Acoustic telemetry with distributed acoustic sensing system

BACKGROUND

0001This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides for acoustic telemetry using a distributed acoustic sensing (DAS) system.

0002It can be useful to monitor parameters in a well over time. For example, production efficiency and output can be enhanced by obtaining the most accurate information available for a given well via downhole sensor measurements. However, a means of obtaining the sensor measurements is needed.

0003For this purpose and others, it would be advantageous to provide advancements in the art of telemetry in wells. For example, such advancements could be used for transmitting sensor measurements from well tools.

BRIEF DESCRIPTION OF THE DRAWINGS

0004<figref idref="DRAWINGS">FIG. 1</figref> is a representative partially cross-sectional view of a well telemetry system and associated method which can embody principles of this disclosure.

0005<figref idref="DRAWINGS">FIG. 2</figref> is a representative cross-sectional view of another example of the system and method.

DETAILED DESCRIPTION

0006In one example described more fully below, a downhole well tool contains one or more sensors and an acoustic transmitter capable of generating an acoustic signal that can be detected by an optical fiber or other optical waveguide connected to a distributed acoustic sensing (DAS) instrument, for example, positioned at or near the earth's surface. With the use of a DAS instrument at the surface, normal, unmodified optical fiber (usually single mode fiber) can be used as an acoustic receiver.

0007Some modifications to standard fiber can be made, if desired. For example, fiber Bragg gratings written in the fiber can allow the fiber to function as a distributed acoustic receiver for detecting acoustic waves which cause vibrations in the fiber. Additionally, standard fiber can be modified by writing or constructing intrinsic or extrinsic Fabry-Perot interferometers in the fiber.

0008If modified fiber is used, different types of instruments, designed to interrogate the various types of modified fiber may be used at the surface. Instruments used to interrogate multiple sensors distributed along modified fiber are well known in the art.

0009A DAS system example is described below, but it should be clearly understood that any type of distributed acoustic sensing system could benefit from the principles described herein. For example, in various different types of distributed acoustic sensing systems, backscattering of light in an optical waveguide may be used to detect acoustic signals (in which case the waveguide itself is an acoustic sensor), intrinsic or extrinsic Fabry-Perot interferometers may be used as acoustic sensors, intrinsic or extrinsic fiber Bragg gratings may be used as acoustic sensors, etc. The scope of this disclosure is not limited to use with any particular type of distributed acoustic sensing system.

0010One or more optical waveguides can be incorporated into a cable installed in a well. The cable can be positioned in cement surrounding a casing, between tubular strings, or in a wall of a tubular string, etc. The scope of this disclosure is not limited to any particular position of the optical waveguide(s) and/or cable.

0011The well tool records measurements from its sensor(s) and generates acoustic data packets, which cause minute, time varying changes in strain in the optical waveguide, in response to the acoustic waves impinging on the optical waveguide. These changes in strain are detected by the DAS instrument or other fiber optic interrogator at the surface, where the acoustic data signal is demodulated.

0012The data could be modulated on the acoustic signal using any of a variety of different modulation techniques. For example, frequency shift keying, phase shift keying, differential phase shift keying, dual tone multi-frequency, amplitude modulation, etc. The scope of this disclosure is not limited to use of any particular modulation technique.

0013Preferably, the well tool is battery powered, or is supplied with electrical power from a downhole source. This is due to the fact that, if electrical lines extend from the surface to the well tool, those lines could be used for transmitting sensor measurements to the surface, without use of acoustic telemetry and the optical waveguide.

0014To conserve battery life, the well tool could store data over time, and transmit a series of time-stamped sensor measurements at predetermined time intervals. If sufficient battery or downhole generated power is available, the well tool may transmit in real time.

0015The well tool could be triggered to send data on command, or to change the data source, data rate, modulation technique or transmitting frequency in response to commands from the surface. These commands may be in the form of acoustic pulses transmitted down the well from the surface, or up the well from a source beyond the well tool.

0016Acoustic pulses could be transmitted using, for example, a HALSONICS™ air gun transmitter marketed by Halliburton Energy Services of Houston, Tex. USA. However, other forms of telemetry could be used in other examples.

0017Commands could be transmitted by movement, including performing certain series of longitudinal and/or rotational movements of the well tool. If the well tool is connected in a tubular string, the tubular string could be manipulated from the surface to transmit certain commands to the well tool.

0018Commands could be transmitted by forces and/or torques applied to the well tool. For example, tension applied to a tubular string in which the well tool is connected can be slacked off to decrease tension (or increase compression) in the tubular string, and can be picked up on to increase tension (or decrease compression) in the tubular string.

0019Commands could be transmitted by applying a series of pressure fluctuations (positive and/or negative) to the well. The pressure fluctuations could be received by a pressure sensor of the well tool.

0020The well tool could be conveyed in the well by, for example, jointed or continuous tubing, by slickline or wireline, etc. In some examples, the well tool could be permanently installed in the well.

0021In one example, the well tool could be conveyed by slickline or coiled tubing, and removably installed in a landing nipple or a side pocket mandrel. In this manner, the well tool may be semi-permanently installed for long term reservoir monitoring, but can be conveniently removed, repaired, and/or replaced if, for example, it becomes inoperable due to electronics failure or spent batteries, it is desired to upgrade the well tool, or if monitoring requirements change. Using multiple landing nipples or side pocket mandrels, the location of the well tool can also be varied as desired.

0022Representatively illustrated in <figref idref="DRAWINGS">FIG. 1</figref> is a telemetry system <b>10</b> and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system <b>10</b> and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system <b>10</b> and method described herein and/or depicted in the drawings.

0023In the <figref idref="DRAWINGS">FIG. 1</figref> example, a well tool <b>12</b> is connected in a tubular string <b>14</b>. The well tool <b>12</b> is received in a side pocket mandrel <b>34</b> of the tubular string <b>14</b>.

0024The tubular string <b>14</b> is deployed in a wellbore <b>16</b> lined with a casing or other tubular string <b>18</b> and cement <b>20</b>. In other examples, the wellbore <b>16</b> could be uncased or open hole.

0025An optical waveguide <b>22</b> (such as, an optical fiber, an optical ribbon, etc.) is positioned in the cement <b>20</b> external to the tubular string <b>18</b>. In other examples, the optical waveguide <b>22</b> could be positioned internal to the tubular string <b>18</b>, in a wall of the tubular string <b>18</b>, etc.

0026The optical waveguide <b>22</b> serves as an acoustic receiver for receiving acoustic signals <b>24</b> transmitted from an acoustic transmitter <b>26</b> of the well tool <b>12</b>. In addition to the transmitter <b>26</b>, the well tool <b>12</b> includes electronic circuitry <b>28</b> (e.g., for modulating information on the acoustic signals <b>24</b>), batteries <b>30</b> and at least one sensor <b>32</b>.

0027The sensor <b>32</b> detects or measures one or more downhole parameters, such as, pressure, temperature, fluid type, water cut, etc. The scope of this disclosure is not limited to use of any particular type of sensor in the well tool <b>12</b>.

0028The acoustic signals <b>24</b> cause vibrations, including variations in strain, in the optical fiber <b>22</b>. An optical interrogator <b>36</b> connected to the optical waveguide <b>22</b> detects variations in light as transmitted through the optical waveguide due to the vibrations, and preferably demodulates the acoustic signal <b>24</b>.

0029In a DAS system, the interrogator <b>36</b> may launch pulses of light into the optical waveguide <b>22</b> and detect backscattering of light (e.g., coherent Rayleigh backscattering) through the optical waveguide. In an interferometric or fiber Bragg grating systems, the interrogator <b>36</b> may detect variations in reflected amplitude and or phase of reflected light (e.g., from fiber Bragg gratings, etc.) through the optical waveguide <b>22</b>, in order to detect the acoustic waves <b>24</b>. Alternatively, if the fiber is in the form of a loop that travels from the surface, into the well and back to the surface, i.e., if both ends of the fiber are accessible at the surface, changes in amplitude and or phase of transmitted light may also be used to interrogate the system.

0030Note that the optical waveguide <b>22</b> is available to receive the acoustic signals <b>24</b> at any location in the wellbore <b>16</b> where the optical waveguide is present (or at least proximate). Thus, the well tool <b>12</b> can be positioned in other side pocket mandrels <b>34</b>, other landing nipples, or other locations, and retain the ability to acoustically transmit the sensor <b>32</b> measurements to the optical waveguide <b>22</b>.

0031Multiple well tools <b>12</b> may be positioned at different locations in the well. Each well tool <b>12</b> can include an acoustic transmitter <b>26</b> and at least one sensor <b>32</b>. The optical waveguide <b>22</b> (and/or fiber Bragg gratings, Fabry-Perot interferometers, etc.) can serve as acoustic receiver(s) to receive the acoustic signals <b>24</b> transmitted from each of the well tools <b>12</b>.

0032Referring additionally now to <figref idref="DRAWINGS">FIG. 2</figref>, another configuration of the system <b>10</b> is representatively illustrated in a lateral cross-sectional view. In this view, it may be seen that the optical waveguide <b>22</b> is included as part of a cable <b>38</b> in an annulus <b>40</b> formed radially between the tubular strings <b>14</b>, <b>18</b>. In some examples, the cable <b>38</b> could be attached to an exterior of the tubular string <b>14</b>.

0033The well tool <b>12</b> is positioned in an interior of the tubular string <b>14</b>. For example, the well tool <b>12</b> could be conveyed by wireline, slickline, coiled tubing, etc., into the tubular string.

0034The transmitter <b>26</b> transmits the acoustic signals <b>24</b> through the tubular string <b>14</b> to the optical waveguide <b>22</b> in the cable <b>38</b>. In other examples, the cable <b>38</b> could be inside the tubular string <b>14</b>, or in a wall of the tubular string.

0035It may now be fully appreciated that the above disclosure provides significant advancements to the well telemetry art. In one example, “wireless” sensor data transmission is available at any point in a well having an optical waveguide positioned nearby. The optical waveguide may be installed in the well for this telemetry purpose, or an existing optical waveguide may be utilized for this purpose, for example, by connecting a suitable optical interrogator to the existing optical waveguide.

0036Note, also, that multiple tools <b>12</b> with multiple sensors <b>32</b> and multiple acoustic transmitters <b>26</b> may be positioned in multiple locations in the well and can transmit acoustic data simultaneously in independent channels to the modified or unmodified optical waveguide <b>22</b>.

0037A system <b>10</b> for use with a subterranean well is described above. In one example, the system <b>10</b> can include at least one well tool <b>12</b> positioned in the well, the well tool <b>12</b> including an acoustic transmitter <b>26</b> and a sensor <b>32</b>, the acoustic transmitter <b>26</b> transmits an acoustic signal <b>24</b> including information representative of a measurement by the sensor <b>32</b> to an optical waveguide <b>22</b> positioned in the well, the optical waveguide <b>22</b> comprising an acoustic receiver. In other examples, the acoustic receiver may comprise fiber Bragg gratings and/or Fabry-Perot interferometers.

0038If an optical waveguide is used, the acoustic signal <b>24</b> may cause vibrations in the optical waveguide <b>22</b>.

0039An optical interrogator <b>36</b> connected to the optical waveguide <b>22</b> may detect backscattering of light in the optical waveguide <b>22</b>. The backscattering of light can be indicative of vibrations distributed along the optical waveguide <b>22</b>.

0040The well tool <b>12</b> may be connected in a tubular string <b>14</b>. The optical waveguide <b>22</b> can be positioned external to the tubular string <b>14</b>.

0041The optical waveguide <b>22</b> may be positioned between tubular strings <b>14</b>, <b>18</b>. The optical waveguide <b>22</b> may be positioned in cement <b>20</b> external to a tubular string <b>18</b>.

0042The at least one well tool may comprise multiple well tools, and the acoustic transmitters of the well tools <b>12</b> may transmit the acoustic signals <b>24</b> including information representative of measurements by the corresponding sensors <b>32</b> to the acoustic receiver.

0043Also described above is an acoustic telemetry method for use with a subterranean well. In one example, the method can comprise: positioning a well tool <b>12</b> in the well, the well tool <b>12</b> including an acoustic transmitter <b>26</b> and a sensor <b>32</b>; and an optical waveguide <b>22</b> in the well receiving an acoustic signal <b>24</b> transmitted by the transmitter <b>26</b>, the acoustic signal <b>24</b> including information representative of a measurement by the sensor <b>32</b>.

0044Another system <b>10</b> for use with a subterranean well can comprise: a well tool <b>12</b> positioned in the well, the well tool <b>12</b> including an acoustic transmitter <b>26</b> and a sensor <b>32</b>; and an optical waveguide <b>22</b> positioned in the well, the optical waveguide <b>22</b> receives an acoustic signal <b>24</b> transmitted by the transmitter <b>26</b>, and the acoustic signal <b>24</b> including information representative of a measurement by the sensor <b>32</b>.

0045Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

0046Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

0047It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

0048In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

0049The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

0050Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.