A method and system to perform distributed downhole acoustic sensing in a borehole are described. The system includes an optical fiber comprising at least one reflector, and a tunable laser configured to perform a transmission of a range of wavelengths through the optical fiber. The system also includes a receiver configured to receive an interferometer signal resulting from the transmission, and a processor configured to determine a component of the interferometer signal.

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.

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. 1is a cross-sectional illustration of a borehole1including a distributed acoustic sensor system100according to an embodiment of the invention. A borehole1penetrates the earth3including a formation4. A set of tools10may be lowered into the borehole1by a string2. In embodiments of the invention, the string2may be a casing string, production string, an armored wireline, a slickline, coiled tubing, or a work string. In measure-while-drilling (MWD) embodiments, the string2may be a drill string, and a drill would be included below the tools10. Information from the sensors and measurement devices included in the set of tools10may be sent to the surface for processing by the surface processing system130via a fiber link or telemetry. The distributed acoustic sensor system100includes an optical fiber110. In the embodiment shown inFIG. 1, the optical fiber110includes point reflectors115. As indicated inFIG. 1, the three exemplary point reflectors115make up two interferometers117aand117b. The distributed acoustic sensor system100also includes a tunable laser120, shown at the surface of the earth3inFIG. 1.

FIG. 2details one embodiment in which the distributed acoustic sensor system100is used to monitor machinery210. The machinery may be, for example, a submersible pump. In the embodiment shown inFIG. 2, the optical fiber110has point reflectors115on it that are coupled to the machinery210. Each set of the point reflectors115shown inFIG. 2are, for example, 10-20 cm apart and comprise a Fabry-Perot interferometer. In alternate embodiments, the interferometer117may be a Michelson interferometer or a Mach-Zehnder interferometer rather than a Fabry-Perot interferometer. Each interferometer117comprised of a set of the point reflectors115in the present embodiment monitors the machinery210in the following way. The tunable laser120emits a range of sequential wavelengths over some finite time interval. The return signals from a pair of the point reflectors115, with no other contributing component, would interfere with each other to generate a sine wave pattern whose frequency reflects the spacing of the point reflectors115(i.e. each interferometer117output would be a sine wave pattern). In a real world scenario, the signal received at the surface from each interferometer117comprised of a set of the point reflectors115will not be a pure sine wave pattern but will, instead, include other signal components contributed by the vibration of the machinery210to which the point reflectors115are coupled, as well as signal components due to non-linear tuning of the tunable laser120. Embodiments using a tunable laser120with a linear tuning characteristic avoid these contributing signal components. Thus, by knowing the spacing between the point reflectors115in an interferometer117, the surface processing system130can determine the interference component or the component of acoustic signal attributable to the machinery210to which the point reflectors115are coupled. That is, with the sine wave as a carrier, the phase shift caused by the machinery210vibration 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 machinery210, 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 machinery210is determined, it may indicate an imminent failure in the machinery210.

FIG. 3details one embodiment of using the distributed acoustic sensor system100to monitor a sandscreen310. The optical fiber110may be directly coupled to the sandscreen310or may be coupled to the sandscreen310through another component320(e.g., Fiber Express Tube™). The tunable laser120sweeps a range of wavelengths over a time interval as in the embodiment discussed with reference toFIG. 2. The resulting interferometer signal (where the interferometer117is comprised of the pair of the point reflectors115in the embodiment shown inFIG. 3) includes a component due to flow through the sandscreen310. That is, just as vibration of the machinery210modulated the sine pattern generated by a reflection of the tunable laser120output by the point reflectors115in the embodiment shown inFIG. 2, flow of formation fluid through the sandscreen310modulates the sine pattern and can be processed and detected by the surface processing system130. For example, a pipe the length of 100 feet may cover a reservoir. By using the distributed acoustic sensor system100, 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 inFIGS. 2 and 3is detailed next.

FIGS. 4-8detail the processing of an exemplary interferometer signal received by the distributed acoustic sensor system100. The processing may be executed by the surface processing system130, for example.FIG. 4shows an exemplary received signal410for a period of time (x-axis420). Amplitude is shown on the y-axis (430). The exemplary received signal410includes interferometer output for a single interferometer117but a received signal410in a distributed acoustic sensor system100that includes more interferometers117will include more interferometer outputs. A Fourier transform is taken of the received signal410to provide the signal510in the frequency domain (x-axis520). The component530, as well as portions of the signal510, are generated because of non-linear characteristics of the tunable laser120. If the interferometer output resulted from a tunable laser120with linear tuning characteristics, the component530(and contributions to the signal510) would not be present. As noted with regard toFIG. 4, a distributed acoustic sensor system100with two or more interferometers117would receive two or more interferometer outputs and, thus, would include two or more signals510in the frequency domain.

A bandpass filter is used to isolate each of the signals510, and then an inverse Fourier transform is taken of each isolated signal510to provide the exemplary complex signal (real component610and imaginary component620) in the time domain (x-axis630) shown inFIG. 6. To be clear, when more than one interferometer117is used by the distributed acoustic sensor system100, more than one bandpass filter would be needed, and the processing discussed with reference toFIGS. 7 and 8would be done for outputs of each of the interferometers117. By taking the arc tangent of (the real component610/the imaginary component620) and then performing phase unwrapping on the resulting phase, the phase710and phase modulation720over time (x-axis730) result, as shown inFIG. 7. The phase modulation720, 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 laser120when the tunable laser120does not have a linear tuning characteristic. Thus, if there were no vibration, flow, or other contribution to the interferometer output and the tunable laser120had linear tuning characteristics, the phase modulation720would be a flat line at 0. As noted above, the portion of interest is the phase modulation720because it includes the vibration or flow contribution to the interferometer output.

By performing a Fourier transform on the phase modulation720, the frequency (x-axis820) and amplitude (y-axis830) (shown on a log scale) of the vibration may be determined. In the exemplary case discussed with reference toFIGS. 4-8, the interferometer output includes a vibration component induced at 137 Hz.FIG. 8shows this component810at 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 toFIG. 2) or the initiation, increase, or decrease of flow (in the embodiment discussed with reference toFIG. 3). In addition, the phase modulation720(indicating vibration or flow) can be localized within the borehole1in the following way. As noted above, when more than one interferometer117is used, the results shown inFIGS. 7 and 8are determined for each of the interferometers117. Thus, by noting which interferometer117output shows the vibration component (810), the location of flow, for example, can be determined based on the location of the point reflectors115that make up the particular interferometer117. Embodiments of the distributed acoustic sensor system100discussed below include additional types of interferometers117and discuss additional methods of determining the location of the interferometer117. In alternate embodiments, the distributed acoustic sensor system100discussed herein may be used for vertical seismic profiling or fracing in addition to vibration and flow monitoring.

FIG. 9depicts another embodiment of the distributed acoustic sensor system100using fiber Bragg gratings (FBGs)910. In this embodiment, FBGs910rather than point reflectors115are used for the interferometer117. The FBGs910act 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 reflectors115, the interferometer signal generated by the FBGs910is processed to isolate the phase perturbation caused by the target disturbance (e.g., vibration of machinery210, flow through sandscreen310).

FIG. 10depicts another embodiment of the distributed acoustic sensor system100using Rayleigh backscatter. This embodiment is based on the fact that, even without any reflector or Bragg grating along the optical fiber110, Rayleigh backscatter is generated at every point along the optical fiber110. With a reference reflector1010at a known location along the optical fiber110, each point on the optical fiber110acts as an interferometer117in conjunction with the reference reflector1010. By isolating a length of optical fiber (d′) within a certain distance (2*d) around the reference reflector1010, an area of interest (e.g., part of a machinery210, sandscreen310) may be isolated for processing of the interferometer signal. For example, a 20 cm spacing within 500 m of the reference reflector1010may be isolated. The interferometer signal generated by the Rayleigh backscatter from the isolated length and the reference reflector1010may then be processed to determine the phase modulation. As discussed with reference toFIGS. 2 and 3, the phase modulation (processed as discussed with reference toFIGS. 4-8) indicates the vibration in the case of the area of interest being part of a machinery210(like a submersible pump) or flow in the case of the area of interest being part of a sandscreen310. As shown, the reference reflector1010is a point reflector115. In other embodiments, the reference reflector1010may be an FBG910.

A reference reflector may be used in conjunction with the point reflectors115or FBGs910discussed with reference toFIGS. 2, 3, and 6, as well. That is, when more than two point reflectors115or FBGs910are used, the spacing between adjacent point reflectors115or FBGs910is varied so that a given pair of the point reflectors115or FBGs910has a unique distance between them and is thereby distinguishable from any other pair along the optical fiber110. However, to determine where along the optical fiber110a given pair of point reflectors115or FBGs910is located, the point reflectors115or FBGs910may be placed at known locations (a priori knowledge) or a reference reflector1010may be used to make the determination.

FIG. 11is a flow diagram of an exemplary method1100of using distributed downhole acoustic sensing. At block1110, arranging the interferometer includes arranging point reflectors115as discussed with reference toFIGS. 2 and 3or FBGs910, as discussed with reference toFIG. 9, with or without a reference reflector1010, or only including a reference reflector1010as discussed with reference toFIG. 10. At1120, obtaining the interferometer signal includes transmitting a range of wavelengths with a tunable laser120and receiving the interferometer signal. The interferometer signal may be received at the surface. At block1130, 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 machinery210such as a submersible pump. Processing at block1130also includes determining flow at location of a sandscreen310. Processing at block1130also includes performing vertical seismic profiling or fracing. The processing at block1130may be in accordance with the discussion above with reference toFIGS. 4-8.