Patent Description:
One such application is in downhole monitoring of vibration and acoustics. Exemplary technologies include distributed acoustic sensing (DAS) or distributed vibration sensing (DVS). Vibration monitoring has numerous applications, such as fluid characterization, leak detection and the condition monitoring of downhole components including borehole strings and electronic submersible pumps (ESPs).

<CIT>, over which the independent claims are characterised, and <CIT> both disclose acoustic telemetry using optical waveguides of a distributed acoustic sensing (DAS) system. <CIT> discloses the use of a displaceable object in a wellbore, wherein the object includes a sensor and a transmitter.

According to an aspect of the present invention, there is provided a system for acoustic sensing and communication as claimed in claim <NUM>.

According to another aspect of the present invention, there is provided a method of acoustic sensing and communication as claimed in claim <NUM>.

Referring now to the drawings, wherein like elements are numbered alike in the several Figures:.

Apparatuses, systems and methods are provided for communicating between a downhole component and another component (e.g., a surface or downhole device). An embodiment of a method includes transmitting a communication from a downhole component by generating an encoded acoustic signal corresponding to data and/or communications generated by the downhole component, and coupling the acoustic signal to a distributed acoustic sensing (DAS) optical fiber to generate an optical signal that is propagated to a receiver. The DAS fiber is employed as both an acoustic sensor and a transmission conduit, e.g., by configuring one or more sections of the DAS fiber as communication sections that detect acoustic transmissions, and configuring one or more other sections that detect acoustic events generated by the downhole environment.

The descriptions provided herein are applicable to various oil and gas or energy industry data activities or operations. Although embodiments herein are described in the context of drilling and/or stimulation operations, they are not so limited. The embodiments may be applied to any energy industry operation. Examples of energy industry operations include surface or subsurface measurement and modeling, reservoir characterization and modeling, formation evaluation (e.g., pore pressure, lithology, fracture identification, etc.), stimulation (e.g., hydraulic fracturing, acid stimulation), coiled tubing operations, drilling, completion and production.

Referring to <FIG>, an exemplary embodiment of an energy industry system <NUM> associated with a borehole <NUM> is shown. In this embodiment, the system <NUM> is a measurement and production system, but is not so limited. The system <NUM> may be configured to perform any energy industry operation, such as a drilling, logging-while-drilling (LWD) and/or wireline operation. A borehole string <NUM> is disposed in the borehole <NUM>, which penetrates at least one earth formation <NUM> for facilitating operations such as drilling, production and making measurements of properties of the formation <NUM> and/or the borehole <NUM>. The borehole string <NUM> includes any of various components to facilitate subterranean operations. The borehole string <NUM> is made from, for example, a pipe, multiple pipe sections or coiled tubing.

The system <NUM> and/or the borehole string <NUM> include any number of downhole tools <NUM> for various processes including drilling, hydrocarbon production, and formation evaluation (FE) for measuring one or more physical quantities in or around a borehole. For example, the tools <NUM> include a measurement assembly, a drilling assembly and/or a pumping assembly. Various measurement tools may be incorporated into the system <NUM> to affect measurement regimes such as wireline measurement applications, production monitoring and logging-while-drilling (LWD) applications.

In one embodiment, the borehole string <NUM> is configured as a production string and includes an electrical submersible pump (ESP) assembly <NUM> as part of, for example, a bottomhole assembly (BHA). The ESP assembly <NUM> is utilized to pump production fluid through the production string <NUM> to the surface. The ESP assembly <NUM> includes components such as a motor <NUM>, a seal section <NUM>, an inlet or intake <NUM> and a pump <NUM>. The motor <NUM> drives the pump <NUM>, which takes in fluid via the inlet <NUM>, and discharges the fluid at increased pressure into the production string <NUM>. The motor <NUM>, in one embodiment, is supplied with electrical power via an electrical conductor such as a power and/or communication cable <NUM>, which is operably connected to a power supply system <NUM>. The cable <NUM> may also include conductors for transmitting communications, such as electrical conductors and/or optical fibers.

The system <NUM> also includes one or more fiber optic components configured to perform various functions in the system <NUM>, such as communication and sensing various parameters. An exemplary fiber optic component is a fiber optic sensor <NUM> configured to measure downhole properties such as temperature, pressure, downhole fluid composition, stress, strain, vibration and deformation of downhole components such as the borehole string <NUM> and the tools <NUM>. The optical fiber sensor <NUM> includes at least one optical fiber having one or more sensing locations disposed along the length of the optical fiber sensor <NUM>. Examples of sensing locations include fiber Bragg gratings (FBG), mirrors, Fabry-Perot cavities and locations of intrinsic scattering. Locations of intrinsic scattering include points in or lengths of the fiber that reflect interrogation signals, such as Rayleigh scattering and Brillouin scattering locations. The optical fiber sensor <NUM> can be configured as a cable or other elongated member, and may include additional features such as strengthening and/or protective layers or members, and additional conductors such as electrical conductors and additional optical fibers for sensing and/or communication.

The fiber optic sensor <NUM> is part of a distributed acoustic sensing (DAS) system. For example, DAS technology can be used to convert a standard telecommunication fiber into an array of sensors that can detect acoustic energy. This array of acoustic/vibration sensors is typically deployed within a wellbore such that the sensors span the majority of the wellbore, or at least a length of interest. Typically this system is used as an instrumentation device to listen to borehole and/or formation related events. In this embodiment, the DAS system is configured as a communication conduit, which can be used for communication only, or communication in conjunction with acoustic sensing. This may include using different spatial sections of the DAS measurement for communication as well as sensing. Likewise, these sections may change over time such that for one period of time the system is configured for communication and later it is used as a sensor for, e.g., wellbore/formation surveillance purposes.

The DAS system includes an optical fiber sensing and/or communication system configured to transmit communications from downhole components, and/or interrogate the optical fiber sensor <NUM> to estimate a parameter (e.g., strain, pressure, vibrations) of the tool <NUM>, ESP assembly <NUM> or other downhole component, the borehole <NUM> and/or the formation <NUM>. The optical fiber sensor <NUM> may be configured as a single optical fiber, such as a single or multi-mode fiber, or multiple fibers. In one embodiment, the optical fiber sensor <NUM> is an optical fiber (e.g., a telecommunication fiber) that includes intrinsic sensing locations without manufactured reflectors or features such as FBGs, mirrors, cavities and other types of scattering or reflecting features. In another embodiment, the optical fiber sensor <NUM> is or includes an optical fiber having manufactured reflectors such as FBGs.

In one embodiment, the monitoring and/or communication system is configured to detect and/or measure vibration of downhole component(s), which may include any type of tool or component that experiences and/or generates vibration, deformation or stress downhole. Examples of tools that experience vibration include motors or generators such as ESP motors, other pump motors and drilling motors, as well as devices and systems that include or otherwise utilize such motors. Vibration and/or other phenomena that can be monitored or measured include naturally occurring acoustic events, such as flow induced vibration due to turbulence and natural acoustic phenomena such as resonances.

The monitoring and/or communication system includes a surface processing unit <NUM> configured to transmit electromagnetic interrogation signals into the optical fiber sensor <NUM> and receive reflected signals from one or more locations in the optical fiber sensor <NUM>. An example of the surface processing unit <NUM> shown in <FIG> includes a signal source <NUM> (e.g., a pulsed light source, LED, laser, etc.) and a signal detector <NUM> operably connected to one or more optical fiber sensors <NUM>. The signal source (e.g., laser) may be modulated or frequency swept. In one embodiment, a processor <NUM> is in operable communication with the signal source <NUM> and the detector <NUM> and is configured to control the source <NUM> and receive reflected signal data from the detector <NUM>. The surface processing unit includes, for example, an OFDR and/or OTDR type interrogator to sample components such as the ESP assembly <NUM> and/or tool <NUM>. The interrogator is not limited to those described herein, and may be any suitable type of interrogator (e.g., an IFPR or EFPR interrogator). The location of the interrogation unit is not limited to that shown in embodiments discussed herein. The interrogation unit (or a component thereof such as a detector and/or signal source) may be disposed downhole, e.g., at a borehole string or BHA.

The monitoring and/or communication system also includes one or more acoustic telemetry units <NUM> configured to transmit and/or receive communications via the DAS optical fiber sensor <NUM>. Each telemetry unit <NUM> includes an acoustic transducer, such as a microphone or piezoelectric device, and a communication circuit for receiving communications and data and generating an encoded and/or modulated signal that is used to actuate the acoustic transducer to emit an encoded acoustic signal. The encoded acoustic signal causes the optical fiber sensor <NUM> to deform and thereby affect return signals reflected or scattered by the sensing locations. The resulting return signal can be detected and optionally demodulated at the surface processing unit <NUM>. The acoustic telemetry unit <NUM> may be any type of device or system capable of transforming input signals (e.g., electrical or optical signals) into acoustic signals, and is not limited to the configurations discussed herein. An example of a transducer of the acoustic telemetry unit is an Electromagnetic Acoustic Transducer (EMAT) device.

Each acoustic telemetry unit <NUM> is connected (e.g., electrically or optically) to a downhole device or system capable of generating signals, communications and/or data. In one embodiment, each acoustic telemetry unit <NUM> is connected to one or more downhole sensor devices such as temperature sensors, pressure sensors, accelerometers, strain sensors and/or combinations thereof. For example, each telemetry unit <NUM> is connected to a sensor device <NUM>. The sensor device <NUM> transmits signals or data to the telemetry unit <NUM>, which generates an encoded acoustic signal toward the optical fiber sensor <NUM>. Although <FIG> shows a telemetry unit connected to one respective sensor, a telemetry unit <NUM> may be connected to multiple sensors or components.

The telemetry unit <NUM> may be the sole means for transmitting communications and data to the surface, or may be included in conjunction with other telemetry systems or communication systems. For example, one or more of the sensor devices <NUM> is connected electrically to the cable <NUM> to receive power and/or for sending and receiving communications. The acoustic telemetry unit <NUM> may be used, for example, as a reserve or back-up unit for transmission in the event that the cable <NUM> is damaged or becomes too noisy.

In one embodiment, the tools, sensors and/or other components are disposed downhole in a "smart" or "intelligent" well configuration. Smart well technology involves measurement and reservoir flow control features that are disposed downhole. Installation of downhole active flow control devices (multi-node), inflow control valves, measurement devices (e.g., for pressure, temperature and flow rate), and/or downhole processing facilities such as hydro-cyclones in the borehole allows for active production monitoring and control. Intelligent wells facilitate control of parameters such as fluid flow and pressure, and facilitate periodically or continuously updating reservoir models during production.

<FIG> illustrates aspects of an embodiment of the monitoring and/or communication system. The acoustic telemetry unit <NUM> includes an acoustic transducer <NUM> such as a microphone or piezoelectric transducer. An electronics unit <NUM> is connected to the transducer <NUM> and includes various components for receiving signals and communications from a downhole component such as a pressure sensor <NUM>. In this embodiment, the downhole component is a pressure sensor, but is not so limited, and can be any component or device that generates outputs that can be processed and transmitted to a surface location or another downhole location.

The electronics unit <NUM> includes processing circuity for receiving inputs from the pressure sensor <NUM>, optionally analyzing the inputs, and generating output signals. The processing circuity may have any number of components, such as a processor <NUM>, memory <NUM> and a modulator <NUM>. The electronics unit <NUM> and transducer <NUM> may be powered by a battery or other downhole power source, or coupled to a surface power supply by an electrical conductor in, e.g., the cable <NUM>.

The pressure sensor <NUM> in this embodiment includes a pressure transducer <NUM> and an electronics and/or processing unit <NUM>. The pressure sensor <NUM> may be powered by the cable <NUM> or by an optional power source <NUM> (e.g., a battery).

In one embodiment, the acoustic telemetry unit <NUM>, or portions thereof, are modular components that can be connected to various downhole components as desired. For example, the telemetry unit <NUM> is configured as an electronic to acoustic module (EAM).

The telemetry unit <NUM> and/or the transducer <NUM> are attached or secured to the borehole string and/or tool <NUM> at a location suitable to allow for acoustic signals to be coupled to the DAS fiber and cause an intensity change, phase change, wavelength shift or other change in optical signals reflected from sensing locations within the optical fiber <NUM> that can be detected by the surface processing unit <NUM>. For example, the transducer <NUM> is attached to the tool <NUM> at a location proximate to the optical fiber so that acoustic signals are coupled to a pre-selected axial location or section of the optical fiber <NUM>. The location and distance between the transducer <NUM> and the optical fiber may be determined, e.g., by performing testing or calibration prior to securing the transducer and disposing the tool <NUM> downhole, to ensure proper acoustic energy transfer into the fiber.

The monitoring and/or communication system can be used to transmit information (e.g., measurements, data and communications) using a DAS system from any suitable component, such as a sensor suite and/or hardware component. Examples of such components include but are not limited to pressure sensors, point temperature sensors, electronic/hydraulic valves, electronic submersible pumps, smart packers and others. Conventionally, many of these components communicate with the surface in some manner, such as via a control line (e.g., fluid, electrical, optical) or by storage of results onboard for later retrieval. For example, some components may include onboard memory and store results and data downhole for an extended period of time, after which the results and data are conventionally collected by physically retrieving the component. Embodiments described herein can be configured to replace such conventional communications with communication using a DAS system, or can be configured to be complementary to convention communication.

The sensing and/or communication system may thus be utilized as a primary or complementary communication system. For example, a telemetry unit or units <NUM> may be used as the sole communication means for a component. Alternatively, a telemetry unit or units <NUM> may be utilized in conjunction with another communication means (e.g., an electrical or optical control line, or mud pulse telemetry). For example, the other communication means is used to receive communications from the surface and a telemetry unit <NUM> is used to transmit all or a portion of the communication and/or data generated by the component. In another example, a telemetry unit <NUM> is used as a conduit to transmit information stored in a downhole memory, providing the option to collect data by retrieving the component or having the data transmitted via the optical fiber <NUM>. In yet another example, a telemetry unit <NUM> is provided as a reserve or back-up communication means, which can be used in the event that another communication means is unavailable, damaged or not optimal.

Although embodiments of the sensing and/or communication system are described as including a discrete telemetry units or a series of discrete units, the embodiments are not so limited, as any suitable acoustic source can be used. For example, vibrations (e.g., axial or torsional) could be induced in the string, tool and/or BHA from the surface or from manipulation of a downhole component such as the ESP. In another example, fluid could be injected according to selected pressure or flow rate parameters to induce acoustic signals. Changes in pressure or flow rate could generate acoustic signals that are directly coupled to a DAS fiber, or another sensor could be used to generate acoustic signals, e.g., a pressure sensor coupled to the transducer <NUM>.

The sensing and/or communication system is configured to transmit communications using the same optical fiber or fibers that are utilized to perform DAS measurements. For example, an interrogator such as the surface processing unit <NUM> injects optical signals into a DAS fiber such as the optical fiber <NUM>, and return signals are analyzed to detect acoustic events generated by the downhole environment. The downhole environment includes any regions, components or conditions (other than acoustic transmitters such as the transducers <NUM>) that can generate acoustic waves, such as downhole components, the borehole (e.g., borehole fluid flow) and/or the formation. In addition, injected signals and return signals are analyzed to detect encoded acoustic signals generated by an acoustic transmitter such as an acoustic transducer <NUM>.

In one embodiment, multiplexing is utilized to differentiate between different acoustic transmitters or transducers, and may also be used to differentiate between signals generated by transducers and acoustic events generated by the downhole environment (e.g., borehole fluid, component vibration, component interaction with a borehole surface, etc.). For example, a frequency band or other communication protocol is selected such that communication bandwidths do not interfere with downhole acoustic events of interest; in this case the DAS fiber can be used to collect a full array of DAS data for sensing purposes as well as still serving as a communication conduit.

To facilitate multiplexing of communication signals from the multiple acoustic transmitters, which may each be coupled to one or more respective components, the transmitters may be arrayed along a DAS fiber with a sufficient separation to allow for differentiation between individual signals based on a time of receipt of such signals. The separation may be of any length so that respective signals can be simultaneously transmitted and received with enough temporal separation to permit differentiation of the signals. In this embodiment, each of the signals may be transmitted using the same spectral bandwidth or acoustic frequency range.

One or more of the transmitters is configured to emit acoustic signals having a communication protocol or frequency spectrum that is different than the frequency spectrum of one or more other acoustic transmitters. For example, for an array of transducers, alternating transducers could be configured to emit signals with one of two different frequency ranges. This configuration is useful, e.g., in instances where the spatial separation between acoustic transmitters is not sufficient to differentiate signals based on time alone.

The monitoring and/or communication system is configured to designate different sections (axial lengths) of the DAS fiber for DAS sensing and for communication. For example, as shown in <FIG>, each transducer <NUM> is disposed proximate to a section of the optical fiber <NUM> and defines a respective section <NUM> for coupling transmissions from a respective pressure sensor <NUM>. Other sections of the fiber <NUM> are designated as sensing sections <NUM> from which downhole acoustic events can be detected. Return signals from each section can be differentiated based on signal transit time and/or the spectral range of return signals.

Although the components and acoustic transmitters are described in some embodiments as disposed at fixed locations relative to a borehole string, they are not so limited. One or more of the components may be moveable relative to the string. In the present invention, the downhole components include wireless sensors that are pumped downhole with fluid through a borehole and/or into a formation. Such wireless sensors could be quite small and deployed potentially in large numbers (e.g., by the thousands). One option might be to collect the sensors on surface to extract the data, which could present problems as retrievable may be difficult or infeasible.

In the present invention, each moveable sensor is equipped with an acoustic transmitter that can be used to track the position of the sensor and/or receive data from the sensor via a DAS fiber. For example, referring again to <FIG>, the monitoring and/or communication system is configured to detect acoustic signals emitted from sensors <NUM> that are pumped into the borehole. This embodiment would allow for transmission of data from each of the sensors uphole without ever needing to recover the sensors, and could be used to track where the sensors are within a borehole and/or where the sensors leave the borehole and enter the formation. This would be valuable from both a measurement standpoint and operationally. Operationally, the sensors could be tracked to determine the number of sensors that are required for a deployment. This embodiment would also provide other advantages. For example, the sensors may be self-destructing sensors which would mitigate the recovery problem as well as the issue of the sensors altering the formation flow characteristics. An example of a self-destructing sensor is a sensor made from a degradable or dissolvable material.

In one embodiment, the monitoring and/or communication system is used to monitor acoustic transmissions sent from a surface or uphole location to engage acoustically activated downhole components. This embodiment can serve as, for example, an engineering or troubleshooting tool.

For example, acoustic monitoring using a DAS fiber is employed to address a situation where an acoustically activated downhole tool does not respond or does not activate as expected when an acoustic signal is injected from the surface. Reasons for this may include, for example, the acoustic receiver of the downhole tool not working, the mechanical/electrical hardware associated with the tool not functioning, or unexpected acoustic impedance within the borehole that attenuates or distorts the signal. For failure situations, the DAS fiber is interrogated and return signals are analyzed to measure the acoustic signal injected from the surface and monitor distortions to the acoustic signal as the acoustic signal propagates to the downhole tool. This could be used to identify problem areas. As an example, if an upper portion of the borehole is filled with a different type of fluid than a lower portion, the resulting impedance mismatch might cause sufficient signal attenuation. If identified with the DAS fiber, the signal could be corrected by altering the fluid levels and then re-transmitting the acoustic signal to activate the downhole hardware.

<FIG> illustrates a method <NUM> of monitoring vibration and/or other parameters of a downhole tool. The method <NUM> includes one or more of stages <NUM>-<NUM> described herein. The method <NUM> may be performed continuously or intermittently as desired. The method may be performed by one or more processors or other devices capable of receiving and processing measurement data, such as the surface processing unit <NUM>. Although the method <NUM> is discussed below in conjunction with the systems shown in <FIG> and <FIG>, it is not so limited, and can be performed using any suitable device or system having components configured to output measurements and/or data. In one embodiment, the method includes the execution of all of stages <NUM>-<NUM> in the order described. However, certain stages <NUM>-<NUM> may be omitted, stages may be added, or the order of the stages changed.

In the first stage <NUM>, a component such as the tool <NUM> and/or the ESP assembly <NUM> is lowered into or otherwise disposed in the borehole <NUM>. In one embodiment, the ESP motor <NUM> is started and production fluid is pumped through the ESP assembly <NUM> and through the production string <NUM> to a surface location. The production string and/or component is coupled to a measurement and/or communication system that includes a DAS optical fiber and one or more acoustic telemetry units.

In the second stage <NUM>, each telemetry unit may be calibrated by selecting an acoustic frequency band or range (or other communication protocol) for each unit. Each telemetry unit is assigned an acoustic frequency band that does not overlap or impinge on frequencies of downhole acoustic events. Such downhole acoustic events may be known from prior operations or other pre-existing knowledge, or determined by performing downhole measurements. For example, optical interrogation signals are transmitted through the DAS fiber from the surface, and return signals are analyzed to determine vibration and/or acoustic signals that are generated downhole by, e.g., the ESP, fluid, string rotation and other downhole conditions. Parameters of the return signals are estimated. For example, frequencies of detected acoustic events are determined, and used to select an appropriate frequency band for the telemetry transducer. It is noted that this stage can be performed at the onset of a downhole operation, at any time during the downhole operation, or prior to commencing the operation. For example, prior to commencing the operation, fluid can be pumped into the borehole and/or the ESP turned on and operated at various levels, and acoustic signals are detected.

Frequency band or other communication protocol parameters may also be selected to differentiate between individual telemetry units. For example, if the separation between two or more telemetry units is not sufficient to allow for effective differentiation between the units using the time of detection of return signals, one or more units can be configured to emit signals using a different frequency band that one or more other units.

In the third stage <NUM>, the downhole operation is commenced. For example, drilling is commenced by driving a drilling assembly and circulating drilling fluid. In another example, a production operation is commenced by injecting fluid into a borehole and/or activating an artificial lift or production device such as an ESP. Various other functions can be performed, depending on the type of operation. For example, during a wireline or other non-drilling measurement operation, sensors are operated and other components such as stabilizers, extension arms and others can also be used to facilitate measurements. For a stimulation operation, other processes may be performed, such as perforation, injection for fracturing, and/or actuation of packers or other components to isolate sections of the borehole.

Various measurement devices may also be used to measure and/or monitor downhole conditions and components. Examples of such devices include pressure sensors, temperature sensors, strain and/or vibration sensors, directional sensors, and formation evaluation sensing devices such as resistivity, nuclear magnetic resonance, pulsed neutron and others. Sensors may be disposed with rotating components (e.g., as part of a LWD device or system) or non-rotating components (e.g., as part of a wireline or production system). One or more of the sensors may be discrete sensors configured to take measurements at specific locations or regions of the borehole.

In the fourth stage <NUM>, the DAS fiber is used to monitor component vibrations, fluid flow and other conditions that cause acoustic signals to be generated. During this measurement stage, acoustic signals are measured by transmitting an optical interrogation signal, detecting return signals, and estimating changes in the DAS fiber based on, for example, changes in amplitude or intensity, or phase shifts.

In the fifth stage <NUM>, measurement data or other communications from one or more components, such as the discrete sensors and/or any other component that outputs communications or data, are transmitted to the surface via the DAS system by generating an encoded acoustic signal using a telemetry unit coupled to each component. For example, measurement data from a pressure sensor, accelerometer, temperature sensor or other type of sensor is transmitted to a respective telemetry unit via an electrical circuit, and an acoustic transmitter is actuated to generate a modulated or otherwise encoded acoustic signal that is incident upon a section of the DAS fiber. Changes in optical return signals reflected from the section are detected and analyzed by a processor to reproduce the encoded signal.

The data may be modulated or encoded on the acoustic signal using any of a variety of different modulation or encoding techniques. Examples of techniques include frequency shift keying, phase shift keying, differential phase shift keying, dual tone multifrequency, amplitude modulation and others. Other encoding methods may be employed.

Acoustic transmission may be triggered or performed in response to various conditions. For example, transmission may occur based on a pre-selected schedule, in response to receiving measurement signals or any form of data, and/or in response to an amount of data. For example, if a component includes a memory, transmission may be prompted by the memory filling up or a selected portion of the memory capacity being used.

For example, the sensing and/or communication system may be coupled to an accelerometer or other vibration sensor for monitoring a component such as an ESP. The vibration sensor in this example includes processing components and memory for processing and storing data such as an accelerometer time history. The sensing and/or communication system can be used to transmit an entire time history or portion thereof, in response to communication from the surface, a pre-selected schedule or in response to how much memory is being used.

In one embodiment, acoustic transmission is triggered in response to a primary communication means failing to function optimally or as desired. In this embodiment, the sensing and/or communication system is a backup system that could be triggered by a command or communication, or automatically in response to a condition of the primary communication means. For example, the sensing and/or communication system is used as a backup system in the event electrical noise became an issue and data transmission is not feasible or possible.

In the sixth stage <NUM>, various actions may be performed in response to the distributed DAS measurements and/or discrete measurements. For example, changes in conditions measured by various discrete sensors, such as pressure and accelerometer sensors, and acoustic events detected using the DAS fiber, are compared to threshold values or otherwise analyzed to determine whether operational parameters of the operation should be adjusted.

In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.

The use of the terms "a" and "an" and "the" and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms "first," "second," and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier "about" used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and / or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi- solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc..

Claim 1:
A system (<NUM>) for acoustic sensing and communication, the system (<NUM>) comprising:
a distributed acoustic sensing (DAS) optical fiber (<NUM>) disposed in a downhole environment with a downhole component (<NUM>);
an optical interrogation device including an optical signal source (<NUM>) configured to inject an optical signal into the DAS optical fiber (<NUM>) and a receiver (<NUM>) configured to detect return signals reflected from sensing locations in the DAS optical fiber (<NUM>);
an acoustic telemetry unit (<NUM>) connected to the downhole component (<NUM>), wherein the acoustic telemetry unit (<NUM>) is disposed in the downhole environment, the acoustic telemetry unit (<NUM>) configured to receive a communication from the downhole component (<NUM>) and generate an acoustic signal having a frequency within a selected frequency range and encoded to carry the communication, wherein the acoustic telemetry unit (<NUM>) includes a plurality of acoustic telemetry units (<NUM>) arrayed along the DAS optical fiber (<NUM>),
characterised by:
at least one of the plurality of acoustic telemetry units (<NUM>) configured to generate an acoustic signal having a frequency that is different than at least another of the plurality of acoustic telemetry units (<NUM>), each acoustic signal applied to a respective first section (<NUM>) of the DAS optical fiber (<NUM>);
wireless sensors (<NUM>) that are pumped downhole with fluid through the borehole (<NUM>) and/or into a formation (<NUM>), wherein each wireless sensor (<NUM>) is equipped with an acoustic transmitter that can be used to track the position of the wireless sensor (<NUM>) and/or receive data from the wireless sensor (<NUM>) via the DAS optical fiber (<NUM>); and
a processor (<NUM>, <NUM>) configured to associate a first portion of the return signals with the respective first section (<NUM>) of the DAS optical fiber (<NUM>) to which the acoustic signal is applied and reproduce the communication based on the first portion of the return signals associated with the respective first section (<NUM>) of the DAS optical fiber (<NUM>), and associate a second portion of the return signals with a second section (<NUM>) of the DAS optical fiber (<NUM>) to detect one or more acoustic events generated by the downhole environment, wherein the system (<NUM>) is configured to detect acoustic signals emitted from the wireless sensors (<NUM>).