WO2014110332A1 - Downhole apparatus with extendable digitized sensor device - Google Patents

Downhole apparatus with extendable digitized sensor device Download PDF

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Publication number
WO2014110332A1
WO2014110332A1 PCT/US2014/010988 US2014010988W WO2014110332A1 WO 2014110332 A1 WO2014110332 A1 WO 2014110332A1 US 2014010988 W US2014010988 W US 2014010988W WO 2014110332 A1 WO2014110332 A1 WO 2014110332A1
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WO
WIPO (PCT)
Prior art keywords
sensor devices
measurements
operable
digital signal
downhole tool
Prior art date
Application number
PCT/US2014/010988
Other languages
French (fr)
Inventor
Patrick Vessereau
Original Assignee
Services Petroliers Schlumberger
Schlumberger Technology B.V.
Schlumberger Holdings Limited
Schlumberger Canada Limited
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Services Petroliers Schlumberger, Schlumberger Technology B.V., Schlumberger Holdings Limited, Schlumberger Canada Limited, Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Services Petroliers Schlumberger
Priority to US14/759,195 priority Critical patent/US20150354338A1/en
Publication of WO2014110332A1 publication Critical patent/WO2014110332A1/en

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/20—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with propagation of electric current
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/002—Survey of boreholes or wells by visual inspection
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling

Definitions

  • a resistivity or similar downhole tool may inject an electrical current into a formation via an injection electrode, and the current may return to the downhole tool from the formation via a return electrode.
  • One or both of the injection and return electrodes may be operable to measure current.
  • the resistivity tool may be utilized in the determination of impedance, resistivity, and/or other characteristic of the formation, where such determination may utilize differences between the injected and returning currents measured by the downhole tool.
  • different types and/or regions of geological formations have different resistivity, impedance, and/or other electrical characteristics, such that their determination may provide an indication of the composition and/or other properties of the geological formation.
  • Downhole tools may have various configurations of measuring electrodes depending on the parameters) to be measured and/or conditions of the wellbore (e.g., type, size, and/or environment in the wellbore).
  • Some downhole tools may include intricate electronics and complex circuitry, and may not be operable in high-pressure environments (e.g., high hydrostatic pressure within a wellbore). Such environments may also contribute to systematic and thermal noise, which may affect the quality of measurements being obtained by the downhole tool and/or the integrity of the downhole tool itself.
  • the present disclosure introduces an apparatus comprising a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation.
  • the downhole tool may include a plurality of sensor devices each extendable from a body of the downhole tool by a corresponding pair of arms.
  • Each of the plurality of sensor devices may comprise a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation, as well as circuitry operable to digitize the plurality of obtained measurements and generate a digital signal corresponding to the characteristic of the
  • the present disclosure also introduces a method comprising operating each of a plurality of sensor devices of a downhole tool within a wellbore extending into a subterranean formation to obtain a plurality of measurements pertaining to the subterranean formation.
  • Each of the plurality of sensor devices is operated to digitize the plurality of measurements obtained by that sensor device, generate a digital signal based on the plurality of measurements obtained and digitized by that sensor device, and transmit the generated digital signal out of that sensor device.
  • the present disclosure also introduces an apparatus comprising a downhole tool conveyable within a wellbore extending into a subterranean formation.
  • the downhole tool comprises a body containing a first electronic component, as well as a plurality of sensor devices each connected to the first electronic component by no more than one electrical conductor.
  • Each of the plurality of sensor devices includes a plurality of electrodes, collectively operable to acquire a plurality of measurements pertaining to the formation, and a plurality of second electronic components, collectively operable to digitize the acquired plurality of measurements, generate a digital signal based on the digitized acquired plurality of measurements, and transmit the generated digital signal to the first electronic component by the corresponding one electrical conductor.
  • FIG. 1 is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.
  • FIG. 2 is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.
  • FIG. 3 is a schematic view of a portion of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.
  • FIG. 4 is a schematic view of a portion of the apparatus shown in FIG. 3 according to one or more aspects of the present disclosure.
  • FIG. 5 is a schematic view of a portion of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.
  • first and second features are formed in direct contact
  • additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
  • FIG. 1 is a schematic view of a downhole system 10 having a cable head 1 1 connected at its lower end to a logging tool 12.
  • An upper end of the cable head 11 is secured to a conveyance 14, such as may be or comprise a wireline, slickline, and/or various types of tubing.
  • the conveyance 14 extends to the surface 16 of a wellbore 18 and is operable to position the cable head 11 and one or more logging tools, such as logging tool 12, with respect to an area where formations and formation parameters may be determined and/or recorded during logging operations.
  • the wellbore 18 is depicted in FIG. 1 as being substantially vertical, but it may also be highly deviated or even horizontal.
  • data may be transmitted from the logging tool 12 to the conveyance 14 through the cable head 1 1.
  • the data may be transmitted to a data-transmission and acquisition system 20 at the surface 16.
  • FIG. 1 depicts the conveyance 14 as a wireline cable
  • the downhole system 10 of the present disclosure may include drilling or logging systems, such as measurement-while- drilling (MWD) systems, logging-while-drilling (LWD) systems, wireline systems, coiled tubing systems, testing systems, completions systems, productions systems, or combinations thereof.
  • the logging tool 12 may be or comprise one or more known and/or future- developed downhole tools operable in the downhole system 10.
  • the logging tool 12 may be or comprise a downhole imaging tool operable to obtain an image of the formation F surrounding the wellbore 18, such as by obtaining resistivity or micro-resistivity measurements.
  • Such downhole imaging tool may measure the resistivity of the formation F by injecting a current into the surrounding formation F using an injection electrode. The current may return to the tool from the surrounding formation F via a return electrode.
  • One or both of the injection electrode and the return electrode may be or represent a current-measuring electrode through which the injected and returning currents may be measured. By comparing the injected and returning currents, the resistivity and/or impedance of the surrounding formation F may be determined. The measured resistivity and/or impedance may subsequently be utilized to obtain an image of the formation F surrounding the wellbore 18.
  • the logging tool 12 may comprise one or more extendable arms each carrying one or more sensor devices. During logging operations, the one or more extendable arms may be extended until the sensor device is placed against the wall of the wellbore 18, at which point measurements are made utilizing one or more sensors of the one or more sensor devices. For example, multiple extendable arms may extend multiple sensor devices against a portion of the circumference of the wellbore 18. The logging tool 12 may be moved along the wellbore 18 such that the one or more sensor devices contacting the wall of the wellbore 18 are disposed across the wall of the wellbore 18 and multiple measurements may be obtained along a length of the wellbore 18.
  • FIG. 2 is a schematic view of an example implementation of at least a portion of the logging tool 12 shown in FIG. 1 and/or another downhole tool according to one or more aspects of the present disclosure.
  • the logging tool 12 is depicted in FIG. 2 as having eight pairs of arms 1 10. Each pair of arms 1 10 is operable to extend a corresponding sensor device 120 away from a body 130 of the logging tool 12.
  • Each sensor device 120 may be, comprise, or resemble a device commonly referred to in the art as a "sensor pad,” except that one or more aspects introduced in the present disclosure further characterize each sensor device 120.
  • the arms 1 10 are grouped in an upper group 140 and a lower group 150.
  • the upper and lower groups 140 and 150 each include four pairs of arms 1 10 and four sensor devices 120.
  • the arms 1 10 of the upper group 140 may slide within channels 145 recessed within the body 130, and the arms 1 10 of the lower group 150 may slide within channels 155 recessed within the body 130.
  • the relative clocking of the upper and lower groups 140 and 150 around the longitudinal axis 160 of the logging tool 12 may be substantially aligned or, as shown in FIG. 2, offset by about 45 degrees. However, other values for the angular offset of the upper and lower groups 140 and 150 are also within the scope of the present disclosure.
  • the logging tool 12 may also comprise one or more centralizers and/or other standoffs 170, such as may be positioned on opposing ends of the logging tool 12 and/or otherwise on opposing sides of the upper and lower groups 140 and 150, collectively.
  • the one or more standoffs 170 may each comprise one or more blades 180 extending radially from the body 130 of the logging tool 12.
  • the logging tool 12 includes two standoffs 170 each comprising two blades 180 extending radially from the body 130 in substantially opposite directions.
  • the logging tool 12 may comprise more or less than two standoffs 170, each having more or less than two blades 180, including in shapes and/or arrangements other than as shown in FIG. 2.
  • the sensor devices 120 are operable in the relatively high hydrostatic pressure environment of the wellbore. Accordingly, electronic components in the sensor devices 120 may also be subject to the affects of operating in such high hydrostatic pressure environments. Thus, for example, the sensor devices 120 may include functional electronic components for acquiring, processing, and transmitting measurements associated with the downhole formation while positioned within a high hydrostatic pressure environment of the wellbore. Consequently, the logging tool 12 may be characterized by a reduced size and/or increased level of integration relative to similar logging tools not operable within high hydrostatic pressure environments.
  • a number of connections, wires, and/or processes of the logging tool 12 that previously were analog-based, including those supporting data acquisition and signal processing, may be implemented and/or performed digitally in the sensor device 120.
  • one or more of the signals transmitted from the sensor device 120 may be or comprise one or more digitized signals.
  • the transmission of such digital signals from the sensor devices 120 may be directed towards electronics 190 housed within the body 130 of the logging tool 120 via one or more electrical wires and/or other transmission means indicated generally in FIG. 2 by reference numeral 195.
  • FIG. 3 is a schematic view of an example implementation of one of the sensor devices 120 shown in FIG. 2.
  • the sensor device 120 includes a plurality of measuring electrodes 210, a first source electrode 220, a second source electrode 222, and a third source electrode 224.
  • the source electrodes 220, 222, and 224 may be electrically isolated from each other by an insulator 230, and the measuring electrodes 210 may similarly be electrically isolated from the source electrode 224 by an insulator material (not shown).
  • the sensor device 120 also includes various structural components, such as end caps 240 and one or more underlying substrates, mandrels, frames, housings, and the like (not shown), as well as circuitry 250 supporting data acquisition, processing, and transmission of a resulting digital signal, such as to the electronics 190 of the logging tool 12 shown in FIG. 2.
  • the measuring electrodes 210 may measure current flow through the formation between the source electrodes, whether between the source electrodes 220 and 224, between the source electrodes 220 and 222, between the source electrodes 222 and 224, or a combination thereof. Consequently, the measuring electrodes 210 may permit an increased measurement density. However, acquiring, processing, and transmitting signals from a potentially large number of the measuring electrodes 210 may involve complex circuitry within a particular sensor device 120, which previously entailed a large number of wires and/or other conductive means to, for example, transmit analog signals from each measuring electrode 210 within and/or out of the sensor device 120.
  • FIG. 4 is a schematic diagram of an example implementation of the circuitry 250 shown in FIG. 3.
  • Data acquired from one or more of the measuring electrodes 210 may be processed in the circuitry 250 contained within each sensor device 120, including undergoing digitization.
  • the digitization may utilize an analog component and/or circuit 310 for measurement signal shaping and gain control.
  • Various techniques may be utilized to digitize the measured signal, perhaps utilizing a clock reference 320.
  • the circuitry 250 may include one or more electronic components 330 individually or collectively operable to digitize measured data received directly from one or more of the measuring electrodes 210, and/or to digitize analog data received via the analog component and/or circuit 310.
  • the circuitry 250 may also include one or more electronic components 340 individually or collectively operable to process the resulting digitized signal.
  • the processed digital signal may then be transmitted out of the sensor device 120 via operation of one or more transmission components 350. Such transmission may be via the one or more electrical wires and/or other transmission means indicated generally in FIG. 2 by reference numeral 195.
  • the transmission means 195 may comprise a single wire bus for each sensor device 120.
  • each sensor device 120 may be reduced, because a single transmission wire bus (or a single instance of another type of transmission channel) may be utilized to transmit data from the measuring electrodes 210 collectively instead of utilizing one connection for each measuring electrode 210.
  • the circuitry 250 may comprise other electronic components supporting the above- described operation.
  • the circuitry 250 may comprise one or more power supplies 360 supplying power to one or more ofthe electronic components 310, 320, 330, 340, and 350.
  • the one or more power supplies 360 may also supply power to one or more of the measurement electrodes 210, one or more of the source electrodes 220, 222, and 224, and/or other components of the sensor device 120.
  • FIG. 5 is a schematic diagram of at least a portion of the electronics 190 ofthe logging tool 12 shown in FIG. 2. Among other aspects, FIG. 5 illustrates an example implementation for transmitting a digitized signal representing data from multiple sensor devices 120 of the logging tool 12.
  • the example implementation depicted in FIG. 5 may represent the transmission of digital signals from multiple sensor devices 120 to a control system 410.
  • the control system 410 may comprise at least a portion of the electronics 190 shown in FIG. 2.
  • the electronics 190 shown in FIG. 2 may also or instead comprise at least a portion ofthe control system 410 shown in FIG. 5.
  • the control system 410 may process digital signals received from each sensor device 120, such as via a single bus or other transmission means 195 corresponding to each sensor device 120.
  • the control system 410 may be further operable to transmit a signal indicative of the outputs from multiple ones ofthe sensor devices 120. Such transmission may include to destinations outside of the logging tool 12, and perhaps destinations outside of a downhole system (such as the downhole system 10 shown in FIG. 1) comprising and/or otherwise utilizing the logging tool 12.
  • an apparatus comprising: a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation, the downhole tool comprising a plurality of sensor devices each extendable from a body of the downhole tool by a
  • each of the plurality of sensor devices comprises: a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation; and circuitry operable to digitize the plurality of obtained measurements and generate a digital signal corresponding to the characteristic of the subterranean formation.
  • each sensor device may be further operable to transmit the digital signal out of the sensor device.
  • each sensor device may comprise a clock reference utilized in the digitization of the plurality of obtained measurements.
  • the circuitry of each sensor device may comprise an analog circuit operable to process the plurality of obtained measurements.
  • each sensor device may comprise a processor operable to process the digital signal.
  • each sensor device may comprise a processor operable to process the plurality of digitized obtained measurements.
  • each sensor device may comprise a power source operable to supply power for at least one of: digitizing the plurality of obtained measurements; processing the digital signal; and transmitting the digital signal out of the sensor device.
  • the downhole tool may further comprise a controller operable to process multiple digital signals each transmitted from a corresponding one of the sensor devices.
  • the controller may be further operable to transmit a combined digital signal out of the downhole tool, wherein the combined digital signal is based on the multiple digital signals each transmitted from a corresponding one of the sensor devices.
  • the downhole tool may be or comprise a downhole imaging tool.
  • the downhole imaging tool may comprise the plurality of sensor devices, and the plurality of measuring electrodes of each of the plurality of sensor devices may be operable to measure a current from a current path extending through the subterranean formation from at least one of the plurality of source electrodes.
  • the present disclosure also introduces a method comprising: operating each of a plurality of sensor devices of a downhole tool within a wellbore extending into a subterranean formation to obtain a plurality of measurements pertaining to the subterranean formation;
  • each of the plurality of sensor devices to digitize the plurality of measurements obtained by that sensor device; operating each of the plurality of sensor devices to generate a digital signal based on the plurality of measurements obtained and digitized by that sensor device; and operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
  • Operating each of the plurality of sensor devices to digitize the plurality of measurements obtained by that sensor device may utilize a clock reference applied to a measured analog signal corresponding to the plurality of obtained measurements.
  • the method may further comprise operating each of the plurality of sensor devices to process the generated digital signal within that sensor device before operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
  • Operating each of the plurality of sensor devices to digitize the plurality of obtained measurements may comprise digitizing an analog measurement from each of a plurality of measuring electrodes disposed on that sensor device.
  • Operating each of the plurality of sensor devices to transmit the generated digital signal may comprise transmitting a digitized signal representative of the analog measurements from each of the plurality of measuring electrodes.
  • the present disclosure also introduces an apparatus comprising: a downhole tool conveyable within a wellbore extending into a subterranean formation, wherein the downhole tool comprises: a body containing a first electronic component; and a plurality of sensor devices each connected to the first electronic component by no more than one electrical conductor, wherein each of the plurality of sensor devices comprises: a plurality of electrodes collectively operable to acquire a plurality of measurements pertaining to the formation; and a plurality of second electronic components collectively operable to: digitize the acquired plurality of measurements; generate a digital signal based on the digitized acquired plurality of
  • the plurality of electrodes may comprise: a plurality of source electrodes each operable to inject electrical current into the formation; and a plurality of measuring electrodes collectively operable to acquire the plurality of measurements, wherein the plurality of measurements may pertain to electrical current exiting the formation.
  • the apparatus may further comprise a control system comprising the first electronic component and operable to transmit the generated digital signal received from each of the plurality of sensor devices to outside the downhole tool.
  • the plurality of sensor devices may comprise a first group of sensor devices and a second group of sensor devices, wherein the first group of sensor devices may be angularly offset about a longitudinal axis of the downhole tool relative to the second group of sensor devices.

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Abstract

An apparatus comprising a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation. The downhole tool may include a plurality of sensor devices each extendable from a body of the downhole tool by a corresponding pair of arms. Each of the plurality of sensor devices may comprise a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation, as well as circuitry operable to digitize the plurality of obtained measurements and generate a digital signal corresponding to the characteristic of the subterranean formation

Description

Downhole Apparatus with Extendable Digitized Sensor Device
Cross-Reference to Related Applications
[0001] This application claims the benefit of U.S. Provisional Application No. 61/750,873, entitled "Digitizing in a Pad of a Downhole Tool Exposed to Hydrostatic Pressure," filed January 10, 2013, Attorney Docket No. IS 13.3000, the entire disclosure of which is hereby incorporated herein by reference.
Background of the Disclosure
[0002] Various downhole tools exist for determining properties of geological formations surrounding wells. For example, a resistivity or similar downhole tool may inject an electrical current into a formation via an injection electrode, and the current may return to the downhole tool from the formation via a return electrode. One or both of the injection and return electrodes may be operable to measure current. The resistivity tool may be utilized in the determination of impedance, resistivity, and/or other characteristic of the formation, where such determination may utilize differences between the injected and returning currents measured by the downhole tool. For example, different types and/or regions of geological formations have different resistivity, impedance, and/or other electrical characteristics, such that their determination may provide an indication of the composition and/or other properties of the geological formation.
[0003] Downhole tools may have various configurations of measuring electrodes depending on the parameters) to be measured and/or conditions of the wellbore (e.g., type, size, and/or environment in the wellbore). Some downhole tools may include intricate electronics and complex circuitry, and may not be operable in high-pressure environments (e.g., high hydrostatic pressure within a wellbore). Such environments may also contribute to systematic and thermal noise, which may affect the quality of measurements being obtained by the downhole tool and/or the integrity of the downhole tool itself.
Summary of the Disclosure
[0004] The present disclosure introduces an apparatus comprising a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation. The downhole tool may include a plurality of sensor devices each extendable from a body of the downhole tool by a corresponding pair of arms. Each of the plurality of sensor devices may comprise a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation, as well as circuitry operable to digitize the plurality of obtained measurements and generate a digital signal corresponding to the characteristic of the
subterranean formation.
[0005] The present disclosure also introduces a method comprising operating each of a plurality of sensor devices of a downhole tool within a wellbore extending into a subterranean formation to obtain a plurality of measurements pertaining to the subterranean formation. Each of the plurality of sensor devices is operated to digitize the plurality of measurements obtained by that sensor device, generate a digital signal based on the plurality of measurements obtained and digitized by that sensor device, and transmit the generated digital signal out of that sensor device.
[0006] The present disclosure also introduces an apparatus comprising a downhole tool conveyable within a wellbore extending into a subterranean formation. The downhole tool comprises a body containing a first electronic component, as well as a plurality of sensor devices each connected to the first electronic component by no more than one electrical conductor. Each of the plurality of sensor devices includes a plurality of electrodes, collectively operable to acquire a plurality of measurements pertaining to the formation, and a plurality of second electronic components, collectively operable to digitize the acquired plurality of measurements, generate a digital signal based on the digitized acquired plurality of measurements, and transmit the generated digital signal to the first electronic component by the corresponding one electrical conductor.
[0007] Additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the materials herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.
Brief Description of the Drawings
[0008] The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. [0009] FIG. 1 is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.
[0010] FIG. 2 is a schematic view of at least a portion of apparatus according to one or more aspects of the present disclosure.
[0011] FIG. 3 is a schematic view of a portion of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.
[0012] FIG. 4 is a schematic view of a portion of the apparatus shown in FIG. 3 according to one or more aspects of the present disclosure.
[0013] FIG. 5 is a schematic view of a portion of the apparatus shown in FIG. 2 according to one or more aspects of the present disclosure.
Detailed Description
[0014] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments.
Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
[0015] FIG. 1 is a schematic view of a downhole system 10 having a cable head 1 1 connected at its lower end to a logging tool 12. An upper end of the cable head 11 is secured to a conveyance 14, such as may be or comprise a wireline, slickline, and/or various types of tubing. The conveyance 14 extends to the surface 16 of a wellbore 18 and is operable to position the cable head 11 and one or more logging tools, such as logging tool 12, with respect to an area where formations and formation parameters may be determined and/or recorded during logging operations. The wellbore 18 is depicted in FIG. 1 as being substantially vertical, but it may also be highly deviated or even horizontal. During a logging operation, data may be transmitted from the logging tool 12 to the conveyance 14 through the cable head 1 1. Within the conveyance 14, the data may be transmitted to a data-transmission and acquisition system 20 at the surface 16.
[0016] While FIG. 1 depicts the conveyance 14 as a wireline cable, the downhole system 10 of the present disclosure may include drilling or logging systems, such as measurement-while- drilling (MWD) systems, logging-while-drilling (LWD) systems, wireline systems, coiled tubing systems, testing systems, completions systems, productions systems, or combinations thereof. Furthermore, the logging tool 12 may be or comprise one or more known and/or future- developed downhole tools operable in the downhole system 10.
[0017] For example, the logging tool 12 may be or comprise a downhole imaging tool operable to obtain an image of the formation F surrounding the wellbore 18, such as by obtaining resistivity or micro-resistivity measurements. Such downhole imaging tool may measure the resistivity of the formation F by injecting a current into the surrounding formation F using an injection electrode. The current may return to the tool from the surrounding formation F via a return electrode. One or both of the injection electrode and the return electrode may be or represent a current-measuring electrode through which the injected and returning currents may be measured. By comparing the injected and returning currents, the resistivity and/or impedance of the surrounding formation F may be determined. The measured resistivity and/or impedance may subsequently be utilized to obtain an image of the formation F surrounding the wellbore 18.
[0018] The logging tool 12 may comprise one or more extendable arms each carrying one or more sensor devices. During logging operations, the one or more extendable arms may be extended until the sensor device is placed against the wall of the wellbore 18, at which point measurements are made utilizing one or more sensors of the one or more sensor devices. For example, multiple extendable arms may extend multiple sensor devices against a portion of the circumference of the wellbore 18. The logging tool 12 may be moved along the wellbore 18 such that the one or more sensor devices contacting the wall of the wellbore 18 are disposed across the wall of the wellbore 18 and multiple measurements may be obtained along a length of the wellbore 18.
[0019] FIG. 2 is a schematic view of an example implementation of at least a portion of the logging tool 12 shown in FIG. 1 and/or another downhole tool according to one or more aspects of the present disclosure. The logging tool 12 is depicted in FIG. 2 as having eight pairs of arms 1 10. Each pair of arms 1 10 is operable to extend a corresponding sensor device 120 away from a body 130 of the logging tool 12. Each sensor device 120 may be, comprise, or resemble a device commonly referred to in the art as a "sensor pad," except that one or more aspects introduced in the present disclosure further characterize each sensor device 120.
[0020] The arms 1 10 are grouped in an upper group 140 and a lower group 150. The upper and lower groups 140 and 150 each include four pairs of arms 1 10 and four sensor devices 120. The arms 1 10 of the upper group 140 may slide within channels 145 recessed within the body 130, and the arms 1 10 of the lower group 150 may slide within channels 155 recessed within the body 130. The relative clocking of the upper and lower groups 140 and 150 around the longitudinal axis 160 of the logging tool 12 may be substantially aligned or, as shown in FIG. 2, offset by about 45 degrees. However, other values for the angular offset of the upper and lower groups 140 and 150 are also within the scope of the present disclosure.
[0021] The logging tool 12 may also comprise one or more centralizers and/or other standoffs 170, such as may be positioned on opposing ends of the logging tool 12 and/or otherwise on opposing sides of the upper and lower groups 140 and 150, collectively. The one or more standoffs 170 may each comprise one or more blades 180 extending radially from the body 130 of the logging tool 12. For example, in the example implementation depicted in FIG. 2, the logging tool 12 includes two standoffs 170 each comprising two blades 180 extending radially from the body 130 in substantially opposite directions. However, the logging tool 12 may comprise more or less than two standoffs 170, each having more or less than two blades 180, including in shapes and/or arrangements other than as shown in FIG. 2.
[0022] The sensor devices 120 are operable in the relatively high hydrostatic pressure environment of the wellbore. Accordingly, electronic components in the sensor devices 120 may also be subject to the affects of operating in such high hydrostatic pressure environments. Thus, for example, the sensor devices 120 may include functional electronic components for acquiring, processing, and transmitting measurements associated with the downhole formation while positioned within a high hydrostatic pressure environment of the wellbore. Consequently, the logging tool 12 may be characterized by a reduced size and/or increased level of integration relative to similar logging tools not operable within high hydrostatic pressure environments. For example, a number of connections, wires, and/or processes of the logging tool 12 that previously were analog-based, including those supporting data acquisition and signal processing, may be implemented and/or performed digitally in the sensor device 120. As a result, for example, one or more of the signals transmitted from the sensor device 120 may be or comprise one or more digitized signals. The transmission of such digital signals from the sensor devices 120 may be directed towards electronics 190 housed within the body 130 of the logging tool 120 via one or more electrical wires and/or other transmission means indicated generally in FIG. 2 by reference numeral 195.
[0023] FIG. 3 is a schematic view of an example implementation of one of the sensor devices 120 shown in FIG. 2. The sensor device 120 includes a plurality of measuring electrodes 210, a first source electrode 220, a second source electrode 222, and a third source electrode 224. The source electrodes 220, 222, and 224 may be electrically isolated from each other by an insulator 230, and the measuring electrodes 210 may similarly be electrically isolated from the source electrode 224 by an insulator material (not shown). The sensor device 120 also includes various structural components, such as end caps 240 and one or more underlying substrates, mandrels, frames, housings, and the like (not shown), as well as circuitry 250 supporting data acquisition, processing, and transmission of a resulting digital signal, such as to the electronics 190 of the logging tool 12 shown in FIG. 2.
[0024] The measuring electrodes 210 may measure current flow through the formation between the source electrodes, whether between the source electrodes 220 and 224, between the source electrodes 220 and 222, between the source electrodes 222 and 224, or a combination thereof. Consequently, the measuring electrodes 210 may permit an increased measurement density. However, acquiring, processing, and transmitting signals from a potentially large number of the measuring electrodes 210 may involve complex circuitry within a particular sensor device 120, which previously entailed a large number of wires and/or other conductive means to, for example, transmit analog signals from each measuring electrode 210 within and/or out of the sensor device 120.
[0025] FIG. 4 is a schematic diagram of an example implementation of the circuitry 250 shown in FIG. 3. Data acquired from one or more of the measuring electrodes 210 may be processed in the circuitry 250 contained within each sensor device 120, including undergoing digitization. For example, the digitization may utilize an analog component and/or circuit 310 for measurement signal shaping and gain control. Various techniques may be utilized to digitize the measured signal, perhaps utilizing a clock reference 320.
[0026] The circuitry 250 may include one or more electronic components 330 individually or collectively operable to digitize measured data received directly from one or more of the measuring electrodes 210, and/or to digitize analog data received via the analog component and/or circuit 310. The circuitry 250 may also include one or more electronic components 340 individually or collectively operable to process the resulting digitized signal. The processed digital signal may then be transmitted out of the sensor device 120 via operation of one or more transmission components 350. Such transmission may be via the one or more electrical wires and/or other transmission means indicated generally in FIG. 2 by reference numeral 195. For example, the transmission means 195 may comprise a single wire bus for each sensor device 120. Thus, the number of connections or wires extending out of each sensor device 120 may be reduced, because a single transmission wire bus (or a single instance of another type of transmission channel) may be utilized to transmit data from the measuring electrodes 210 collectively instead of utilizing one connection for each measuring electrode 210.
[0027] The circuitry 250 may comprise other electronic components supporting the above- described operation. For example, the circuitry 250 may comprise one or more power supplies 360 supplying power to one or more ofthe electronic components 310, 320, 330, 340, and 350. The one or more power supplies 360 may also supply power to one or more of the measurement electrodes 210, one or more of the source electrodes 220, 222, and 224, and/or other components of the sensor device 120.
[0028] FIG. 5 is a schematic diagram of at least a portion of the electronics 190 ofthe logging tool 12 shown in FIG. 2. Among other aspects, FIG. 5 illustrates an example implementation for transmitting a digitized signal representing data from multiple sensor devices 120 of the logging tool 12.
[0029] For example, the example implementation depicted in FIG. 5 may represent the transmission of digital signals from multiple sensor devices 120 to a control system 410. The control system 410 may comprise at least a portion of the electronics 190 shown in FIG. 2. The electronics 190 shown in FIG. 2 may also or instead comprise at least a portion ofthe control system 410 shown in FIG. 5.
[0030] The control system 410 may process digital signals received from each sensor device 120, such as via a single bus or other transmission means 195 corresponding to each sensor device 120. The control system 410 may be further operable to transmit a signal indicative of the outputs from multiple ones ofthe sensor devices 120. Such transmission may include to destinations outside of the logging tool 12, and perhaps destinations outside of a downhole system (such as the downhole system 10 shown in FIG. 1) comprising and/or otherwise utilizing the logging tool 12. [0031] In view of the entirety of the present disclosure, including FIGS. 1 -5, a person having ordinary skill in the art will recognize that the present disclosure introduces an apparatus comprising: a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation, the downhole tool comprising a plurality of sensor devices each extendable from a body of the downhole tool by a
corresponding pair of arms, wherein each of the plurality of sensor devices comprises: a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation; and circuitry operable to digitize the plurality of obtained measurements and generate a digital signal corresponding to the characteristic of the subterranean formation.
[0032] The circuitry of each sensor device may be further operable to transmit the digital signal out of the sensor device.
[0033] The circuitry of each sensor device may comprise a clock reference utilized in the digitization of the plurality of obtained measurements.
[0034] The circuitry of each sensor device may comprise an analog circuit operable to process the plurality of obtained measurements.
[0035] The circuitry of each sensor device may comprise a processor operable to process the digital signal.
[0036] The circuitry of each sensor device may comprise a processor operable to process the plurality of digitized obtained measurements.
[0037] The circuitry of each sensor device may comprise a power source operable to supply power for at least one of: digitizing the plurality of obtained measurements; processing the digital signal; and transmitting the digital signal out of the sensor device.
[0038] The downhole tool may further comprise a controller operable to process multiple digital signals each transmitted from a corresponding one of the sensor devices. The controller may be further operable to transmit a combined digital signal out of the downhole tool, wherein the combined digital signal is based on the multiple digital signals each transmitted from a corresponding one of the sensor devices.
[0039] The downhole tool may be or comprise a downhole imaging tool. The downhole imaging tool may comprise the plurality of sensor devices, and the plurality of measuring electrodes of each of the plurality of sensor devices may be operable to measure a current from a current path extending through the subterranean formation from at least one of the plurality of source electrodes.
[0040] The present disclosure also introduces a method comprising: operating each of a plurality of sensor devices of a downhole tool within a wellbore extending into a subterranean formation to obtain a plurality of measurements pertaining to the subterranean formation;
operating each of the plurality of sensor devices to digitize the plurality of measurements obtained by that sensor device; operating each of the plurality of sensor devices to generate a digital signal based on the plurality of measurements obtained and digitized by that sensor device; and operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
[0041] Operating each of the plurality of sensor devices to digitize the plurality of measurements obtained by that sensor device may utilize a clock reference applied to a measured analog signal corresponding to the plurality of obtained measurements.
[0042] The method may further comprise operating each of the plurality of sensor devices to process the generated digital signal within that sensor device before operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
[0043] Operating each of the plurality of sensor devices to digitize the plurality of obtained measurements may comprise digitizing an analog measurement from each of a plurality of measuring electrodes disposed on that sensor device. Operating each of the plurality of sensor devices to transmit the generated digital signal may comprise transmitting a digitized signal representative of the analog measurements from each of the plurality of measuring electrodes.
[0044] The present disclosure also introduces an apparatus comprising: a downhole tool conveyable within a wellbore extending into a subterranean formation, wherein the downhole tool comprises: a body containing a first electronic component; and a plurality of sensor devices each connected to the first electronic component by no more than one electrical conductor, wherein each of the plurality of sensor devices comprises: a plurality of electrodes collectively operable to acquire a plurality of measurements pertaining to the formation; and a plurality of second electronic components collectively operable to: digitize the acquired plurality of measurements; generate a digital signal based on the digitized acquired plurality of
measurements; and transmit the generated digital signal to the first electronic component by the corresponding one electrical conductor. [0045] The plurality of electrodes may comprise: a plurality of source electrodes each operable to inject electrical current into the formation; and a plurality of measuring electrodes collectively operable to acquire the plurality of measurements, wherein the plurality of measurements may pertain to electrical current exiting the formation.
[0046] The apparatus may further comprise a control system comprising the first electronic component and operable to transmit the generated digital signal received from each of the plurality of sensor devices to outside the downhole tool.
[0047] The plurality of sensor devices may comprise a first group of sensor devices and a second group of sensor devices, wherein the first group of sensor devices may be angularly offset about a longitudinal axis of the downhole tool relative to the second group of sensor devices.
[0048] The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
[0049] The Abstract at the end of this disclosure is provided to comply with 37 C.F.R.
§ 1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

WHAT IS CLAIMED IS:
1. An apparatus, comprising:
a downhole tool operable to measure a characteristic of a subterranean formation from within a wellbore extending into the subterranean formation, the downhole tool comprising a plurality of sensor devices each extendable from a body of the downhole tool by a corresponding pair of arms, wherein each of the plurality of sensor devices comprises:
a plurality of source and measuring electrodes collectively operable to obtain a plurality of measurements pertaining to the characteristic of the subterranean formation; and circuitry operable to digitize the plurality of obtained measurements and generate a
digital signal corresponding to the characteristic of the subterranean formation.
2. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices is further operable to transmit the digital signal out of the sensor device.
3. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices
comprises a clock reference utilized in the digitization of the plurality of obtained measurements.
4. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices
comprises an analog circuit operable to process the plurality of obtained measurements.
5. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices
comprises a processor operable to process the digital signal.
6. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices
comprises a processor operable to process the plurality of digitized obtained measurements.
7. The apparatus of claim 1 wherein the circuitry of each of the plurality of sensor devices comprises a power source operable to supply power for at least one of:
digitizing the plurality of obtained measurements;
processing the digital signal; and
transmitting the digital signal out of the sensor device.
8. The apparatus of claim 1 wherein the downhole tool further comprises a controller operable to process multiple digital signals each transmitted from a corresponding one of the plurality of sensor devices.
9. The apparatus of claim 8 wherein the controller is further operable to transmit a combined digital signal out of the downhole tool, wherein the combined digital signal is based on the multiple digital signals each transmitted from a corresponding one of the plurality of sensor devices.
10. The apparatus of claim 1 wherein the downhole tool comprises a downhole imaging tool.
11. The apparatus of claim 10 wherein the downhole imaging tool comprises the plurality of sensor devices, and where the plurality of measuring electrodes of each of the plurality of sensor devices is operable to measure a current from a current path extending through the subterranean formation from at least one of the plurality of source electrodes.
12. A method, comprising:
operating each of a plurality of sensor devices of a downhole tool within a wellbore extending into a subterranean formation to obtain a plurality of measurements pertaining to the subterranean formation;
operating each of the plurality of sensor devices to digitize the plurality of measurements
obtained by that sensor device;
operating each of the plurality of sensor devices to generate a digital signal based on the plurality of measurements obtained and digitized by that sensor device; and
operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
13. The method of claim 12 wherein operating each of the plurality of sensor devices to digitize the plurality of measurements obtained by that sensor device utilizes a clock reference applied to a measured analog signal corresponding to the plurality of obtained measurements.
14. The method of claim 12 further comprising operating each of the plurality of sensor devices to process the generated digital signal within that sensor device before operating each of the plurality of sensor devices to transmit the generated digital signal out of that sensor device.
15. The method of claim 12 wherein operating each of the plurality of sensor devices to digitize the plurality of obtained measurements comprises digitizing an analog measurement from each of a plurality of measuring electrodes disposed on that sensor device.
16. The method of claim 15 wherein operating each of the plurality of sensor devices to transmit the generated digital signal comprises transmitting a digitized signal representative of the analog measurements from each of the plurality of measuring electrodes.
17. An apparatus, comprising:
a downhole tool conveyable within a wellbore extending into a subterranean formation, wherein the downhole tool comprises:
a body containing a first electronic component; and
a plurality of sensor devices each connected to the first electronic component by no more than one electrical conductor, wherein each of the plurality of sensor devices comprises:
a plurality of electrodes collectively operable to acquire a plurality of
measurements pertaining to the formation; and
a plurality of second electronic components collectively operable to:
digitize the acquired plurality of measurements;
generate a digital signal based on the digitized acquired plurality of
measurements; and
transmit the generated digital signal to the first electronic component by the corresponding one electrical conductor.
18. The apparatus of claim 17 wherein the plurality of electrodes comprises:
a plurality of source electrodes each operable to inject electrical current into the formation; and a plurality of measuring electrodes collectively operable to acquire the plurality of
measurements, wherein the plurality of measurements pertain to electrical current exiting the formation.
19. The apparatus of claim 17 further comprising a control system comprising the first electronic component and operable to transmit the generated digital signal received from each of the plurality of sensor devices to outside the downhole tool.
20. The apparatus of claim 17 wherein the plurality of sensor devices comprises a first group of sensor devices and a second group of sensor devices, wherein the first group of sensor devices is angularly offset about a longitudinal axis of the downhole tool relative to the second group of sensor devices.
PCT/US2014/010988 2013-01-10 2014-01-10 Downhole apparatus with extendable digitized sensor device WO2014110332A1 (en)

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