Patent Publication Number: US-2021173106-A1

Title: Downhole fiber optic hydrophone

Description:
FIELD OF THE DISCLOSURE 
     This disclosure generally relates to borehole tools, and in particular to methods and apparatuses for conducting acoustic investigation in a borehole intersecting an earth formation. More particularly, the disclosure relates to acoustic sensors and methods of using such acoustic sensors in various tools, including acoustic logging tools. 
     BACKGROUND OF THE DISCLOSURE 
     Drilling wells for various purposes is well-known. Such wells may be drilled for geothermal purposes, to produce hydrocarbons (e.g., oil and gas), to produce water, and so on. Well depth may range from a few thousand feet to 25,000 feet or more. In hydrocarbon wells, downhole tools often incorporate various sensors, instruments, and control devices in order to carry out any number of downhole operations. Downhole acoustic logging tools, which are used to investigate subsurface features, can include one or more acoustic transmitters or sources and a number of acoustic receivers. Additionally or alternatively, self-contained acoustic sensors may be installed within the borehole on either a temporary or permanent basis. 
     In some cases, the transmitters emit acoustic energy into the subsurface environment surrounding the wellbore. The acoustic signals are reflected by interfaces associated with the wellbore, well structures, and/or the formation. The reflected acoustic signals are detected by the receivers in the logging tool and processed to provide estimates of one or more properties of the wellbore, well structures, and/or the formation. Drilling systems having an acoustic “logging-while-drilling” (‘LWD’) or “measurement-while-drilling” (‘MWD’) system as part of a bottomhole assembly, or an after-drilling wireline logging system having an acoustic device for measuring properties of subsurface formations (during or after drilling of the wellbores), such as, for example, determining the location of formation bed boundaries around the bottomhole assembly, as in the MWD system, or around the wireline logging system are known. 
     In drilling a borehole to recover oil from the earth, it is often helpful to turn or steer the downhole drill bit toward or away from subterranean targets. Acoustic data may be used to determine a drill bit location on the seismic section to facilitate geosteering. With Vertical Seismic Profiling (VSP), acquisition may be conducted between one or more acoustic (seismic) sources on or near the surface of the earth, and receivers in the earth, such as, for example, in a wellbore. The response of an acoustic sensor, such as a seismic sensor (e.g., a hydrophone) at various depths in a borehole to sources on the surface may be recorded as downhole measurements. 
     SUMMARY OF THE DISCLOSURE 
     In aspects, the present disclosure is related to methods and apparatus for performing formation evaluation in a borehole intersecting an earth formation, including estimating at least one parameter of interest relating to the formation, such as, for example, a property of an acoustically reflective boundary in the formation. 
     Apparatus embodiments may comprise an acoustic sensor including a pressure transducer. The pressure transducer may comprise: an interface between a fluid reservoir and a fluid body, the interface including a flexing member 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 to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member, the acoustic pressure signal propagated via the fluid body; a detector configured to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating strain on the medium; and at least one coupled oscillator displacing a volume of the fluid reservoir responsive to the acoustic pressure signal to modify conversion by the flexing member of signal components of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents a modified acoustic signal. 
     The coupled oscillator may be coupled to the flexing member by the fluid reservoir. The at least one coupled oscillator may be configured to modify conversion by the flexing member of the signal components by altering sensitivity of the flexing member to the signal components. The at least one coupled oscillator may be configured to increase sensitivity of the flexing member to the signal components. The at least one coupled oscillator may be configured to decrease sensitivity of the flexing member to the signal components. The movement of the flexing member responsive to the incident component signals may be influenced by movement of the at least one coupled oscillator responsive to the incident signal components. 
     Changes in a volume of the fluid reservoir responsive to movement of the at least one coupled oscillator, which may be responsive to the incident signal components, may influence the movement of the flexing member. The at least one coupled oscillator may be configured to suppress conversion of the signal components of the acoustic pressure signal within the predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents the acoustic signal filtered to substantially remove the signals within the predefined frequency range. 
     The flexing member may have a first value of an oscillation parameter and at least one of the at least one coupled oscillator may have a second value of the oscillation parameter substantially different than the first value. The oscillation parameter may comprise at least one of: i) mass; ii) stiffness; iii) geometry; iv) spring constant; and v) density. 
     The at least one coupled oscillator may be configured to amplify conversion of the signal components of the acoustic pressure signal within the predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents the acoustic signal filtered to amplify the signals within the target frequency window. 
     The at least one coupled oscillator may be configured to suppress conversion of a first portion of the signal components of the acoustic pressure signal within a first target frequency window in the predefined frequency range into strain of the optical medium and to amplify conversion of a second portion of the signal components of the acoustic pressure signal within a second target frequency window in the predefined frequency range into strain of the optical medium. 
     The at least one coupled oscillator may be at least one additional flexing member. The at least one coupled oscillator may comprise at least one piston. The interface may comprise at least one opening providing for fluid exchange between the fluid reservoir and the fluid body and configured to suppress conversion of low-frequency signals and constant pressure into strain of the optical medium. The modified acoustic signal may be at least one of i) a filtered signal; and ii) an amplified signal. 
     Method embodiments may include using a pressure transducer comprising an interface between a fluid reservoir and a fluid body, the interface including a flexing member attached to an optical medium, to convert an acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member, the acoustic pressure signal propagated via the fluid body, comprising displacing a volume of the fluid reservoir with at least one coupled oscillator responsive to the acoustic pressure signal to modify conversion by the flexing member of signal components of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium; and using a detector to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, the at least one optical property of the medium being responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents a modified acoustic signal. The coupled oscillator may be coupled to the flexing member by the fluid reservoir. The at least one coupled oscillator may be configured to modify conversion by the flexing member of the signal components by altering sensitivity of the flexing member to the signal components. Methods may include influencing movement of the flexing member responsive to the incident component signals with movement of the at least one coupled oscillator responsive to the incident signal components. 
     Methods may include using the acoustic measurement information to estimate a parameter of interest comprising at least one of: i) a slowness of a volume of interest of the formation; ii) an acoustic data communication message; iii) a stand-off from the transducer to a wall of the borehole; iv) a geometry of the borehole; and v) a sound speed of the downhole fluid. 
     Apparatus embodiments may comprise an acoustic sensor including: a pressure transducer comprising a flexing member attached to an optical medium, the transducer configured to convert a low-amplitude, high-frequency acoustic pressure signal within a nominal borehole pressure incident on the transducer to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member while suppressing conversion of low-frequency signals and constant pressure into strain of the optical medium, the acoustic pressure signal propagated via a downhole fluid coupled with the transducer; and a detector configured to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, the at least one optical property of the medium being responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents the acoustic signal. The pressure transducer may comprise an interface between reservoirs containing a reservoir fluid, with the interface comprising the flexing member and at least one opening providing for communication of the reservoir fluid between the reservoirs. 
     The apparatus may comprise a portion of a drillstring, and the ambient pressure noise may comprise vibration of the drillstring. The received radiation comprises 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. A ratio of an average signal amplitude of the high-frequency acoustic pressure signal to the nominal borehole pressure may be less than 10 1 . 
     The pressure transducer may be configured to fluid-mechanically filter low-frequency ambient pressure noise. The opening and the reservoirs may be configured to fluid-mechanically filter ambient pressure noise using bypass flow of the reservoir fluid through the opening via pressure equalization. The flexing member may comprise at least one of: i) a membrane; and ii) a bender bar. The at least one opening may comprise at least one of: i) a slit in the flexing member; and ii) a capillary tube. The at least one opening may comprise a plurality of slits, and the flexing member may comprise a portion of the interface between a first slit of the plurality and a second slit of the plurality. 
     The pressure transducer may include a second interface between one of the reservoirs and the downhole fluid, the second interface comprising a second flexing member responsive to the high-frequency acoustic pressure signal incident on the transducer. A first reservoir of the reservoirs may be defined by a first reservoir member and a second reservoir of the reservoirs may be defined by a second reservoir member. The first reservoir member may be received by the second reservoir member. 
     The dimensions and orientations of the reservoirs may be configured to suppress acceleration-induced quasi-hydrostatic pressure signals by producing a pressure at the flexing member in the first reservoir substantially equal to another pressure at the flexing member in the second reservoir. In some apparatus embodiments, every plane normal to a line intersecting the center of gravity of the combined reservoir fluid volumes intersects either: i) both the first reservoir and the second reservoir, or ii) neither the first reservoir nor the second reservoir. 
     The transducer may comprise a flexural element supporting the flexing member. The transducer may comprise a flexural element supporting the flexing member and configured to amplify movement of the flexing member. The medium may comprise fiber Bragg gratings positioned with respect to the flexural element proximate a location of maximum displacement of the medium. The transducer may include a reservoir filled with a dilatant fluid. The dilatant fluid may be configured to act, responsive to the high-frequency acoustic pressure signal, as a solid transmitting the high-frequency acoustic pressure signal to the flexing member, and, responsive to the ambient pressure noise, as a liquid preventing transmission of the ambient pressure noise to the flexing member. 
     Methods include using a pressure transducer comprising a flexing member attached to an optical medium to convert a low amplitude, high-frequency acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member while suppressing conversion of low-frequency signals and constant pressure into strain of the optical medium, the acoustic pressure signal propagated via a downhole fluid coupled with the transducer; and using a detector to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, the at least one optical property of the medium being responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents the acoustic signal. Methods 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) a slowness of a volume of interest of the formation; ii) an acoustic data communication message; iii) a stand-off from the transducer to a wall of the borehole; iv) a geometry of the borehole; and v) a sound speed of the downhole fluid. 
     Further apparatus embodiments comprise an acoustic sensor including a pressure transducer. The pressure transducer may comprise an interface between a fluid reservoir and a fluid body, the interface including a flexing member 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 to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member, the acoustic pressure signal propagated via the fluid body; a detector configured to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, at least one optical property of the medium being responsive to the alternating strain on the medium; and at least one coupled oscillator coupled to the flexing member and configured to modify conversion by the flexing member of component signals of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents a modified acoustic signal. 
     Some embodiments include a non-transitory computer-readable medium product accessible to the processor and having instructions thereon that, when executed, causes the at least one processor to perform methods described above. Apparatus embodiments may include at least one processor and a computer memory accessible to the at least one processor comprising a computer-readable medium having instructions thereon that, when executed, causes the at least one processor to perform methods described above. 
     Examples of some features of the disclosure may be summarized rather broadly herein in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein: 
         FIGS. 1A &amp; 1B  illustrate components of systems in accordance with embodiments of the present disclosure; 
         FIGS. 2A-2C  are schematic diagrams illustrating operation of device embodiments including acoustic sensors in accordance with embodiments of the present disclosure; 
         FIG. 3A  shows a schematic diagram illustrating an acoustic sensor in accordance with embodiments of the present disclosure; 
         FIG. 3B  illustrates a sensor including multiple pressure transducers on a single fiber; 
         FIGS. 4A-4H  illustrate transducers in accordance with embodiments of the present disclosure; 
         FIGS. 5A &amp; 5B  illustrate transducer components in accordance with embodiments of the present disclosure; 
         FIG. 6  illustrates another transducer in accordance with embodiments of the present disclosure; 
         FIG. 7A  shows a flow chart illustrating methods for performing well logging in a borehole intersecting an earth formation in accordance with embodiments of the present disclosure; 
         FIG. 7B  shows a flow chart illustrating methods for obtaining acoustic data; 
         FIGS. 8A-8F  illustrate an acoustic sensor including a pressure transducer configured to modify the represented acoustic signal in accordance with embodiments of the present disclosure; 
         FIG. 8G  illustrates a model of a coupled oscillation in accordance with embodiments of the present disclosure; 
         FIGS. 9A-9F  show the computational model and the response functions for a modeled system having a flexing member and a coupled oscillator having various oscillation parameters in accordance with embodiments of the present disclosure 
         FIG. 10  shows a flow chart illustrating methods for obtaining acoustic data. 
     
    
    
     DETAILED DESCRIPTION 
     Aspects of the present disclosure relate to apparatus and methods for acoustic well logging, including measurement and interpretation of physical phenomena indicative of parameters of interest of the formation, the borehole, or the downhole fluids therein, including vertical seismic profiling (using seismic measurements from the borehole). Aspects of the present disclosure include a novel acoustic sensor (e.g., a hydrophone) well suited for detecting very small pressure differences (e.g., acoustic signals) in a very high-pressure environment. Aspects of the disclosure may be suited to detection of acoustically reflective boundaries (referred to herein as ‘reflectors’ or ‘boundaries’), e.g., geologic structures, and related parameters of interest (e.g., properties of these boundaries) from borehole acoustic array data. 
     Aspects of the disclosure include acquisition of a vertical seismic profile (VSP) using a sensor inside the wellbore and a source at the surface near the well. VSP measurements may result in images of higher resolution than surface seismic images. VSP measurements may also be used for looking ahead of the drill bit during drilling operations. A surface seismic source (e.g., a plate vibrator on land, an air gun at sea) may be used to generate the detected acoustic signals. 
     Embodiments of the disclosure include methods of evaluating an earth formation. Methods may include deploying an array of seismic receivers in a borehole and recording seismic signals in the array of receivers responsive to an activation of a seismic source at a plurality of positions on the surface of the earth. For a walkaway geometry, the method may further include estimating, from travel times of seismic waves from the plurality of source positions to the plurality of receivers, velocities of propagating seismic waves over a plurality of intervals. Estimated parameters (e.g., vertical velocities, estimated anisotropy parameters, etc.) may be used to further process surface seismic data to give a seismic image in depth for the purpose of interpretation. 
     Aspects of the disclosure may relate to seismic inversion, wherein seismic reflection data is processed to recover parameters of interest including properties of a volume of interest of the formation, such as a portion of the saturated rock matrix. Such parameters may include acoustic impedance, shear impedance, density, anisotropy parameters, and so on. Performing the inversion may include the use of further constraints generated from additional reservoir measurements (e.g., well logs). Further aspects relate to the estimation of formation slowness, acoustic data communication messages (e.g., mud pulse, etc.), acoustic stand-off, acoustic caliper, general sound speed measurements, and so on. 
     It is known to detect acoustic signals in liquids with hydrophones employing optical fibers carrying fiber Bragg gratings (FBG). These sensors use the FBG in combination with a pressure transducer converting the acoustic signal (e.g., alternating pressures) to alternating strain acting on the optical fiber along the fiber axis. The FBG reflects a small spectral portion of the light propagating in the optical fiber. The central wavelength of this spectrum changes with the measured quantity (e.g., pressure), which is detected using an optical detector at one end of the fiber (detecting either the reflected or the remaining spectrum). 
     In aspects of the present disclosure, Bragg gratings may be written into the fiber or other optical medium (e.g., bulk glass or glass foil) using a femtosecond laser. This technique allows imprinting of various grating shapes by modifying the grating period and depth, and hence to realize a wide variety of effects, including apodized, pi-shifted, and chirped gratings, among others. Furthermore, this process can be applied to standard optical fibers. In contrast, UV light-based methods, which may be advantageous in particular applications, may require photo-sensitive fiber cores and may suffer from hydrogen darkening under downhole conditions. Using the femtosecond-laser based process thus may increase the life of the fiber and potentially reduce packaging costs. 
     To obtain hydrocarbons such as oil and gas, boreholes (wellbores) are drilled through hydrocarbon-bearing subsurface formations. Recently, horizontal boreholes, extending several thousand meters (“extended reach” boreholes), have been drilled to access hydrocarbon reserves at reservoir flanks and to develop satellite fields from existing offshore platforms. Downhole acoustic logging tools, which are used to investigate subsurface features, can include one or more acoustic transmitters or sources and a number of acoustic receivers. Alternatively, the drilled borehole may be outfitted with stand-alone acoustic sensors. 
     The environmental conditions in deep oil wells, such as, for example, underground or undersea wells, are very harsh. Temperatures may approach 250 degrees Celsius and pressures may reach 20-30,000 psi (200 MPa) or more. In addition to the rigorous tool specifications required to prevent premature wear or failure, these very high pressures also exacerbate the small amplitude of the desired signal and make accurate signal detection problematic. The variation in acoustic pressure signal may be, for example, 1 Pa to 10 kPa (10 −4  to 1 psi), on the very large constant offset pressure provided by the ambient pressure of the borehole. Thus, a ratio of an average signal amplitude of the high-frequency acoustic pressure signal to the nominal borehole pressure is often less than 10 −3 , and may reach the range of 10 −4  to 10 −6  or less. For example, it may be desirable for a signal pressure of less than 0.1 psi to be detected on an offset pressure of 20,000 psi or more. 
     Thus, aspects of the present disclosure include methods and apparatus for use in a borehole detecting acoustic signals. General apparatus embodiments may comprise an acoustic sensor including a pressure transducer comprising a flexing member attached to an optical medium. An acoustic pressure signal may be propagated via a downhole fluid coupled with 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 to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member. The configuration may be such that this is accomplished while suppressing conversion of both low-frequency signals and constant pressure signals into strain of the optical medium. The pressure transducer may be further configured to fluid-mechanically filter low-frequency ambient pressure noise. 
     A detector may be configured to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis, with the at least one optical property of the medium being responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents the acoustic signal. See, for example, U.S. Pat. No. 6,396,572 to Chang et al. 
     In particular embodiments, the pressure transducer comprises an interface between reservoirs containing a reservoir fluid. The interface may include the flexing member and at least one opening providing for communication of the reservoir fluid between the reservoirs. The opening and the reservoirs may be configured to fluid-mechanically filter ambient pressure noise using bypass flow of the reservoir fluid through the opening via pressure equalization. The pressure transducer may further include a second interface between one of the reservoirs and the downhole fluid, the second interface comprising a second flexing member responsive to the high-frequency acoustic pressure signal incident on the transducer. The transducer may include a flexural element supporting the flexing member. 
     In other embodiments, the transducer may be implemented with a reservoir filled with a dilatant fluid. The dilatant fluid may be configured to act, responsive to the high-frequency acoustic pressure signal, as a solid transmitting the high-frequency acoustic pressure signal to the flexing member; responsive to the ambient pressure noise, the dilatant fluid may be configured to act as a liquid preventing transmission of the ambient pressure noise to the flexing member. 
     Aspects of the present disclosure relate to using at least one acoustic sensor as part of one or more downhole acoustic well logging tools or distributed sensor systems to produce acoustic information responsive to a pressure signal received at the sensor from the earth formation. The signal may be seismic in nature, or may be generated from excitations in the borehole. At least one acoustic receiver may be disposed in the borehole. The information is indicative of a parameter of interest. The term “information” as used herein includes any form of information (analog, digital, EM, printed, etc.), and may include one or more of: raw data, processed data, and signals. 
     Methods may include estimating a parameter of interest from the information, evaluating the formation using the parameter of interest, and/or performing further borehole or formation operations in dependence upon the location of the reflection points, the location of the boundary, the parameter of interest of the boundary, or other parameters of interest derived from these. In particular embodiments, a state of drilling operations, characteristics of the borehole or formation, or orientation of components of the downhole tool may be estimated using the parameter of interest, and then used in performing an operation as described above. 
     Aspects of the present disclosure are subject to application in various different embodiments. The sensor may be used in conjunction with a carrier such as a drill string, coiled tubing, a slickline, an e-line, a wireline, etc. The sensor may be disposed on the tool for measurement, deployed from the tool, or deployed separately (either preceding or subsequent to conveyance of the tool in the borehole. Sensors, downhole tools, and other system components may be coupled or combined with additional tools, including, e.g., some or all the information processing system, as shown in  FIG. 1B , discussed in further detail below. In some general embodiments, a carrier is implemented as a tool string of a drilling system, and the acoustic wellbore logging may be characterized as “logging-while-drilling” (LWD) or “measurement-while-drilling” (MWD) operations. As described herein, “borehole” or “wellbore” refers to a single hole that makes up all or part of a drilled well. Depending on the configuration, systems shown herein may be used during drilling and/or after the wellbore has been formed, including, in some instances, after the installation of casing or production infrastructure. While a land system is shown, the teachings of the present disclosure may also be utilized in offshore or subsea applications. As described herein, “formations” refer to the various features and materials that may be encountered in a subsurface environment and surround the borehole. 
       FIGS. 1A and 1B  illustrate components of systems in accordance with embodiments of the present disclosure.  FIG. 1A  schematically illustrates a system  100  having a downhole tool  10  configured to acquire information for estimating a downhole parameter of interest (e.g., a value of a property of the formation  80 , the borehole  50 , or downhole fluid  90  therein) using an acoustic measurement instrument  40 . A transducer module  45  may define a portion of the exterior surface of the instrument, extend from tool body  30  out into the borehole, or be trailed behind the tool body  30 . The at least one measurement instrument  40  is responsive to the parameter of interest. Non-limiting examples of downhole fluids include drilling fluids, return fluids, formation fluids, production fluids containing one or more hydrocarbons, oils and solvents used in conjunction with downhole tools, water, brine, engineered fluids, and combinations thereof. 
     The system  100  may include a conventional derrick  60  erected on a derrick floor  70 . A conveyance device (carrier  15 ) which may be rigid or non-rigid, may be configured to convey the downhole tool  10  into wellbore  50  in proximity to a volume of interest  80  of an earth formation  85 . The carrier  15  may be a drill string, coiled tubing, a slickline, an e-line, a wireline, etc. Downhole tool  10  may be coupled or combined with additional tools e.g., some or all the information processing system (inset). Thus, depending on the configuration, the tool  10  may be used during drilling and/or after the wellbore  50  has been formed. As described herein, “borehole” or “wellbore” refers to a single hole that makes up all or part of a drilled well. While a land system is shown, the teachings of the present disclosure may also be utilized in offshore or subsea applications. The carrier  15  may include embedded conductors for power and/or data for providing signal and/or power communication between the surface and downhole equipment (e.g., a seven conductor cable). The carrier  15  may include a bottom hole assembly, which may include a drilling motor for rotating a drill bit. 
     Downhole fluid (e.g., drilling fluid, or ‘mud’)  90  may be present between the formation  85  and the downhole tool  10 . A surface control system  65  receives signals from acoustic measurement instrument(s)  40  and other sensors used in 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 that is utilized by an operator. The surface control system  65  may further communicate with a downhole control system  20  at a suitable location on downhole tool  10 . The surface control system  65  may process data relating to the operations and data from the sensors  40 , and may control one or more downhole operations performed by system  100 . 
     In one embodiment, electronics  30  associated with sensors  40  may be configured to record and/or process the information obtained. Certain embodiments of the present disclosure may be implemented with a hardware environment that includes an information processor  17 , an information storage medium  13 , an input device  11 , processor memory  9 , and may include peripheral information storage medium  19 . The hardware environment may be in the well, at the rig, or at a remote location. Moreover, the several components of the hardware environment may be distributed among those locations. The input device  11  may be any data reader or user input device, such as data card reader, keyboard, USB port, etc. The information storage medium  13  stores information provided by the detectors. Information storage medium  13  may include any non-transitory computer-readable medium for standard computer information storage, such as a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical disks or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. Information storage medium  13  stores a program that when executed causes information processor  17  to execute the disclosed method. Information storage medium  13  may also store the formation information provided by the user, 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 disk, removable RAM, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. Information processor  17  may be any form of computer or mathematical processing hardware, including Internet based hardware. When the program is loaded from information storage medium  13  into processor memory  9  (e.g. computer RAM), the program, when executed, causes information processor  17  to retrieve detector information from either information storage medium  13  or peripheral information storage medium  19  and process the information to estimate a parameter of interest. Information processor  17  may be located on the surface or downhole. 
     The term “information” as used herein 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 disclosure, an information processing device includes a computer that executes programmed instructions for performing various methods. These instructions may provide for equipment operation, control, data collection and analysis and other functions in addition to the functions described in this disclosure. The processor may execute instructions stored in computer memory accessible to the processor, or may employ logic implemented as field-programmable gate arrays (‘FPGAs’), application-specific integrated circuits (‘ASICs’), other combinatorial or sequential logic hardware, and so on. 
     To perform the measurements during a single trip, the tool may use a high bandwidth transmission to transmit the information acquired by detectors  20 ,  30  to the surface for analysis. For instance, a communication line for transmitting the acquired information may be an optical fiber, a metal conductor, or any other suitable signal conducting medium. It should be appreciated that the use of a “high bandwidth” communication line may allow surface personnel to monitor and control operations in “near real-time.” 
     One point of novelty of the system illustrated in  FIG. 1A  is that the surface control system  65  and/or the downhole control system  20  are configured to perform certain methods (discussed below) that are not in the prior art. A surface control system or downhole control system may be configured to control the tool described above and any incorporated sensors and to estimate a parameter of interest according to methods described herein. 
     Aspects of the present disclosure are subject to application in various different embodiments. In some general embodiments, carrier  15  is implemented as a tool string of a drilling system, and measurements taken in the borehole may be characterized as “logging-while-drilling” (LWD) or “measurement-while-drilling” (MWD) operations. 
       FIG. 1B  shows an exemplary embodiment of an MWD system for evaluation of an earth formation using measurements from an acoustic measurement tool. The system  101  includes a carrier  111  that is shown disposed in a wellbore or borehole  50  that penetrates at least one earth formation  195 . The system  101  also includes a tool  110  configured for taking acoustic measurements in the borehole. 
       FIG. 1B  shows a drill string  120  including a bottomhole assembly (BHA)  190  conveyed in the borehole  50  as the carrier. The drilling system  101  includes a conventional derrick  111  erected on a platform or floor  112  which supports a rotary table  114  that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. A tubing (such as jointed drill pipe  122 ), having the 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 , disintegrates the geological formations when it is rotated to drill the borehole  50 . The drill string  120  is coupled to a drawworks  130  via a Kelly joint  121 , swivel  128  and line  129  through a pulley. Drawworks  130  is operated to control the weight on bit (“WOB”). The drill string  120  may be rotated by a top drive (not shown) instead of by the prime mover and the rotary table  114 . Alternatively, a coiled-tubing may be used as the tubing  122 . A tubing injector  114   a  may be used to convey the coiled-tubing having the drilling assembly attached to its bottom end. The operations of the drawworks  130  and the tubing injector  114   a  are known in the art and are thus not described in detail herein. 
     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, slanted wells, multilateral wells and so on. Accordingly, use of directional terms herein (e.g., above, below, upper, lower, upward, downward, topmost, lowermost, uphole, downhole, etc) refer to the direction of travel along the borehole either toward or away from the surface, with the upward direction being toward the surface and the downward direction being away from the surface. 
     A suitable drilling fluid  131  (also referred to as the “mud”) from a source  132  thereof, such as a mud pit, is circulated under pressure through the drill string  120  by a mud pump  134 . The drilling fluid  131  passes from the mud pump  134  into the drill string  120  via a discharger  136  and the fluid line  138 . The drilling fluid  131   a  from the drilling tubular discharges at the borehole bottom  151  through openings in the drill bit  150 . The returning drilling fluid  131   b  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 drill cutting screen  185  that removes the drill cuttings  186  from the returning drilling fluid  131   b . A sensor S 1  in line  138  provides information about the fluid flow rate. A surface torque sensor S 2  and a sensor S 3  associated with the drill string  120  respectively provide information about the torque and the rotational speed of the drill string  120 . Tubing injection speed is determined from the sensor S 5 , while the sensor S 6  provides the hook load of the drill string  120 . 
     Well control system  147  is placed at the top end of the borehole  50 . The well control system  147  includes a surface blow-out-preventer (BOP) stack  115  and a surface choke  149  in communication with a wellbore annulus  127 . The surface choke  149  can control the flow of fluid out of the borehole  50  to provide a back pressure as needed to control the well. 
     In some applications, the drill bit  150  is rotated by only 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) for a given BHA largely depends on the WOB or the thrust force on the drill bit  150  and its rotational speed. 
     A surface control unit or controller  140  receives signals from the downhole sensors and devices via a sensor  143  placed in the fluid line  138  and signals from sensors S 1 -S 6  and other sensors used in the 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, and other information on a display/monitor  141  that is utilized by an 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, tape or hard disc, and one or more computer programs  146  in the storage device  144  that are accessible to the processor  142  for executing 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 relating to the drilling operations, data from the sensors and devices on the surface, and data received from downhole; and may control one or more operations of the downhole and surface devices. The data may be transmitted in analog or digital form. 
     The BHA  190  may include a tool  110  configured for performing acoustic measurements. The BHA  190  may also contain other formation evaluation sensors or devices (also referred to as measurement-while-drilling (“MWD”) or logging-while-drilling (“LWD”) sensors) determining resistivity, density, porosity, permeability, acoustic properties, nuclear-magnetic resonance properties, formation pressures, properties or characteristics of the fluids downhole and other desired properties of the formation  195  surrounding the BHA  150 . For convenience, all such sensors are generally denoted herein by 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, oscillations, whirl, stick-slip, weight-on-bit, fluid flow rate, pressure, temperature, rate of penetration, azimuth, tool face, drill bit rotation, etc. 
     The BHA  190  may include a steering apparatus or tool  158  for steering the drill bit  50  along a desired drilling path. In one aspect, the steering apparatus may include a steering unit  160 , having a number of force application members  161   a - 161   n . The force application 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 application members may be mounted on a sleeve, which is rotatable about the center axis of the drill string. The force application members may be activated using electro-mechanical, electro-hydraulic or mud-hydraulic actuators. In yet another embodiment the steering apparatus may include a steering unit  158  having a bent sub and a first steering device  158   a  to orient the bent sub in the wellbore and the second steering device  158   b  to maintain the bent sub along a selected drilling direction. The steering unit  158 ,  160  may include near-bit inclinometers and magnetometers. 
     The drilling system  101  may include sensors, circuitry and processing software and algorithms for providing information about desired drilling parameters relating to the BHA, drill string, the drill bit and downhole equipment such as a drilling motor, steering unit, thrusters, etc. Many current drilling systems, especially for drilling highly deviated and horizontal wellbores, utilize coiled-tubing for conveying the drilling assembly downhole. In such applications a thruster may be deployed in the drill string  120  to provide the required force on the drill bit. 
     Exemplary sensors for determining drilling parameters include, but are not limited to drill bit sensors, an RPM sensor, a weight on bit sensor, sensors for measuring mud motor parameters (e.g., mud motor stator temperature, differential pressure across a mud motor, and fluid flow rate through a mud motor), and sensors for measuring acceleration, vibration, whirl, radial displacement, stick-slip, torque, shock, vibration, strain, stress, bending moment, bit bounce, axial thrust, friction, backward rotation, BHA buckling, and radial thrust. Sensors distributed along the drill string can measure physical quantities such as drill string acceleration and strain, internal pressures in the drill string bore, external pressure in the annulus, vibration, temperature, electrical and magnetic field intensities inside the drill string, bore of the drill string, etc. Suitable systems for making dynamic downhole measurements include COPILOT, a downhole measurement system, manufactured by BAKER HUGHES INCORPORATED. 
     The drilling system  101  can include one or more downhole processors at a suitable location such as  193  on the BHA  190 . The processor(s) can be a microprocessor that uses a computer program implemented on a suitable non-transitory computer-readable medium that enables the processor to perform the control of system  101  and processing of information, such as information from the 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, and the like will be apparent to one skilled in the art. In one embodiment, the MWD system utilizes mud pulse telemetry to communicate data from a downhole location to the surface while drilling operations take place. The surface processor  142  can process the surface measured data, along with the data transmitted from the downhole processor, to evaluate the formation. 
     Surface processor  142  or downhole processor  193  may also be configured to control steering apparatus  158 , mud pump  134 , drawworks  130 , rotary table  114 , downhole motor  155 , other components of the BHA  190 , or other components of the drilling system  101 . Surface processor  142  or downhole processor  193  may be configured to control sensors described above and to estimate a parameter of interest according to methods described herein. 
     Control of these components may be carried out using one or more models using methods described below. For example, surface processor  142  or downhole processor  193  may be configured to modify drilling operations i) autonomously upon triggering conditions, ii) in response to operator commands, or iii) combinations of these. Such modifications may include changing drilling parameters, steering the drillbit (e.g., geosteering), altering the drilling fluid program, activating well control measures, and so on. Control of these devices, and of the various processes of the drilling system generally, may be carried out in a completely automated fashion or through interaction with personnel via notifications, graphical representations, user interfaces and the like. Reference information accessible to the processor may also be used. In some general embodiments, surface processor  142 , downhole processor  193 , or other processors (e.g. remote processors) may be configured to operate the evanescent tool  110  to generate an evanescent wave and measure signals. 
     The system  101  may include any number of downhole tools for various processes including formation drilling, geosteering, and formation evaluation (FE) for making electrical measurements versus depth and/or time of one or more physical properties in or around a borehole, including a volume of interest of the formation intersected by the borehole. The tool  110  may be included in or embodied as a BHA, drillstring component or other suitable carrier. 
     While a drill string  120  is shown as a conveyance device for tool  110 , it should be understood that embodiments of the present disclosure may be used in connection with tools conveyed via rigid (e.g. jointed tubular or coiled tubing) as well as non-rigid (e. g. wireline, slickline, e-line, etc.) conveyance systems. The drilling system  101  may include a bottomhole assembly and/or sensors and equipment for implementation of embodiments of the present disclosure on either a drill string or a wireline. 
     Mathematical models, look-up tables, or other models representing relationships between the signals and the parameter values may be used to characterize the formation, the borehole location, or operations in the formation; optimize one or more operational parameters of a production or development; and so on. The system may carry out these actions through notifications, advice, and/or intelligent control. Various types of downhole parameters may be determined using measurements in accordance with the present disclosure and making evaluations in accordance with embodiments disclosed herein. 
     U.S. Pat. No. 7,035,165 to Tang having the same assignee as the present disclosure and the contents of which are incorporated herein by reference discloses a method in which a plurality of multicomponent acoustic measurements are obtained at a plurality of depths and for a plurality of source-receiver spacings on the logging tool. An orientation sensor on the logging tool, such as a magnetometer, may be used for obtaining an orientation measurement indicative of an orientation of the logging tool. The multicomponent measurements are rotated to a fixed coordinate system (such as an earth based system defined with respect to magnetic or geographic north) using the orientation measurement, giving rotated multicomponent measurements. The rotated multicomponent measurements are processed for providing an image of the subsurface. 
     U.S. Pat. No. 8,055,448 B2 to Mathiszik et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, discloses further improvements in MWD acoustic imaging. A downhole acoustic logging tool is used for generating a guided borehole wave that propagates into the formation as a body wave, reflects from an interface and is converted back into a guided borehole wave. Guided borehole waves resulting from reflection of the body wave are used to image a reflector. U.S. Pat. No. 8,811,114 B2 to Geerits et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, discloses further improvements in MWD acoustic imaging. 
       FIGS. 2A-2C  are schematic diagrams illustrating operation of device embodiments including acoustic sensors in accordance with embodiments of the present disclosure. In general device embodiments, a sensor in accordance 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 being suspended in a fluid by individual or common tether, free-floating, or being attached to the wellbore. Thus, the probe may be stationary or in motion after installation. 
     Referring to  FIG. 2A , system  200  comprises a plurality of probes  202  suspended in a fluid  90  in a borehole  50  by tether  204 . An exterior of the probe housing may be immersed in the downhole fluid during installation. In alternative embodiments, the probe  202  may be retractable; for instance, when in operation the probe may be inserted or placed into the downhole fluid in the borehole and then retracted for cleaning or to allow further operations in the borehole. 
       FIG. 2B  is a schematic illustration showing VSP measurement acquisition in accordance with embodiments of the present disclosure. Rig  221  resides at the earth surface  223 . This may be a drilling rig or it may be a mast rig which conveys a wireline into a borehole  201 . The borehole  201  penetrates layers  203 ,  205 . Positioned in the borehole  201  are seismic sensors denoted by  211   a ,  211   b ,  211   c ,  211   d  and so on. Each of the sensors may be a sensor (e.g., a hydrophone) in accordance with embodiments of the present disclosure. Data for a single offset VSP is typically acquired using a single seismic source such as  225   a  at the surface (or within a body of water at the surface). In reference to  FIG. 2B , a surface of a body of water may be considered to be an earth surface. An exemplary raypath which depicts the propagation of seismic energy from the source  225   a  to a detector  211   d  is depicted by the ray  227   a  that is reflected from the bottom of layer  205  at the boundary  206  and reaches the receiver  211   d  along the raypath denoted by  229   a.    
     In one typical type of VSP operation, data resulting from operation of a source at a single position such as  225   a  is recorded in each of the receivers  211   a ,  211   b ,  211   c ,  211   d , etc. in the borehole. Analysis of the reflected data can provide information about the seismic velocities in the subsurface and the configuration of the layer boundaries. In a walkaway VSP, this process is repeated for operation of the source at a plurality of source positions such as  225   b ,  225   c . Acquisition of data from a plurality of source positions at a plurality of detectors provides a redundant sampling of the subsurface region, making it possible to determine the velocity of the subsurface based on the travel-times for the rays between each of the sources and each of the receivers. This determination of velocity using travel-times is called “tomographic inversion” and numerous processing packages are available commercially and as open source software (e.g., OpenTOAST) that perform this tomographic inversion of seismic travel-time data. Processing of VSP measurements to characterize the formation is a well-developed field. See, for example, U.S. Pat. No. 7,751,279 to Aronstam, and U.S. Pat. No. 7,751,279 to Zhao et al., hereby incorporated by reference in its entirety. 
       FIG. 2C  shows a simulated geometry of a surface seismic survey. A vertical borehole has been assumed, the sources have been “reflected” in the borehole to simulated receiver locations on the surface  285   a ,  285   b ,  285   c . Similarly, the raypaths have also been reflected to give simulated raypaths on the left side of the borehole. In operation, methods include deploying in a borehole an array of seismic receivers as described herein and recording seismic signals in the array of receivers responsive to an activation of a seismic source at a plurality of positions on the surface of the earth. For walkaway techniques, the method further includes estimating, from travel times of seismic waves from the plurality of source positions to the plurality of receivers, velocities of vertically propagating seismic waves in a plurality of intervals, and two anisotropy parameters ε and δ related to a normal moveout curve of compressional waves for the plurality of intervals. The estimated vertical velocities and the estimated interval anisotropy parameters may be used to further process surface seismic data to give a seismic image in depth for the purpose of interpretation. For a multi-azimuthal walkaway or 3D VSP geometry, the method may further include estimating, from travel times of seismic waves from the plurality of source positions around the well to the plurality of receivers, velocities of vertically propagating seismic waves in a plurality of intervals, and five orthorhombic anisotropy parameters ε 1 , ε 1 , δ 1 , δ 2  and δ 3  related to a normal moveout velocity of compressional waves for the plurality of intervals. The estimated vertical velocities and the estimated anisotropy parameters may be used to further process surface seismic data to give a seismic image in depth for the purpose of interpretation. See, for example, U.S. Pat. No. 8,750,074 to Blias, hereby incorporated by reference in its entirety. 
     Downhole Fiber Optic Hydrophone 
       FIG. 3A  shows a schematic diagram illustrating an acoustic sensor in accordance with embodiments of the present disclosure. The sensor  300  is part of a measurement instrument configured to be conveyed in a borehole  50 . Sensor  300  may include a pressure transducer  302  and a interrogator  304 . The pressure transducer  302  comprises a transducer body  312  having a portion (e.g., face  322 ) immersed in the downhole fluid. The transducer body  312  may be mechanically de-coupled from the sensor tool body (drill collar, wireline, etc.) in order to insulate the transducer body  312  from structure-borne sound transmission. An acoustic pressure signal is propagated via the downhole fluid coupled with the transducer. In some embodiments, some (or all) of the instrument may protrude from the tool body into the borehole. Transducer  302  is configured to convert an acoustic pressure signal within a nominal borehole pressure incident on the transducer to an alternating strain on an optical medium (e.g., optical fiber  303 ). 
     Fiber  303  includes fiber Bragg gratings (‘FBG’)  305 . These fiber Bragg gratings are a type of distributed Bragg reflector constructed in a segment of optical fiber (e.g., by using pulses from a femtosecond laser) that reflects light centered about a particular wavelength, such as, for example, by creating a periodic variation in the refractive index of the fiber core and thus generating a wavelength specific dielectric mirror. FBG  305  reflects a small spectral portion of electromagnetic radiation (e.g., light) propagating in the optical fiber  303 , allowing a remaining portion to travel through. 
     The electromagnetic radiation is provided by an energy source  308 , such as a light source configured to provide light for the sensors via the optical fiber. As one example, the energy source may be a tunable laser light source that is configured to provide a light having a wavelength that sweeps across a range of wavelengths at a selected rate, but the energy source may be any tunable light source or a 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 may be optically coupled to the fiber  303  to provide an infrared light beam. The energy source  308  may optionally be incorporated as part of the interrogator  304 , as shown in  FIG. 3A . 
     The central wavelength of the reflected spectral portion (‘reflected spectrum’ or ‘reflection spectrum’) is responsive to physical parameters on the fiber, including, particularly, strain along the axis of the fiber. Due to the configuration of the transducer, strain on the fiber is representative of the pressure. Thus, the central wavelength of the spectrum changes with changes in pressure on the transducer, and is indicative of the acoustic pressure signal on the sensor. 
     The optical fiber  303  may run through the transducer  302  and into the interrogator  304 . Interrogator  304  (implemented using, e.g., one or more photodetectors, charge-coupled devices, optical-electrical converters, or the like) is optically coupled to the fiber  303  and detects electromagnetic signals (e.g., light) received from the fiber. 
     A light coupling or separation mechanism  307  such as an optical circulator or fiber optic splitter may be used to couple or separate optical signals travelling in opposite directions in the fiber  303 , such as, for example, by providing light from the light source  308  to the transducer  302  via the fiber  303 , and sending light returning on the fiber from the transducer  302  to spectral detector  306 . Spectral detector  306  generates measurement information indicative of the pressure signal based on electromagnetic signals responsive to partial reflection of the electromagnetic energy. 
     Sensor  300  may include circuitry  310  for making measurements using the 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 the at least one processor described above with reference to  FIGS. 1A &amp; 1B , or may be an additional processor or other supporting circuitry. In some implementations, portions of circuitry  310  may be located at the instrument, at other locations in the tool (including, for example, in other subs), or at the surface. 
     In operation, the instrument may be controlled by circuitry  310 , including the control unit (e.g., a processor), which actuates the energy source  308  while the portion of the transducer (e.g., face  322 ) is immersed in the downhole fluid and receives measurement information (e.g., data) from spectral detector  306 . 
     Interrogator  304  is thus configured to generate acoustic measurement information responsive to received electromagnetic radiation (e.g., the reflected spectrum) transmitted through the medium. Alternatively, the central wavelength may be detected using an optical detector at the opposite end of the fiber detecting or the remaining portion of the original spectrum. A time-varying value of the central wavelength may be used to generate a time-varying value of the acoustic pressure signal. Spectral detector  306  may be implemented, for example, using one or more photo detectors corresponding to the desired wavelength. 
       FIG. 3B  illustrates a sensor including multiple pressure transducers  341 ,  342 ,  343  on a single fiber. The section of the fiber corresponding to each transducer includes a unique Bragg grating. The characteristic wavelength of each of the gratings is spaced from those of the remaining gratings, such that the signal for a particular transducer may be recovered. A spectral demultiplexer  355 , such as a set of additional Bragg gratings on the detector side, separates the signals to a corresponding set of photodetectors  360 ,  361 ,  362 , with one Bragg grating and one photodetector for each transducer. This configuration allows the simultaneous interrogation of two or more sensors. 
     Pressure transducer  302  is configured to convert a low-amplitude, high-frequency acoustic pressure signal within a nominal borehole pressure incident on the transducer to an alternating strain on the optical medium along an axis of the medium via movement of a flexing member while suppressing conversion of low-frequency signals and constant pressure into strain of the optical medium. 
     High-Offset Sensor Transducer 
       FIGS. 4A-4H  illustrate transducers in accordance with embodiments of the present disclosure. Referring to  FIG. 4A , transducer  400  includes a transducer body  406  containing a first reservoir  408  and a second reservoir  410 . The pressure transducer  400  comprises an interface  424  between the reservoirs. Body  406  and interface  424  may be fabricated from silicon, glass, crystalline structures, composites, or the like, such as, for example, by bonding together wafers, by subtractive manufacture (e.g., etching, laser ablation), etc. Each reservoir is filled with the same type of reservoir fluid (e.g., silicone oil), and the interface  424  includes at least one opening providing for communication of the reservoir fluid between the first reservoir  408  and a second reservoir  410 . The opening is a capillary  404 . Other implementations may use more than one capillary, or may use a different type of opening. 
     The interface  424  also includes a flexing member, implemented as flexible membrane  420 . Flexible membrane  420  may be made of a polymer bonded to the body (e.g., polyvinylidene difluoride (‘PVDF’)). In other implementations flexing member be an additional wafer bonded in place, or may be created through subtractive manufacture of the body  406 . A segment of optical fiber  403  is attached to the membrane which includes a FBG proximate to the point of attachment. The fiber may be attached using an adhesive, welding, soldering, or splicing process. The optical fiber may traverse the membrane in the center in normal direction and is attached to the membrane at the boundary point. A second interface separates one of the reservoirs  408  and the downhole fluid  90 . The second interface comprises a second flexing member  422  responsive to the high-frequency acoustic pressure signal incident on the transducer. 
     The FBG may be written into the fiber using a femtosecond laser. This allows imprinting of various grating shapes by modifying the grating period and depth, and hence to realize apodized, pi-shifted, and chirped gratings. Furthermore, this process can be applied to standard optical fibers, in contrast to UV light-based methods that require photo-sensitive fiber cores. 
     Acoustic signals in the downhole fluid are incident on membrane  422 . The fluid of reservoir  408  behind (interior to) the membrane  422  experiences a high ambient pressure from the downhole fluid, but this pressure is equalized across membrane  424  via the capillary  404 . The fluid response interior to the transducer body  406 , in the presence of the capillary  404 , to constant or low-frequency pressure is to equalize through the capillary without appreciable response on (movement of) membrane  420 . Capillary  404  may therefore be said to filter out the low frequency signal. In contrast, a high frequency signal incident on membrane  422  causes a symmetrical response on membrane  420 , with the corresponding strain signal generated on the fiber. With elevated pressures equalized across all fluids, the response on membrane  420 , and hence the fiber, exhibits remarkable fidelity (e.g., on the order of less than 10 percent per MPa differential pressure, less than 5 percent per MPa differential pressure, or down to and including 1 percent per MPa differential pressure or better). The transducer body  406  may be mechanically de-coupled from the sensor tool body (drill collar, wireline, etc.) in order to insulate the transducer body  406  from structure-borne sound transmission. 
     The collective result of these features is that the pressure transducer is configured to fluid-mechanically filter low-frequency ambient pressure noise using bypass flow of the reservoir fluid through the opening via pressure equalization. This is achieved through fluid bypass with a cross section configured to compensate by slowly carrying differential pressure between the two reservoirs. In  FIG. 4A , the bypass is realized by introducing capillary  404  with appropriate diameter and length between the two silicon-oil filled reservoirs for the desired cutoff frequency (f): 
     
       
         
           
             
               
                 
                   f 
                   = 
                   
                     
                       
                         r 
                         4 
                       
                       · 
                       ρ 
                       · 
                       
                         c 
                         2 
                       
                     
                     
                       16 
                       · 
                       μ 
                       · 
                       l 
                       · 
                       V 
                     
                   
                 
               
               
                 
                   ( 
                   1 
                   ) 
                 
               
             
           
         
       
     
     wherein 
     l is the length of the capillary tube; 
     r is the radius of the capillary tube; 
     V is the volume of the reservoir behind the capillary tube; 
     μ is the dynamic viscosity of the fluid; 
     ρ is the fluid density; and 
     c is the speed of sound of the fluid. 
       FIGS. 4B &amp; 4C  illustrate another transducer in accordance with embodiments of the present disclosure.  FIG. 4B  is a lateral view of the transducer  430 .  FIG. 4C  is a top view of the interface  444 . Transducer  430  includes a transducer body  436  containing a first reservoir  438  and a second reservoir  440 . In some implementations, reservoirs  438  and  440  may be configured such that their respective maximum extents in a direction normal to the interface  444  are equal (and opposite). This configuration may result in effective compensation of pressure differences occurring at the interface due to quasi-hydrostatic pressure. The transducer body  436  may also be mechanically de-coupled from the sensor tool body (drill collar, wireline, etc.) in order to insulate the transducer body  436  from structure-borne sound transmission. The pressure transducer  430  comprises an interface  444  between the reservoirs. Each reservoir is filled with the same type of reservoir fluid (e.g., silicone oil), and the interface  444  includes two openings providing for communication of the reservoir fluid between the first reservoir  438  and a second reservoir  440 . The openings comprise slits  451 ,  452  in the interface  444 . Other implementations may additionally use a capillary, or may use more or fewer openings of various dimensions. 
     The flexing member  421  is implemented as a portion of the interface between a first slit  451  of the plurality and a second slit  452  of the plurality forming a bender bar. A segment of optical fiber  433  is attached (e.g., using adhesives) to the flexing member  421 , and includes an FBG centered over the attachment. A second interface separates one of the reservoirs  438  and the downhole fluid  90 . The second interface comprises a second flexing member  432  (e.g., a membrane) responsive to the high-frequency acoustic pressure signal incident on the transducer. 
     As before, acoustic signals in the downhole fluid are incident on the exterior membrane  452 . Low frequency pressure is equalized across the interface via the capillary slits  451  and  452  while preventing a corresponding appreciable response on member  421 , thus filtering out the low frequency pressure signal and constant pressure. Again, with elevated pressures equalized across all fluids, the response on member  421 , and hence the fiber are greatly improved from traditional techniques. The bypass is realized by configuring slits  451  and  452  having appropriate dimensions between the two silicon-oil filled reservoirs for the desired cutoff frequency (f): 
     
       
         
           
             
               
                 
                   f 
                   = 
                   
                     
                       
                         w 
                         3 
                       
                       · 
                       l 
                       · 
                       ρ 
                       · 
                       
                         c 
                         2 
                       
                     
                     
                       24 
                        
                       
                         π 
                         · 
                         μ 
                         · 
                         h 
                         · 
                         V 
                       
                     
                   
                 
               
               
                 
                   ( 
                   2 
                   ) 
                 
               
             
           
         
       
     
     wherein 
     l is the length of the slit; 
     h is the height of the slit; 
     w is the width of the slit; 
     V is the volume of the reservoir behind the slit; 
     μ is the dynamic viscosity of the fluid; 
     ρ is the fluid density; and 
     c is the speed of sound of the fluid. 
       FIGS. 4D-4H  illustrate another transducer in accordance with embodiments of the present disclosure.  FIG. 4D  is a lateral view of the transducer  470 .  FIG. 4E  is a second lateral view of the transducer  470  perpendicular to the first view. Transducer  470  includes a transducer 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  providing for communication of the reservoir fluid between the first reservoir  478  and the second reservoir  480 . A second interface comprises a second flexing member  472  (e.g., a membrane) responsive to the high-frequency acoustic pressure signal incident on the transducer.  FIG. 4F  is a top view of the interface. A segment of optical fiber  483  is attached (e.g., using adhesives) to the flexing member  491 , and includes an FBG  493  centered over the attachment, as above. 
     Transducer  470  represents a transducer configured for vibration compensation. As above with respect to  FIGS. 4B &amp; 4C , the maximum extent of reservoirs  478  and  480  with respect to the interface  474  in a direction normal to the interface  474  may be equal, and this configuration may result in effective compensation of pressure differences occurring at the interface due to quasi-hydrostatic pressure. In order to attain the same effect in all directions, transducer  470  may be configured such that the upper and lower reservoirs  478  and  480  may satisfy the same condition in two perpendicular and respectively perpendicular directions  494  and  495 . 
       FIGS. 4G and 4H  illustrate one construction of transducer  470 .  FIG. 4G  shows a side view of upper reservoir member  497  and  FIG. 4H  shows a front view of lower reservoir member  498 . Each reservoir is symmetric in two dimensions. The lower reservoir member  498  is configured to receive upper reservoir member  497 . By rotating upper reservoir  497  by 90 degrees and coupling the reservoir members as an interlocking assembly, the transducer  470  may be constructed. The reservoir members are also configured such that the upper reservoir member  497  is substantially symmetric to the lower reservoir member  498 . The upper reservoir member  497  may have substantially identical dimensions to the lower reservoir member  498  but different orientations as aligned for assembly. The volume of fluid of the reservoirs is substantially the same. Thus, the reservoirs have a shape and respective orientation which results in suppression of any acceleration-induced quasi-hydrostatic pressure signal. This is achieved by ensuring that the pressure at the flexing member is identical in both reservoirs. 
       FIGS. 5A &amp; 5B  illustrate transducer components in accordance with embodiments of the present disclosure. Transducer  500  includes glass plate  544 , which acts as an interface wall in a similar fashion to interface  444 . An additional reservoir may be formed above the glass plate  544  by an extension of a transducer body and membranes (not shown). The pressure transducer  500  comprises a flexing member  521 . The flexing member  521  is implemented as a portion of the interface between a first slit  551  of the plurality and a second slit  552  of the plurality forming a bender bar. A segment of optical fiber  533  is attached (e.g., using adhesives) to the flexing member  521 . Flexural element  550  supports the flexing member  521 . The flexural element includes a notch  554  in which optical fiber  533  resides and a cavity  555 . The FBG  503  within the optical fiber  533  is positioned above the cavity  555  at a distance from the notch configured for maximal elastic strain within the fiber from generated leverage from the flexural element at the notch end. The wedge profile of the flexural element results in reduced mass, and thus increased fundamental frequency, with respect to other embodiments (e.g., approaching 10 kHz, or more). 
       FIG. 6  illustrates another transducer in accordance with embodiments of the present disclosure. The transducer may be implemented with a reservoir filled with a dilatant fluid. The dilatant fluid may be configured to act, responsive to the high-frequency acoustic pressure signal, as a solid transmitting the high-frequency acoustic pressure signal to the flexing member; responsive to the ambient pressure noise, the dilatant fluid may be configured to act as a liquid preventing transmission of the ambient pressure noise to the flexing member. 
     Transducer  600  includes a transducer body  606  containing a reservoir  608 . Flexing members  622  are implemented as a plurality of biasing members  621  (e.g., springs) within the reservoir  608  which bias a plurality of wave impingement members  634  (e.g., planar discs) which are connected with a segment of optical fiber  633  (which extends through the body  606 ). An FBG  603  is centered between the discs  634 . The optical fiber may traverse through (and be connected at) each disc  634  in the center in a normal direction. An interface  607  separates one of the reservoir  608  and the downhole fluid  90 . The interface comprises an exterior membrane  652  responsive to the high-frequency acoustic pressure signal incident on the transducer. 
     The reservoir  608  is filled with a dilatant fluid. The dilatant fluid is configured to act, responsive to the high-frequency acoustic pressure signal, as a solid transmitting the high-frequency acoustic pressure signal to the flexing member; responsive to ambient pressure noise or constant pressure, however, the dilatant fluid is configured to act as a liquid, thus preventing transmission of the ambient pressure noise to the flexing member. 
     As before, acoustic signals in the downhole fluid are incident on the exterior membrane  652 . Responsive the high-frequency acoustic signals passed to the reservoir  608  by the membrane  652 , the dilatant fluid acts as a solid transmitting the signal to impingement members  634 , which relieves strain on the fiber  633 . In contrast, low-frequency or constant pressure are absorbed in the liquid-mode fluid, resulting in such signals being suppressed. 
     The above described transducers together with the optical fibers and FBGs constitute sensors which are sensitive to acoustically induced dynamic pressure variations, but insensitive to constant and slowly varying pressures. Thus, the transducer embodiments above may be insensitive to pressure waves below a particular frequency, such as, for example, 10 kHz, 1 kHz, 100 Hz, or 10 Hz, or below. This makes the sensor insensitive to pressures consistent with the nominal downhole environment without decreasing the sensitivity to acoustic signals. 
       FIG. 7A  shows a flow chart  700  illustrating methods for performing well logging in a borehole intersecting an earth formation in accordance with embodiments of the present disclosure. In optional step  710 , an acoustic sensor in accordance with the present disclosure is positioned in the borehole. For example, an acoustic well logging tool may be conveyed in a borehole using a carrier. The borehole may be filled with downhole fluid, such as, for example, drilling fluid. In other examples, a sensor probe may be installed in the formation. See, for example, U.S. Pat. No. 7,201,221 to Tubel et al, which is commonly owned and herein incorporated by reference in its entirety. 
     Optional step  720  of the method  700  may include obtaining acoustic data with the acoustic sensor. Step  720  may include generating a plurality of acoustic signals within the borehole, or from seismic devices at the surface, and generating acoustic wave data at at least one sensor downhole in response to acoustic signals received at the sensor, such as, for example, a plurality of acoustic reflections of acoustic waves from a boundary responsive to the transmitted acoustic signals. 
     Step  730  comprises characterizing the formation using the acoustic data including generating formation information. Step  730  may include using the location in the formation for each reflection point to estimate at least one property of the acoustic reflective boundary. This may include estimating from the acoustic data a distance from a boundary, a dip, a location of the boundary in the formation, and so on. Optional step  740  comprises transmitting formation information uphole. Optional step  750  comprises conducting further operations in the formation in dependence upon the formation information. 
       FIG. 7B  shows a flow chart  760  illustrating methods for obtaining acoustic data. Step  770  comprises using a pressure transducer comprising a flexing member attached to an optical medium to convert a low amplitude, high-frequency acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member. This may be carried out by mitigating a pressure offset due to the nominal borehole pressure. 
     Step  780  comprises using a detector to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis. The at least one optical property of the medium being responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents the acoustic signal. 
     Optional methods may include estimating a parameter of interest of the formation and using the parameter of interest to estimate a characteristic of a formation or to conduct further operations. Estimation of 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: (i) a mathematical equation, (ii) an algorithm, (iii) an deconvolution technique, and so on. Reference information accessible to the processor may also be used. 
     Coupled Oscillator Modification 
     For some applications, alternative techniques for production of a modified signal may be warranted to optimize detection of signals with particular characteristics, such as, for example, signals in a desired frequency range. For example, detection of signals from a particular source type or removal of signal components characterized as noise may be beneficial. Modification of the transducers above for detection of acoustically reflective boundaries and for determining related parameters of interest, detecting velocities of propagating seismic waves over a plurality of intervals, estimating vertical velocities or anisotropy parameters, generating seismic images, performing seismic inversion, or otherwise estimating parameters of interest from borehole acoustic array data may be desirable. Additionally, implementations using a fluid bypass may display more resistive behavior as frequencies increase, acting as a first order filter. Aspects of the present disclosure below may produce a steeper filter curve. Modification of the signal may be carried out by at least one coupled oscillator influencing the flexing member. 
     The acoustic pressure signal is made up of component signals, with each component signal having an associated frequency range. While detection of some of the component signals is desirable, the presence of other component signals may be unwanted. It may be desirable to suppress conversion of signals within a particular frequency range, such as for example, those representing drilling-noise, while allowing conversion of component signals in another frequency range (the ‘target frequency range’). Further, it may be desirable to amplify conversion of component signals in the target frequency range (‘target component signals’). 
       FIGS. 8A-8F  illustrate an acoustic sensor including a pressure transducer configured to modify the represented acoustic signal in accordance with embodiments of the present disclosure.  FIG. 8A  and  FIG. 8B  show acoustic sensors including a pressure transducer employing coupled oscillators. The pressure transducer  800  comprises a fluid reservoir  804  and an interface  805  between the reservoir  804  and a fluid body  802 . Depending on the configuration of the transducer, the fluid body may comprise the fluid-filled borehole annulus or other downhole fluid. The interface includes a flexing member  810  attached to an optical medium, as described herein above. A coupled oscillator  820  is coupled to the flexing member  810  such that motion of the flexing member  810  is influenced by motion of the coupled oscillator  820  in at least some circumstances. The coupled oscillator  820  may be directly coupled as shown in  FIG. 8A  or indirectly coupled, e.g., through the physical interaction of one or more components of the transducer as shown in  FIG. 8B . In  FIG. 8B  the coupling is achieved by the elastic properties of the fluid in the reservoir  804 . 
       FIGS. 8C &amp; 8D  show a pressure transducer  800 ′ employing a plurality of coupled oscillators. The movement of the flexing member  810  responsive to the incident component pressure signals may be influenced by movement of the at least one coupled oscillator responsive to the incident component pressure signals. The at least one coupled oscillator may be implemented as a flexible membrane, piston, bender bar, or the like, or as another flexing member, or as combinations of these. In operation, the coupled oscillators ( 820   a ,  820   b ,  820   c ) are each responsive to incident pressure and having different eigenfrequencies. 
     An acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer may be propagated via the fluid body  802 . The pressure transducer may be implemented with components in accordance with any of the embodiments described herein. As described in detail hereinabove, the pressure transducer is configured to convert at least a portion of the acoustic pressure signal to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member. 
     The at least one coupled oscillator is configured to affect conversion by the flexing member of component signals of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents a modified acoustic signal. The at least one coupled oscillator may be configured to modify conversion by the flexing member of the component signals by altering sensitivity of the flexing member to the component signals. The at least one coupled oscillator may be configured to increase sensitivity of the flexing member to particular component signals or to decrease sensitivity (e.g., of an unwanted or over-represented signal component). 
     The at least one coupled oscillator may be configured to suppress conversion of the component signals of the acoustic pressure signal within the predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents the acoustic signal filtered to substantially remove the signals within the predefined frequency range. The predefined frequency range may comprise frequencies from zero to a predefined low-frequency threshold, so that the electromagnetic radiation received by the detector represents the acoustic signal filtered to substantially remove the signals below the predefined frequency threshold. The at least one coupled oscillator is configured to amplify conversion of the component signals of the acoustic pressure signal within the predefined frequency range into strain of the optical medium, so that the electromagnetic radiation received by the detector represents the acoustic signal filtered to amplify the signals within the target frequency window. The at least one coupled oscillator is configured to suppress 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 strain of the optical medium and to amplify 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 strain of the optical medium. 
     In particular embodiments, modification is carried out by at least one coupled oscillator displacing a volume of the fluid reservoir responsive to the acoustic pressure signal to modify conversion by the flexing member of component signals of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium. In this way, the electromagnetic radiation received by the detector represents a modified acoustic signal. 
       FIG. 8E  illustrates a pressure transducer from an acoustic sensor configured to modify the represented acoustic signal using at least one coupled oscillator displacing a volume of the fluid reservoir responsive to the acoustic pressure signal in accordance with embodiments of the present disclosure. Transducer  822  comprises an interface  825  between a fluid reservoir  834  and a fluid body  832 . The interface includes a flexing member implemented as flexible membrane  840  and at least one opening providing for communication of fluid between fluid reservoir  834  and a fluid body  832 , and configured to suppress conversion of low-frequency signals and constant pressure into strain of the optical medium, as described in greater detail hereinabove. A segment of optical fiber is attached to the membrane as illustrated hereinabove. The opening is a capillary  844 . Other implementations may use more than one capillary, or may use a different type of opening. The interface comprises a coupled oscillator implemented as second flexible membrane  850  responsive to the acoustic pressure signal incident on the transducer. 
       FIG. 8F  illustrates another pressure transducer from an acoustic sensor with a coupled oscillator. The flexing member  840 ′ is implemented as a portion of the interface between a first slit  841  and a second slit  842  forming a bender bar. The interface  825 ′ might also comprise a second flexing member or the like (not shown). The coupled oscillator  851  is implemented as piston  850 ′ and a spring  852 . 
       FIG. 8G  illustrates a model of a coupled oscillation in accordance with embodiments of the present disclosure. In the model of  FIG. 8G , a first flexing member is modeled as a piston with an additional piston coupled via the fluid of the reservoir. Referring to  FIG. 8G , the pistons are modeled as a coupled two mass oscillatory system. The springs of the oscillatory systems are provided by the compressibility of the fluid. Mass m 2  represents the mass that is coupled to the optical transducer that coverts the deflection into an optical signal representing the motion of the piston. 
     Equations of motion for a damped, two mass oscillatory system with forced excitation may be expressed as: 
     
       
         
           
             
               
                 
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       FIGS. 9A-9F  show the computational model and the response functions for a modeled system having a flexing member and a coupled oscillator having various oscillation parameters in accordance with embodiments of the present disclosure. The coupled oscillator is implemented as a second damped spring-mass system.  FIG. 9A  is a model that serves for illustrational purposes to illustrate the effect of the coupling of the two oscillatory systems. It has no coupling between the two oscillatory systems and provides subsequently two independent resonance curves.  FIGS. 9B &amp; 9C  show for illustration purposes the amplitude and phase, respectively, of two oscillators with no coupling (k 2 =0 and λ 2 =0) excited by forces f 1 (t) and f 2 (t) acting on the masses, wherein f 1 (t)=f 1 *cos(ω*t) and f 2 (t)=f 2 *cos(ω*t). This results in two independent resonance curves of the two oscillators. The modeled system has parameter values: 
     k 1 =1.0 
     k 3 =1.0 
     m 1 =1.0 
     m 2 =0.25 
     λ 1 =0.15 
     λ 3 =0.15 
     f 1 =1 
     f 2 =−1 
       FIG. 9D  shows the computational model of the coupled system. Spring k 2  couples oscillatory system of mass m 1  with the oscillatory system of mass m 2 .  FIGS. 9  E &amp;  9 F show the amplitude and phase of the now coupled two-mass oscillator system a coupling by spring k 2 =1 modifies the response to the excitation forces f 1  and f 2 . This example of the modeled system has parameter values: 
     k 1 =1.0 
     k 2 =0.5 
     k 3 =1.0 
     m 1 =1.0 
     m 2 =0.25 
     λ 1 =0.2 
     λ 3 =0.2 
     f 1 =1 
     f 2 =−1 
     An optical medium that is attached to mass m 2  would experience a modified response to the acoustic signal. It would have a suppression of response in the lower frequency range where unwanted signal is expected and would have an amplified response to the desired signal in the higher frequency range. 
       FIG. 10  shows a flow chart  1000  illustrating methods for obtaining acoustic data. Step  1002  comprises using a pressure transducer comprising an interface between a fluid reservoir and a fluid body, the interface including a flexing member attached to an optical medium, to convert an acoustic pressure signal within a nominal borehole pressure incident on the pressure transducer to an alternating strain on the optical medium along an axis of the medium via movement of the flexing member. Step  1002  includes displacing a volume of the fluid reservoir with at least one coupled oscillator responsive to the acoustic pressure signal to modify conversion by the flexing member of signal components of the acoustic pressure signal having a frequency within a predefined frequency range into strain of the optical medium. This may influence movement of the flexing member responsive to the incident signal components with movement of the at least one coupled oscillator responsive to the incident signal components. 
     Steep  1004  comprises using a detector to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium along the axis. The at least one optical property of the medium may be responsive to the alternating strain on the medium such that the electromagnetic radiation received by the detector represents a modified acoustic signal. 
     Optional methods may include estimating a parameter of interest of the formation and using the parameter of interest to estimate a characteristic of a formation or to conduct further operations. Estimation of 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: (i) a mathematical equation, (ii) an algorithm, (iii) an deconvolution technique, and so on. Reference information accessible to the processor may also be used. 
     Method embodiments may include conducting further operations in the earth formation in dependence upon formation information, estimated properties of the reflector(s), or upon models created using ones of these. Further 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 present or future development in the formation or in a similar formation; viii) optimizing present or future exploration in the formation or in a similar formation; ix) drilling the borehole; and x) producing one or more hydrocarbons from the formation information. 
     Estimated parameters of interest may be stored (recorded) as information or visually depicted on a display. The parameters of interest may be transmitted before or after storage or display. For example, information may be transmitted to other downhole components or to the surface for storage, display, or further processing. Aspects of the present disclosure relate to modeling a volume of an earth formation using the estimated parameter of interest, such as, for example, by associating estimated parameter values with portions of the volume of interest to which they correspond, or by representing the boundary and the formation in a global coordinate system. The model of the earth formation generated and maintained in aspects of the disclosure may be implemented as a representation of the earth formation stored as information. The information (e.g., data) may also be transmitted, stored on a non-transitory machine-readable medium, and/or rendered (e.g., visually depicted) on a display. 
     The processing of the measurements by a processor may occur at the tool, the surface, or at a remote location. The data acquisition may be controlled at least in part by the electronics. Implicit in the control and processing of the data is the use of a computer program on a suitable non-transitory machine readable medium that enables the processors to perform the control and processing. The non-transitory machine readable medium may include ROMs, EPROMs, EEPROMs, flash memories and optical disks. The term processor is intended to include devices such as a field programmable gate array (FPGA). 
     The term “conveyance device” as used above means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting conveyance devices include drill strings of the coiled tube type, of the jointed pipe type and any combination or portion thereof. Other conveyance device examples include casing pipes, wirelines, wire line sondes, slickline sondes, drop shots, downhole subs, BHA&#39;s, drill string inserts, modules, internal housings and substrate portions thereof, self-propelled tractors. As used above, the term “sub” refers to any structure that is configured to partially enclose, completely enclose, house, or support a device. The term “information” as used above includes any form of information (Analog, digital, EM, printed, 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. An information processing device may include a microprocessor, resident memory, and peripherals for executing programmed instructions. The processor may execute instructions stored in computer memory accessible to the processor, or may employ logic implemented as field-programmable gate arrays (‘FPGAs’), application-specific integrated circuits (‘ASICs’), other combinatorial or sequential logic hardware, and so on. Thus, a processor may be configured to perform one or more methods as described herein, and configuration of the processor may include operative connection with resident memory and peripherals for executing programmed instructions. 
     As used herein, the term “fluid” and “fluids” refers to one or more gasses, one or more liquids, and mixtures thereof. A “downhole fluid” as used herein includes any gas, liquid, flowable solid and other materials having a fluid property and relating to hydrocarbon recovery. A downhole fluid may be natural or man-made and may be transported downhole or may be recovered from a downhole location. Non-limiting examples of downhole fluids include drilling fluids, return fluids, formation fluids, production fluids containing one or more hydrocarbons, engineered fluids, oils and solvents used in conjunction with downhole tools, water, brine, and combinations thereof. An “engineered fluid” may be used herein to mean a human made fluid formulated for a particular purpose. The term “geosteering” may refer to changing direction of the drill bit, stopping progression of the drill bit, or continuing advancement of the drill bit. 
     It is apparent that the values of slowness and velocity may be used interchangeably in the techniques disclosed herein. The parameters slowness and velocity are inversely related and the measurement of either may be converted to the other by simple mathematical relations that are well known in the art. Thus, the term “slowness” as used herein may refer to slowness as traditionally understood, as well as other parametric equivalents. 
     The term vertical seismic profile (‘VSP’) as used herein is meant to mean any of zero-offset VSP, offset VSP, walkaway VSP, walk-above VSP, salt-proximity VSP, shear-wave VSP, and drill-noise or seismic-while-drilling VSP. Acoustic signal is meant to mean any signal acoustically measured or processed, including seismic signals. The terms “fast varying” or “high-frequency” as used herein refer to frequency characteristics corresponding to typical acoustic signals used for measurement applications downhole. The terms “slowly varying” or “low-frequency” as used herein refer to frequency characteristics corresponding to acoustic signals below a level representing desired acoustic measurements, and may be represented by pressure waves below a cutoff frequency such as 10 kHz, 1 kHz, 100 Hz, 10 Hz, or below. Ambient pressure noise should be understood to refer to non-signal pressure variations endemic to borehole applications, including low frequency pressures, such as tool vibration. Mechanically filtering ambient pressure noise thus may suppress ambient noise tool vibration, such as pump noise. Tool vibration may have a characteristic frequency of 80 to 500 Hz, in comparison with an acoustic signal of 1 kHz or more. 
     While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.