenuated seismic data, polarization filtering based on the ellipticity ratio and within a specific frequency band defined by a velocity constraint may be applied to the scaled hydrophone component and vertical geophone component to attenuate the residual guided waves (block  646 ), as shown in  FIGS. 10-12  and as discussed with respect to the process  600 . 
     After the two passes of polarization filtering, seismic data having a hydrophone component and vertical geophone component may be produced with attenuated noise from the guided waves (block  648 ). As noted in the disclosure, the attenuated seismic data may be used to generate a seismic image of a region of interest (for example, a subsea rock formation). 
     Advantageously, embodiments of the disclosure avoid the use of multichannel filtering approaches which are affected by spatial aliasing. Additionally, the use of multichannel filtering may introduce a smearing effect and adversely affect the preservation of the relative amplitude variation of reflection arrivals with offsets required for seismic inversion approaches. The embodiments described in the disclosure are not affected by aliasing and do not introduce the amplitude smearing across offsets because the attenuation is performed using receivers recording at the same spatial location and filtering is performed on each multicomponent receiver station independently. 
       FIGS. 13-15  depict the impact of the Scholte wave and guided wave attenuation described in the disclosure on the average spectrum of multicomponent seismic data in accordance with an example embodiment of the disclosure. 
       FIG. 13  depicts example raw receiver gathers for a hydrophone component ( 1300 ) and a vertical geophone component ( 1302 ) of multicomponent seismic data illustrating Scholte waves  1304  (that is, Scholte waves&#39; arrivals) in accordance with an embodiment of the disclosure. The average amplitude spectrum for the hydrophone component ( 1300 ) is depicted in inset  1306 . The average amplitude spectrum for the vertical geophone component ( 1302 ) is depicted in inset  1308 . The narrow band and relatively large amplitude signature for the Scholte waves in the average amplitude spectrum the hydrophone component ( 1300 ) is highlighted by arrow  1310 . The narrow band and relatively large amplitude signature for the Scholte waves in the average amplitude spectrum for the vertical geophone component ( 1302 ) is highlighted by arrow  1312 . 
       FIG. 14  depicts an example hydrophone component ( 1400 ) and vertical geophone component ( 1402 ) of multicomponent seismic data after the attenuation of Scholte waves using polarization filtering in accordance with an embodiment of the disclosure. The average amplitude spectrum for the hydrophone component ( 1400 ) is depicted in inset  1406 . The average amplitude spectrum for the vertical geophone component ( 1402 ) is depicted in inset  1408 . As shown in  FIG. 14 , there is an absence of the low frequency and low velocity dispersive noise arrivals of the Scholte wave in the hydrophone component ( 1400 ) and vertical geophone component ( 1402 ). As shown in the insets  1406  and  1408 , there is a corresponding absence of the low frequency peak (visible in  FIG. 13 ) of the Scholte waves in the average amplitude spectrum. The average amplitude spectrum for the hydrophone component ( 1400 ) also shows a frequency dip around 100 Hz resulting from a side source ghost that may, in some embodiments, be addressed by deghosting.  FIG. 14  also depicts the guided waves (shown by arrows  1410  and  1412 ) that remain in the hydrophone component ( 1400 ) and vertical geophone component ( 1402 ) and are not attenuated by the polarization filtering applied to the Scholte waves. 
       FIG. 15  depicts an example hydrophone component ( 1500 ) and vertical geophone component ( 1502 ) of multicomponent seismic data after the attenuation of guided waves using polarization filtering based on the ellipticity ratio in accordance with an embodiment of the disclosure. The average amplitude spectrum for the hydrophone component ( 1500 ) is depicted in inset  1506 . The average amplitude spectrum for the vertical geophone component ( 1502 ) is depicted in inset  1508 . The arrows  1510  and  1512  shown in  FIG. 15  illustrate the enhanced desired signal (that is, reflection arrivals) recovery after the attenuation of guided waves. A comparison between the average amplitude spectra  1406  and  1408  shown in  FIG. 14  and the average amplitude spectra  1506  and  1508  shown in  FIG. 15  indicates that the contribution of the guided waves is significant in the frequency band where relatively strong signal arrivals are expected. As shown in the comparison, the amplitude overshoot above the −10 db level shown in the average power spectrum in insets  1506  and  1508  of  FIG. 15  caused by guided wave arrivals is significantly reduced after the application of polarization filtering. 
       FIG. 16  depicts a simplified example seismic surveying system  1600  in a marine environment in accordance with an embodiment of the present disclosure. The example seismic surveying system  1600  includes a seismic energy source (for example, one or more seismic shot stations)  1602  configured to emit seismic waves into the ocean  1604  and the earth  1606  to evaluate subsea and subsurface conditions and to detect possible concentrations of oil, gas, and other subsurface minerals. The example seismic surveying system  1600  also includes an ocean bottom cable (OBC)  1608  having seismic receiving stations (receivers)  1610 , such as hydrophones and geophones. It should be appreciated that the number and position of the ocean bottom cable, hydrophones, and geophones are simplified for illustration and may vary in different configurations and systems. In other embodiments, the example seismic surveying system  1600  may include one or more ocean bottom nodes (OBN) having seismic receiving stations (receivers) such as hydrophones and geophones. 
     Accordingly, the hydrophones and geophones may be positioned to receive and record seismic energy data or seismic field records in any form including, but not limited to, a geophysical time series recording of the acoustic reflection and refraction of waveforms that travel from the seismic energy source  1602  to the hydrophones and geophones. Variations in the travel times of reflection and refraction events in one or more field records in seismic data processing can be processed to produce a seismic image that demonstrates subsurface structure and can be used to aid in the search for, and exploitation of, subsurface mineral deposits. 
     The geophones are seismic energy sensors that convert ground movement (or displacement of the ground) into voltage which may be recorded at a recording station. A deviation of the measured voltage from a base line measured voltage produces a seismic response which can be analyzed and processed to produce a seismic image of subsurface geophysical structures. As known in the art, the geophones are constrained to respond to a single dimension—typically the vertical dimension. Thus, the geophones may be used to record seismic energy waves reflected by the subsurface geology, such as subsurface formations in the earth  1606 . 
     The hydrophones are seismic energy sensors for underwater recording of seismic energy data or seismic field records. In some embodiments, the hydrophones may be piezoelectric transducers, as is known and understood by those skilled in the art, that generate electricity when subjected to a pressure change. Such piezoelectric transducers may convert a seismic energy signal into an electric signal, as seismic energy signals are a pressure wave in fluids. 
     As mentioned above, the hydrophones and geophones may be positioned to receive and record seismic energy data or seismic field records in any form, such as a geophysical time series recording of the acoustic reflection and refraction of waveforms that travel from the seismic energy source  1602 . The variations in the travel times of reflection and refraction events in one or more field records in a plurality of seismic signals may be used to produce a seismic image that demonstrates subsurface structure. As discussed in the disclosure, guided waves may be generated in an acoustic medium (the ocean  1604 ) overlying an elastic medium (the earth  1606 ) using multicomponent receivers  1610  (geophones and hydrophones) located at the interface of the acoustic and elastic mediums. The guided waves result from constructive interference of acoustic waves reflected at the acoustic/elastic medium interface (that is, the water bottom where the receivers are located) and at the water/air interface (that is, the, free surface of the ocean). 
     Each of the seismic receiving stations  1610  receives seismic signals  1612  and generates raw seismic data  1614  representing the seismic signals. Any number of seismic receiving stations  1610  may be used. In certain embodiments, the seismic receiving stations  1610  are positioned in a substantially linear array, each receiving station being spaced from adjacent real receiving stations at equal intervals; such positioning can be defined or adjusted according to particular considerations, needs, and constraints known by those having skill in the art. 
     The seismic receiving stations  1610  of the ocean bottom cable  1608  may be in communication with a seismic data processing system  1616  that receives the raw seismic data  1614  and attenuations guided waves (and, in some embodiments, Scholte waves) in accordance with embodiments of the disclosure. In some embodiments, the hydrophones and geophones may transmit data to the seismic data processing system  1616  using a wired connection or wireless connection (such as via antennae for transmitting and receiving wireless communication signals. 
       FIG. 17  depicts components of a seismic data processing system  1700  in accordance with an embodiment of the disclosure. In some embodiments, the seismic data processing system  1700  may be in communication with other components of a system for obtaining and producing seismic data. Such other components may include, for example, seismic shot stations (sources) and seismic receiving stations (receivers). As shown in  FIG. 17 , the seismic data processing system  1700  may include a seismic data processor  1702 , a memory  1704 , a display  1706 , and a network interface  1708 . It should be appreciated that the seismic data processing system  1700  may include other components that are omitted for clarity. In some embodiments, seismic data processing system  1700  may include or be a part of a cloud-computing system, a data center, a server rack or other server enclosure, a server, a virtual server, a desktop computer, a laptop computer, a tablet computer, or the like. 
     The seismic data processor  1702  (as used the disclosure, the term “processor” encompasses microprocessors) may include one or more processors having the capability to receive and process seismic data, such as data received from seismic receiving stations. In some embodiments, the seismic data processor  1702  may include an application-specific integrated circuit (AISC). In some embodiments, the seismic data processor  1702  may include a reduced instruction set (RISC) processor. Additionally, the seismic data processor  1702  may include a single-core processors and multicore processors and may include graphics processors. Multiple processors may be employed to provide for parallel or sequential execution of one or more of the techniques described in the disclosure. The seismic data processor  1702  may receive instructions and data from a memory (for example, memory  1704 ). 
     The memory  1704  (which may include one or more tangible non-transitory computer readable storage mediums) may include volatile memory, such as random access memory (RAM), and non-volatile memory, such as ROM, flash memory, a hard drive, any other suitable optical, magnetic, or solid-state storage medium, or a combination thereof. The memory  1704  may be accessible by the seismic data processor  1702 . The memory  1704  may store executable computer code. The executable computer code may include computer program instructions for implementing one or more techniques described in the disclosure. For example, the executable computer code may include guided wave attenuation instructions  1714  to implement one or more embodiments of the present disclosure. In some embodiments, the guided wave attenuation instructions  1714  may implement one or more elements of process  600  described above and illustrated in  FIG. 6 . In some embodiments, the guided wave attenuation instructions  1714  may receive, as input, raw seismic data  1710  and provide, as output, seismic data  1712  with attenuated noise (for example, attenuation guided waves and, in some embodiments, attenuated Scholte waves). The seismic data  1712  may be stored in the memory  1704 . 
     The display  1706  may include a cathode ray tube (CRT) display, liquid crystal display (LCD), an organic light emitting diode (OLED) display, or other suitable display. The display  1706  may display a user interface (for example, a graphical user interface). In accordance with some embodiments, the display  1706  may be a touch screen and may include or be provided with touch sensitive elements through which a user may interact with the user interface. In some embodiments, the display  1706  may display seismic data  1718 , such the seismic data generated by the guided wave attenuation instructions  1710  in accordance with the techniques described herein. 
     The network interface  1708  may provide for communication between the seismic data processing system  1700  and other devices. The network interface  1708  may include a wired network interface card (NIC), a wireless (e.g., radio frequency) network interface card, or combination thereof. The network interface  1708  may include circuitry for receiving and sending signals to and from communications networks, such as an antenna system, an RF transceiver, an amplifier, a tuner, an oscillator, a digital signal processor, and so forth. The network interface  1708  may communicate with networks, such as the Internet, an intranet, a wide area network (WAN), a local area network (LAN), a metropolitan area network (MAN) or other networks. Communication over networks may use suitable standards, protocols, and technologies, such as Ethernet Bluetooth, Wireless Fidelity (Wi-Fi) (e.g., IEEE 802.11 standards), and other standards, protocols, and technologies. In some embodiments, for example, the raw seismic data  1710  may be received over a network via the network interface  1708 . In some embodiments, for example, the seismic data  1712  may be provided to other devices over the network via the network interface  1708 . 
     In some embodiments, seismic data processing computer may be coupled to an input device  1720  (for example, one or more input devices). The input devices  1720  may include, for example, a keyboard, a mouse, a microphone, or other input devices. In some embodiments, the input device  1720  may enable interaction with a user interface displayed on the display  1706 . For example, in some embodiments, the input devices  1720  may enable the entry of inputs that control the acquisition of seismic data, the processing of seismic data, and so on. 
     Ranges may be expressed in the disclosure as from about one particular value, to about another particular value, or both. When such a range is expressed, it is to be understood that another embodiment is from the one particular value, to the other particular value, or both, along with all combinations within said range. 
     Further modifications and alternative embodiments of various aspects of the disclosure will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the embodiments described in the disclosure. It is to be understood that the forms shown and described in the disclosure are to be taken as examples of embodiments. Elements and materials may be substituted for those illustrated and described in the disclosure, parts and processes may be reversed or omitted, and certain features may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description. Changes may be made in the elements described in the disclosure without departing from the spirit and scope of the disclosure as described in the following claims. Headings used in the disclosure are for organizational purposes only and are not meant to be used to limit the scope of the description.