Abstract:
An example omnidirectional sensing system may include a fiber optic cable wrapped around a sphere or spheroid in no preferred direction. The wrapped fiber optic cable may make the system more receptive to acoustic disturbances and increase the fidelity of the sensor in the area of the sphere or spheroid. The system may be used, for instance, for vertical seismic profiling via a wireline technique, placement at the surface of the earth for surface seismic, and in marine applications.

Description:
TECHNICAL FIELD 
       [0001]    The present disclosure relates generally to techniques for sensing acoustic information, and more particularly, to the use of fiber optics in distributed acoustic sensors having an omnidirectional antenna for use in downhole and marine applications. 
       BACKGROUND 
       [0002]    Collecting subsurface data is important to the process of oil and gas drilling. Sensors are often used to collect information such as acoustics, which are particularly useful for monitoring downhole conditions. Fiber optic cables have proven well suited for use in downhole applications. When used for distributed acoustic sensing (DAS), the fiber optic cable itself may form an acoustic sensor. Fiber optic cables are capable of detecting and locating vibration, strain, and other pertinent downhole parameters. Detecting these parameters has a number of applications, including, but not limited to, wellbore interventions, wellbore wireline activities, well completions, reservoir properties, seismic correlations, petrophysics, rock mechanics, and other areas. 
         [0003]    Acoustic sensing based on DAS may use the Rayleigh backscatter property of a fiber&#39;s optical core and may spatially detect disturbances that are distributed along the fiber length. DAS may also detect reflections from fiber Bragg gratings (FBGs) or fiber optic partial mirrors added to a fiber optic cable. Such systems may rely on detecting phase changes brought about by changes in strain along the fiber&#39;s core. Externally-generated acoustic disturbances may create very small strain changes, which translate into phase changes of the reflected light along the optical fiber. Indeed, fiber optic cables are very good sensors since they can pick up very slight changes in a downhole or marine condition. Furthermore, the use of fiber optic cables in downhole and marine environments is also beneficial since they do not experience interference from downhole electrical devices and do not degrade over time. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0004]      FIG. 1  is a schematic diagram illustrating examples of different angles of incidence with which vibrations might encounter the surface of a fiber optic cable used as a sensor in accordance with the present disclosure; 
           [0005]      FIG. 2  is a schematic diagram of an example system with fiber optic sensors according to the present disclosure may be utilized; 
           [0006]      FIG. 3  is a schematic diagram of an example DAS data collection system in accordance with the present disclosure; 
           [0007]      FIGS. 4A-B  are schematic diagrams of a fiber optic cable wrapped around a sphere to form an omnidirectional sensor in accordance with some embodiments of the present disclosure; 
           [0008]      FIG. 5  is a schematic diagram of a fiber optic cable wrapped around a spheroid to form an omnidirectional sensor in accordance with some embodiments of the present disclosure. 
           [0009]      FIGS. 6A-B  are schematic diagrams illustrating several different ways of multiplexing multiple spheres in accordance with the present disclosure; 
           [0010]      FIG. 7  illustrates an embodiment where the multiplexing of multiple fiber optic wrapper spheres in connection with the present disclosure is utilized in a marine application; and 
           [0011]      FIG. 8  is a block diagram of an exemplary computing system for use with the acoustic sensors in accordance with the present disclosure. 
           [0012]      FIG. 9  is a schematic diagram of an example drilling system with the drill string removed, in accordance with the present disclosure. 
           [0013]      FIG. 10  is a diagram of an example completion assembly, in accordance with the present disclosure. 
       
    
    
       [0014]    While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure. 
       DETAILED DESCRIPTION 
       [0015]    To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells. Embodiments may be implemented using a tool that is made suitable for testing, retrieval and sampling along sections of the formation. Embodiments may be implemented with tools that, for example, may be conveyed through a flow passage in tubular string or using a wireline, slickline, coiled tubing, downhole robot or the like. 
         [0016]    The present disclosure describes systems and methods for an omnidirectional fiber optic DAS. DAS data collection systems rely on detecting phase changes in backscattered light signals to determine changes in strain (e.g., caused by acoustic waves or vibrations) along the length of optical fiber. Vibrations traveling at a smaller angle of incidence to perpendicular of the surface of the cable are detected more strongly than vibrations traveling at a larger angle of incidence. Even when arranged on a spool or coil there would be some intrinsic directionality to the fiber optic cable because the arrangement is not spherically symmetric. By wrapping the cable in the shape of a sphere or spheroid, that directionality may be reduced or eliminated. 
         [0017]    To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure and its advantages are best understood by referring to  FIGS. 1 through 10 , where like numbers are used to indicate like and corresponding parts. 
         [0018]      FIG. 1  illustrates vibrations and temperature changes inducing detectable disturbances along a fiber optic cable. Vibration v 1    101  has a smaller angle of incidence  103  to the surface of the fiber optic cable  105  than equivalent vibration v 2    102 , which forms an angle of incidence  104 . Therefore, vibration v 1    101  will be detected more strongly than vibration v 2    102 . By wrapping the fiber optic cable around spheres or spheroids located at intervals along its length, the surface of the cable is omnidirectional, which may better enable the cable to detect vibrations because a small angle of incidence will exist between the vibrations and at least one direction in which the surface of the cable is oriented. Wrapping the fiber optic cable  105  around the spheres or spheroids may also allow better detection of changes in temperature  106 . Wrapping additional fiber optic cable around the sphere or spheroid also has the effect of increasing fidelity of the sensor in the area of the sphere or spheroid. 
         [0019]      FIG. 2  illustrates an example completed well system  200  incorporating a DAS data collection system  212 , in accordance with embodiments of the present disclosure. The system  200  includes a rig  201  located at a surface  211  and positioned above a wellbore  203  within a subterranean formation  202 . One or more tubulars are positioned within the wellbore  203  in a telescopic fashion. As depicted, the tubulars comprise a surface casing  204  and a production casing  205 . The surface casing  204  comprises the largest tubular and is secured in the wellbore  203  via a cement layer  206 . The production casing  205  is at least partially positioned within the surface casing  204  and may be secured with respect to the formation  202  and the surface casing  204  via a casing hangar (not shown) and a cement layer. The system  200  further includes tubing  207  positioned within the production casing  205 . Other configurations and orientations of tubulars within the wellbore  203  are possible. 
         [0020]    As depicted, the DAS data collection system  212  is located at the surface  211 . The DAS system  212  may be coupled to an fiber optic cable  213  that is at least partially positioned within the wellbore  103 . As depicted, the cable  213  is positioned between the surface casing  204  and the production casing  205  and is wrapped around at least one sphere  280 . The cable  213  may be secured in place between the surface casing  204  and the production casing  205  such that it functions as a “permanent” seismic sensor. In other embodiments, the cable  213  may be secured to the tubing  207 , for instance, lowered into the wellbore  203  through the inner bore of the tubing  207  in a removable wireline arrangement, or positioned at any other suitable position. 
         [0021]    Although illustrated as including one DAS system  212  coupled to cable  213 , any suitable number of DAS systems  212  (each coupled to cable  213  located downhole) may be placed inside or adjacent to wellbore  203 . With cable  213  positioned inside a portion of wellbore  203 , DAS system  212  may obtain information associated with formation  202  based on disturbances caused by one or more seismic sources, including an artificial seismic source  215  positioned at the surface. Some examples of artificial seismic sources may include explosives (e.g., dynamite), air guns, thumper trucks, or any other suitable vibration source for creating seismic waves in formation  202 . DAS system  212  may thus be configured to collect seismic data along the length of cable  213  based on determined phase changes in light signals. Example DAS systems  212  and their functionality are described further below. 
         [0022]    As depicted, the system  200  further includes an information handling system  210  positioned at the surface  211 . The information handling system  210  may be communicably coupled to the DAS  212  through, for instance, a wired or wireless connection. The information handling system  210  may receive seismic measurements from the DAS  212  and perform one or more actions that will be described in detail below. The information handling system  210  may comprise a processor and a memory device coupled to the processor, with the memory device containing a set of instructions that cause the processor to perform the actions. Although the information handling system  210  is shown near the wellbore  203 , it may also be located remotely. Additionally, the information handling system  210  may receive seismic measurements from a data center or storage server in which the measurements from the DAS  212  were previously stored. 
         [0023]    Modifications, additions, or omissions may be made to  FIG. 2  without departing from the scope of the present disclosure. For example, the DAS systems and cables may be used during wireline or slickline logging operations before some or all of the tubulars have been secured within the wellbore, and/or before the wellbore  203  is completed. As another example, multiple seismic sources  215  may be used in conjunction with system  200  and DAS system  212 . Moreover, components may be added to or removed from system  200  without departing from the scope of the present disclosure. 
         [0024]      FIG. 3  illustrates an example DAS data collection system  300 , in accordance with embodiments of the present disclosure. DAS data collection system  300  may be used for measuring dynamic strain, acoustics, or vibration downhole in a completed well system such as completed well system  200  of  FIG. 2 . For example, DAS data collection system  300  may be coupled to components of completed well system similar to completed well system  200  in order to detect disturbances in the system and/or seismic information for the surrounding formation. 
         [0025]    DAS data collection system  300  comprises DAS box (optoelectronic interrogator)  301  coupled to sensing fiber  330 . DAS box  301  may be a physical container that comprises optical components suitable for performing DAS techniques using optical signals  312  transmitted through sensing fiber  330 , including signal generator  310 , circulators  320 , coupler  340 , mirrors  350   a - 350   b,  photodetectors  360   a - 360   c,  and information handling system  370  (all of which are communicably coupled with optical fiber), while sensing fiber  330  may be any suitable optical fiber for performing DAS measurements. DAS box  301  and sensing fiber  330  may be located at any suitable location for detecting disturbances or vibrations. For example, in some embodiments, DAS box  301  may be located at the surface of the wellbore with sensing fiber  330  coupled to one or more components of the drilling system, such as a mud pump, a mud return tube, and a drill string. 
         [0026]    Signal generator  310  may include a laser and associated opto-electronics for generating optical signals  312  that travel down sensing fiber  330 . Signal generator  310  may be coupled to one or more circulators  320  inside DAS box  301 . In certain embodiments, optical signals  312  from signal generator  310  may be amplified using optical gain elements, such as any suitable amplification mechanisms including, but not limited to, Erbium Doped Fiber Amplifiers (EDFAs) or Semiconductor Optical Amplifiers (SOAs). Optical signals  312  may be highly coherent, narrow spectral line width interrogation light signals in particular embodiments. 
         [0027]    As optical signals  312  travel down sensing fiber  330  as illustrated in  FIG. 3 , imperfections in the sensing fiber  330  may cause portions of the light to be backscattered along the sensing fiber  330  due to Rayleigh scattering. Scattered light according to Rayleigh scattering is returned from every point along the sensing fiber  330  along the length of the sensing fiber  330  and is shown as backscattered light  314  in  FIG. 3 . This backscatter effect may be referred to as Rayleigh backscatter. Density fluctuations in the sensing fiber  330  may give rise to energy loss due to the scattered light, with the following coefficient: 
         [0000]    
       
         
           
             
               α 
               scat 
             
             = 
             
               
                 
                   8 
                    
                   
                     π 
                     3 
                   
                 
                 
                   3 
                    
                   
                     λ 
                     4 
                   
                 
               
                
               
                 n 
                 8 
               
                
               
                 p 
                 2 
               
                
               
                 kT 
                 f 
               
                
               β 
             
           
         
       
     
         [0000]    where n is the refraction index, p is the photoelastic coefficient of the sensing fiber  230 , k is the Boltzmann constant, and is the isothermal compressibility. T 1  is a fictive temperature, representing the temperature at which the density fluctuations are “frozen” in the material. In certain embodiments, sensing fiber  330  may be terminated with low reflection device  331 . In some embodiments, the low reflection device may be a fiber coiled and tightly bent such that all the remaining energy leaks out of the fiber due to macrobending. In other embodiments, low reflection device  331  may be an angle cleaved fiber. In still other embodiments, the low reflection device  331  may be a coreless optical fiber. In still other embodiments, low reflection device  331  may be a termination, such as an AFL ENDLIGHT. In still other embodiments, sensing fiber  330  may be terminated in an index matching gel or liquid. 
         [0028]    Backscattered light  314  may consist of an optical light wave or waves with a phase that is altered by changes to the optical path length at some location or locations along sensing fiber  330  caused by vibration or acoustically induced strain. By sensing the phase of the backscattered light signals, it is possible to quantify the vibration or acoustics along sensing fiber  330 . An example method of detecting the phase of the backscattered light is through the use of a 3×3 coupler, as illustrated in  FIG. 3  as coupler  340 . Backscattered light  314  travels through circulator  320  toward coupler  340 , which may split backscattered light  314  among at least two paths (i.e., paths α and β in  FIG. 3 ). One of the two paths may comprise an additional length L beyond the length of the other path. The split backscattered light  314  may travel down each of the two paths, and then be reflected by mirrors  350   a - 350   b.  Mirrors  350  may include any suitable optical reflection device, such as a Faraday rotator mirror. The reflected light from mirrors  350  may then be combined in coupler  340  and passed toward photodetectors  360   a - 360   c.  The backscattered light signal at each of photodetectors  360   a - 360   c  will contain the interfered light signals from the two paths (α and β ), with each signal having a relative phase shift of  120  degrees from the others. The signals at photodetectors  360   a - 360   c  may be passed to information handling system  370  for analysis. Information handling system  370  may be located at any suitable location, and may be located downhole, uphole (e.g., in control unit  210  of  FIG. 2 ), or in a combination thereof. In particular embodiments, information handling system  370  may measure the interfered signals at photodetectors  360   a - 360   c  having three different relative phase shifts of 0, +120, and −120 degrees, and accordingly determine the phase difference between the backscattered light signals along the two paths. This phase difference determined by information handling system  370  may be used to measure strain on sensing fiber  330  caused by vibrations in a formation. By sampling the signals at photodetectors  360   a - 360   c  at a high sample rate, various regions along sensing fiber  330  may be sampled, with each region being the length of the path mismatch L between paths α and β. 
         [0029]    The below equations may define the light signal received by photodetectors  360   a - 360   c:    
         [0000]    
       
         
           
             a 
             = 
             
               k 
               + 
               
                 
                   P 
                   α 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       2 
                        
                       π 
                        
                       
                           
                       
                        
                       ft 
                     
                     ) 
                   
                 
               
               + 
               
                 
                   P 
                   β 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       
                         2 
                          
                         π 
                          
                         
                             
                         
                          
                         ft 
                       
                       + 
                       φ 
                     
                     ) 
                   
                 
               
             
           
         
       
       
         
           
             b 
             = 
             
               k 
               + 
               
                 
                   P 
                   α 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       2 
                        
                       π 
                        
                       
                           
                       
                        
                       ft 
                     
                     ) 
                   
                 
               
               + 
               
                 
                   P 
                   β 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       
                         2 
                          
                         π 
                          
                         
                             
                         
                          
                         ft 
                       
                       + 
                       φ 
                       + 
                       
                         
                           2 
                            
                           π 
                         
                         3 
                       
                     
                     ) 
                   
                 
               
             
           
         
       
       
         
           
             c 
             = 
             
               k 
               + 
               
                 
                   P 
                   α 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       2 
                        
                       π 
                        
                       
                           
                       
                        
                       ft 
                     
                     ) 
                   
                 
               
               + 
               
                 
                   P 
                   β 
                 
                  
                 
                   cos 
                    
                   
                     ( 
                     
                       
                         2 
                          
                         π 
                          
                         
                             
                         
                          
                         ft 
                       
                       + 
                       φ 
                       - 
                       
                         
                           2 
                            
                           π 
                         
                         3 
                       
                     
                     ) 
                   
                 
               
             
           
         
       
     
         [0000]    where a represents the signal at photodetector  360   a,  b represents the signal at photodetector  360   b,  c represents the signal at photodetector  360   c,  f represents the optical frequency of the light signal, φ=optical phase difference between the two light signals from the two arms of the interferometer, P α  and P β  represent the optical power of the light signals along paths α and β, respectively, and k represents the optical power of non-interfering light signals received at the photodetectors (which may include noise from an amplifier and light with mismatched polarization which will not produce an interference signal). In embodiments where photodetectors  360   a - 360   c  are square law detectors with a bandwidth much lower than the optical frequency (e.g., less than 1 GHz), the signal obtained from the photodetectors may be approximated by the below equations: 
         [0000]    
       
         
           
             A 
             = 
             
               
                 1 
                 2 
               
                
               
                 ( 
                 
                   
                     2 
                      
                     
                         
                     
                      
                     
                       k 
                       2 
                     
                   
                   + 
                   
                     P 
                     α 
                     2 
                   
                   + 
                   
                     2 
                      
                     
                         
                     
                      
                     
                       P 
                       α 
                     
                      
                     
                       P 
                       β 
                     
                      
                     
                       cos 
                        
                       
                         ( 
                         φ 
                         ) 
                       
                     
                   
                   + 
                   
                     P 
                     β 
                     2 
                   
                 
                 ) 
               
             
           
         
       
       
         
           
             B 
             = 
             
               
                 1 
                 2 
               
                
               
                 ( 
                 
                   
                     2 
                      
                     
                         
                     
                      
                     
                       k 
                       2 
                     
                   
                   + 
                   
                     P 
                     α 
                     2 
                   
                   + 
                   
                     P 
                     β 
                     2 
                   
                   - 
                   
                     
                       P 
                       α 
                     
                      
                     
                       
                         P 
                         β 
                       
                        
                       
                         ( 
                         
                           
                             cos 
                              
                             
                               ( 
                               φ 
                               ) 
                             
                           
                           + 
                           
                             
                               3 
                             
                              
                             
                               sin 
                                
                               
                                 ( 
                                 φ 
                                 ) 
                               
                             
                           
                         
                         ) 
                       
                     
                   
                 
                 ) 
               
             
           
         
       
       
         
           
             C 
             = 
             
               
                 1 
                 2 
               
                
               
                 ( 
                 
                   
                     2 
                      
                     
                         
                     
                      
                     
                       k 
                       2 
                     
                   
                   + 
                   
                     P 
                     α 
                     2 
                   
                   + 
                   
                     P 
                     β 
                     2 
                   
                   + 
                   
                     
                       P 
                       α 
                     
                      
                     
                       
                         P 
                         β 
                       
                        
                       
                         ( 
                         
                           
                             - 
                             
                               cos 
                                
                               
                                 ( 
                                 φ 
                                 ) 
                               
                             
                           
                           + 
                           
                             
                               3 
                             
                              
                             
                               sin 
                                
                               
                                 ( 
                                 φ 
                                 ) 
                               
                             
                           
                         
                         ) 
                       
                     
                   
                 
                 ) 
               
             
           
         
       
     
         [0000]    where A represents the approximated signal at photodetector  360   a,  B represents the approximated signal at photodetector  360   b,  and C represents the approximated signal at photodetector  360   c.  It will be understood by those of skill in the art that the terms in the above equations that contain φ are the terms that provide relevant information about the optical phase difference since the remaining terms involving the power (k, P α , and P β ) do not change as the optical phase changes. The terms above and the structure of the DAS system in which they are utilized are not intended to be limiting, however, as this is only one of many possible DAS systems. 
         [0030]    In particular embodiments, quadrature processing may be used to determine the phase shift between the two signals. A quadrature signal may refer to a two-dimensional signal whose value at some instant in time can be specified by a single complex number having two parts: a real (or in-phase) part and an imaginary (or quadrature) part. Quadrature processing may refer to the use of the quadrature detected signals at photodetectors  360   a - 360   c.  For example, a phase modulated signal y(t) with amplitude A, modulating phase signal  0 (t), and constant carrier frequency fmay be represented as: 
         [0000]        y ( t )= A  sin(2πft+θ( t ))
 
         [0000]    or 
         [0000]        y ( t )= I ( t ) sin(2πft)+ Q ( t )cos(2πft)
 
         [0000]    where 
         [0000]        I ( t )≡ A  cos(θ( t ))
 
         [0000]        Q ( t )≡ A  sin(θ( t ))
 
         [0000]    Mixing the signal y(t) with a signal at the carrier frequency f results in a modulated signal at the baseband frequency and at 2f, wherein the baseband signal may be represented as follows: 
         [0000]        y ( t ) e   iθ(t)   =I ( t )+ i*Q ( t ) 
         [0000]    Because the Q term is shifted by 90 degrees from the I term above, the Hilbert transform may be performed on the I term to get the Q term. Thus, where          (·) represents the Hilbert transform: 
         [0000]        Q ( t )=         ( I ( t )) 
         [0031]    The amplitude and phase of the signal may be represented by the following equations: 
         [0000]    
       
         
           
             
                
               
                 y 
                  
                 
                   ( 
                   t 
                   ) 
                 
               
                
             
             = 
             
               
                 
                   
                     I 
                      
                     
                       ( 
                       t 
                       ) 
                     
                   
                   2 
                 
                 + 
                 
                   
                     Q 
                      
                     
                       ( 
                       t 
                       ) 
                     
                   
                   2 
                 
               
             
           
         
       
       
         
           
             
               θ 
                
               
                 ( 
                 t 
                 ) 
               
             
             = 
             
               arctan 
                
               
                 ( 
                 
                   
                     Q 
                      
                     
                       ( 
                       t 
                       ) 
                     
                   
                   
                     I 
                      
                     
                       ( 
                       t 
                       ) 
                     
                   
                 
                 ) 
               
             
           
         
       
     
         [0032]    It will be understood by those of skill in the art that for signals A, B, and C above, the corresponding quadrature I and Q terms may be represented by the following equations: 
         [0000]    
       
         
           
             I 
             = 
             
               
                 A 
                 + 
                 B 
                 - 
                 
                   2 
                    
                   
                       
                   
                    
                   C 
                 
               
               = 
               
                 
                   
                     3 
                     2 
                   
                    
                   
                     P 
                     α 
                   
                    
                   
                     
                       P 
                       β 
                     
                      
                     
                       ( 
                       
                         
                           cos 
                            
                           
                             ( 
                             φ 
                             ) 
                           
                         
                         - 
                         
                           
                             3 
                           
                            
                           
                             sin 
                              
                             
                               ( 
                               φ 
                               ) 
                             
                           
                         
                       
                       ) 
                     
                   
                 
                 = 
                 
                   3 
                    
                   
                       
                   
                    
                   
                     P 
                     α 
                   
                    
                   
                     P 
                     β 
                   
                    
                   
                     cos 
                      
                     
                       ( 
                       
                         φ 
                         + 
                         
                           π 
                           3 
                         
                       
                       ) 
                     
                   
                 
               
             
           
         
       
       
         
           
             Q 
             = 
             
               
                 
                   3 
                 
                  
                 
                   ( 
                   
                     A 
                     - 
                     B 
                   
                   ) 
                 
               
               = 
               
                 
                   
                     3 
                     2 
                   
                    
                   
                     P 
                     α 
                   
                    
                   
                     
                       P 
                       β 
                     
                      
                     
                       ( 
                       
                         
                           
                             3 
                           
                            
                           
                             cos 
                              
                             
                               ( 
                               φ 
                               ) 
                             
                           
                         
                         + 
                         
                           sin 
                            
                           
                             ( 
                             φ 
                             ) 
                           
                         
                       
                       ) 
                     
                   
                 
                 = 
                 
                   3 
                    
                   
                       
                   
                    
                   
                     P 
                     α 
                   
                    
                   
                     P 
                     β 
                   
                    
                   
                     sin 
                      
                     
                       ( 
                       
                         φ 
                         + 
                         
                           π 
                           3 
                         
                       
                       ) 
                     
                   
                 
               
             
           
         
       
     
         [0000]    wherein the phase shift, which is shifted by π/3, is represented by: 
         [0000]    
       
         
           
             φ 
             = 
             
               
                 arctan 
                  
                 
                   ( 
                   
                     Q 
                     I 
                   
                   ) 
                 
               
               - 
               
                 π 
                 3 
               
             
           
         
       
     
         [0033]    Accordingly, the phase of the backscattered light in sensing fiber  330  may be determined using the quadrature representations of the DAS data signals received at photodetectors  360 . This allows for an elegant way to arrive at the phase using the quadrature signals inherent to the DAS data collection system. 
         [0034]    Modifications, additions, or omissions may be made to  FIG. 3  without departing from the scope of the present disclosure. For example,  FIG. 3  shows a particular configuration of components of system  300 . However, any suitable configuration of components configured to detect the optical phase and/or amplitude of coherent Rayleigh backscatter in optical fiber using spatial multiplexing (i.e., monitoring different locations, or channels, along the length of the fiber) may be used. For example, although optical signals  312  are illustrated as pulses, DAS data collection system  300  may transmit continuous wave optical signals  312  down sensing fiber  330  instead of, or in addition to, optical pulses. As another example, the measurement of acoustic disturbances in the optical fiber may be accomplished using FBGs embedded in the optical fiber. As yet another example, an interferometer may be placed in the launch path (i.e., in a position that splits and interferes optical signals  312  prior to traveling down sensing fiber  330 ) of the interrogating signal (i.e., the transmitted optical signal  312 ) to generate a pair of signals that travel down sensing fiber  330 , as opposed to the use of an interferometer further downstream as shown in  FIG. 3 . 
         [0035]    Turning now to the fiber optic sensors,  FIGS. 4A-4B  illustrate example fiber-wrapped sensors in accordance with embodiments of the present disclosure.  FIG. 4A  illustrates an example portion of a fiber optic cable  401  that has been wrapped repeatedly, in no preferred direction, around a sphere  402 . The fiber optic cable may be coupled with a DAS system ( 330  of  FIG. 3 ). The sensor may consist of one or more fiber optic cables  401  that have no preferred directionality. The cable  401 &#39;s diameter should be smaller than the acoustic wavelengths of interest. The cable  401  should be wrapped around a sphere  402  with a smaller diameter than the acoustic wavelengths of interest. The wrapping may be random or uniform. The cable  401  should be wrapped so as to measure three orthogonal directions. The sphere  402  may be made out of a compliant material. For example, the sphere may but are not required to be made out of thermoplastic polymers (TPU&#39;s) and thermoplastic elastomers (TPE&#39;s), which exhibit a combination of a low Young&#39;s modulus (E) and a low Poisson ratio (sigma). The Poisson&#39;s ratio may be preferably below 0.5, which is the Poisson&#39;s ratio of natural rubber.  FIG. 5  illustrates another example in accordance with the present disclosure, wherein the fiber optic cable  501  may be wrapped around a spheroid  502 , instead of a sphere ( 402  of  FIG. 4 ), as long as the same wrapping parameters are achieved. 
         [0036]      FIG. 4B  illustrates another exemplary embodiment of the fiber optic sensors in accordance with the present disclosure, wherein a pair of reflecting elements  403  is placed at each end of the sphere  402  where the fiber  401  enters and exits. This configuration enhances the signal-to-noise (SNR) ratio of the sensor. The reflecting elements  403  may be FBGs or any other refractive index change mechanism that generates a reflection. In particular embodiments, the sensors may be multiplexed by time division (TDM), wavelength division (WDM), or both. 
         [0037]      FIGS. 6A-6B  illustrate example embodiments of fiber optic sensors in accordance with the present disclosure that utilize reflecting elements to create a multiplexed sensor configuration.  FIG. 6A  illustrates an exemplary embodiment wherein a plurality of fiber-wrapped spheres  602  are placed along the fiber optic cable so as to create a multiplexed configuration. Partial reflectors  605  are placed on the surface of the fiber optic cable between the each of the fiber-wrapped spheres  602 .  FIG. 6B  illustrates an example of multiplexing using FBGs  604  placed between each of the plurality of fiber-wrapped spheres  602 . With TDM, the light pulse  606  travels down the cable, reflecting off the reflectors  605  or FBGs  604 . The optical circulator  607  separates the incoming light for processing  608  by a DAS system, an example of which is shown and described in connection with  FIG. 3 . With WDM, the different reflectors  605  or FBGs  604  may reflect different wavelengths of light. The TDM and WDM methods may be combined to achieve higher numbers of sensors than would be possible with either method individually. 
         [0038]    In particular embodiments, the sensors may be tethered to a marine vessel in order to detect disturbances in marine environments.  FIG. 7  illustrates an example of a fiber optic cable  701  wrapped around a one or more spheres  702  tethered to a marine vessel  703 . The DAS may be located on the marine vessel  703 . In particular embodiments, in addition to detecting strain and vibrations, DAS may also be used to detect parameters related to strain. For instance, changes in temperature ( 106  of  FIG. 1 ) may induce disturbances that can be detected by the DAS. Wrapping fiber optic cable ( 401  of  FIG. 4A ) around the sphere ( 402  of  FIG. 4A ) or spheroid ( 502  of  FIG. 5 ) improves detection of those parameters related to strain, such as temperature. 
         [0039]      FIG. 8  illustrates a block diagram of an exemplary computing system  800  for use with drilling system  200  of  FIG. 2 , or DAS data collection system  300  of  FIG. 3 , in accordance with embodiments of the present disclosure. Computing system  800  or components thereof can be located at the surface (e.g., in control unit  210  of  FIG. 2 ), downhole (e.g., in BHA  206  and/or in LWD/MWD apparatus  207  of  FIG. 2 ), or some combination of both locations (e.g., certain components may be disposed at the surface while certain other components may be disposed downhole, with the surface components being communicatively coupled to the downhole components). If the fiber optic cable and spheres are tethered to a marine vessel, the computing system  800  may be located on the marine vessel ( 703  of  FIG. 7 ). 
         [0040]    Computing system  800  may be configured to detect vibrations or disturbances, in a downhole drilling system, in accordance with the teachings of the present disclosure. In particular embodiments, computing system  800  may include acoustic detection module  802 . Acoustic detection module  802  may include any suitable components. For example, in some embodiments, acoustic detection module  802  may include processor  804 . Processor  804  may include, for example a microprocessor, microcontroller, digital signal processor (DSP), application specific integrated circuit (ASIC), or any other digital or analog circuitry configured to interpret and/or execute program instructions and/or process data. In some embodiments, processor  804  may be communicatively coupled to memory  806 . Processor  804  may be configured to interpret and/or execute program instructions or other data retrieved and stored in memory  806 . Program instructions or other data may constitute portions of software  808  for carrying out one or more methods described herein. Memory  806  may include any system, device, or apparatus configured to hold and/or house one or more memory modules; for example, memory  806  may include read-only memory (ROM), random access memory (RAM), solid state memory, or disk-based memory. Each memory module may include any system, device or apparatus configured to retain program instructions and/or data for a period of time (e.g., computer-readable non-transitory media). For example, instructions from software  808  may be retrieved and stored in memory  806  for execution by processor  804 . 
         [0041]    In particular embodiments, acoustic detection module  802  may be communicatively coupled to one or more displays  810  such that information processed by acoustic detection module  802  may be conveyed to operators of drilling equipment. For example, acoustic detection module  802  may convey information related to the detection of acoustics (e.g., timing between the detected mud pulses) to display  810 . 
         [0042]    Modifications, additions, or omissions may be made to  FIG. 8  without departing from the scope of the present disclosure. For example,  FIG. 8  shows a particular configuration of components of computing system  800 . However, any suitable configurations of components may be used. For example, components of computing system  800  may be implemented either as physical or logical components. Furthermore, in some embodiments, functionality associated with components of computing system  800  may be implemented in special purpose circuits or components. In other embodiments, functionality associated with components of computing system  800  may be implemented in configurable general purpose circuit or components. For example, components of computing system  800  may be implemented by configured computer program instructions. 
         [0043]      FIG. 9  illustrates a schematic diagram of a wireline tool. At various times during the drilling process, the drill string ( 205  of  FIG. 2 ) may be removed from the wellbore  916  ( 203  of  FIG. 2 ). Once the drill string ( 205  of  FIG. 2 ) has been removed, measurement/logging operations can be conducted using a wireline tool  934 , i.e., an instrument that is suspended into the borehole  916  by a cable  915  having conductors for transporting power to the tool from a surface power source, and telemetry from the tool body to the surface. The wireline tool  934  may comprise electronic components similar to the electronic components described above. For instance, the wireline tool  934  may comprise logging and measurement elements  936 . The elements  936  may be communicatively coupled to the cable  915 . A logging facility  944  (shown in  FIG. 9  as a truck, although it may be any other structure) may collect measurements from the tool  936 , and may include computing facilities (including, e.g., a control unit/information handling system) for controlling, processing, storing, and/or visualizing the measurements gathered by the elements  936 . In certain embodiments, the elements  936  may include an acoustic sensor comprising a fiber optic cable wrapped around one or more spheres or spheroids, as described above. The sensor may be coupled with a DAS ( 300  of  FIG. 3 ), which may be located in the logging facility  934 . The computing facilities may be communicatively coupled to the elements  936  by way of the cable  915 . In certain embodiments, the computing system ( 800  of  FIG. 8 ) may serve as the computing facilities of the logging facility  944 . 
         [0044]      FIG. 10  illustrates an example completion assembly  1090  within the wellbore  1016 , according to aspects of the present disclosure. Once the wellbore  1016  reaches a desired depth, completion operations may be undertaken to prepare the wellbore  1016  to produce hydrocarbons. Completion operations may include, but are not limited to, hydraulic fracturing, perforation, and formation isolation. In order to detect disturbances along the completion assembly  1090 , a fiber optic cable wrapped around a plurality of spheres or spheroids may be attached to the completion assembly  1090  and used as a sensor. As depicted, the assembly  1090  includes a production tubular  1060  coupled between the surface (not shown) of the formation  1018 , and completion stages  1062  and  1064 . The completion stages  1062  and  1064  may but are not required to comprise portions of the wellbore  1016  and formation  1018  isolated by packers  1066 - 70 . As depicted, each completion stage  1062  and  1064  isolates a fractured portion of the formation  1018 . Stage  1062 , for instance, comprises at least one remotely actuatable valve  1072  that selectively isolates the fractured portion  1074  of the formation  1018  from the production tubular  1060 . As depicted, one or more control lines may extend from the valve  1072  to the surface to provide control of the valve  1072 . The valve  1072  may comprise an electrical component. The completion stages  1062  and  1064  as well as other completion tools may comprise electrical components similar to the ones described above. When opened, the valve  1072  may provide fluid communication between the fracture  1074  and the production tubular, such that hydrocarbons may be produced to the surface. 
         [0045]    An omnidirectional sensing system, comprising a fiber optic cable wrapped around at least one sphere, a light source coupled to the fiber optic cable, and an optoelectronic interrogator coupled to the fiber optic cable is disclosed. An omnidirectional sensing system, comprising a fiber optic cable wrapped around at least one spheroid, in no preferred direction, the spheroid forming an acoustic sensor, a light source coupled to the fiber optic cable, and an optoelectronic interrogator coupled to the fiber optic cable is also disclosed. A method of sensing a disturbance and its location, comprising directing a light source into a fiber optic cable which is wrapped around at least one sphere or at least one spheroid in no preferred direction, detecting reflected light with an optoelectronic interrogator, and analyzing and recording the disturbance and its location based on the time domain information collected by the interrogator is also disclosed. 
         [0046]    In any of the embodiments described in this or the preceding paragraph, the omnidirectional sensing system may comprise a plurality of spheres around which the fiber optic cable is wrapped. In any of the embodiments described in this or the preceding paragraph, the plurality of spheres may be disposed downhole within a wellbore of a subterranean formation. In any of the embodiments described in this or the preceding paragraph, the plurality of spheres may be tethered to a marine vessel. In any of the embodiments described in this or the preceding paragraph, the fiber optic cable may form an acoustic antenna and at least one sphere may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding paragraph, the fiber optic cable may form a sensor to detect changes in temperature and at least one sphere may enhance sensitivity of the sensing system. In any of the embodiments described in this or the preceding paragraph, the fiber optic cable may form a vibration sensor and at least one sphere may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding paragraph, the fiber optic cable may form a pressure sensor and at least one sphere may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding paragraph, the optoelectronic interrogator may be remote from at least one of the spheres. 
         [0047]    In any of the embodiments described in this or the preceding two paragraphs, the omnidirectional sensing system may comprise a plurality of spheroids around which the fiber optic cable is wrapped. In any of the embodiments described in this or the preceding two paragraphs, the plurality of spheroids may be disposed downhole within a wellbore of a subterranean formation. In any of the embodiments described in this or the preceding two paragraphs, the plurality of spheroids may be tethered to a marine vessel. In any of the embodiments described in this or the preceding two paragraphs, the fiber optic cable may form an acoustic antenna and at least one spheroid may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding two paragraphs, the fiber optic cable may form a sensor to detect changes in temperature and at least one spheroid may enhance sensitivity of the sensing system. In any of the embodiments described in this or the preceding two paragraphs, the fiber optic cable may form a vibration sensor and at least one spheroid may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding two paragraphs, the fiber optic cable may form a pressure sensor and at least one spheroid may enhance the sensitivity of the sensing system. In any of the embodiments described in this or the preceding two paragraphs, the optoelectronic interrogator may be remote from at least one of the spheroids. 
         [0048]    In any of the embodiments described in this or the preceding three paragraphs, reflected light may be detected by detecting coherent Rayleigh backscatter from the fiber optic cable. In any of the embodiments described in this or the preceding three paragraphs, reflected light may be detected by detecting light reflected from Bragg gratings distributed along the fiber optic cable. In any of the embodiments described in this or the preceding three paragraphs, light may be detected by detecting light reflected from fiber optic partial mirrors distributed along the fiber optic cable. 
         [0049]    Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the specific implementation goals, which may vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure. 
         [0050]    The terms “couple” or “couples” as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical or mechanical connection via other devices and connections. The term “upstream” as used herein means along a flow path towards the source of the flow, and the term “downstream” as used herein means along a flow path away from the source of the flow. The term “uphole” as used herein means along the drill string or the hole from the distal end towards the surface, and “downhole” as used herein means along the drill string or the hole from the surface towards the distal end. 
         [0051]    The present disclosure is therefore well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.