Downhole fiber optic hydrophone

Abstract

The present invention provides a method, system, apparatus, and product for acoustic inspection in a borehole. An apparatus embodiment includes an acoustic sensor comprising a pressure transducer, the pressure transducer comprising: an interface located between a fluid reservoir and a fluid body, the interface comprising a flexure attached to an optical medium, the pressure transducer configured to convert an acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer along an axis of the medium into an alternating stress on the optical medium by movement of the flexure, the acoustic pressure signal propagating through the fluid body; a detector configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium; and at least one coupled oscillator displacing a volume of the fluid reservoir in response to the acoustic pressure signal to modify, through the flexure, the conversion of a signal component of the acoustic pressure signal having a frequency within a predefined frequency range into a stress on the optical medium, such that the electromagnetic radiation received by the detector represents the modified acoustic signal.

Description

Technical Field

[0001] The present disclosure relates generally to drilling tools and, in particular, to methods and apparatus for conducting acoustic studies in a borehole intersecting an earth formation. More particularly, the present disclosure relates to acoustic sensors and methods of using such acoustic sensors in various tools, including acoustic logging tools. Background Art

[0002] Drilling wells for various purposes is well known. Such wells can be drilled for geothermal purposes, to produce hydrocarbons (e.g., oil and gas), to produce water, etc. Well depths can range from several thousand feet to 25,000 feet or more. In hydrocarbon wells, downhole tools typically incorporate various sensors, instruments, and control devices to enable any number of downhole operations. Downhole acoustic logging tools used to study subsurface characteristics may include one or more acoustic transmitters or sources and multiple acoustic receivers. Additionally or alternatively, self-contained acoustic sensors may be temporarily or permanently installed in the borehole.

[0003] In some cases, the transmitter transmits acoustic energy into the subsurface environment surrounding the wellbore. The acoustic signal is reflected by interfaces associated with the wellbore, well structure, and / or formation. The reflected acoustic signal is detected by a receiver in the logging tool and processed to provide an estimate of one or more properties of the wellbore, hole structure, and / or formation. Drilling systems having an acoustic "logging while drilling" ('LWD') or "measurement while drilling" ('MWD') system as part of a bottom hole assembly, or post-drilling wireline logging systems having acoustic equipment for measuring properties of the subsurface formation (during or after drilling of the wellbore) (such as, for example, determining the position of the formation bed boundary around the bottom hole assembly (as in an MWD system) or around the logging system) are known.

[0004] When drilling a borehole to extract oil from the ground, it is often helpful to steer the downhole drill bit toward or away from a subsurface target. Acoustic data can be used to determine the drill bit position on a seismic profile to facilitate geosteering. Using vertical seismic profiling (VSP), acquisitions can be made between one or more acoustic (seismic) sources on or near the Earth's surface and receivers in the Earth, such as, for example, in a wellbore. The responses of acoustic sensors, such as seismic sensors (e.g., hydrophones), to the sources on the ground at various depths in the borehole can be recorded as downhole measurements. Summary of the Invention

[0005] In various aspects, the present disclosure relates to methods and apparatus for performing formation evaluation in a borehole intersecting a formation, including estimating at least one parameter of interest related to the formation, such as, for example, properties of an acoustic reflection boundary in the formation.

[0006] An embodiment of the apparatus may include an acoustic sensor comprising a pressure transducer. The pressure transducer may include: an interface positioned between a fluid reservoir and a fluid body, the interface comprising a flexure attached to an optical medium, the pressure transducer configured to convert an acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer along an axis of the medium into an alternating stress on the optical medium by movement of the flexure along an axis of the medium, the acoustic pressure signal propagating through the fluid body; a detector configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium; and at least one coupled oscillator displacing a volume of the fluid reservoir in response to the acoustic pressure signal to modify, through the flexure, the conversion of a signal component of the acoustic pressure signal having a frequency within a predefined frequency range into a stress on the optical medium, such that the electromagnetic radiation received by the detector represents the modified acoustic signal.

[0007] The coupled oscillator may be coupled to the flexure member via a fluid reservoir. The at least one coupled oscillator may be configured to modify conversion of the flexure member to the signal component by changing the sensitivity of the flexure member to the signal component. The at least one coupled oscillator may be configured to increase the sensitivity of the flexure member to the signal component. The at least one coupled oscillator may be configured to decrease the sensitivity of the flexure member to the signal component. Movement of the flexure member in response to an incident component signal may be affected by movement of the at least one coupled oscillator in response to the incident signal component.

[0008] A change in the volume of the fluid reservoir in response to movement of the at least one coupled oscillator (which may be responsive to an incident signal component) may affect movement of the flexure member. The at least one coupled oscillator may be configured to suppress conversion of signal components of the acoustic pressure signal within a predefined frequency range into stress in the optical medium, such that electromagnetic radiation received by the detector represents an acoustic signal filtered to substantially remove signals within the predefined frequency range.

[0009] The flexure may have a first value for an oscillation parameter, and at least one of the at least one coupled oscillator may have a second value for the oscillation parameter that is substantially different from the first value. The oscillation parameter may include at least one of: i) mass; ii) stiffness; iii) geometry; iv) spring constant; and v) density.

[0010] The at least one coupled oscillator may be configured to amplify the conversion of signal components of the acoustic pressure signal within a predefined frequency range to stress in the optical medium such that the electromagnetic radiation received by the detector represents the acoustic signal filtered to amplify signals within a target frequency window.

[0011] The at least one coupled oscillator may be configured to suppress conversion of a first portion of a signal component of the acoustic pressure signal within a first target frequency window in the predefined frequency range into stress of the optical medium, and to amplify conversion of a second portion of a signal component of the acoustic pressure signal within a second target frequency window in the predefined frequency range into stress of the optical medium.

[0012] The at least one coupled oscillator may be at least one additional flexure. The at least one coupled oscillator may include at least one piston. The interface may include at least one opening that provides fluid exchange between the fluid reservoir and the fluid body and is configured to suppress conversion of low-frequency signals and constant pressure into stress in the optical medium. The modified acoustic signal may be at least one of: i) a filtered signal; and ii) an amplified signal.

[0013] Method embodiments may include using a pressure transducer comprising an interface between a fluid reservoir and a fluid body, the interface comprising a flexure attached to an optical medium to convert an acoustic pressure signal incident on the pressure transducer within a nominal borehole pressure along an axis of the medium into an alternating stress on the optical medium by movement of the flexure, the acoustic pressure signal propagating through the fluid body, comprising: displacing the volume of the fluid reservoir with at least one coupled oscillator in response to the acoustic pressure signal to modify, through the flexure, the conversion of a signal component of the acoustic pressure signal having a frequency within a predefined frequency range into a stress on the optical medium; and using a detector to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium, such that the electromagnetic radiation received by the detector represents the modified acoustic signal. The coupled oscillator may be coupled to the flexure via the fluid reservoir. The at least one coupled oscillator may be configured to modify the conversion of the signal component by the flexure by changing the sensitivity of the flexure to the signal component. The method may include affecting movement of the flexure member in response to the incident component signal and movement of at least one coupled oscillator in response to the incident signal component.

[0014] The method may include using acoustic measurement information to estimate at least one parameter of interest including: i) the slowness of the volume of interest of the formation; ii) acoustic data communication messages; iii) the distance from the transducer to the borehole wall (stand-off); iv) the geometry of the borehole; and v) the acoustic velocity of the downhole fluid.

[0015] An apparatus embodiment may include an acoustic sensor comprising: a pressure transducer including a flexure attached to an optical medium, the transducer configured to convert a low-amplitude, high-frequency acoustic pressure signal incident on the transducer within a nominal borehole pressure along an axis of the medium into an alternating stress on the optical medium by movement of the flexure while suppressing conversion of low-frequency signals and constant pressure to stress in the optical medium, the acoustic pressure signal propagating through a downhole fluid coupled to the transducer; and a detector configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium, such that the electromagnetic radiation received by the detector represents the acoustic signal. The pressure transducer may include an interface between reservoirs containing a stored fluid, wherein the interface includes the flexure and at least one opening providing communication between the stored fluids.

[0016] The apparatus may include a portion of a drill string, and the ambient pressure noise may include vibrations of the drill string. The received radiation may include at least one of: i) radiation transmitted through a fiber Bragg grating (FBG) in the medium; ii) radiation reflected from a fiber Bragg grating (FBG) in the medium. The ratio of the average signal amplitude of the high frequency acoustic pressure signal to the nominal borehole pressure may be less than 10 -3 .

[0017] The pressure transducer may be configured to mechanically filter low-frequency ambient pressure noise. The opening and the reservoir may be configured to mechanically filter ambient pressure noise by pressure equalization using a bypass flow of the storage fluid through the opening. The curved member may include at least one of: i) a membrane; and ii) a curved rod. The at least one opening may include at least one of: i) a slit in the curved member; and ii) a capillary tube. The at least one opening may include a plurality of slits, and the curved member may include a portion of an interface between a first slit of the plurality of slits and a second slit of the plurality of slits.

[0018] The pressure transducer may include a second interface between one of the reservoirs and the downhole fluid, the second interface including a second flexure responsive to a high-frequency acoustic pressure signal incident on the transducer. A first reservoir in the reservoirs may be defined by a first storage member, and a second reservoir in the reservoirs may be defined by a second storage member. The first storage member may be received by the second storage member.

[0019] The reservoirs can be sized and oriented to suppress acceleration-induced quasi-hydrostatic pressure signals by generating a pressure at the flexure member in the first reservoir that is substantially equal to another pressure at the flexure member in the second reservoir. In some device embodiments, each plane perpendicular to a line intersecting the center of gravity of the combined stored fluid volumes intersects: i) both the first reservoir and the second reservoir, or ii) neither the first reservoir nor the second reservoir.

[0020] The transducer may include a flexure element supporting the flexure member. The transducer may include a flexure element supporting the flexure member and configured to amplify movement of the flexure member. The medium may include a fiber Bragg grating positioned relative to the flexure element at a maximum displacement position adjacent to the medium. The transducer may include a reservoir filled with an inflation fluid. The inflation fluid may be configured to act as a solid to transmit the high-frequency acoustic pressure signal to the flexure member in response to the high-frequency acoustic pressure signal, and to act as a liquid to prevent the transmission of ambient pressure noise to the flexure member in response to ambient pressure noise.

[0021] The method includes using a pressure transducer including a curved member attached to an optical medium to convert a low-amplitude, high-frequency acoustic pressure signal incident on the pressure transducer within a nominal borehole pressure along an axis of the medium into an alternating stress on the optical medium by movement of the curved member while suppressing conversion of low-frequency signals and constant pressure to stress in the optical medium, the acoustic pressure signal propagating through a downhole fluid coupled to the transducer; and using a detector to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium, such that the electromagnetic radiation received by the detector represents the acoustic signal. The method may include using the acoustic measurement information to estimate a parameter of interest, such as a property of the formation or the borehole. The parameter of interest may be at least one of: i) the slowness of a volume of interest of the formation; ii) an acoustic data communication message; iii) the distance from the transducer to the borehole wall; iv) the geometry of the borehole; and v) the velocity of sound in the downhole fluid.

[0022] Another device embodiment includes an acoustic sensor comprising a pressure transducer. The pressure transducer may include: an interface positioned between a fluid reservoir and a fluid body, the interface comprising a flexure attached to an optical medium, the pressure transducer configured to convert an acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer along an axis of the medium into an alternating stress on the optical medium by movement of the flexure, the acoustic pressure signal propagating through the fluid body; a detector configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating stress on the medium; and at least one coupled oscillator coupled to the flexure and configured to modify, through the flexure, the conversion of a component signal of the acoustic pressure signal having a frequency within a predefined frequency range into a stress on the optical medium, such that the electromagnetic radiation received by the detector represents the modified acoustic signal.

[0023] Some embodiments include a non-transitory computer-readable medium product accessible by a processor and having instructions thereon that, when executed, cause at least one processor to perform the above-described method. Apparatus embodiments may include at least one processor and computer memory accessible by the at least one processor, the at least one processor including a computer-readable medium having instructions thereon that, when executed, cause the at least one processor to perform the above-described method.

[0024] Examples of some features of the disclosure may be outlined herein rather broadly so that the detailed description thereof that follows may be better understood, and so that the contribution to the art that they represent may be appreciated. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments in conjunction with the accompanying drawings, in which like elements are designated by like numerals, and in which:

[0026] Figure 1A and Figure 1B illustrates components of a system according to an embodiment of the present disclosure;

[0027] Figures 2A to 2C is a schematic diagram illustrating the operation of an embodiment of a device including an acoustic sensor according to an embodiment of the present disclosure;

[0028] Figure 3A shows a schematic diagram illustrating an acoustic sensor according to an embodiment of the present disclosure;

[0029] Figure 3B A sensor comprising multiple pressure transducers on a single optical fiber is shown;

[0030] Figures 4A to 4Hshows a transducer according to an embodiment of the present disclosure;

[0031] Figure 5A and Figure 5B shows a transducer assembly according to an embodiment of the present disclosure;

[0032] Figure 6 Another transducer according to an embodiment of the present disclosure is shown;

[0033] Figure 7A A flow chart illustrating a method for logging in a borehole intersecting a subterranean formation according to an embodiment of the present disclosure is shown;

[0034] Figure 7B presents a flow chart illustrating a method for obtaining acoustic data;

[0035] Figures 8A to 8F An acoustic sensor including a pressure transducer configured to modify a represented acoustic signal is shown according to an embodiment of the present disclosure;

[0036] Figure 8G shows a model of a coupled oscillator according to an embodiment of the present disclosure;

[0037] Figures 9A to 9F Computational models and response functions of a modeling system with a flexure member and coupled oscillators with various oscillation parameters are presented according to embodiments of the present disclosure.

[0038] Figure 10 A flow chart illustrating a method for obtaining acoustic data is presented. DETAILED DESCRIPTION

[0039] Aspects of the present disclosure relate to apparatus and methods for acoustic well logging, including measuring and interpreting physical phenomena indicative of parameters of interest in a formation, borehole, or downhole fluid therein, including vertical seismic profiling (using seismic measurements from a borehole). Aspects of the present disclosure include novel acoustic sensors (e.g., hydrophones) well-suited for detecting very small pressure differentials (e.g., acoustic signals) in extremely high-pressure environments. Aspects of the present disclosure may be suitable for detecting acoustic reflection boundaries (referred to herein as 'reflectors' or 'boundaries'), e.g., geological structures, and related parameters of interest (e.g., the nature of these boundaries) from borehole acoustic array data.

[0040] Various aspects of the present disclosure include acquiring vertical seismic profiles (VSPs) using sensors within the wellbore and sources at the surface near the well. VSP measurements can produce images with higher resolution than surface seismic images. VSP measurements can also be used to visualize the drill bit during drilling operations. Surface seismic sources (e.g., plate vibrators on land, air guns offshore) can be used to generate the detected acoustic signals.

[0041] Embodiments of the present disclosure include methods for evaluating Earth formations. The method may include deploying an array of seismic receivers in a borehole and recording seismic signals in the receiver array in response to activation of seismic sources at multiple locations on the Earth's surface. For variable well-source-distance geometries, the method may further include estimating the velocity of seismic waves propagating within multiple intervals based on the travel time of seismic waves from multiple source locations to multiple receivers. For interpretation purposes, the estimated parameters (e.g., vertical velocity, estimated anisotropy parameters, etc.) may be used to further process the surface seismic data to obtain seismic images at depth.

[0042] Aspects of the present disclosure may relate to seismic inversion, in which seismic reflection data is processed to recover parameters of interest, including properties of a volume of interest in a formation, such as a portion of a saturated rock matrix. Such parameters may include acoustic impedance, shear impedance, density, anisotropy parameters, and the like. Performing the inversion may include using other constraints generated by additional storage measurements (e.g., well logs). Other aspects relate to estimating formation slowness, acoustic data communication messages (e.g., mud pulses, etc.), acoustic distance, acoustic caliper, general sound velocity measurements, and the like.

[0043] It is known to use hydrophones that employ optical fibers carrying fiber Bragg gratings (FBGs) to detect acoustic signals in fluids. These sensors combine the FBG with a pressure transducer that converts the acoustic signal (e.g., alternating pressure) into alternating stress acting on the fiber along the fiber axis. The FBG reflects a small spectral portion of the light propagating in the fiber. The central wavelength of this spectrum varies with the quantity being measured (e.g., pressure), which is detected using an optical detector at one end of the fiber (detecting the reflected or remaining spectrum).

[0044] In various aspects of the present disclosure, a femtosecond laser can be used to write Bragg gratings into optical fibers or other optical media (e.g., bulk glass or glass foil). This technique allows a variety of grating shapes to be printed by modifying the grating period and depth, and thus achieves various effects, including apodization, pi-shifting, and chirped gratings. In addition, this process can be applied to standard optical fibers. In contrast, UV-light-based methods, which may be advantageous in certain applications, may require a photosensitive fiber core and may suffer from hydrogen darkening under downhole conditions. Therefore, using a femtosecond laser-based process can increase the lifetime of the optical fiber and potentially reduce packaging costs.

[0045] To access hydrocarbons such as oil and gas, boreholes (wellbores) are drilled through hydrocarbon-bearing subsurface formations. More recently, horizontal boreholes extending for thousands of meters ("extended-reach" boreholes) have been drilled to access hydrocarbon reserves near reservoirs and develop satellite fields from existing offshore platforms. Downhole acoustic logging tools used to study subsurface characteristics may include one or more acoustic transmitters or sources and multiple acoustic receivers. Alternatively, the drilled borehole may be equipped with independent acoustic sensors.

[0046] Environmental conditions in deep oil wells, such as, for example, underground or subsea wells, are very harsh. Temperatures can approach 250 degrees Celsius, and pressures can reach 20 to 30,000 psi (200 MPa) or more. In addition to the stringent tool specifications required to prevent premature wear or failure, these very high pressures also exacerbate the small amplitude of the desired signal and make signal detection accuracy problematic. Under the extremely constant offset pressure provided by the ambient pressure of the borehole, the variation in the acoustic pressure signal can be, for example, 1 Pa to 10 kPa (10 -4 psi to 1 psi). Therefore, the ratio of the average signal amplitude of the high frequency acoustic pressure signal to the nominal borehole pressure is typically less than 10 -3 , and can reach 10 -4 to 10 -6 For example, it may be desirable to detect a signal pressure of less than 0.1 psi at an offset pressure of 20,000 psi or greater.

[0047] Thus, aspects of the present disclosure include methods and apparatus for detecting acoustic signals in a borehole. A general apparatus embodiment may include an acoustic sensor comprising a pressure transducer comprising a curved member attached to an optical medium. An acoustic pressure signal may be propagated through a downhole fluid coupled to the transducer. The transducer may be configured to convert a low-amplitude, high-frequency acoustic pressure signal within a nominal borehole pressure incident on the transducer along the axis of the medium by movement of the curved member into an alternating stress on the optical medium. The configuration may enable this to be achieved while suppressing the conversion of low-frequency signals and constant pressure signals to stresses on the optical medium. The pressure transducer may further be configured to filter low-frequency ambient pressure noise in a mechanical flow manner.

[0048] The detector may be configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted along an axis through a medium, wherein at least one optical property of the medium is responsive to an alternating stress on the medium such that the electromagnetic radiation received by the detector represents an acoustic signal. See, for example, U.S. Patent No. 6,396,572 to Chang et al.

[0049] In certain embodiments, a pressure transducer includes an interface positioned between reservoirs containing stored fluid. The interface may include a flexure and at least one opening providing communication between the reservoirs. The opening and the reservoirs may be configured to mechanically flow filter ambient pressure noise by pressure equalization using a bypass flow of the stored fluid through the opening. The pressure transducer may further include a second interface positioned between one of the reservoirs and the downhole fluid, the second interface including a second flexure responsive to a high-frequency acoustic pressure signal incident on the transducer. The transducer may include a flexure element supporting the flexure.

[0050] In other embodiments, the transducer may be implemented with a reservoir filled with an inflation fluid. The inflation fluid may be configured to act as a solid in response to a high-frequency acoustic pressure signal, transmitting the high-frequency acoustic pressure signal to the flexure member; and in response to ambient pressure noise, the inflation fluid may be configured to act as a liquid, preventing the ambient pressure noise from being transmitted to the flexure member.

[0051] Aspects of the present disclosure relate to using at least one acoustic sensor as part of one or more downhole acoustic logging tools or distributed sensor systems to generate acoustic information in response to pressure signals received from a formation at the sensor. The signal may be seismic in nature or may be generated by an excitation in a borehole. At least one acoustic receiver may be positioned in the borehole. The information indicates a parameter of interest. As used herein, the term "information" includes information in any form (analog, digital, EM, printed, etc.) and may include one or more of the following: raw data, processed data, and signals.

[0052] The method may include estimating a parameter of interest from the information, evaluating the formation using the parameter of interest, and / or performing other drilling or formation operations based on the location of the reflection point, the location of the boundary, the parameter of interest of the boundary, or other parameters of interest derived therefrom. In certain embodiments, the parameter of interest may be used to estimate the status of the drilling operation, the characteristics of the borehole or formation, or the orientation of a component of a downhole tool, and then used to perform the operations described above.

[0053] Aspects of the present disclosure may be employed in a variety of different embodiments. The sensors may be used in conjunction with a carrier such as a drill string, coiled tubing, wireline, e-line, slickline, etc. The sensors may be mounted on a tool for measurement, deployed from a tool, or deployed separately (before or after delivery of the tool in the borehole). The sensors, downhole tools, and other system components may be coupled or combined with additional tools, including, for example, some or all of an information processing system, such as Figure 1B, discussed in further detail below. In some common embodiments, the carrier is implemented as a tool string of a drilling system, and acoustic wellbore logging can be characterized as a "logging while drilling" (LWD) or "measurement while drilling" (MWD) operation. As described herein, a "borehole" or "wellbore" refers to a single hole that constitutes all or a portion of a well drilled. Depending on the configuration, in some cases, the system shown herein can be used during drilling and / or after the wellbore has been formed, including after the casing is installed or the infrastructure is generated. Although a land system is shown, the teachings of the present disclosure can also be used in offshore or subsea applications. As described herein, a "formation" refers to the various features and materials that may be encountered in a subsurface environment and surrounding a borehole.

[0054] Figure 1A and Figure 1B Components of a system according to an embodiment of the present disclosure are shown. Figure 1A A system 100 is schematically shown having a downhole tool 10 configured to acquire information regarding a downhole parameter of interest (e.g., a value of a property of a formation 80, a borehole 50, or a downhole fluid 90 therein) using an acoustic measurement instrument 40. A transducer module 45 may define a portion of an outer surface of the instrument, extend from the tool body 30 into the borehole, or be trailed behind the tool body 30. At least one measurement instrument 40 is responsive to the parameter of interest. Non-limiting examples of downhole fluids include drilling fluids, flowback fluids, formation fluids, production fluids containing one or more hydrocarbons, petroleum, and solvents used in conjunction with downhole tools, water, brine, engineered fluids, and combinations thereof.

[0055] The system 100 may include a conventional derrick 60 erected on a drill floor 70. A conveying device (carrier 15), which may be rigid or non-rigid, may be configured to convey the downhole tool 10 into a wellbore 50 proximate a volume of interest 80 of a formation 85. The carrier 15 may be a drill string, coiled tubing, wireline, e-line, slickline, or the like. The downhole tool 10 may be coupled or combined with additional tools, such as some or all of an information processing system (illustrated). Thus, depending on the configuration, the tool 10 may be used during drilling and / or after the wellbore 50 is formed. As described herein, a "borehole" or "wellbore" refers to a single hole that constitutes all or a portion of a drilled well. Although a land system is shown, the teachings of the present disclosure may also be used in offshore or subsea applications. The carrier 15 may include embedded conductors for providing power and / or data for signal and / or power communication between the surface and downhole equipment (e.g., a seven-core cable). The carrier 15 may include a bottom hole assembly, which may include a drilling motor for rotating the drill bit.

[0056] A drilling fluid (e.g., drilling fluid or 'mud') 90 may be present between the formation 85 and the downhole tool 10. The surface control system 65 receives signals from one or more acoustic measuring instruments 40 and other sensors for the system 100 and processes such signals according to programmed instructions provided to the surface control system 65. The surface control system 65 may display desired parameters and other information on a display / monitor used by an operator. The surface control system 65 may further communicate with the downhole control system 20 at a suitable location on the downhole tool 10. The surface control system 65 may process data related to the operation and data from the sensors 40 and may control one or more downhole operations performed by the system 100.

[0057] In one embodiment, the electronics 30 associated with the sensor 40 can be configured to record and / or process the acquired information. Certain embodiments of the present disclosure can be implemented using a hardware environment comprising an information processor 17, an information storage medium 13, an input device 11, processor memory 9, and may include a peripheral information storage medium 19. The hardware environment may be located in the well, at the drilling rig, or at a remote location. Furthermore, several components of the hardware environment may be distributed between those locations. The input device 11 may be any data reader or user input device, such as a data card reader, a keyboard, a USB port, etc. The information storage medium 13 stores the information provided by the detector. The information storage medium 13 may comprise any non-transitory computer-readable medium for standard computer information storage, such as a USB drive, a memory stick, a hard drive, removable RAM, EPROM, EAROM, flash memory, and optical disks, or other commonly used memory storage systems known to those skilled in the art, including internet-based storage. The information storage medium 13 stores a program that, when executed, causes the information processor 17 to perform the disclosed method. The information storage medium 13 may also store user-provided formation information, or the formation information may be stored in a peripheral information storage medium 19, which may be any standard computer information storage device, such as a USB drive, memory stick, hard drive, removable RAM, or other commonly used memory storage systems known to those skilled in the art, including internet-based storage. The information processor 17 may be any form of computer or mathematical processing hardware, including internet-based hardware. When a program is loaded from the information storage medium 13 into the processor memory 9 (e.g., computer RAM), the program, when executed, causes the information processor 17 to retrieve the detector information from the information storage medium 13 or the peripheral information storage medium 19 and process the information to estimate the parameter of interest. The information processor 17 may be located above ground or underground.

[0058] As used herein, the term "information" includes any form of information (analog, digital, EM, printed, etc.). As used herein, a processor is any information processing device that transmits, receives, manipulates, converts, calculates, modulates, transposes, carries, stores, or otherwise utilizes information. In several non-limiting aspects of the present disclosure, an information processing device includes a computer that executes programming instructions for executing various methods. In addition to the functions described in the present disclosure, these instructions may also provide equipment operation, control, data collection and analysis, and other functions. The processor may execute instructions stored in a computer memory accessible to the processor, or may adopt logic implemented as a field programmable gate array ("FPGA"), an application specific integrated circuit ("ASIC"), other combinational or sequential logic hardware, etc.

[0059] To perform measurements during a single pass, the tool can use high-bandwidth transmission to transmit the information acquired by the detectors 20, 30 to the surface for analysis. For example, the communication line used to transmit the acquired information can be an optical fiber, a metallic conductor, or any other suitable signal-conducting medium. It will be appreciated that the use of a "high-bandwidth" communication line can allow surface personnel to monitor and control operations in "real time."

[0060] Figure 1A One novel aspect of the system shown in FIG is that the surface control system 65 and / or the downhole control system 20 are configured to perform certain methods not known in the prior art (discussed below). Either the surface control system or the downhole control system can be configured to control the aforementioned tools and any combination of sensors and estimate parameters of interest according to the methods described herein.

[0061] Aspects of the present disclosure find application in a variety of different embodiments. In some general embodiments, carrier 15 is implemented as a downhole tool string of a drilling system, and measurements taken in the borehole can be characterized as "logging while drilling" (LWD) or "measurement while drilling" (MWD) operations.

[0062] Figure 1B An exemplary embodiment of a MWD system for evaluating a formation using measurements from an acoustic measurement tool is shown. System 101 includes a carrier 111, which is shown positioned in a wellbore or borehole 50 penetrating at least one formation 195. System 101 also includes a tool 110 configured to perform acoustic measurements in the borehole.

[0063] Figure 1BA drill string 120 is shown, including a bottom hole assembly (BHA) 190 that serves as a carrier for transport within a borehole 50. Drilling system 101 includes a conventional derrick 111 erected on a platform or floor 112, which supports a rotary table 114 that is rotated at a desired rotational speed by a prime mover, such as an electric motor (not shown). Tubing, such as jointed drill pipe 122, with drilling assembly 190 attached at its bottom end, extends from the surface to the bottom 151 of the borehole 50. A drill bit 150, attached to drilling assembly 190, decomposes geological formations as it rotates to drill the borehole 50. Drill string 120 is coupled to a drawworks 130 via a kelly joint 121, a rotary joint 128, and a line 129 through pulleys. Drawworks 130 is operated to control weight on bit ("WOB"). Drill string 120 can be rotated by a top drive (not shown) rather than by a prime mover and rotary table 114. Alternatively, coiled tubing may be used as tubing 122. Tubing ejector 114a may be used to deliver the coiled tubing having a drilling assembly attached to its bottom end. The operation of drawworks 130 and tubing ejector 114a is known in the art and will not be described in detail herein.

[0064] It should be understood that embodiments of the present disclosure are well suited for use in wells having various configurations, including horizontal wells, deviated wells, inclined wells, multi-lateral wells, etc. Accordingly, the use of directional terms herein (e.g., above, below, upper, lower, upward, downward, topmost, lowermost, uphole, downhole, etc.) refers to a direction traveling along the borehole toward or away from the surface, with an upward direction being toward the surface and a downward direction being away from the surface.

[0065] A suitable drilling fluid 131 (also referred to as "mud") from its source 132 (such as a mud pit) is circulated under pressure through the drill string 120 by a mud pump 134. The drilling fluid 131 flows from the mud pump 134 into the drill string 120 via an ejector 136 and a fluid line 138. Drilling fluid 131a from the drill pipe is discharged through an opening in the drill bit 150 at the bottom of the borehole 151. Returning drilling fluid 131b circulates uphole through the annular space 127 between the drill string 120 and the borehole 50 and returns to the mud pit 132 via a return line 135 and a cuttings screen 185, which removes drill cuttings 186 from the returning drilling fluid 131b. A sensor S1 in line 138 provides information about the fluid flow rate. Surface torque sensors S2 and S3 associated with the drill string 120 provide information about the torque and rotational speed of the drill string 120, respectively. The tubing injection rate is determined by sensor S5, while sensor S6 provides the hook load of the drill string 120.

[0066] A well control system 147 is placed at the top of the borehole 50. The well control system 147 includes a surface blowout preventer (BOP) stack 115 and surface chokes 149 in communication with the wellbore annulus 127. The surface chokes 149 can control the flow of fluid out of the borehole 50 to provide back pressure as needed to control the well.

[0067] In some applications, the drill bit 150 is rotated solely by rotating the drill pipe 122. However, in many other applications, a downhole motor 155 (mud motor) disposed in the BHA 190 also rotates the drill bit 150. The rate of penetration (ROP) of a given BHA depends largely on the thrust on the WOB or drill bit 150 and the speed at which the drill bit is rotated.

[0068] A surface control unit or controller 140 receives signals from downhole sensors and equipment via sensors 143 disposed in fluid lines 138, as well as signals from sensors S1-S6 and other sensors used in system 101, and processes such signals according to programmed instructions provided to the surface control unit 140. The surface control unit 140 displays drilling parameters and other parameters of interest related to the borehole, formation, and drilling operations on a display / monitor 141, as well as other information used by the operator to control the drilling operations. The surface control unit 140 may be a computer-based unit that may include a processor 142 (such as a microprocessor), a storage device 144 (such as a solid-state memory, magnetic tape, or hard disk), and one or more computer programs 146 in the storage device 144, which may be accessed by the processor 142 for executing the instructions contained in such programs. The surface control unit 140 may further communicate with a remote control unit 148. The surface control unit 140 may process data related to the drilling operation, data from sensors and equipment on the surface, and data received from downhole; and may control one or more operations of the downhole equipment and the surface equipment. Data can be transmitted in analog or digital form.

[0069] The BHA 190 may include a tool 110 configured to perform acoustic measurements. The BHA 190 may also include other formation evaluation sensors or devices (also referred to as measurement-while-drilling ("MWD") or logging-while-drilling ("LWD") sensors) for determining resistivity, density, porosity, permeability, acoustic properties, nuclear magnetic resonance properties, formation pressure, properties or characteristics of downhole fluids, and other desired properties of the formation 195 surrounding the BHA 150. For convenience, all such sensors are generally referred to herein by the numeral 165. The BHA 190 may further include a variety of other sensors and devices 159 for determining one or more properties of the BHA 190, such as vibration, bending moment, acceleration, oscillation, eddy current, stick-slip, weight on bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, and the like.

[0070] The BHA 190 may include a steering device or tool 158 for steering the drill bit 50 along a desired drilling path. In one aspect, the steering device may include a steering unit 160 having a plurality of force-applying members 161a-161n. The force-applying members may be mounted directly on the drill string, or they may be at least partially integrated into the drilling motor. In another aspect, the force-applying members may be mounted on a sleeve that is rotatable about the central axis of the drill string. The force-applying members may be activated using an electromechanical actuator, an electrohydraulic actuator, or a hydrostatic actuator. In another embodiment, the steering device may include a steering unit 158 having a bend sub, and a first steering device 158a for orienting the bend sub in the wellbore and a second steering device 158b for maintaining the bend sub in a selected drilling direction. The steering units 158, 160 may include a near-bit inclinometer and a magnetometer.

[0071] The drilling system 101 may include sensors, circuitry, and processing software and algorithms for providing information about desired drilling parameters associated with the BHA, drill string, drill bit, and downhole equipment such as drilling motors, steering units, thrusters, etc. Many current drilling systems, particularly those used to drill highly deviated and horizontal wellbores, utilize coiled tubing to transport drilling components downhole. In such applications, thrusters may be deployed in the drill string 120 to provide the desired force on the drill bit.

[0072] Exemplary sensors for determining drilling parameters include, but are not limited to, drill bit sensors, RPM sensors, weight-on-bit sensors, sensors for measuring mud motor parameters (e.g., mud motor stator temperature, pressure differential across the mud motor, and fluid flow rate through the mud motor), and sensors for measuring acceleration, vibration, eddy currents, radial displacement, stick-slip, torque, shock, vibration, strain, stress, bending moment, bit runout, axial thrust, friction, back-rotation, BHA buckling, and radial thrust. Sensors distributed along the drill string can measure physical quantities such as drill string acceleration and stress, internal pressure in the drill string bore, external pressure in the annulus, vibration, temperature, electric and magnetic field strengths within the drill string, the bore of the drill string, etc. Suitable systems for performing dynamic downhole measurements include COPILOT, a downhole measurement system manufactured by Baker Hughes Incorporated.

[0073] The drilling system 101 may include one or more downhole processors at a suitable location (such as 193 on the BHA 190). The one or more processors may be microprocessors using a computer program implemented on a suitable non-transitory computer-readable medium that enables the processor to perform control of the system 101 and processing of information (such as information from sensors). The non-transitory computer-readable medium may include one or more ROMs, EPROMs, EAROMs, EEPROMs, flash memories, RAMs, hard drives, and / or optical disks. Other equipment such as power and data buses, power supplies, etc. will be apparent to those skilled in the art. In one embodiment, the MWD system utilizes mud pulse telemetry to transmit data from a downhole location to the surface while drilling operations are being performed. The surface processor 142 may process the surface measurement data and the data transmitted from the downhole processor to evaluate the formation.

[0074] The surface processor 142 or the downhole processor 193 may also be configured to control the steering device 158, the mud pump 134, the drawworks 130, the rotary table 114, the downhole motor 155, other components of the BHA 190, or other components of the drilling system 101. The surface processor 142 or the downhole processor 193 may be configured to control the aforementioned sensors and estimate parameters of interest according to the methods described herein.

[0075] Control of these components can be performed using one or more models using the methods described below. For example, the ground processor 142 or the downhole processor 193 can be constructed to: i) autonomously modify the drilling operation when a trigger condition occurs; ii) modify the drilling operation in response to an operator command; or iii) a combination of these. Such modifications may include changing drilling parameters, steering the drill bit (e.g., geosteering), changing the drilling fluid program, activating well control measures, etc. Generally speaking, control of these devices and control of the various processes of the drilling system can be performed in a fully automated manner or by interacting with personnel via notifications, graphical representations, user interfaces, etc. Reference information that can be accessed by the processor can also be used. In some common embodiments, the ground processor 142, the downhole processor 193 or other processors (e.g., a remote processor) can be configured to operate the vanishing tool 110 to generate vanishing waves and measurement signals.

[0076] System 101 may include any number of downhole tools used for various processes, including formation drilling, geosteering, and formation evaluation (FE) for making electrical measurements of depth and / or time of one or more physical properties in or around a borehole, including a volume of interest of a formation intersected by the borehole. Tool 110 may be included in or embodied as a BHA, drill string component, or other suitable carrier.

[0077] While the drill string 120 is shown as a delivery device for the tool 110, it should be understood that embodiments of the present disclosure may be used in conjunction with tools delivered via rigid delivery systems (e.g., jointed tubulars or coiled tubing) as well as non-rigid delivery systems (e.g., slickline, wireline, e-line, etc.). The drilling system 101 may include bottom hole components and / or sensors and equipment for implementing embodiments of the present disclosure on the drill string or slickline.

[0078] Mathematical models, lookup tables, or other models representing the relationship between signals and parameter values can be used to characterize a formation, a borehole location, or operations within a formation; optimize one or more operational parameters of production or development; and the like. The system can perform these actions through notifications, recommendations, and / or intelligent control. Various types of downhole parameters can be determined using measurements according to the present disclosure and evaluated according to the embodiments disclosed herein.

[0079] Tang's U.S. Patent No. 7,035,165, which has the same assignee as the present disclosure and is incorporated herein by reference, discloses a method in which a plurality of multi-component acoustic measurements are obtained at multiple depths and for multiple source-receiver spacings on a logging tool. A directional sensor (such as a magnetometer) on the logging tool can be used to obtain a directional measurement indicating the orientation of the logging tool. The directional measurement is used to rotate the multi-component measurement to a fixed coordinate system (such as an earth-based system defined relative to magnetic north or geographic north), thereby providing a rotated multi-component measurement. The rotated multi-component measurement is processed to provide an image of the subsurface.

[0080] U.S. Patent No. 8,055,448 B2, issued to Mathiszik et al., and having the same assignee as the present disclosure and incorporated herein by reference, discloses further improvements in MWD acoustic imaging. A downhole acoustic logging tool is used to generate a guided borehole wave, which propagates into the formation as a body wave, reflects from an interface, and is converted back into a guided borehole wave. The guided borehole wave generated by the reflection of the body wave is used to image a reflector. U.S. Patent No. 8,811,114 B2, issued to Geerits et al., and having the same assignee as the present disclosure and incorporated herein by reference, discloses further improvements in MWD acoustic imaging.

[0081] Figures 2A to 2C is a schematic diagram illustrating the operation of an apparatus embodiment including an acoustic sensor according to an embodiment of the present disclosure. In a typical apparatus embodiment, a sensor according to the present disclosure may be implemented as a probe and installed in a downhole fluid. This installation may be permanent or temporary and may involve suspension in the fluid, free floating, or attachment to the wellbore via a separate or shared tether. Thus, the probe may be stationary or in motion after installation.

[0082] refer to Figure 2A , system 200 includes a plurality of probes 202 suspended in fluid 90 in a borehole 50 by tethers 204. During installation, the exterior of the probe housing can be submerged in the downhole fluid. In alternative embodiments, the probes 202 can be retractable; for example, during operation, the probes can be inserted or placed into the downhole fluid in the borehole and then retracted to perform cleaning or allow other operations in the borehole.

[0083] Figure 2B is a schematic diagram illustrating the acquisition of VSP measurements according to an embodiment of the present disclosure. A drilling rig 221 is located at the surface 223. This can be a drilling rig, or it can be a mast rig that delivers a slickline into the borehole 201. The borehole 201 penetrates the layers 203, 205. Positioned in the borehole 201 are seismic sensors represented by 211a, 211b, 211c, 211d, etc. Each sensor can be a sensor according to an embodiment of the present disclosure (e.g., a hydrophone). Data for a single offset VSP is typically acquired using a single seismic source, such as 225a at the surface (or in a body of water at the surface). Reference Figure 2B An exemplary ray path depicting seismic energy propagating from source 225a to detector 211d is depicted by ray 227a, which reflects from the bottom of layer 205 at boundary 206 and reaches receiver 211d along the ray path indicated by 229a.

[0084] In a typical type of VSP operation, data generated by operation at a single location (such as 225a) is recorded at each of the receivers 211a, 211b, 211c, 211d, etc. in the borehole. Analysis of the reflected data provides information about the seismic velocities of the subsurface and the configuration of layer boundaries. In a variable-well source spacing VSP, this process is repeated to operate the source at multiple source locations, such as 225b, 225c. Acquiring data from multiple source locations at multiple detectors provides redundant sampling of the subsurface region, making it possible to determine the subsurface velocity based on the travel time of rays between each of the sources and each of the receivers. This operation of using travel time to determine velocity is called "tomographic inversion," and many processing packages are commercially available and available as open source software (e.g., OpenTOAST) that perform tomographic inversion of this seismic travel time data. Processing VSP measurements to characterize formations is a well-developed field. See, for example, US Patent No. 7,751,279 to Aronstam and US Patent No. 7,751,279 to Zhao et al., which are hereby incorporated by reference in their entireties.

[0085] Figure 2CA simulated geometry for a surface seismic survey is shown. A vertical borehole has been assumed, in which the source has been "reflected" to simulated receiver locations on the ground 285a, 285b, 285c. Similarly, the ray paths have also been reflected to give simulated ray paths on the left side of the borehole. In operation, the method includes deploying a seismic receiver array as described herein in the borehole, and recording seismic signals in the receiver array in response to activation of seismic sources at multiple locations on the earth's surface. For the variable well source spacing technique, the method further includes estimating the velocity of the vertically propagating seismic waves in multiple intervals based on the travel time of the seismic waves from the multiple source locations to the multiple receivers, and two anisotropy parameters ε and δ related to the normal travel curve of the compression wave in the multiple intervals. For interpretation purposes, the estimated vertical velocity and the estimated interval anisotropy parameters can be used to further process the surface seismic data to obtain seismic images at depth. For multi-azimuth, variable well source distance or 3D VSP geometries, the method may further include estimating the velocity of vertically propagating seismic waves within a plurality of intervals and five orthorhombic anisotropy parameters ε1, ε1, δ1, δ2, and δ3, which are related to the normal travel velocity of compressional waves within the plurality of intervals, based on the travel times of the seismic waves from a plurality of source locations around the well to a plurality of receivers. For purposes of explanation, the estimated vertical velocity and the estimated anisotropy parameters may be used to further process the surface seismic data to obtain seismic images at depth. See, for example, U.S. Patent No. 8,750,074 to Blias, which is hereby incorporated by reference herein in its entirety.

[0086] Downhole fiber optic hydrophone

[0087] Figure 3A A schematic diagram illustrating an acoustic sensor according to an embodiment of the present disclosure is shown. Sensor 300 is part of a measurement instrument configured to be delivered in a borehole 50. Sensor 300 may include a pressure transducer 302 and an interrogator 304. Pressure transducer 302 includes a transducer body 312 having a portion (e.g., face 322) immersed in the downhole fluid. Transducer body 312 may be mechanically decoupled from the sensor tool body (drill collar, slickline, etc.) to insulate transducer body 312 from structure-borne sound transmission. An acoustic pressure signal is propagated through the downhole fluid coupled to the transducer. In some embodiments, some (or all) of the instruments may protrude from the tool body into the borehole. Transducer 302 is configured to convert the acoustic pressure signal within the nominal borehole pressure on the transducer into an alternating stress incident on an optical medium (e.g., optical fiber 303).

[0088] Optical fiber 303 includes fiber Bragg gratings (FBGs) 305. These are a type of distributed Bragg reflector constructed in a section of optical fiber (e.g., using pulses from a femtosecond laser) that reflects light centered around a specific wavelength, such as by creating periodic variations in the refractive index of the fiber core and thereby producing a dielectric mirror at a specific wavelength. FBGs 305 reflect a small spectral portion of electromagnetic radiation (e.g., light) propagating in optical fiber 303, allowing the remaining portion to pass through.

[0089] Electromagnetic radiation is provided by an energy source 308, such as a light source configured to provide light to the sensor through an optical fiber. As an example, the energy source can be a tunable laser source configured to provide light having a wavelength that sweeps across a range of wavelengths at a selected rate, but the energy source can be any tunable light source or swept wavelength light source that covers a range of wavelengths including visible, ultraviolet, and infrared light. As another example, a light emitting diode or superluminescent diode can be optically coupled to the optical fiber 303 to provide an infrared beam. The energy source 308 can optionally be incorporated as part of the interrogator 304, such as Figure 3A As displayed.

[0090] The central wavelength of the reflected portion of the spectrum (the 'reflected spectrum' or 'reflection spectrum') is responsive to physical parameters on the fiber, including, in particular, the stress along the fiber axis. Due to the transducer configuration, the stress on the fiber represents pressure. Therefore, the central wavelength of the spectrum changes as the pressure on the transducer changes, and is indicative of the acoustic pressure signal on the sensor.

[0091] Fiber 303 may travel through transducer 302 and into interrogator 304. Interrogator 304 (implemented using, for example, one or more photodetectors, charge coupled devices, opto-electrical converters, etc.) is optically coupled to fiber 303 and detects electromagnetic signals (e.g., light) received from the fiber.

[0092] An optical coupling or splitting mechanism 307, such as an optical circulator or fiber splitter, may be used to couple or split optical signals traveling in opposite directions in the optical fiber 303, such as, for example, providing light from a light source 308 to the transducer 302 through the optical fiber 303, and sending light returning on the optical fiber from the transducer 302 to the spectral detector 306. The spectral detector 306 generates measurement information indicative of a pressure signal based on an electromagnetic signal responsive to the partial reflection of the electromagnetic energy.

[0093] Sensor 300 may include circuitry 310 for taking measurements using interrogator 304. Circuitry 310 may include a control unit operatively connected to source 308 and spectral detector 306. Circuitry 310 may be implemented at least in part as described above with reference to FIG. Figure 1A and Figure 1BThe at least one processor described may be an additional processor or other supporting circuitry. In some embodiments, portions of circuitry 310 may be located at the instrument, elsewhere in the tool (including, for example, in other alternative tools), or at the surface.

[0094] In operation, the instrument may be controlled by circuitry 310 , including a control unit (e.g., a processor), which drives energy source 308 while a portion of the transducer (e.g., face 322 ) is immersed in downhole fluid and receives measurement information (e.g., data) from spectral detector 306 .

[0095] Thus, interrogator 304 is configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium (e.g., the reflected spectrum). Alternatively, an optical detector may be used to detect the central wavelength at the opposite end of the optical fiber or at the remaining portion of the original spectrum. The time-varying value of the central wavelength may be used to generate the time-varying value of the acoustic pressure signal. Spectral detector 306 may be implemented, for example, using one or more optical detectors corresponding to the desired wavelength.

[0096] Figure 3B A sensor is shown that includes multiple pressure transducers 341, 342, and 343 on a single optical fiber. The fiber section corresponding to each transducer includes a unique Bragg grating. The characteristic wavelength of each grating is spaced apart from the characteristic wavelengths of the remaining gratings, allowing the signal of a specific transducer to be recovered. A spectral demultiplexer 355, such as a set of additional Bragg gratings on the detector side, separates the signal into a corresponding set of photodetectors 360, 361, and 362, with one Bragg grating and one photodetector for each transducer. This configuration allows for simultaneous interrogation of two or more sensors.

[0097] The pressure transducer 302 is configured to convert a low-amplitude, high-frequency acoustic pressure signal within the nominal borehole pressure incident on the transducer into an alternating stress on the optical medium along the axis of the medium by movement of the flexure, while suppressing conversion of low-frequency signals and constant pressure into stress on the optical medium.

[0098] High-excursion sensor transducers

[0099] Figures 4A to 4H A transducer according to an embodiment of the present disclosure is shown. Figure 4A, transducer 400 includes a transducer body 406 containing a first reservoir 408 and a second reservoir 410. Pressure transducer 400 includes an interface 424 located between the reservoirs. Body 406 and interface 424 can be made of silicon, glass, a crystalline structure, a composite material, etc., such as, for example, by bonding wafers together, by subtractive manufacturing (e.g., etching, laser ablation), etc. Each reservoir is filled with the same type of reservoir fluid (e.g., silicone oil), and interface 424 includes at least one opening that provides communication of the reservoir fluid between first reservoir 408 and second reservoir 410. The opening is a capillary 404. Other embodiments may use more than one capillary, or may use different types of openings.

[0100] The interface 424 also includes a flexure implemented as a flexible membrane 420. The flexible membrane 420 can be made of a polymer (e.g., polyvinylidene fluoride ('PVDF')) bonded to the body. In other embodiments, the flexure is an additional wafer bonded in place, or can be produced by subtractive manufacturing of the body 406. A segment of the optical fiber 403 is attached to the membrane, which includes an FBG near the attachment point. The optical fiber can be attached using adhesives, forging, welding, or splicing processes. The optical fiber can pass through the membrane in the center in a normal direction and be attached to the membrane at boundary points. A second interface separates one of the reservoirs 408 and the downhole fluid 90. The second interface includes a second flexure 422 that responds to a high frequency acoustic pressure signal incident on the transducer.

[0101] FBGs can be written into optical fibers using femtosecond lasers. This allows for the printing of a variety of grating shapes by modifying the grating period and depth, and thus enables the realization of apodized, pi-shifted, and chirped gratings. Furthermore, in contrast to UV-based methods that require a photosensitive fiber core, this process can be applied to standard optical fibers.

[0102] An acoustic signal in the downhole fluid is incident on the membrane 422. The fluid in the reservoir 408 behind (inside) the membrane 422 is subjected to a high ambient pressure from the downhole fluid, but this pressure is balanced across the membrane 424 by the capillary 404. In the presence of the capillary 404, the fluid response to a constant or low-frequency pressure inside the transducer body 406 is balanced by the capillary without producing a significant response (movement) to the membrane 420. Therefore, it can be said that the capillary 404 filters out low-frequency signals. In contrast, high-frequency signals incident on the membrane 422 induce a symmetrical response on the membrane 420, wherein a corresponding strain signal is generated on the optical fiber. In the case of a pressure increase that is balanced across all fluids, the response on the membrane 420 and therefore the optical fiber exhibits significant fidelity (e.g., less than 10% per MPa pressure difference, or less than 5% per MPa pressure difference, or including less than 1% per MPa pressure difference or better). The transducer body 406 may be mechanically decoupled from the sensor tool body (drill collar, slickline, etc.) in order to insulate the transducer body 406 from structure-borne sound transmission.

[0103] The collective result of these features is that the pressure transducer is configured to fluidically filter low frequency ambient pressure noise by pressure equalization using a bypass flow of the reservoir fluid through the opening. This is achieved by the fluid bypass flow having a cross section configured to compensate for the pressure difference between the two reservoirs by slowly carrying it. Figure 4A In , bypass flow is achieved by introducing a capillary tube 404 of appropriate diameter and length between two silicone oil filled reservoirs to achieve the desired cutoff frequency ("f"):

[0104]

[0105] in,

[0106] l is the length of the capillary;

[0107] r is the radius of the capillary;

[0108] V is the volume of the reservoir behind the capillary;

[0109] μ is the dynamic viscosity of the fluid;

[0110] ρ is the fluid density; and

[0111] c is the speed of sound in the fluid.

[0112] Figure 4B and Figure 4C Another transducer according to an embodiment of the present disclosure is shown. Figure 4B is a side view of transducer 430 . Figure 4Cis a top view of interface 444. Transducer 430 includes a transducer body 436 containing a first reservoir 438 and a second reservoir 440. In some embodiments, reservoirs 438 and 440 can be configured so that their respective maximum ranges in a direction perpendicular to interface 444 are equal (and opposite). This configuration effectively compensates for pressure differences at the interface due to quasi-hydrostatic pressure. Transducer body 436 can also be mechanically decoupled from the sensor tool body (drill collar, slickline, etc.) to insulate transducer body 436 from structure-borne sound transmission. Pressure transducer 430 includes an interface 444 between the reservoirs. Each reservoir is filled with the same type of reservoir fluid (e.g., silicone oil), and interface 444 includes two openings that provide communication between the reservoir fluids of first reservoir 438 and second reservoir 440. The openings include slits 451 and 452 in interface 444. Other embodiments may additionally utilize capillaries, or may utilize more or fewer openings of various sizes.

[0113] Flexure member 421 is implemented as a portion of a curved rod forming the interface between a first slot 451 of the plurality of slots and a second slot 452 of the plurality of slots. A segment of optical fiber 433 is attached to flexure member 421 (e.g., using an adhesive) and includes an FBG centered around the attachment. A second interface separates one of reservoirs 438 from downhole fluid 90. The second interface includes a second flexure member 432 (e.g., a membrane) that responds to a high-frequency acoustic pressure signal incident on the transducer.

[0114] As previously described, an acoustic signal in the downhole fluid is incident on the outer membrane 452. Low-frequency pressure is equalized across the interface by capillary slits 451 and 452, while preventing a corresponding significant response on component 421, thereby filtering the low-frequency pressure signal and maintaining constant pressure. Again, with the pressure increase being equalized across all fluids, the response on component 421, and therefore the optical fiber, is significantly improved over conventional techniques. Bypass flow is achieved by configuring slits 451 and 452 of appropriate dimensions between two silicone oil-filled reservoirs to achieve the desired cutoff frequency ("f"):

[0115]

[0116] in,

[0117] l is the length of the slit;

[0118] h is the height of the slit;

[0119] w is the width of the slit;

[0120] V is the volume of the reservoir behind the slit;

[0121] μ is the dynamic viscosity of the fluid;

[0122] ρ is the fluid density; and

[0123] c is the speed of sound in the fluid.

[0124] Figures 4D to 4H Another transducer according to an embodiment of the present disclosure is shown. Figure 4D is a side view of transducer 470 . Figure 4E 4 is a second side view of transducer 470, perpendicular to the first view. Transducer 470 includes a sensor body 476 containing a first reservoir 478 and a second reservoir 480. Each reservoir is filled with the same type of reservoir fluid (e.g., silicone oil), and an interface 474 between the reservoirs includes openings 481 and 482 that provide communication of the reservoir fluid between first reservoir 478 and second reservoir 480. The second interface includes a second flexure 472 (e.g., a membrane) that responds to high-frequency acoustic pressure signals incident on the transducer. Figure 4F is a top view of the interface.A segment of optical fiber 483 is attached (eg, using an adhesive) to a flexure 491 and includes an FBG 493 centered about the attachment, as described above.

[0125] Transducer 470 represents a transducer configured for vibration compensation. Figure 4B and Figure 4C As described above, the maximum ranges of reservoirs 478 and 480 relative to interface 474 in a direction perpendicular to interface 474 can be equal, and this configuration can effectively compensate for the pressure difference generated at the interface due to quasi-hydrostatic pressure. To achieve the same effect in all directions, transducer 470 can be configured so that upper reservoir 478 and lower reservoir 480 can meet the same conditions in two perpendicular and respectively perpendicular directions 494 and 495.

[0126] Figure 4G and 4H One configuration of transducer 470 is shown. Figure 4G showing a side view of the upper reservoir member 497, and Figure 4HA front view of lower reservoir member 498 is shown. Each reservoir is symmetrical in two dimensions. Lower reservoir member 498 is configured to receive upper reservoir member 497. Transducer 470 can be constructed by rotating upper reservoir 497 90 degrees and coupling the reservoir members with an interlocking assembly. The reservoir members are also configured so that upper reservoir member 497 is substantially symmetrical with lower reservoir member 498. Upper reservoir member 497 may have substantially the same dimensions as lower reservoir member 498, but a different orientation with respect to assembly alignment. The fluid volumes of the reservoirs are substantially the same. Thus, the reservoirs have a shape and corresponding orientation that results in suppression of any acceleration-induced quasi-hydrostatic pressure signals. This is achieved by ensuring that the pressure at the flexure is the same in both reservoirs.

[0127] Figure 5A and 5B A transducer assembly according to an embodiment of the present disclosure is shown. Transducer 500 includes a glass plate 544, which acts as an interface wall in a manner similar to interface 444. An additional reservoir can be formed above glass plate 544 by extensions of the transducer body and membrane (not shown). Pressure transducer 500 includes a flexure 521. Flexure 521 is implemented as a portion of a flexure rod forming an interface between a first slit 551 of a plurality of slits and a second slit 552 of a plurality of slits. A segment of optical fiber 533 is attached to flexure 521 (e.g., using an adhesive). Flexure element 550 supports flexure 521. Flexure element includes a notch 554 and a cavity 555, in which optical fiber 533 is positioned. FBG 503 within optical fiber 533 is positioned above cavity 555, at a distance from the notch configured such that the maximum elastic strain within the optical fiber results from the leverage created by the flexure element at the end of the notch. The wedge-shaped profile of the flexure allows for a reduction in mass and, therefore, an increase in fundamental frequency relative to other embodiments (eg, near 10 kHz or more).

[0128] Figure 6 Another transducer according to an embodiment of the present disclosure is shown. The transducer can be implemented using a reservoir filled with an inflation fluid. The inflation fluid can be configured to act as a solid, transmitting high-frequency acoustic pressure signals to a flexure member, in response to a high-frequency acoustic pressure signal; and can be configured to act as a liquid, preventing the ambient pressure noise from being transmitted to the flexure member, in response to ambient pressure noise.

[0129] Transducer 600 includes a transducer body 606 containing reservoirs 608. Flexure members 622 are implemented as a plurality of biasing members 621 (e.g., springs) within reservoirs 608, which bias a plurality of wave impact members 634 (e.g., planar disks) connected to segments of optical fiber 633 extending through body 606. FBGs 603 are centered between disks 634. Optical fiber can pass through (and connect to) each disk 634 in the center in a normal direction. An interface 607 separates one of reservoirs 608 from downhole fluid 90. The interface includes an outer membrane 652 that responds to high-frequency acoustic pressure signals incident on the transducer.

[0130] Reservoir 608 is filled with an inflation fluid. The inflation fluid is configured to act as a solid in response to a high-frequency acoustic pressure signal, transmitting the high-frequency acoustic pressure signal to the flexure member; however, in response to ambient pressure noise or a constant pressure, the inflation fluid is configured to act as a liquid, preventing the ambient pressure noise from being transmitted to the flexure member.

[0131] As previously described, an acoustic signal in the downhole fluid is incident on the outer membrane 652. In response to the high-frequency acoustic signal transmitted through the membrane 652 to the reservoir 608, the expanding fluid acts as a solid, transmitting the signal to the impact member 634, which relieves the stress on the optical fiber 633. In contrast, low frequencies or constant pressure are absorbed in the liquid mode fluid, causing such signals to be suppressed.

[0132] The transducers described above, along with the optical fiber and FBG, form a sensor that is sensitive to acoustically induced dynamic pressure changes, but insensitive to constant and slowly varying pressures. Thus, the transducer embodiments described above may be insensitive to pressure waves below a specific frequency, such as, for example, 10 kHz, 1 kHz, 100 Hz, or 10 Hz, or lower. This makes the sensor insensitive to pressures consistent with nominal downhole environments without compromising sensitivity to acoustic signals.

[0133] Figure 7A A flowchart 700 is shown illustrating a method for logging a borehole intersecting a subterranean formation according to an embodiment of the present disclosure. In optional step 710, an acoustic sensor according to the present disclosure is positioned in the borehole. For example, a carrier may be used to transport the acoustic logging tool in the borehole. The borehole may be filled with a downhole fluid, such as drilling fluid. In other examples, a sensor probe may be installed in the subterranean formation. See, for example, U.S. Patent No. 7,201,221 to Tubel et al., which is commonly owned and incorporated herein by reference in its entirety.

[0134] Optional step 720 of method 700 may include obtaining acoustic data with an acoustic sensor. Step 720 may include generating a plurality of acoustic signals within the borehole or from a seismic device at the surface, and generating acoustic data downhole at at least one sensor in response to acoustic signals received at the sensor, such as, for example, in response to a plurality of acoustic reflections of the transmitted acoustic signals from a boundary.

[0135] Step 730 includes characterizing the formation using the acoustic data including the generated formation information. Step 730 may include estimating at least one property of the acoustic reflection boundary using the position of each reflection point in the formation. This may include estimating the distance to the boundary, the dip angle, the position of the boundary in the formation, etc. from the acoustic data. Optional step 740 includes transmitting the formation information uphole. Optional step 750 includes performing other operations in the formation based on the formation information.

[0136] Figure 7B A flowchart 760 illustrating a method for obtaining acoustic data is shown. Step 770 includes using a pressure transducer including a flexure attached to an optical medium to convert a low-amplitude, high-frequency acoustic pressure signal incident on the pressure transducer within the nominal borehole pressure along the axis of the medium through movement of the flexure. This is accomplished by mitigating pressure excursions caused by the nominal borehole pressure.

[0137] Step 780 includes using a detector to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis. At least one optical property of the medium is responsive to the alternating stress on the medium such that the electromagnetic radiation received by the detector represents an acoustic signal.

[0138] Optionally, the method may include estimating a parameter of interest of the formation and using the parameter of interest to estimate a property of the formation or perform other operations. Estimating the parameter may include the use of a model. In some embodiments, the model may include, but is not limited to, one or more of the following: (i) a mathematical equation, (ii) an algorithm, (iii) a deconvolution technique, etc. Reference information accessible by the processor may also be used.

[0139] Coupled oscillator modification

[0140] For some applications, alternative techniques for producing modified signals may be warranted to optimize the detection of signals having specific characteristics, such as, for example, signals within a desired frequency range. For example, it may be beneficial to detect signals from specific source types or to remove signal components characterized as noise. It may be desirable to modify the above-described transducers to detect acoustic reflection boundaries and determine related parameters of interest, detect the velocity of seismic wave propagation within multiple intervals, estimate vertical velocity or anisotropy parameters, generate seismic images, perform seismic inversion, or otherwise estimate parameters of interest from borehole acoustic array data. In addition, embodiments using a fluid bypass flow may exhibit more resistive behavior as frequency increases, thereby acting as a first-order filter. Aspects of the present disclosure below may produce steeper filter curves. Modification of the signal may be performed by affecting at least one coupled oscillator of the bending member.

[0141] The acoustic pressure signal is composed of component signals, each of which has an associated frequency range. While it is desirable to detect some of the component signals, the presence of other component signals may be undesirable. It may be desirable to suppress the conversion of signals within a particular frequency range, such as, for example, those representing drilling noise, while allowing the conversion of component signals within another frequency range (a 'target frequency range'). Additionally, it may be desirable to amplify the conversion of component signals within the target frequency range (a 'target component signal').

[0142] Figures 8A to 8F An acoustic sensor including a pressure transducer configured to modify a represented acoustic signal is shown according to an embodiment of the present disclosure. Figure 8A and Figure 8B An acoustic sensor including a pressure transducer employing a coupled oscillator is shown. The pressure transducer 800 includes a fluid reservoir 804 and an interface 805 between the reservoir 804 and a body of fluid 802. The body of fluid may include a fluid-filled borehole annulus or other downhole fluid. The interface includes a curved member 810 attached to an optical medium, as described above. A coupled oscillator 820 is coupled to the curved member 810 such that movement of the curved member 810 is affected by movement of the coupled oscillator 820 in at least some cases. The coupled oscillator 820 may be as described above. Figure 8A Direct coupling as shown, or as Figure 8B Indirect coupling is shown, for example, through physical interaction of one or more components of the transducer. Figure 8B In the embodiment, coupling is achieved through the elastic properties of the fluid in the reservoir 804.

[0143] Figure 8C and Figure 8DA pressure transducer 800' employing multiple coupled oscillators is shown. Movement of a flexure member 810 in response to an incident component pressure signal can be affected by movement of at least one coupled oscillator in response to the incident component pressure signal. The at least one coupled oscillator can be implemented as a flexible membrane, a piston, a flexure rod, or the like, or as another flexure member, or as a combination of these. In operation, the coupled oscillators (820a, 820b, 820c) each respond to the incident pressure and have different eigenfrequencies.

[0144] An acoustic pressure signal incident on the pressure transducer within the nominal borehole pressure can propagate through the fluid body 802. The pressure transducer can be implemented using a component according to any of the embodiments described herein. As described in detail above, the pressure transducer is configured to convert at least a portion of the acoustic pressure signal into an alternating stress on the optical medium along the axis of the medium by movement of the bending member.

[0145] The at least one coupled oscillator is configured to influence the conversion of a component signal of an acoustic pressure signal having a frequency within a predefined frequency range by the flexure member into stress in the optical medium such that electromagnetic radiation received by the detector represents the modified acoustic signal. The at least one coupled oscillator can be configured to modify the conversion of the component signal by the flexure member by changing the sensitivity of the flexure member to the component signal. The at least one coupled oscillator can be configured to increase or decrease the sensitivity of the flexure member to specific component signals (e.g., signal components that are undesirable or overrepresented).

[0146] The at least one coupled oscillator may be configured to suppress the conversion of component signals of the acoustic pressure signal within a predefined frequency range into stress in the optical medium, such that the electromagnetic radiation received by the detector represents the acoustic signal filtered to substantially remove signals within the predefined frequency range. The predefined frequency range may include frequencies from zero to a predefined low-frequency threshold, such that the electromagnetic radiation received by the detector represents the acoustic signal filtered to substantially remove signals below the predefined frequency threshold. The at least one coupled oscillator may be configured to amplify the conversion of component signals of the acoustic pressure signal within the predefined frequency range into stress in the optical medium, such that the electromagnetic radiation received by the detector represents the acoustic signal filtered to amplify signals within a target frequency window. The at least one coupled oscillator may be configured to suppress the conversion of a first portion of the component signals of the acoustic pressure signal within a first target frequency window in the predefined frequency range into stress in the optical medium, and amplify the conversion of a second portion of the component signals of the acoustic pressure signal within a second target frequency window in the predefined frequency range into stress in the optical medium.

[0147] In certain embodiments, the modification is performed by at least one coupled oscillator that displaces the volume of the fluid reservoir in response to the acoustic pressure signal to modify the conversion of signal components of the acoustic pressure signal having frequencies within a predefined frequency range into stress in the optical medium via the flexure member. In this manner, the electromagnetic radiation received by the detector represents the modified acoustic signal.

[0148] Figure 8E A pressure transducer from an acoustic sensor, according to an embodiment of the present disclosure, is shown. The acoustic sensor is configured to modify a represented acoustic signal using at least one coupled oscillator that displaces the volume of a fluid reservoir in response to an acoustic pressure signal. Transducer 822 includes an interface 825 between a fluid reservoir 834 and a fluid body 832. The interface comprises a flexure implemented as a flexible membrane 840 and at least one opening that provides fluid communication between fluid reservoir 834 and fluid body 832 and is configured to suppress the conversion of low-frequency signals and constant pressure into stress in an optical medium, as described in more detail above. As shown above, a segment of optical fiber is attached to the membrane. The opening is a capillary tube 844. Other embodiments may use more than one capillary tube or different types of openings. The interface includes a coupled oscillator implemented as a second flexible membrane 850 that responds to an acoustic pressure signal incident on the transducer.

[0149] Figure 8F Another pressure transducer from an acoustic sensor with a coupled oscillator is shown. Flexure member 840' is implemented as part of a curved rod forming the interface between first slit 841 and second slit 842. Interface 825' may also include a second flexure member, etc. (not shown). Coupled oscillator 851 is implemented as piston 850' and spring 852.

[0150] Figure 8G A model of coupled oscillations according to an embodiment of the present disclosure is shown. Figure 8G In the model of , the first curved member is modeled as a piston with an additional piston coupled through a fluid in a reservoir. Figure 8G , the piston is modeled as a coupled two-mass oscillating system. The spring of the oscillating system is provided by the compressibility of the fluid. The mass m2 represents the mass coupled to the optical transducer, which reflects the deflection into the optical signal representing the motion of the piston.

[0151] The equation of motion for a damped two-mass oscillating system with forced excitation can be expressed as:

[0152]

[0153] Figures 9A to 9FThe computational model and response functions of a modeling system with a bending member and a coupled oscillator with various oscillation parameters according to an embodiment of the present disclosure are presented. The coupled oscillator is implemented as a second damped spring-mass system. Figure 9A is a model used for illustration purposes to show the coupling effect of two oscillatory systems. It does not couple between the two oscillatory systems and subsequently provides two independent resonance curves. Figure 9B and Figure 9C For illustration purposes, the amplitude and phase of two uncoupled oscillators (k2=0 and λ2=0) excited by forces f1(t) and f2(t) acting on the mass, where f1(t)=f1*cos(ω*t) and f2(t)=f2*cos(ω*t), are shown, respectively. This yields two independent resonance curves for the two oscillators. The modeled system has parameter values:

[0154] k1=1.0

[0155] k3=1.0

[0156] m1=1.0

[0157] m2=0.25

[0158] λ1=0.15

[0159] λ3=0.15

[0160] f1=1

[0161] f2=-1

[0162] Figure 9D Shows the computational model of a coupled system. Spring k2 couples an oscillating system of mass m1 to an oscillating system of mass m2. Figure 9E and Figure 9F Shows the amplitude and phase of a coupled two-mass oscillator system, with spring k2 = 1, in response to the excitation forces f1 and f2. This example of a modeled system has parameter values:

[0163] k1=1.0

[0164] k2=0.5

[0165] k3=1.0

[0166] m1=1.0

[0167] m2=0.25

[0168] λ1=0.2

[0169] λ3=0.2

[0170] f1=1

[0171] f2=-1

[0172] The optical medium attached to mass m2 will experience a modified response to the acoustic signal. It will suppress the response in the lower frequency range where unwanted signals are expected, and will amplify the response in the higher frequency range to desired signals.

[0173] Figure 10 A flowchart 1000 illustrating a method for obtaining acoustic data is shown. Step 1002 includes using a pressure transducer including an interface between a fluid reservoir and a body of fluid, the interface including a flexure member attached to an optical medium to convert an acoustic pressure signal incident on the pressure transducer within a nominal borehole pressure along the axis of the medium via movement of the flexure member. Step 1002 includes displacing the volume of the fluid reservoir with at least one coupled oscillator in response to the acoustic pressure signal to modify the conversion of a signal component of the acoustic pressure signal having a frequency within a predefined frequency range into a stress on the optical medium via the flexure member. This can affect both the movement of the flexure member in response to the incident signal component and the movement of the at least one coupled oscillator in response to the incident signal component.

[0174] Step 1004 includes using a detector to generate acoustic measurement information in response to received electromagnetic radiation transmitted through the medium along the axis. At least one optical property of the medium may be responsive to an alternating stress on the medium such that the electromagnetic radiation received by the detector represents a modified acoustic signal.

[0175] Optionally, the method may include estimating a parameter of interest of the formation and using the parameter of interest to estimate a property of the formation or perform other operations. Estimating the parameter may include the use of a model. In some embodiments, the model may include, but is not limited to, one or more of the following: (i) a mathematical equation, (ii) an algorithm, (iii) a deconvolution technique, etc. Reference information accessible by the processor may also be used.

[0176] Method embodiments may include performing other operations in the Earth formation based on the formation information, the estimated properties of the reflectors, or a model created using one of these. The other operations may include at least one of: i) geosteering; ii) drilling additional boreholes in the formation; iii) performing additional measurements on the formation; iv) estimating additional parameters of the formation; v) installing equipment in the borehole; vi) evaluating the formation; vii) optimizing current or future development in the formation or similar formations; viii) optimizing current or future exploration in the formation or similar formations; ix) drilling a borehole; and x) producing one or more hydrocarbons from the formation information.

[0177] The estimated parameters of interest can be stored (recorded) as information on a display or visually depicted on a display. The parameters of interest can be transmitted before or after storage or display. For example, the information can be transmitted to other downhole components or to a surface for storage, display, or further processing. Various aspects of the present disclosure relate to using the estimated parameters of interest to model the volume of a formation, such as, for example, by associating the estimated parameter values with the portion of the volume of interest to which they correspond, or by representing boundaries and formations in a global coordinate system. The model of the formation generated and maintained in various aspects of the present disclosure can be implemented as a representation of the formation, which is stored as information. Information (e.g., data) can also be transmitted, stored on a non-transitory machine-readable medium, and / or presented (e.g., visually depicted) on a display.

[0178] Processing of the measurements by the processor may occur at the tool, at the surface, or at a remote location. Data acquisition may be controlled, at least in part, by electronics. Implicit in the control and processing of data is the use of a computer program on a suitable non-transitory machine-readable medium that enables the processor to perform the control and processing. Non-transitory machine-readable media may include ROM, EPROM, EEPROM, flash memory, and optical disks. The term processor is intended to include devices such as field programmable gate arrays (FPGAs).

[0179] As used above, the term "transport equipment" refers to any device, device component, combination of devices, medium and / or component that can be used to transport, accommodate, support or otherwise facilitate the use of another device, device component, combination of devices, medium and / or component. Exemplary non-limiting transport equipment includes coiled tubing type, drill string of drill pipe type and any combination or part thereof. Other examples of transport equipment include casing, wireline, wireline sonde, wireline sonde, dropshot, downhole submersible, BHA, drill string plug-in, module, internal housing and its base portion, self-propelled tractor. As mentioned above, the term "submersible" refers to any structure configured to partially enclose, fully enclose, accommodate or support equipment. The term "information" as used above includes information in any form (analog, digital, EM, print, etc.). The term "processor" or "information processing device" herein includes but is not limited to any device that transmits, receives, manipulates, converts, calculates, modulates, transposes, carries, stores or otherwise utilizes information. The information processing device may include a microprocessor, resident memory and peripheral devices for executing programming instructions. The processor may execute instructions stored in a computer memory accessible to the processor, or may employ logic implemented as a field programmable gate array ("FPGA"), an application specific integrated circuit ("ASIC"), other combinational or sequential logic hardware, etc. Thus, the processor may be configured to perform one or more methods as described herein, and the configuration of the processor may include operative connection to resident memory and peripheral devices for executing programmed instructions.

[0180] As used herein, the term "fluid" or "fluids" refers to one or more gases, one or more liquids, and mixtures thereof. As used herein, "downhole fluid" includes any gas, liquid, flowable solid, and other material having fluid properties and related to hydrocarbon recovery. Downhole fluids can be natural or artificial and can be transported downhole or recovered from a downhole location. Non-limiting examples of downhole fluids include drilling fluids, flowback fluids, formation fluids, production fluids containing one or more hydrocarbons, engineered fluids, oils and solvents used with downhole tools, water, brine, and combinations thereof. "Engineered fluid" may be used herein to refer to artificial fluids formulated for a specific purpose. The term "geosteering" may refer to changing the direction of a drill bit, stopping the drill bit, or continuing to advance the drill bit.

[0181] It will be apparent that in the technology disclosed herein, the values of slowness and speed are used interchangeably. The parameters slowness and speed are inversely related, and the measurement of one can be converted to the measurement of the other through simple mathematical relationships well known in the art. Therefore, the term "slowness" as used herein can refer to slowness as traditionally understood, as well as other parameter equivalents.

[0182] As used herein, the term vertical seismic profile ('VSP') means any of zero-offset VSP, offset VSP, variable-well source standoff VSP, walk-above VSP, salt-proximity VSP, shear-wave VSP, and drilling noise or seismic-while-drilling VSP. Acoustic signal means any signal that is acoustically measured or processed, including seismic signals. As used herein, the term "fast-varying" or "high-frequency" refers to frequency characteristics corresponding to typical acoustic signals used for downhole measurement applications. As used herein, the term "slow-varying" or "low-frequency" refers to frequency characteristics corresponding to acoustic signals below a level representing a desired acoustic measurement value, and may be represented by pressure waves below a cutoff frequency, such as 10 kHz, 1 kHz, 100 Hz, 10 Hz, or less. Ambient pressure noise should be understood to refer to non-signal pressure variations applied to the borehole, including low-frequency pressures such as tool vibrations. Thus, mechanically filtered ambient pressure noise can suppress ambient noise tool vibrations, such as pump noise. Tool vibrations may have a characteristic frequency of 80 to 500 Hz, compared to acoustic signals of 1 kHz or greater.

[0183] While the foregoing disclosure is directed to one mode embodiment of the present disclosure, various modifications will be apparent to those skilled in the art. It is intended that all such variations be covered by the foregoing disclosure.

Claims

1. A device for drilling a hole, comprising: An acoustic sensor, the acoustic sensor comprising a pressure transducer, the pressure transducer comprising: an interface between a fluid reservoir and a fluid body, the interface comprising a flexure attached to an optical medium, the pressure transducer configured to convert an acoustic pressure signal within a borehole pressure incident on the pressure transducer along an axis of the optical medium into a stress on the optical medium by movement of the flexure along an axis of the optical medium, the acoustic pressure signal propagating through the fluid body; a detector configured to generate acoustic measurement information in response to received electromagnetic radiation transmitted along the axis through the optical medium, at least one optical property of the optical medium being responsive to the stress on the optical medium; and at least one coupled oscillator included in the interface between the fluid reservoir and the fluid body, the at least one coupled oscillator displacing a volume of fluid in the fluid reservoir in response to the acoustic pressure signal to affect movement of the flexure member such that the optical medium attached to the flexure member experiences an amplified response to the acoustic pressure signal within a predefined frequency range, and the electromagnetic radiation received by the detector represents the amplified acoustic pressure signal within the predefined frequency range; wherein the at least one coupled oscillator and the flexure member form a coupled two-mass oscillatory system comprising a coupling spring provided by elastic properties of the fluid in the fluid reservoir, and wherein the flexure member and the at least one coupled oscillator are directly coupled via the coupling spring, wherein the predefined frequency range is determined by the elastic properties of the fluid in the fluid reservoir.

2. The apparatus of claim 1, wherein the at least one coupled oscillator is coupled to the flexure member via a fluid in the fluid reservoir. 3 . The apparatus of claim 1 , wherein the at least one coupled oscillator is configured to reduce sensitivity of the flexure member to the acoustic pressure signal.

4. The apparatus of claim 1 , wherein changing the volume of fluid in the fluid reservoir in response to movement of the at least one coupled oscillator affects the movement of the flexure member.

5. The apparatus of claim 1 , wherein the at least one coupled oscillator is configured to suppress conversion of the acoustic pressure signal within the predefined frequency range into stress in the optical medium, such that the electromagnetic radiation received by the detector represents an acoustic pressure signal filtered to remove acoustic pressure signals within the predefined frequency range.

6. The apparatus of claim 1 , wherein the at least one coupled oscillator is configured to suppress conversion of a first portion of the acoustic pressure signal within a first target frequency window in the predefined frequency range into stress in the optical medium, and to amplify conversion of a second portion of the acoustic pressure signal within a second target frequency window in the predefined frequency range into stress in the optical medium.

7. The apparatus of claim 1, wherein the at least one coupled oscillator comprises at least one additional curved member.

8. The apparatus of claim 1, wherein the at least one coupled oscillator comprises at least one piston.

9. The apparatus of claim 1, wherein the flexure member has a first value of an oscillation parameter and at least one of the at least one coupled oscillator has a second value of the oscillation parameter that is different from the first value.

10. The apparatus of claim 9, wherein the oscillation parameter comprises at least one of: i) mass; ii) stiffness; iii) geometry; iv) spring constant; and v) density.

11. The apparatus of claim 2, wherein the coupling of the at least one coupled oscillator and the flexure member is determined by the compressibility of the fluid in the fluid reservoir.

12. The device of claim 1, wherein the interface comprises at least one opening providing fluid communication between the fluid reservoir and the fluid body.

13. The apparatus of claim 1, wherein the flexure is included in the interface at a first position, and the at least one coupled oscillator is included in the interface at a second position different from the first position.

14. The apparatus of claim 1, wherein the body of fluid comprises downhole fluid.

15. The apparatus of claim 1, wherein the coupled dual-mass oscillating system comprises a first spring-mass system and a second spring-mass system, the first spring-mass system comprising a first spring (k1) and a first mass (m1), the second spring-mass system comprising a second spring (k3) and a second mass (m2), and wherein, The coupling spring (k2) couples the first mass (m1) and the second mass (m2) together.

16. The apparatus of claim 15, wherein at least one of the first spring-mass system and the second spring-mass system is damped.

17. A method for acoustic testing in a borehole, the method comprising: using a pressure transducer including an interface between a fluid reservoir and a body of fluid, the interface including a flexure attached to an optical medium to convert an acoustic pressure signal within a downhole fluid pressure incident on the pressure transducer along an axis of the optical medium by movement of the flexure along an axis of the optical medium, the acoustic pressure signal propagating through the body of fluid; displacing a volume of fluid in the fluid reservoir with at least one coupled oscillator included in an interface between the fluid reservoir and the fluid body in response to the acoustic pressure signal to affect movement of the flexure member such that the optical medium attached to the flexure member experiences an amplified response to the acoustic pressure signal within a predefined frequency range; as well as using a detector to generate acoustic measurement information in response to received electromagnetic radiation transmitted along the axis through the optical medium, the at least one optical property of the optical medium being responsive to the stress on the optical medium, such that the electromagnetic radiation received by the detector represents an amplified acoustic pressure signal within the predefined frequency range; wherein the at least one coupled oscillator and the flexure member form a coupled two-mass oscillatory system comprising a coupling spring provided by elastic properties of the fluid in the fluid reservoir, and wherein the flexure member and the at least one coupled oscillator are directly coupled via the coupling spring, wherein the predefined frequency range is determined by the elastic properties of the fluid in the fluid reservoir.

18. The method of claim 17, wherein the at least one coupled oscillator is coupled to the flexure member via the fluid reservoir.

19. The method of claim 17, wherein the flexure member has a first value of an oscillation parameter and at least one of the at least one coupled oscillator has a second value of the oscillation parameter that is different from the first value.

20. The method of claim 19, comprising selecting a second value for the oscillation parameter, wherein the oscillation parameter comprises at least one of: i) mass; ii) stiffness; iii) geometry; iv) spring constant; and v) density.

21. The method of claim 17, wherein the interface comprises at least one opening providing fluid communication between the fluid reservoir and the fluid body.

22. The method of claim 17, wherein the flexure is included in the interface at a first position, and the at least one coupled oscillator is included in the interface at a second position different from the first position.

23. The method of claim 17, wherein the coupled dual-mass oscillating system comprises a first spring-mass system and a second spring-mass system, the first spring-mass system comprising a first spring (k1) and a first mass (m1), the second spring-mass system comprising a second spring (k3) and a second mass (m2), and wherein, The coupling spring (k2) couples the first mass (m1) and the second mass (m2) together.

24. The method of claim 23, wherein at least one of the first spring-mass system and the second spring-mass system is damped.

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