BR112019005546B1 - APPARATUS FOR USE IN A HOLE AND METHOD FOR ACOUSTIC DETECTION IN A HOLE - Google Patents

Abstract

Methods, systems, devices and products for acoustic detection in a borehole. Embodiments of apparatus comprise an acoustic sensor including: a pressure transducer comprising a bending member connected to an optical means, the transducer configured to convert a low amplitude, high frequency acoustic pressure signal into a borehole pressure incident. nominal well in the transducer for an alternating voltage in the optical medium along a medium axis through movement of the bending member while suppressing the conversion of low frequency and constant pressure signals into optical medium voltage, the propagated acoustic pressure signal through a downhole fluid coupled to the transducer; and 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 voltage in the medium, such that the electromagnetic radiation received by the detector represents the acoustic signal.

Description

DISCLOSURE FIELD

[0001] This disclosure normally relates to drilling tools and, in particular, to methods and apparatus for conducting acoustic investigation in a borehole that intersects a land formation. More particularly, the disclosure relates to acoustic sensors and methods of using such acoustic sensors in various tools, including acoustic profiling tools.

FUNDAMENTALS OF DISCLOSURE

[0002] Drilling wells for various purposes are well known. These wells can be drilled for geothermal purposes, to produce hydrocarbons (eg oil and gas), to produce water, and so on. Well depth can 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 perform any number of downhole operations. Downhole acoustic profiling tools, which are used to investigate subsurface features, can include one or more acoustic transmitters or sources and multiple acoustic receivers. Additionally or alternatively, independent acoustic sensors can be installed inside the borehole either temporarily or permanently.

[0003] In some cases, transmitters emit acoustic energy into the subsurface environment surrounding the wellbore. Acoustic signals are reflected by interfaces associated with the wellbore, well structures and/or the formation. The reflected acoustic signals are detected by receivers in the logging tool and processed to provide estimates of one or more properties of the borehole, wellbore structure and/or formation. Drilling systems are known which have an acoustic "measure-while-logging" ("LWD") or "measure-while-drilling" ("MWD") acoustic system as part of a bottom assembly or wired recording system. after drilling with an acoustic device for measuring properties of subsurface formations (during or after drilling the well holes), such as, for example, determining the location of the formation bed boundaries around the bottom assembly, as in MWD system, or around the wired registration system.

[0004] When drilling a borehole to recover oil from the earth, it is often helpful to rotate or direct the borehole bit into or away from underground targets. Acoustic data can be used to determine the location of a drill in the seismic section to facilitate geo-orientation. With Vertical Seismic Profiling (VSP), acquisition can be performed between one or more acoustic (seismic) sources on or near the earth's surface and earth receivers, for example in a borehole. The response from an acoustic sensor such as a seismic sensor (eg a hydrophone) at various depths in a borehole to surface sources can be recorded as downhole measurements.

DISCLOSURE SUMMARY

[0005] In aspects, the present disclosure refers to the methods and apparatus for carrying out formation evaluation in a wellbore that intersects an earth formation, including the estimation of at least one formation-related parameter of interest, such as, for example, a property of an acoustic reflective boundary in the formation.

[0006] Embodiments of apparatus may comprise an acoustic sensor including: a pressure transducer comprising a bending element connected to an optical means, the transducer configured to convert a low amplitude, low frequency acoustic pressure signal into a pressure of nominal borehole incident on the transducer for an alternating voltage in the optical medium along a medium axis through movement of the bending element while suppressing the conversion of low frequency signals and constant pressure into optical medium voltage, the acoustic signal of pressure propagated through a fluid at the bottom of the well coupled to the transducer; and 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 voltage in 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 bending member and at least one aperture providing for communication of reservoir fluid between the reservoirs.

[0007] The apparatus may comprise a portion of a drill string and the ambient pressure noise may comprise the vibration of the drill string. 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 middle. A ratio of an average signal amplitude of the high frequency acoustic pressure signal to the nominal wellbore pressure can be less than 10-3.

[0008] The pressure transducer can be configured to mechanically filter low frequency ambient pressure noise in fluid. The aperture and reservoirs can be configured to mechanically filter in fluid noise from ambient pressure utilizing the bypass flow of reservoir fluid through the aperture via pressure equalization. The bending element may comprise at least one of: i) a membrane; and ii) a bending bar. The at least one opening may comprise at least one of: i) a slit in the bending member; and ii) a capillary tube. The at least one opening can comprise a plurality of slots and the bending element can comprise a part of the interface between a first slot of the plurality and a second slot of the plurality.

[0009] The pressure transducer may include a second interface between one of the reservoirs and the downhole fluid, the second interface comprising a second bending element that responds to the high frequency acoustic pressure signal incident on the transducer. A first reservoir of reservoirs may be defined by a first reservoir member and a second reservoir of reservoirs may be defined by a second reservoir member. The first reservoir member is receiveable by the second reservoir member.

[0010] The dimensions and orientations of the reservoirs can be configured to suppress acceleration-induced quasi-hydrostatic pressure signals, producing a pressure in the flexing element in the first reservoir substantially equal to another pressure in the flexing element in the second reservoir. In some embodiments of apparatus, every plane normal to a line intersecting the center of gravity of the combined reservoir fluid volumes intersects: i) both the first reservoir and the second reservoir, or ii) neither the first reservoir nor the second reservoir.

[0011] The transducer may comprise a bending member supporting the bending member. The transducer may comprise a bending member that supports the bending member and is configured to amplify movement of the bending member. The medium may comprise fiber Bragg gratings positioned relative to the bending member near a location of maximum displacement of the medium. The transducer may include a reservoir filled with a swelling fluid. The dilation fluid can be configured to act, responsive to the high frequency pressure acoustic signal, as a solid that transmits the high frequency acoustic pressure signal to the flexed limb and, responsive to ambient pressure noise, as a liquid that prevents the transmission of ambient pressure noise to the bending member.

[0012] The methods include using a pressure transducer comprising a bending member connected to an optical means to convert a low-amplitude, low-frequency acoustic pressure signal within a nominal borehole pressure incident on the transducer to an alternating voltage in the optical medium along a medium axis through the movement of the bending element while suppressing the conversion of low frequency and constant pressure signals into voltage of the optical medium, the acoustic pressure signal propagated through a fluid at the bottom of the well coupled to the transducer; and using a detector 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 voltage in the medium such that the electromagnetic radiation received by the detector represents the acoustic signal. Methods may include using acoustic measurement information to estimate a parameter of interest, such as a formation or borehole property. The parameter of interest can be at least one of: i) a slowness of a volume of interest of the formation; ii) an acoustic data communication message; iii) an offset of the transducer to a wellbore wall; iv) a borehole geometry; and v) a sound velocity of the fluid at the bottom of the well.

[0013] Some embodiments include a non-transient, computer-readable, processor-accessible medium product with instructions thereon that, when executed, cause at least one processor to execute the methods described above. Embodiments of the apparatus may include at least one processor and computer memory accessible to the at least one processor comprising a computer-readable medium with instructions thereon which, when executed, cause the at least one processor to execute the methods described above.

[0014] Examples of some features of the disclosure can be summarized quite broadly here in order that the detailed description thereof can be better understood and in order that the contributions they represent to the art can be recognized.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] For a detailed understanding of the present disclosure, reference should be made to the following detailed description of embodiments taken in conjunction with the accompanying drawings in which like elements have been given like numerals, in which: FIGS. 1A and 1B illustrate components of systems in accordance with embodiments of the present disclosure; FIGS. 2A to 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 the embodiments of the present disclosure; FIG. 3B illustrates a sensor including multiple pressure transducers in a single fiber; FIGS. 4A to 4H illustrate transducers in accordance with embodiments of the present disclosure; FIGS. 5A and 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 flowchart illustrating methods for performing well logging in a borehole intersecting an earth formation in accordance with the embodiments of the present disclosure; FIG. 7B shows a flowchart illustrating methods for obtaining acoustic data.

DETAILED DESCRIPTION

[0016] Aspects of this disclosure refer to apparatus and methods for profiling acoustic wells, including the measurement and interpretation of physical phenomena indicative of parameters of interest in the formation, the wellbore or the bottom-hole fluids, including profile vertical seismic (using borehole seismic measurements). Aspects of the present disclosure include a novel acoustic sensor (e.g., a hydrophone) well suited to detecting very small pressure differences (e.g., acoustic signals) in a high-pressure environment. Aspects of the disclosure may be suitable for detecting acoustically reflective boundaries (herein referred to as "reflectors" or "boundaries"), e.g. geological structures and related parameters of interest (e.g. properties of those boundaries) from acoustic ensemble data well hole.

[0017] Aspects of the disclosure include acquisition of a vertical seismic profile (VSP) using a sensor inside the wellbore and a surface source close to the wellbore. VSP measurements can result in higher resolution images than surface seismic images. VSP measurements can also be used to look ahead of the bit during drilling operations. A surface seismic source (eg plate shaker on land, air gun at sea) can be used to generate the detected acoustic signals.

[0018] Disclosure modalities include methods of evaluating a land formation. Methods may include deploying a set of seismic receivers in a borehole and recording seismic signals on the set of receivers that respond to an activation of a seismic source at a plurality of positions on the earth's surface. For a boundary geometry, the method may further include estimations, from travel times of seismic waves from the plurality of source positions to the plurality of receivers, propagation velocities of seismic waves over a plurality of intervals. The estimated parameters (eg vertical velocities, estimated anisotropy parameters, etc.) can be used to process further surface seismic data to provide a depth seismic image for interpretation purposes.

[0019] Disclosure aspects may refer to seismic inversion, in which seismic reflection data are processed to recover the parameters of interest including the properties of a formation volume of interest, 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 other constraints generated from additional reservoir measurements (eg well logs). Other aspects relate to formation slowness estimation, acoustic data communication messages (eg, mud pulse, etc.), acoustic insulation, acoustic caliper, general sound velocity measurements, and so on.

[0020] 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 that converts the acoustic signal (eg alternating pressures) into an alternating voltage that acts on the optical fiber along the fiber axis. The FBG reflects a small spectral portion of the light that propagates in the optical fiber. The central wavelength of this spectrum changes with the measured quantity (eg pressure), which is detected using an optical detector at one end of the fiber (detecting the reflected spectrum or the remainder).

[0021] In aspects of the present disclosure, Bragg gratings can be written onto the fiber or other optical medium (e.g. bulk glass or sheet glass) using a femtosecond laser. This technique allows printing of various grid shapes, modifying grid period and depth, and therefore realizing a wide variety of effects, including apodized, pi-shifted, and chirped grids, 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 photosensitive fiber cores and may undergo hydrogen darkening under downhole conditions. Using the femtosecond laser-based process can increase fiber life and potentially reduce packaging costs.

[0022] To obtain hydrocarbons such as oil and gas, wells (well holes) are drilled through subsurface formations containing hydrocarbons. Recently, horizontal wells extending several thousand meters (“extended reach” wells) have been drilled to access hydrocarbon reserves on the reservoir flanks and to develop satellite fields from existing offshore platforms. Downhole acoustic profiling tools, which are used to investigate subsurface features, can include one or more acoustic transmitters or sources and multiple acoustic receivers. Alternatively, the drilled hole can be equipped with independent acoustic sensors.

[0023] The environmental conditions in deep oil wells, such as, for example, underground or subsea wells, are very severe. Temperatures can approach 250 degrees Celsius and pressures can reach 20 to 30,000 psi (200 MPa) or more. In addition to the stringent tooling specifications needed 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 the acoustic pressure signal can be, for example, 1 Pa to 10 kPa (10-4 to 1 psi), at the very large constant displacement pressure provided by the ambient borehole pressure. Thus, a ratio of an average signal amplitude of the high frequency pressure acoustic signal to the nominal borehole pressure is often less than 10-3 and can range from 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 at a displacement pressure of 20,000 psi or greater.

[0024] Thus, aspects of the present disclosure include methods and apparatus for use in a hole that detect acoustic signals. General embodiments of the apparatus may comprise an acoustic sensor including a pressure transducer comprising a bending member connected to an optical means. An acoustic pressure signal can be propagated through a downhole fluid coupled to the transducer. The transducer may be configured to convert a low amplitude, high frequency acoustic pressure signal within a nominal bore pressure incident on the transducer to an alternating voltage in the optical medium along a medium axis through movement of the bending member. The configuration can be such that this is achieved while suppressing the conversion of both low frequency signals and constant pressure signals into voltage from the optical medium. The pressure transducer can be further configured to mechanically filter out low frequency ambient pressure noise in fluid.

[0025] 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 voltage in the medium, such that the electromagnetic radiation received by the detector medium represents the acoustic signal. See, for example, US Patent 6,396,572 to Chang et al.

[0026] In particular embodiments, the pressure transducer comprises an interface between reservoirs containing a reservoir fluid. The interface may include the flex element and at least one opening that allows communication of reservoir fluid between the reservoirs. The aperture and reservoirs can be configured to mechanically filter in fluid noise from ambient pressure utilizing the bypass flow of reservoir fluid through the aperture 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 bending member that responds to the high frequency acoustic pressure signal incident on the transducer. The transducer may include a bending member that supports the bending member.

[0027] In other embodiments, the transducer can be implemented with a reservoir filled with an expansion fluid. The dilating fluid can be configured to act, responsive to the high frequency pressure acoustic signal, like a solid transmitting the high frequency pressure acoustic signal to the bending member; Responsive to ambient pressure noise, the swelling fluid can be configured to act as a liquid preventing the transmission of ambient pressure noise to the bending member.

[0028] Aspects of the present disclosure refer to the use of at least one acoustic sensor as part of one or more acoustic well recording tools in the well or distributed sensor systems to produce acoustic information that responds to a pressure signal received at the sensor of earth formation. The signal may be seismic in nature or may be generated from excitations in the borehole. At least one acoustic receiver can be disposed in the hole. The information is indicative of a parameter of interest. The term "information", as used herein, includes any form of information (analog, digital, EM, print, etc.) and can include one or more of: raw data, processed data and signals.

[0029] The methods may include estimating a parameter of interest from the information, evaluating the formation using the parameter of interest and/or performing other drilling or formation operations depending on the location of the reflection points, the location of the boundary, the boundary parameter of interest or other parameters of interest derived from these. In particular embodiments, a state of drilling operations, wellbore characteristics or formation or orientation of downhole tool components, can be estimated using the parameter of interest and then used in performing an operation as described above.

[0030] Aspects of the present disclosure are subject to application in several different embodiments. The sensor can be used together with a conveyor, such as a drill string, a coil, an elastic line, an electronic line, a fixed line, etc. The sensor can be disposed on the tool for measurement, deployed from the tool, or deployed separately (preceding or subsequent to transporting the tool into the hole). The sensors, hole tools and other components of the system can be coupled or combined with additional tools including, for example, some or all of the information processing system, as shown in FIG. 1B, discussed in more detail below. In some general embodiments, the conveyor is implemented as a tool string of a drilling system, and acoustic borehole logging can be characterized as "logging while drilling" (LWD) or "measuring while drilling" (MWD) operations. . As described herein, "well" or "wellhole" refers to a single hole that constitutes all or part of a drilled well. Depending on the configuration, the systems shown here can be used during drilling and/or after wellbore formation including, in some cases, after installation of casing or production infrastructure. Although a land system is shown, the teachings of the present disclosure can also be used in marine or subsea applications. As described herein, “formations” refer to the various features and materials that can be found in a subsurface environment and surround the borehole.

[0031] 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 to estimate a downhole parameter of interest (e.g., a value of a formation property 80, hole 50, or downhole fluid 90 on it) using an acoustic measuring instrument. 40. A transducer module 45 may define a portion of the instrument's exterior surface, extend from the tool body 30 into the hole, or be drawn behind the tool body 30. The at least one measurement instrument 40 responds 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, projected fluids and combinations thereof.

[0032] The system 100 may include a conventional tower 60 erected on a tower floor 70. A transport device (conveyor 15) which may be rigid or non-rigid may be configured to transport the downhole tool 10 to the drill hole. well 50 close to a volume of interest 80 of an earth formation 85. The conveyor 15 may be a drill string, coiled tubing, a flat cable, an electronic line, a steel cable, etc. The downhole tool 10 can be coupled or combined with additional tools, for example part or all of the information processing system (insert). Thus, depending on the configuration, the tool 10 can be used during drilling and/or after the wellbore 50 has been formed. As described herein, "well" or "wellhole" refers to a single hole that constitutes all or part of a drilled well. Although a land system is shown, the teachings of the present disclosure can also be used in marine or subsea applications. Conveyor 15 may include embedded power and/or data conductors to provide signal and/or power communication between surface and downhole equipment (e.g., a seven-conductor cable). The conveyor 15 may include a downhole assembly may include a drill motor for rotating a drill bit.

[0033] The 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 the (s) ) acoustic measurement instrument(s) 40 and other sensors used in the system 100 and processes these signals in accordance with programmed instructions supplied to the surface control system 65. The surface control system 65 can display the desired parameters and other information on a display/monitor that is used by an operator. The surface control system 65 can further communicate with a downhole control system 20 at a suitable location on the downhole tool 10. The surface control system 65 can process data related to operations and sensor data 40 and may control one or more downhole operations performed by system 100.

[0034] In one embodiment, the electronic components 30 associated with the sensor 40 can 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 can be in the well, on the rig or at a remote location. Additionally, the various components of the hardware environment can be distributed across these locations. Input device 11 can be any data reader or user input device such as data card reader, keyboard, USB port, etc. The information storage means 13 stores the information provided by the detectors. The information storage medium 13 may include any non-transient computer-readable medium for standard computer information storage, such as a USB drive, memory card, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical discs or another commonly used memory storage system known to one of ordinary skill in the art, including Internet-based storage. Information storage means 13 stores a program that, when executed, causes information processor 17 to perform the disclosed method. The information storage medium 13 may also store training information provided by the user, or the training information may be stored on a peripheral information storage medium 19, which may be any standard computer information storage device, such as a USB drive, memory card, hard disk, removable RAM or other memory storage system commonly used by one skilled in the art, including Internet-based storage. Information processor 17 can be any form of computer or math processing hardware, including Internet-based hardware. When the program is loaded from the information storage medium 13 into the memory of the processor 9 (e.g., computer RAM), the program, when executed, causes the information processor 17 to retrieve detector information from the medium. of information storage 13 or peripheral information storage medium 19 and process the information to estimate a parameter of interest. The information processor 17 can be located at the surface or downhole.

[0035] The term “information” as used herein includes any form of information (analog, digital, EM, print, etc.). As used herein, a processor is any information processing device that transmits, receives, manipulates, converts, computes, modulates, transposes, transports, stores or uses information. In various non-limiting aspects of the disclosure, an information processing device includes a computer that executes programmed instructions to perform 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 it may employ logic implemented as field-programmable gate arrays ('FPGAs'), application-specific integrated circuits ('ASICs'), other combinatorial or sequential logic hardware, and so on.

[0036] To perform the measurements during a single trip, the tool can use a high bandwidth transmission to transmit the information acquired by the detectors 20, 30 to the surface for analysis. For example, a communication line for transmitting the acquired information can be an optical fiber, a metal conductor or any other suitable signal conducting medium. It should be realized that the use of a “high bandwidth” communication line can allow surface personnel to monitor and control operations in “near real time.”

[0037] A novelty point of the system illustrated in FIG. 1A is that surface control system 65 and/or 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 can be configured to control the previously described tool and any incorporated sensors and to estimate a parameter of interest according to the methods described herein.

[0038] Aspects of the present disclosure are subject to application in several different embodiments. In some general embodiments, the conveyor 15 is implemented as a tool string of a drilling system and the measurements taken in the well can be characterized as "profiling while drilling" (LWD) or "measuring while drilling" (MWD) operations. ).

[0039] FIG. 1B shows an exemplary embodiment of an MWD system for evaluating a land formation using measurements from an acoustic measurement tool. System 101 includes a conveyor 111 that is shown disposed in a borehole or shaft 50 that penetrates at least one earth formation 195. System 101 also includes a tool 110 configured to take acoustic measurements in the borehole.

[0040] FIG 1B shows a drill string 120 including a downhole assembly (BHA) 190 carried in well 50 as the conveyor. The drilling system 101 includes a conventional turret 111 raised on a platform or floor 112 that 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 pipeline (such as articulated drill pipe 122), having the drill assembly 190 attached at its lower end from the surface to the base 151 of the bottom 50. A drill bit 150, attached to the drill assembly 190, disrupts geological formations when it is rotated to drill hole 50. The drill string 120 is coupled to a drill winch 130 via a kelly joint 121, pivot 128 and line 129 via a pulley. The drill winch 130 is operated to control the weight on the bit (“WOB”). Drill string 120 can be rotated by a top drive (not shown) instead of the main motor and rotary table 114. Alternatively, spiral tubing can be used as tubing 122. A tubing injector 114a can be used to convey the spiral piping having the perforation set fixed at its lower end. The operations of the drill winches 130 and the pipe injector 114a are known in the art and therefore are not described in detail here.

[0041] It is to be understood that the embodiments of the present disclosure are well suited for use in wells having various configurations, including horizontal wells, deviated wells, inclined wells, multilateral wells, and so on. Consequently, the use of directional terms here (eg, up, down, top, bottom, up, down, up, down, hole up, hole down, etc.) refers to the direction of travel along the hole, either towards or away from the surface, with the upward direction being towards the surface and the downward direction being away from the surface.

[0042] A suitable drilling fluid 131 (also referred to as the "mud") from a source 132 thereof, such as a mud deposit, is circulated under pressure through the drill string 120 by a mud pump 134. Drilling fluid 131 passes from the mud pump 134 to the drill string 120 through a surge discharger 136 and fluid line 138. Drilling fluid 131a from the drill pipe discharges at the base of the hole 151 through openings in the bit drilling 150. Return drilling fluid 131b circulates uphole through annular space 127 between drill string 120 and well 50 and returns to mud pit 132 via a return line 135 and drilling 185 which removes drill cuttings and cuttings 186 from return drilling fluid 131b. An S1 sensor on line 138 provides information about fluid flow. A surface torque sensor S2 and a sensor S3 associated with the drill string 120, respectively, provide information on the torque and rotational speed of the drill string 120. The pipe injection speed is determined by the sensor S5, while the sensor S6 provides the hook load of drill string 120.

[0043] The well control system 147 is placed at the upper end of the well 50. The well control system 147 includes a stack of preventer sets (BOP) 115 and a surface choke 149 in communication with the bore ring wellhead 127. The surface choke 149 can control the flow of fluid out of the wellbore 50 to provide a back pressure as needed to control the wellbore.

[0044] In some applications, the drill bit 150 is rotated just by turning the drill pipe 122. However, in many other applications, a downhole motor 155 (mud motor) arranged in the BHA 190 also rotates the bit drill bit 150. The rate of penetration (ROP) for a given BHA depends greatly on the WOB or thrust force on the drill bit 150 and its speed of rotation.

[0045] A surface control unit or controller 140 receives signals from sensors and downhole devices through a sensor 143 placed in the fluid line 138 and signals from sensors S1-S6 and other sensors used in the system 101 and processes these signals in accordance with programmed instructions supplied to the surface control unit 140. The surface control unit 140 displays drilling parameters and other parameters of interest related to the wellbore, formation and drilling operations and other desired information on a display/ monitor 141 which is used by an operator to control drilling operations. The surface control unit 140 may be a computer based unit which may include a processor 142 (such as a microprocessor), a storage device 144 such as solid state memory, tape or hard disk and one or more programs computer files 146 on storage device 144 that are accessible to processor 142 for executing instructions contained in such programs. The surface control unit 140 can further communicate with a remote control unit 148. The surface control unit 140 can process data related to drilling operations, data from sensors and devices on the surface and data received from downhole, and can control one or more downhole and surface device operations. Data can be transmitted in analog or digital format.

[0046] The BHA 190 may include a tool 110 configured to perform acoustic measurements. The BHA 190 may also contain other sensors or formation evaluation devices (also called measurement while drilling (“MWD”) or profiling while drilling (“LWD”) sensors) that determine resistivity, density, porosity, permeability, acoustic properties, nuclear magnetic resonance properties, formation pressures, downhole fluid properties or characteristics, and other desired properties of the formation 195 surrounding the BHA 150. For convenience, all of these sensors are generally denoted herein by the numeral 165. BHA 190 can 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, eddying, stick-slip, weight on bit, fluid flow rate , pressure, temperature, penetration rate, azimuth, tool face, drill bit rotation, etc.

[0047] The BHA 190 may include a guiding apparatus or tool 158 for guiding the drill bit 50 along a desired drill path. In one aspect, the targeting apparatus may include a targeting unit 160 having an array of force-applying elements 161a-161n. The force application elements can be mounted directly on the drill string, or they can be at least partially integrated into the drill motor. In another aspect, the force application elements may be mounted on a sleeve which is rotatable about the central axis of the drill string. The force application elements can be activated using electromechanical, electro-hydraulic or mud-hydraulic actuators. In yet another embodiment, the orienting apparatus may include a orienting unit 158 having a sub-bent and a first orienting device 158a for orienting the sub-bent in the borehole and a second orienting device 158b for maintaining the sub-bent along the shaft. from a selected drilling direction. The targeting unit 158, 160 may include inclinometers and magnetometers close to the drill.

[0048] The drilling system 101 may include sensors, circuits and software and processing algorithms to provide information about desired drilling parameters relating to the BHA, drill string, drill bit and downhole equipment, such as a drill motor drilling, steering unit, impellers, etc. Many current drilling systems, especially for drilling highly offset and horizontal boreholes, use spiral tubing to transport the drill set to the downhole. In such applications, an impeller can be implanted in the drillstring 120 to provide the required force on the drill bit.

[0049] Exemplary sensors for determining drilling parameters include, but are not limited to, drill bit sensors, an RPM sensor, a weight sensor on the bit, sensors for measuring mud motor parameters (for example, stator temperature of mud motor, differential pressure through a mud motor, and fluid flow rate through a mud motor) and sensors to measure acceleration, vibration, swing, radial displacement, snag-slip, torque, shock, vibration, strain , tension, bending moment, drill kickback, axial thrust, friction, backward rotation, BHA bending and radial thrust. Sensors distributed along the drill string can measure physical quantities such as acceleration and deformation of the drill string, internal pressures in the drill string hole, external pressure in the annulus, vibration, temperature, electric and magnetic field strengths within the drill string drilling rig, drill string hole, etc. Suitable systems for making dynamic downhole measurements include COPILOT, a downhole measurement system manufactured by BAKER HUGHES INCORPORATED.

[0050] The drilling system 101 may include one or more downhole processors in a suitable location, such as 193 in the BHA 190. The processor(s) may be a microprocessor using a computer program implemented on a suitable non-transient computer-readable medium that allows the processor to perform control of system 101 and processing of information, such as sensor information. The non-transient computer-readable medium may include one or more ROMs, EPROMs, EAROMs, EEPROMs, flash memories, RAMs, hard disks 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 are taking place. The surface processor 142 can process the measured surface data, along with the data transmitted from the downhole processor, to evaluate the formation.

[0051] The surface processor 142 or the downhole processor 193 can also be configured to control the guidance apparatus 158, the mud pump 134, the drill winch 130, the rotary table 114, the downhole motor well 155, other components of the BHA 190 or other components of the drilling system 101. The surface processor 142 or the downhole processor 193 can be configured to control the sensors described above and to estimate a parameter of interest according to the methods described here.

[0052] The control of these components can be performed using one or more models using methods described below. For example, surface processor 142 or downhole processor 193 can be configured to modify drilling operations i) autonomously upon trigger conditions, ii) in response to operator commands, or iii) combinations thereof. Such modifications could include changing the drilling parameters, the direction of the bit (eg geo-orientation), changing the drilling fluid program, activating well control measures and so on. Control of these devices and the various processes of the drilling system can usually be accomplished completely automatically or through interaction with personnel through 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) can be configured to operate evanescent tool 110 to generate an evanescent wave and measure signals.

[0053] System 101 may include any number of downhole tools for various processes including formation drilling, geo-guidance and formation evaluation (FE) to make electrical measurements as a function of depth and/or time of one or more physical properties in or around a well, including a volume of interest of formation intercepted by the hole. Tool 110 may be included or incorporated as a BHA, drill string component, or other suitable carrier.

[0054] Although a drill string 120 is shown as a transport device for the tool 110, it should be understood that embodiments of the present disclosure may be used in connection with tools transported via rigid transport systems (e.g., articulated tubular or pipe spiral) as well as non-rigid (e.g. steel cable, flat cable, electronic line, etc.). Drilling system 101 may include bottom composition and/or sensors and equipment for implementing embodiments of the present disclosure on either a drill string or a wire rope.

[0055] Mathematical models, lookup tables or other models that represent relationships between signals and parameter values can be used to characterize the formation, the location of the hole or the operations in the formation; optimize one or more operational parameters of a production or development; and so on. The system can perform these actions through notifications, advice and/or smart control. Various types of downhole parameters can be determined using measurements in accordance with the present disclosure and making assessments in accordance with embodiments disclosed herein.

[0056] The U.S. patent U.S. Patent No. 7,035,165 to Tang, which is assigned to the same assignee as the present disclosure and whose contents are incorporated herein by reference, discloses a method in which a plurality of multi-component acoustic measurements are obtained at a plurality of depths and for a plurality of source spacings. -receiver in the profiling tool. An orientation sensor on the profiling tool, such as a magnetometer, can be used to obtain an orientation measurement indicative of an orientation of the profiling tool. Multi-component measurements are rotated to a fixed coordinate system (such as an earth-based system defined relative to magnetic or geographic north) using the orientation measure, providing rotated multi-component measurements. Measurements from multiple rotated components are processed to provide a subsurface image.

[0057] US Patent 8,055,448 B2 to Mathiszik et al., which is co-assigned as the present disclosure and whose contents are incorporated herein by reference, discloses further improvements in MWD acoustic imaging. A downhole acoustic logging tool is used to generate a guided downhole wave that propagates into the formation as a body wave, reflects off an interface and is converted back into a guided borehole wave. Guided waves from holes resulting from body wave reflection are used to image a reflector. US Patent 8,811,114 B2 to Geerits et al., which is co-applicant with the present disclosure and the contents of which are incorporated herein by reference, discloses further improvements in MWD acoustic imaging.

[0058] FIGS. 2A to 2C are schematic diagrams illustrating the operation of embodiments of device including acoustic sensors in accordance with embodiments of the present disclosure. In general device embodiments, a sensor according to the present disclosure can be implemented as a probe and installed in a downhole fluid. This installation can be permanent or temporary and can involve being suspended in a fluid by means of individual or common chain, free floating or being attached to the borehole. Thus, the probe can be stationary or moving after installation.

[0059] Referring to FIG. 2A, the system 200 comprises a plurality of probes 202 suspended in a fluid 90 in a hole 50 by chain 204. An exterior of the probe housing may be immersed in the downhole fluid during installation. In alternative embodiments, probe 202 may be retractable; for example, when in operation, the probe can be inserted or placed in the downhole fluid and then retracted for cleaning or to allow further downhole operations.

[0060] FIG. 2B is a schematic illustration showing VSP measurement acquisition in accordance with the embodiments of the present disclosure. Platform 221 resides on land surface 223. This may be a drilling rig, or it may be a mast platform that transmits a fixed line to a hole 201. Hole 201 penetrates layers 203, 205. Positioned in hole 201 are the seismic sensors designated by 211a, 211b, 211c, 211d and so on. Each of the sensors may be a sensor (e.g., a hydrophone) in accordance with the embodiments of the present disclosure. Data for a single VSP displacement is typically acquired using a single seismic source, such as 225a at the surface (or within a surface body of water). Referring to FIG. 2B, a surface of a body of water can be considered a land surface. An exemplary ray path representing propagation of seismic energy from source 225a to a detector 211d is represented by ray 227a which is reflected from the bottom of layer 205 at boundary 206 and reaches receiver 211d along the ray path represented by 229a.

[0061] In a typical type of VSP operation, data resulting from operating a source at a single position, such as 225a, is recorded at each of the receivers 211a, 211b, 211c, 211d, etc. in the hole. Analysis of the reflected data can provide information about seismic velocities in the subsurface and the configuration of layer boundaries. In a trailing VSP, this process is repeated for source operation at a plurality of source positions, such as 225b, 225c. Acquiring data from a plurality of source positions at a plurality of detectors provides redundant sampling of the subsurface region, making it possible to determine the subsurface velocity based on the travel times of the rays between each of the sources and each of the receivers. . This velocity determination using travel times is called “tomographic inversion” and numerous processing packages are available commercially and as open source software (eg OpenTOAST) that perform this tomographic inversion of seismic travel time data. Processing VSP measurements to characterize formation is a well-developed field. See, for example, US Patent 7,751,279 to Aronstam and US Patent 7,751,279 to Zhao et al., incorporated herein by reference in its entirety.

[0062] FIG. 2C shows simulated geometry from a surface seismic survey. A vertical hole was considered, sources were “reflected” in the hole to simulated receiver locations on the surface 285 a, 285 b, 285 c. Likewise, the ray paths were also reflected to give simulated ray paths on the left side of the hole. In operation, the methods include deploying in a borehole the array of seismic receivers described herein and recording seismic signals in the array of receivers that respond to an activation of a seismic source at a plurality of positions on the earth's surface. For traversal techniques, the method further includes estimates of travel times of seismic waves from the plurality of source positions to the plurality of receivers, vertical propagation velocities of seismic waves in a plurality of intervals and two anisotropy parameters ε and δ related to a normal motion curve of compression waves for the plurality of intervals. The estimated vertical velocities and the estimated range anisotropy parameters can be used to further process the surface seismic data to provide a depth seismic image for interpretation purposes. For a multiazimuth 3D or walking VSP geometry, the method may further include estimates, of travel times of seismic waves from the plurality of source positions around the wellbore to the plurality of receivers, velocities of vertically propagating seismic waves in a plurality of intervals and five parameters of orthorhombic anisotropy ε1, ε1, δ1, δ2 and δ3 related to a normal velocity of displacement of compressional waves for the plurality of intervals. The estimated vertical velocities and estimated anisotropy parameters can be used to further process the surface seismic data to provide a depth seismic image for interpretation purposes. See, for example, Blias US Patent 8,750,074, incorporated herein by reference in its entirety.

Downhole fiber optic hydrophone

[0063] 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 carried in a bore 50. The sensor 300 may include a pressure transducer 302 and an interrogator 304. The pressure transducer 302 comprises a transducer body 312 having a portion (for example, face 322) immersed in the downhole fluid. The transducer body 312 may be mechanically disengaged from the sensor tool body (drill collar, fixed line, etc.) in order to isolate the transducer body 312 from sound transmission from the structure. An acoustic pressure signal propagates through a downhole fluid coupled to the transducer. In some embodiments, some (or all) of the instruments may protrude from the tool body into the hole. Transducer 302 is configured to convert an acoustic pressure signal within a nominal bore pressure incident on the transducer to an alternating voltage in an optical medium (eg, optical fiber 303).

[0064] Fiber 303 includes fiber Bragg gratings ('FBG') 305. These fiber Bragg gratings are a type of Bragg reflector distributed in a fiber optic segment (for example, using pulses from a femtosecond laser ) that reflects light centered on a certain wavelength, for example, 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 (eg, light) that propagates in optical fiber 303, allowing a remaining portion to drift.

[0065] The electromagnetic radiation is provided by a power source 308, such as a light source configured to deliver light to the sensors via the optical fiber. As an example, the power source could be a tunable laser light source that is configured to deliver light with a wavelength that scans a range of wavelengths at a selected rate, but the power source could be any source. tunable light source or wavelength light source covering a range of wavelengths including visible, ultraviolet, and infrared light. As another example, a light emitting diode or a superluminescent diode can be optically coupled to fiber 303 to provide a beam of infrared light. Power source 308 may optionally be incorporated as part of interrogator 304, as shown in FIG. 3A.

[0066] The central wavelength of the reflected spectral portion (“reflected spectrum” or “reflection spectrum”) is sensitive to the physical parameters of the fiber including, in particular, the tension along the fiber axis. Due to the transducer configuration, the tension in the fiber is representative of the pressure. Thus, the central wavelength of the spectrum changes with changes in transducer pressure and is indicative of the acoustic pressure signal at the sensor.

[0067] The optical fiber 303 can pass through the transducer 302 and into the interrogator 304. The interrogator 304 (implemented using, for example, one or more photodetectors, charge-coupled devices, optical-to-electrical converters, or the like) is optically coupled to the fiber 303 and detects electromagnetic signals (eg light) received from the fiber.

[0068] A light coupling or separation mechanism 307, such as an optical circulator or optical fiber splitter, can be used to couple or separate optical signals traveling in opposite directions in the fiber 303, for example, supplying light from the source of light 308 to transducer 302 through fiber 303 and sending light back from transducer fiber 302 to spectral detector 306. Spectral detector 306 generates measurement information indicative of the pressure signal based on electromagnetic signals that respond to partial reflection of electromagnetic energy.

[0069] Sensor 300 may include circuit 310 for making measurements using interrogator 304. Circuit 310 may include a control unit operatively connected to source 308 and spectral detector 306. Circuit 310 may be implemented, at least in part , such as the at least one processor described above with reference to FIG. 1A and 1B or it may be an additional processor or other support circuitry. In some implementations, parts of circuit 310 may be located in the instrument, in other locations in the tool (including, for example, in other subs), or on the surface.

[0070] In operation, the instrument can be controlled by the circuit 310, including the control unit (for example, a processor), which drives the power source 308 while the transducer part (for example, face 322) is submerged in the downhole fluid and receives measurement information (e.g., data) from spectral detector 306.

[0071] The interrogator 304 is thus configured to generate acoustic measurement information that responds to received electromagnetic radiation (eg, the reflected spectrum) transmitted through the medium. Alternatively, the center wavelength can be detected using an optical detector at the opposite end of the fiber detection or the remaining portion of the original spectrum. A time-varying value of the center wavelength can be used to generate a time-varying value of the acoustic pressure signal. Spectral detector 306 can be implemented, for example, using one or more photodetectors that correspond to the desired wavelength.

[0072] FIG. 3B illustrates a sensor including multiple pressure transducers 341, 342, 343 on a single fiber. The fiber section corresponding to each transducer includes a specific Bragg grid. The characteristic wavelength of each of the networks is spaced from that of the remaining networks, such that the signal for a particular transducer can be recovered. A spectral demultiplexer 355, such as a set of additional Bragg gratings on the detector side, splits 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.

[0073] The pressure transducer 302 is configured to convert a high-frequency, low-amplitude acoustic pressure signal within a nominal bore pressure incident on the transducer into an alternating voltage in the optical medium along a medium axis through movement of a bending element while suppressing the conversion of low frequency signals and constant pressure in the optical medium voltage.

high displacement sensor transducer

[0074] FIGS. 4A to 4H illustrate transducers in accordance with embodiments of the present disclosure. Referring to FIG. 4A, transducer 400 includes a transducer body 406 that contains a first reservoir 408 and a second reservoir 410. Pressure transducer 400 comprises an interface 424 between the reservoirs. Body 406 and interface 424 can be fabricated from silicon, glass, crystalline structures, composites, or the like, such as, for example, by bonding wafers, by subtractive fabrication (eg, 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 reservoir fluid communication port between the first reservoir 408 and a second reservoir 410. The aperture is a 404 capillary. Other implementations may use more than one capillary or may use a different type of aperture.

[0075] Interface 424 also includes a flexing element, implemented as flexible membrane 420. Flexible membrane 420 may be made of a polymer bonded to the body (eg, polyvinylidene difluoride ('PVDF')). In other implementations, the bending element may be an additional patch glued in place, or it may be created by subtractive fabrication of the body 406. A fiber optic segment 403 is attached to the membrane that includes an FBG near the attachment point. The fiber can be bonded using an adhesive, solder, solder or splicing process. The optical fiber can cross the membrane at the center in the 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 bending element 422 that responds to the high frequency pressure acoustic signal incident on the transducer.

[0076] The FBG can be written into the fiber using a femtosecond laser. This allows printing of various lattice shapes, modifying the period and lattice depth, and therefore to perceive apodized, pi-shifted and chirped lattice formations. Furthermore, this process can be applied to standard optical fibers, unlike UV light-based methods that require photosensitive fiber cores.

[0077] The acoustic signals in the downhole fluid are incident on the membrane 422. The fluid in the reservoir 408 behind (inside) the membrane 422 undergoes a high ambient pressure from the downhole fluid, but this pressure is equalized through membrane 424 through capillary 404. The response of the interior fluid to the transducer body 406, in the presence of capillary 404, at constant or low frequency pressure, is equalized through the capillary with no appreciable response in (movement of) membrane 420 It can be said that the capillary 404 can therefore filter out the low frequency signal. In contrast, a high frequency signal incident on membrane 422 causes a symmetric response in membrane 420, with the corresponding strain signal generated in the fiber. With high pressures equalized in all fluids, the response in the 420 membrane, and therefore in the fiber, exhibits remarkable fidelity (e.g., on the order of less than 10 percent per MPa of differential pressure, less than 5 percent per MPa of differential pressure, or up to and including 1 percent differential pressure MPa or better). The transducer body 406 may be mechanically disengaged from the sensor tool body (drill collar, fixed line, etc.) in order to isolate the transducer body 406 from sound transmission from the structure.

em que é o comprimento do tubo capilar; é o raio do tubo capilar; é o volume do reservatório atrás do tubo capilar; é a viscosidade dinâmica do fluido; é a densidade do fluido; é a velocidade do som do fluido.[0078] The collective result of these features is that the pressure transducer is configured to mechanically filter low-frequency ambient pressure noise into the fluid using bypass flow of reservoir fluid through the port via pressure equalization. This is achieved by diverting fluid with a cross section configured to compensate by slowly carrying the differential pressure between the two reservoirs. In FIG. 4A, the bypass is performed by introducing the capillary 404 of appropriate diameter and length between the two reservoirs filled with silicon oil for the desired cut-off frequency (f):

where is the length of the capillary tube; is the radius of the capillary tube; is the volume of the reservoir behind the capillary tube; is the dynamic viscosity of the fluid; is the density of the fluid; is the speed of sound of the fluid.

[0079] FIGS. 4B and 4C illustrate another transducer in accordance with embodiments of the present disclosure. FIG. 4B is a side view of transducer 430. FIG. 4C is a top view of interface 444. Transducer 430 includes a transducer body 436 that contains a first reservoir 438 and a second reservoir 440. In some implementations, reservoirs 438 and 440 can be configured such that their respective lengths maxima in a direction normal to the 444 interface are equal (and opposite). This configuration can result in effective compensation of pressure differences that occur at the interface due to quasi-hydrostatic pressure. The transducer body 436 may also be mechanically decoupled from the sensor tool body (drill collar, fixed line, etc.) in order to isolate the transducer body 436 from sound transmission from the structure. 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 for communicating reservoir fluid between the first reservoir 438 and a second reservoir 440. The openings comprise slots 451, 452 on the 444 interface. Other implementations may additionally use a capillary or may use more or less openings of various dimensions.

[0080] The bending element 421 is implemented as a portion of the interface between a first slot 451 of the plurality and a second slot 452 of the plurality forming a bending bar. A fiber optic segment 433 is attached (e.g., using adhesives) to bending member 421 and includes an FBG centered over the fixture. A second interface separates one of the reservoirs 438 and the downhole fluid 90. The second interface comprises a second bending member 432 (e.g., a membrane) that responds to the high frequency acoustic pressure signal incident on the transducer.

em que é o comprimento da fenda; é a altura da fenda; é- é a largura da fenda; é o volume do reservatório atrás da fenda; é a viscosidade dinâmica do fluido; é a densidade do fluido; é a velocidade do som do fluido.[0081] As before, the acoustic signals in the downhole fluid are incident on the outer membrane 452. The low frequency pressure is equalized across the interface through the capillary slits 451 and 452, while avoiding a corresponding appreciable response in the member 421, thus filtering out the low frequency pressure signal and constant pressure. Again, with high pressures equalized across all fluids, the response in the 421 member and therefore the fiber is greatly improved from traditional techniques. The bypass is performed by setting slots 451 and 452 having appropriate dimensions between the two silicon oil filled reservoirs to the desired cutoff frequency (f):

where is the length of the slit; is the height of the slit; is- is the width of the slit; is the volume of the reservoir behind the slit; is the dynamic viscosity of the fluid; is the density of the fluid; is the speed of sound of the fluid.

[0082] FIGS. 4D to 4H illustrate another transducer in accordance with embodiments of the present disclosure. FIG. 4D is a side view of transducer 470. FIG. 4E is a second side view of transducer 470 perpendicular to the first view. Transducer 470 includes a transducer body 476 that contains 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 the openings 481 and 482 that allow communication of reservoir fluid between the first reservoir 478 and the second reservoir 480. A second interface comprises a second bending member 472 (e.g., a membrane) that responds to the high frequency pressure acoustic signal incident on the transducer. FIG. 4F is a top view of the interface. A fiber optic segment 483 is attached (e.g., using adhesives) to bending member 491 and includes an FBG 493 centered over the fixture, as before.

[0083] Transducer 470 represents a transducer configured for vibration compensation. As previously with respect to FIGS. 4B and 4C, the maximum extent of the reservoirs 478 and 480 relative to the interface 474 in a direction normal to the interface 474 can be equal, and this configuration can result in effective compensation for pressure differences that occur across the interface due to near- hydrostatic. In order to obtain the same effect in all directions, the transducer 470 can be configured in such a way that the upper and lower reservoirs 478 and 480 can satisfy the same condition in two perpendicular directions and, respectively, perpendicular 494 and 495.

[0084] FIGS. 4G and 4H illustrate a transducer construction 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 symmetrical in two dimensions. Lower reservoir member 498 is configured to receive upper reservoir member 497. By rotating upper reservoir member 497 90 degrees and coupling the reservoir members as an interlocking assembly, transducer 470 can be constructed. The reservoir members are also configured such that the upper reservoir member 497 is substantially symmetrical to the lower reservoir member 498. The upper reservoir member 497 can have substantially identical dimensions to the lower reservoir member 498, but different orientations when aligned to the assembly. The fluid volume of the reservoirs is substantially the same. Thus, the reservoirs have a shape and their orientation which results in the suppression of any sign of quasi-hydrostatic pressure induced by acceleration. This is achieved by ensuring that the pressure on the bending member is identical in both reservoirs.

[0085] FIGS. 5A and 5B illustrate transducer components in accordance with embodiments of the present disclosure. Transducer 500 includes a glass plate 544, which acts as an interface grid in a similar manner 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 bending member 521. The bending member 521 is implemented as an interface portion between a first slot 551 of the plurality and a second slot 552 of the plurality that forms a bending bar. An optical fiber segment 533 is attached (e.g., using adhesives) to the bending member 521. The bending member 550 supports the bending member 521. The bending member includes a notch 554 in which the 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 maximum elastic deformation within the fiber from the leverage generated from the bending element at the end of the notch. The wedge profile of the bending element results in reduced mass and thus increases the fundamental frequency over other embodiments (e.g. approaching 10 kHz or more).

[0086] FIG. 6 illustrates another transducer in accordance with the embodiments of the present disclosure. The transducer can be implemented with a reservoir filled with a swelling fluid. The dilating fluid can be configured to act, responsive to the high frequency pressure acoustic signal, like a solid transmitting the high frequency pressure acoustic signal to the bending member; Responsive to ambient pressure noise, the swelling fluid can be configured to act as a liquid preventing the transmission of ambient pressure noise to the bending member.

[0087] The transducer 600 includes a transducer body 606 containing a reservoir 608. The bending elements 622 are implemented as a plurality of biasing members 621 (e.g., springs) within the reservoir 608 that bias a plurality of impact members waveforms 634 (e.g., planar disks) which are connected with an optical fiber segment 633 (which extends through body 606). An FBG 603 is centered between the disks 634. The optical fiber can pass through (and be connected to) each disk 634 at the center in a normal direction. An interface 607 separates one of the reservoir 608 and the downhole fluid 90. The interface comprises an outer membrane 652 which responds to the high frequency pressure acoustic signal incident on the transducer.

[0088] Reservoir 608 is filled with an expansion fluid. The dilating fluid is configured to act, responsive to the high frequency pressure acoustic signal, like a solid transmitting the high frequency pressure acoustic signal to the bending member; responsive to ambient pressure noise or constant pressure, however, the dilating fluid is configured to act like a liquid thus preventing the transmission of ambient pressure noise to the bending member.

[0089] As before, the acoustic signals in the downhole fluid are incident on the outer membrane 652. Responsive to the high frequency acoustic signals passed to the reservoir 608 by the membrane 652, the swelling fluid acts as a solid transmitting the signal to the impact elements 634, which relieves the stress on the fiber 633. Conversely, low frequency or constant pressure are absorbed into the fluid in liquid mode, resulting in the suppression of these signals.

[0090] The transducers described above, together with optical fibers and FBGs, constitute sensors that are sensitive to acoustically induced dynamic pressure variations, but insensitive to constant and slow variable pressures. Thus, the foregoing transducer embodiments 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 compatible with the nominal downhole environment without decreasing sensitivity to acoustic signals.

[0091] FIG. 7A shows a flowchart 700 illustrating methods for performing well logging in a borehole intersecting an earth formation in accordance with embodiments of the present disclosure. At optional step 710, an acoustic sensor according to the present disclosure is positioned in the hole. For example, an acoustic well logging tool can be transported in a hole using a conveyor. The hole can be filled with downhole fluid, such as, for example, drilling fluid. In other examples, a sensor probe can be installed in the formation. See, for example, US Patent 7,201,221 to Tubel et al, which is commonly owned and is incorporated herein by reference in its entirety.

[0092] Optional step 720 of 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 on the surface and generating acoustic wave data in at least one borehole of the sensor 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 transmitted acoustic signals.

[0093] 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 can include estimating from the acoustic data the distance to a boundary, an immersion, a boundary location in the formation, and so on. Optional step 740 comprises transmitting training information into the interior. Optional step 750 comprises performing additional operations on the formation depending on the formation information.

[0094] FIG. 7B shows a flowchart 760 illustrating methods for obtaining acoustic data. Step 770 comprises using a pressure transducer comprising a bending member connected to an acoustic means to convert a low amplitude high frequency acoustic pressure signal at a nominal bore pressure incident on the pressure transducer to an alternating voltage on the pressure transducer. acoustic medium along an axis of the acoustic medium through movement of the bending member. This can be done by decreasing a pressure offset due to the nominal hole pressure.

[0095] Step 780 comprises using a detector to generate acoustic measurement information that responds to received electromagnetic radiation transmitted through the medium along the axis. The at least one optical property of the medium that responds to the alternating voltage in the medium, in such a way that the electromagnetic radiation received by the detector represents the acoustic signal.

[0096] Optional methods may include estimating a formation parameter of interest and using the parameter of interest to estimate a characteristic of a formation or to conduct other operations. Parameter estimation 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) a deconvolution technique, and so on. Reference information accessible to the processor may also be used.

[0097] The modalities of the method may include performing additional operations on the earth formation, depending on the formation information, the estimated properties of the reflector(s) or the models created using these. Additional operations may include at least one of: i) geo-orientation; ii) drill additional holes in the formation; iii) carry out additional measurements in the formation; iv) estimating additional training parameters; v) install equipment in the hole; vi) evaluate training; vii) optimize current or future development in training or similar training; viii) optimize current or future exploration in the formation or similar formation; ix) drilling the hole; and x) producing one or more hydrocarbons from the formation to the formation.

[0098] The estimated parameters of interest can be stored (registered) as information or represented visually on a display. Parameters of interest can be passed before or after storage or display. For example, information can 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 a land formation using the estimated parameter of interest, such as, for example, associating estimated parameter values with parts of the volume of interest to which they correspond or representing the boundaries and training in a global coordinate system. The land formation model generated and maintained in the disclosure aspects can be implemented as a representation of the land formation stored as information. Information (eg, data) may also be transmitted, stored on a non-transient machine-readable medium, and/or executed (eg, represented visually) on a display.

[0099] The processing of measurements by a processor can occur in the tool, on the surface or in a remote location. Data acquisition can be controlled at least in part by electronics. Implicit in controlling and processing the data is the use of a computer program on a suitable non-transient machine-readable medium that allows the processors to perform control and processing. Non-transient machine-readable media may include ROMs, EPROMs, EEPROMs, flash memories and optical discs. The term processor is intended to include devices such as a field-programmable gate array (FPGA).

[00100] The term “transport device” as used above means any device, device component, combination of devices, means and/or element that can be used to transport, house, support or otherwise facilitate the use of another device, device component, combination of devices, means and/or element. Exemplary non-limiting conveying devices include spiral tube type drill strings, swivel tube type drill strings, and any combination or portion thereof. Other examples of conveying devices include casing tubes, wire ropes, wire rope rigs, smooth cable rigs, drop shots, downhole subs, BHA's, drill string inserts, modules, internal housings and portions of their substrate, self-propelled tractors. As used previously, the term “sub” refers to any structure that is configured to partially enclose, fully enclose, house or support a device. The term “information”, as used above, includes any form of information (Analog, Digital, EM, Print, etc.). The term "processor" or "information processing device" herein includes, but is not limited to, any device that transmits, receives, manipulates, converts, calculates, modulates, transposes, transports, stores or otherwise uses 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 it 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 can be configured to perform one or more methods as described herein, and the processor configuration can include operative connection to resident memory and peripherals to execute programmed instructions.

[00101] As used herein, the term “fluid” and “fluids” refers to one or more gases, one or more liquids and mixtures thereof. A "downhole fluid", as used herein, includes any gas, liquid, solid fluid and other materials with a fluid property and related to the recovery of hydrocarbons. A downhole fluid can be natural or artificial and can be transported into the well or can 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, spray fluids, oils and solvents used in conjunction with downhole tools, water, brine, and combinations of the same. An "engineered fluid" can be used here to mean a man-made fluid formulated for a particular purpose. The term “geo-orientation” can refer to changing the direction of the drill, stopping drill progression, or continuing to advance the drill.

[00102] It is evident that the values of slowness and speed can be used interchangeably in the techniques disclosed herein. The slowness and speed parameters are inversely related and the measurement of one or the other can be converted to the other by simple mathematical relationships, which are well known in the art. Thus, the term "slowness", as used here, can refer to slowness as traditionally understood, as well as other parametric equivalents.

[00103] The term vertical seismic profile ('VSP') as used herein shall mean any zero displacement VSP, drift VSP, walking VSP, overhead pass VSP, salt proximity VSP, noise and shear wave VSP drilling equipment or seismic VSP while drilling. Acoustic signal means any acoustically measured or processed signal, including seismic signals. The terms "rapid variation" or "high frequency", as used herein, refer to frequency characteristics that correspond to typical acoustic signals used for downhole measurement applications. The terms "slowly varying" or "low frequency" as used herein refer to the frequency characteristics that correspond to acoustic signals below a level representing the desired acoustic measurements and can be represented by pressure waves below a frequency of cut as 10 kHz, 1 kHz, 100 Hz, 10 Hz or below. Ambient pressure noise should be understood to refer to unsigned pressure variations, which are endemic to downhole applications, including low frequency pressures such as tool vibration. Mechanical filtration ambient pressure noise can therefore suppress tool vibration from ambient noise such as pump noise. Tool vibration can have a characteristic frequency of 80 to 500 Hz, compared to an acoustic signal of 1kHz or more.

[00104] Although the foregoing disclosure refers to embodiments of one mode of the disclosure, various modifications will be apparent to those skilled in the art. All variations are intended to be adopted by the prior disclosure.

Claims (14)

1. Apparatus for use in a borehole, comprising: an acoustic sensor (300) including: a pressure transducer (302, 400) comprising a bending element (420) connected to an optical means (433), the transducer (302, 400) configured to convert a low amplitude, high frequency acoustic pressure signal within a nominal bore pressure incident on the transducer (302, 400) to an alternating deformation in the optical medium (433) along an axis of the optical medium ( 433) through movement of the bending member (420) while suppressing the conversion of low frequency and constant pressure signals into voltage from the optical medium (433), the acoustic pressure signal propagated through a downhole fluid (90) coupled to the transducer (302, 400); and a detector (304) configured to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium (433) along the axis, the at least one optical property of the medium (433) being responsive to alternating voltage in the medium (433) ), in such a way that the electromagnetic radiation received by the detector (304) represents the acoustic signal, characterized in that the pressure transducer (302, 400) comprises an interface (424) between reservoirs (408, 410), each reservoir (408, 410) containing a same reservoir fluid, the interface (424) comprising at least one opening (404) providing reservoir fluid communication between the reservoirs (408, 410) and the bending member (420) connected to interface (424). 2. Apparatus according to claim 1, characterized in that the pressure transducer (302, 400) is configured to mechanically filter low-frequency ambient pressure noise in fluid. 3. Apparatus according to claim 1, characterized in that the at least one opening (404) and the reservoirs (408, 410) can be configured to mechanically filter ambient pressure noise fluid using the fluid bypass flow from the reservoir through the opening (404) via pressure equalization. Apparatus according to claim 1, characterized in that the bending member (420) comprises at least one of: i) a membrane (420); and ii) a bending bar (421). Apparatus according to claim 4, characterized in that the at least one opening (404) comprises at least one of: i) a slot in the bending member (451, 452); and ii) a capillary tube (404). 6. Apparatus according to claim 5, characterized in that the at least one opening (404) comprises a plurality of slots and the bending member (420) comprises a portion of the interface between a first slot (451) of the plurality and a second slot (452) of the plurality. 7. Apparatus according to claim 1, characterized in that the pressure transducer (302, 400) comprises a second interface between one of the reservoirs (408) and the downhole fluid (90), the second interface comprising a second bending member (422) responsive to the high frequency acoustic pressure signal incident on the transducer (302, 400). 8. Apparatus according to claim 1, characterized in that a first reservoir of reservoirs is defined by a first reservoir member (497) and a second reservoir of reservoirs is defined by a second reservoir member (498) and the first reservoir (497) is received by the second reservoir member (498), and wherein the dimensions and orientations of the reservoirs are configured to suppress acceleration-induced quasi-hydrostatic pressure signals, producing a pressure on the bending member (420) at the first reservoir equal to another pressure in the bending member (420) in the second reservoir. 9. Apparatus according to claim 8, characterized in that every plane normal to a line that intersects the center of gravity of the combined volumes of fluid in the reservoir intersects: i) both the first reservoir and the second reservoir or ii) neither the first reservoir nor the second reservoir. 10. Apparatus according to claim 1, characterized in that the transducer (302, 400) comprises a bending element (550) that supports the bending member (420) and is configured to amplify the movement of the bending member (420). 11. Apparatus according to claim 10, characterized in that the means (433) comprises fiber Bragg gratings (503) positioned relative to the bending element (550) close to a location of maximum displacement of the means (433 ). 12. Apparatus according to claim 1, characterized in that the transducer (302, 400) comprises a reservoir (608) filled with an expansion fluid, the expansion fluid configured to act responsive to the acoustic pressure signal of high frequency, such as a solid transmitting the high frequency pressure acoustic signal to the bending member (420) and the expanding fluid configured to act, responsive to ambient pressure noise, such as a liquid preventing the transmission of pressure noise environment for the bending member (420). 13. Apparatus according to claim 1, characterized in that the apparatus comprises a portion of a drill string and the ambient pressure noise comprises vibration of the drill string. 14. A method for acoustic detection in a hole, the method comprising: using a pressure transducer (302, 400) comprising a bending member (420) connected to an optical means (433) to convert an acoustic pressure signal from low amplitude and high frequency within a nominal bore pressure incident on the pressure transducer (302, 400) for an alternating deformation of the optical medium (433) along an axis of the optical medium (433) via movement of the bending member ( 420) while suppressing the conversion of the low frequency and constant pressure signals into voltage from the optical medium (433), the acoustic pressure signal propagated through a downhole fluid (90) coupled to the transducer (302, 400); and using a detector (304) to generate acoustic measurement information responsive to received electromagnetic radiation transmitted through the medium (433) along the axis, at least one optical property of the medium (433) being responsive to alternating voltage in the medium (433) , such that the electromagnetic radiation received by the detector means (304) represents the acoustic signal, characterized in that the pressure transducer (302, 400) comprises an interface (424) between reservoirs (408, 410), each reservoir (408 , 410) containing a same reservoir fluid, the interface (424) comprising at least one opening (404) providing reservoir fluid communication between the reservoirs (408, 410) and the bending member (420) connected to the interface ( 424).

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