Patent Document

BACKGROUND 
     In downhole exploration and geologic resource recovery efforts, the ability to obtain information about the conditions of the environment and the status of the equipment downhole can be helpful in making decisions. For example, information indicating imminent failure of equipment may lead to actions that mitigate costly consequences of the failure. Many sensors and measurement devices (e.g., temperature and pressure sensors) are currently used downhole. Additional monitoring and measurement techniques would be appreciated by the drilling industry. 
     SUMMARY 
     According to one aspect of the invention, a system to perform distributed downhole acoustic sensing in a borehole includes an optical fiber comprising at least one reflector; a tunable laser configured to perform a transmission of a range of wavelengths through the optical fiber; a receiver configured to receive an interferometer signal resulting from the transmission; and a processor configured to determine a component of the interferometer signal. 
     According to another aspect of the invention, a method of performing distributed downhole acoustic sensing in a borehole includes arranging an interferometer in the borehole, the interferometer coupled to a component of interest; obtaining an interferometer signal from the interferometer; and processing the interferometer signal to determine information regarding the component of interest. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Referring now to the drawings wherein like elements are numbered alike in the several Figures: 
         FIG. 1  is a cross-sectional illustration of a borehole including a distributed acoustic sensor system according to an embodiment of the invention; 
         FIG. 2  details one embodiment is which a distributed acoustic sensor system is used to monitor machinery; 
         FIG. 3  details one embodiment in which a distributed acoustic sensor system is used to monitor a sandscreen; 
         FIGS. 4 to 8  relate to the processing performed on interferometer output according to embodiments of the invention; 
         FIG. 9  depicts another embodiment of the distributed acoustic sensor system using fiber Bragg gratings (FBGs); 
         FIG. 10  depicts another embodiment of the distributed acoustic sensor system using Rayleigh backscatter; and 
         FIG. 11  is a flow diagram of an exemplary method of using distributed downhole acoustic sensing. 
     
    
    
     DETAILED DESCRIPTION 
     High frequency acoustic signals (e.g., from machine vibrations, flow) can provide valuable information about the status of the borehole and of machinery in the borehole. Embodiments of the invention described herein relate to measuring distributed acoustic signals to not only detect but also localize desired information. 
       FIG. 1  is a cross-sectional illustration of a borehole  1  including a distributed acoustic sensor system  100  according to an embodiment of the invention. A borehole  1  penetrates the earth  3  including a formation  4 . A set of tools  10  may be lowered into the borehole  1  by a string  2 . In embodiments of the invention, the string  2  may be a casing string, production string, an armored wireline, a slickline, coiled tubing, or a work string. In measure-while-drilling (MWD) embodiments, the string  2  may be a drill string, and a drill would be included below the tools  10 . Information from the sensors and measurement devices included in the set of tools  10  may be sent to the surface for processing by the surface processing system  130  via a fiber link or telemetry. The distributed acoustic sensor system  100  includes an optical fiber  110 . In the embodiment shown in  FIG. 1 , the optical fiber  110  includes point reflectors  115 . As indicated in  FIG. 1 , the three exemplary point reflectors  115  make up two interferometers  117   a  and  117   b . The distributed acoustic sensor system  100  also includes a tunable laser  120 , shown at the surface of the earth  3  in  FIG. 1 . 
       FIG. 2  details one embodiment in which the distributed acoustic sensor system  100  is used to monitor machinery  210 . The machinery may be, for example, a submersible pump. In the embodiment shown in  FIG. 2 , the optical fiber  110  has point reflectors  115  on it that are coupled to the machinery  210 . Each set of the point reflectors  115  shown in  FIG. 2  are, for example, 10-20 cm apart and comprise a Fabry-Perot interferometer. In alternate embodiments, the interferometer  117  may be a Michelson interferometer or a Mach-Zehnder interferometer rather than a Fabry-Perot interferometer. Each interferometer  117  comprised of a set of the point reflectors  115  in the present embodiment monitors the machinery  210  in the following way. The tunable laser  120  emits a range of sequential wavelengths over some finite time interval. The return signals from a pair of the point reflectors  115 , with no other contributing component, would interfere with each other to generate a sine wave pattern whose frequency reflects the spacing of the point reflectors  115  (i.e. each interferometer  117  output would be a sine wave pattern). In a real world scenario, the signal received at the surface from each interferometer  117  comprised of a set of the point reflectors  115  will not be a pure sine wave pattern but will, instead, include other signal components contributed by the vibration of the machinery  210  to which the point reflectors  115  are coupled, as well as signal components due to non-linear tuning of the tunable laser  120 . Embodiments using a tunable laser  120  with a linear tuning characteristic avoid these contributing signal components. Thus, by knowing the spacing between the point reflectors  115  in an interferometer  117 , the surface processing system  130  can determine the interference component or the component of acoustic signal attributable to the machinery  210  to which the point reflectors  115  are coupled. That is, with the sine wave as a carrier, the phase shift caused by the machinery  210  vibration can be thought of as a modulation of the carrier, and the modulation can be processed and determined as detailed below. Over time, by monitoring this vibration component of the machinery  210 , changes (e.g., an increase in vibration) can be determined and dealt with. For example, if a rapid increase in the vibrational component of the machinery  210  is determined, it may indicate an imminent failure in the machinery  210 . 
       FIG. 3  details one embodiment of using the distributed acoustic sensor system  100  to monitor a sandscreen  310 . The optical fiber  110  may be directly coupled to the sandscreen  310  or may be coupled to the sandscreen  310  through another component  320  (e.g., Fiber Express Tube™). The tunable laser  120  sweeps a range of wavelengths over a time interval as in the embodiment discussed with reference to  FIG. 2 . The resulting interferometer signal (where the interferometer  117  is comprised of the pair of the point reflectors  115  in the embodiment shown in  FIG. 3 ) includes a component due to flow through the sandscreen  310 . That is, just as vibration of the machinery  210  modulated the sine pattern generated by a reflection of the tunable laser  120  output by the point reflectors  115  in the embodiment shown in  FIG. 2 , flow of formation fluid through the sandscreen  310  modulates the sine pattern and can be processed and detected by the surface processing system  130 . For example, a pipe the length of 100 feet may cover a reservoir. By using the distributed acoustic sensor system  100 , the flow of oil can be localized along the pipe. The processing of the interferometer signal to determine the component attributable to the disturbance (e.g., vibration, flow) according to the embodiments shown in  FIGS. 2 and 3  is detailed next. 
       FIGS. 4-8  detail the processing of an exemplary interferometer signal received by the distributed acoustic sensor system  100 . The processing may be executed by the surface processing system  130 , for example.  FIG. 4  shows an exemplary received signal  410  for a period of time (x-axis  420 ). Amplitude is shown on the y-axis ( 430 ). The exemplary received signal  410  includes interferometer output for a single interferometer  117  but a received signal  410  in a distributed acoustic sensor system  100  that includes more interferometers  117  will include more interferometer outputs. A Fourier transform is taken of the received signal  410  to provide the signal  510  in the frequency domain (x-axis  520 ). The component  530 , as well as portions of the signal  510 , are generated because of non-linear characteristics of the tunable laser  120 . If the interferometer output resulted from a tunable laser  120  with linear tuning characteristics, the component  530  (and contributions to the signal  510 ) would not be present. As noted with regard to  FIG. 4 , a distributed acoustic sensor system  100  with two or more interferometers  117  would receive two or more interferometer outputs and, thus, would include two or more signals  510  in the frequency domain. 
     A bandpass filter is used to isolate each of the signals  510 , and then an inverse Fourier transform is taken of each isolated signal  510  to provide the exemplary complex signal (real component  610  and imaginary component  620 ) in the time domain (x-axis  630 ) shown in  FIG. 6 . To be clear, when more than one interferometer  117  is used by the distributed acoustic sensor system  100 , more than one bandpass filter would be needed, and the processing discussed with reference to  FIGS. 7 and 8  would be done for outputs of each of the interferometers  117 . By taking the arc tangent of (the real component  610 /the imaginary component  620 ) and then performing phase unwrapping on the resulting phase, the phase  710  and phase modulation  720  over time (x-axis  730 ) result, as shown in  FIG. 7 . The phase modulation  720 , which is the portion of interest, reflects the contribution of the downhole parameter of interest (e.g., vibration, flow) to interferometer output and also the contribution of the tunable laser  120  when the tunable laser  120  does not have a linear tuning characteristic. Thus, if there were no vibration, flow, or other contribution to the interferometer output and the tunable laser  120  had linear tuning characteristics, the phase modulation  720  would be a flat line at 0. As noted above, the portion of interest is the phase modulation  720  because it includes the vibration or flow contribution to the interferometer output. 
     By performing a Fourier transform on the phase modulation  720 , the frequency (x-axis  820 ) and amplitude (y-axis  830 ) (shown on a log scale) of the vibration may be determined. In the exemplary case discussed with reference to  FIGS. 4-8 , the interferometer output includes a vibration component induced at 137 Hz.  FIG. 8  shows this component  810  at 137 Hz. By monitoring this output over time, changes in frequency and/or amplitude of vibration may be used to determine the condition of machinery (in the embodiment discussed with reference to  FIG. 2 ) or the initiation, increase, or decrease of flow (in the embodiment discussed with reference to  FIG. 3 ). In addition, the phase modulation  720  (indicating vibration or flow) can be localized within the borehole  1  in the following way. As noted above, when more than one interferometer  117  is used, the results shown in  FIGS. 7 and 8  are determined for each of the interferometers  117 . Thus, by noting which interferometer  117  output shows the vibration component ( 810 ), the location of flow, for example, can be determined based on the location of the point reflectors  115  that make up the particular interferometer  117 . Embodiments of the distributed acoustic sensor system  100  discussed below include additional types of interferometers  117  and discuss additional methods of determining the location of the interferometer  117 . In alternate embodiments, the distributed acoustic sensor system  100  discussed herein may be used for vertical seismic profiling or fracing in addition to vibration and flow monitoring. 
       FIG. 9  depicts another embodiment of the distributed acoustic sensor system  100  using fiber Bragg gratings (FBGs)  910 . In this embodiment, FBGs  910  rather than point reflectors  115  are used for the interferometer  117 . The FBGs  910  act as reflectors around the resonant wavelength of the Bragg grating. The number and distribution of the Bragg gratings may be varied to affect the reflective characteristic. As with the point reflectors  115 , the interferometer signal generated by the FBGs  910  is processed to isolate the phase perturbation caused by the target disturbance (e.g., vibration of machinery  210 , flow through sandscreen  310 ). 
       FIG. 10  depicts another embodiment of the distributed acoustic sensor system  100  using Rayleigh backscatter. This embodiment is based on the fact that, even without any reflector or Bragg grating along the optical fiber  110 , Rayleigh backscatter is generated at every point along the optical fiber  110 . With a reference reflector  1010  at a known location along the optical fiber  110 , each point on the optical fiber  110  acts as an interferometer  117  in conjunction with the reference reflector  1010 . By isolating a length of optical fiber (d′) within a certain distance (2*d) around the reference reflector  1010 , an area of interest (e.g., part of a machinery  210 , sandscreen  310 ) may be isolated for processing of the interferometer signal. For example, a 20 cm spacing within 500 m of the reference reflector  1010  may be isolated. The interferometer signal generated by the Rayleigh backscatter from the isolated length and the reference reflector  1010  may then be processed to determine the phase modulation. As discussed with reference to  FIGS. 2 and 3 , the phase modulation (processed as discussed with reference to  FIGS. 4-8 ) indicates the vibration in the case of the area of interest being part of a machinery  210  (like a submersible pump) or flow in the case of the area of interest being part of a sandscreen  310 . As shown, the reference reflector  1010  is a point reflector  115 . In other embodiments, the reference reflector  1010  may be an FBG  910 . 
     A reference reflector may be used in conjunction with the point reflectors  115  or FBGs  910  discussed with reference to  FIGS. 2, 3, and 6 , as well. That is, when more than two point reflectors  115  or FBGs  910  are used, the spacing between adjacent point reflectors  115  or FBGs  910  is varied so that a given pair of the point reflectors  115  or FBGs  910  has a unique distance between them and is thereby distinguishable from any other pair along the optical fiber  110 . However, to determine where along the optical fiber  110  a given pair of point reflectors  115  or FBGs  910  is located, the point reflectors  115  or FBGs  910  may be placed at known locations (a priori knowledge) or a reference reflector  1010  may be used to make the determination. 
       FIG. 11  is a flow diagram of an exemplary method  1100  of using distributed downhole acoustic sensing. At block  1110 , arranging the interferometer includes arranging point reflectors  115  as discussed with reference to  FIGS. 2 and 3  or FBGs  910 , as discussed with reference to  FIG. 9 , with or without a reference reflector  1010 , or only including a reference reflector  1010  as discussed with reference to  FIG. 10 . At  1120 , obtaining the interferometer signal includes transmitting a range of wavelengths with a tunable laser  120  and receiving the interferometer signal. The interferometer signal may be received at the surface. At block  1130 , processing the interferometer signal to determine the information of interest includes determining the vibration and, over time, monitoring changes in vibrations of a part of a machinery  210  such as a submersible pump. Processing at block  1130  also includes determining flow at location of a sandscreen  310 . Processing at block  1130  also includes performing vertical seismic profiling or fracing. The processing at block  1130  may be in accordance with the discussion above with reference to  FIGS. 4-8 . 
     While one or more embodiments have been shown and described, modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustrations and not limitation.

Technology Category: g