Sensor mouting method under cover sleeve for logging while drilling and measurement while drilling downhole tools

Abstract

A work string performs a method of obtaining a measurement in a borehole in an earth formation. The work string is disposed in the borehole. The work string includes a tubular body (302), a cavity (306) in the tubular body at a selected axial location, a cover sleeve (312) that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section (314) having a first thickness and a second azimuthal section (316) having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity, and a sensor (307) in the cavity. A measurement is obtained using the sensor.

Description

65NUL-509925-WO-2 (INT1021PCT) SENSOR MOUTING METHOD UNDER COVER SLEEVE FOR LOGGING WHILE DRILLING AND MEASUREMENT WHILE DRILLING DOWNHOLE TOOLS CROSS REFERENCE TO RELATED APPLICATIONS This application claims the benefit of an earlier filing date from U.S. Provisional Application Serial No.63 / 624,333, filed January 24, 2024, the entire disclosure of which is incorporated herein by reference. BACKGROUND

[0001] In the resource recovery, a sensor on a work string in a borehole can obtain measurements of various parameters, such as formation parameters. The sensor is disposed in a cavity of the work string and a cover sleeve or hatch is placed over the cavity to protect the sensor from the borehole environment. Being between the sensor and the object being tested (e.g., the formation), the cover sleeve reduces a quality of measurements obtained by the sensor. For example, the cover sleeve can absorb neutrons and / or gamma rays in nuclear measurements. Therefore, it is desired to have a cover sleeve that protects the sensor while interfering minimally with sensor measurements. SUMMARY

[0002] Disclosed herein is a work string for obtaining a measurement in a borehole in an earth formation, the work string includes a tubular body, a cavity in the tubular body at a selected axial location, a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity, and a sensor in the cavity.

[0003] Also disclosed herein is a method of obtaining a measurement in a borehole in an earth formation. A work string is disposed in the borehole, the work string including a tubular body, a cavity in the tubular body at a selected axial location, a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity, and a sensor in the cavity. A measurement is obtained using the sensor.65NUL-509925-WO-2 (INT1021PCT) BRIEF DESCRIPTION OF THE DRAWINGS

[0004] The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

[0005] FIG.1 shows a schematic diagram of a system for performing downhole operations.

[0006] FIG.2 shows a schematic cross-sectional illustration of a signal-transparent tubular in accordance with an embodiment of the present disclosure;

[0007] FIG.3 is an axial cross-sectional view of the drilling tubular at the selected axial location of the drill string;

[0008] FIG.4 shows an axial cross-sectional view of the drilling tubular at the selected axial location of the drill string with the sensor in an extended position;

[0009] FIG.5 shows an axial cross-sectional view of the drilling tubular at the selected axial location of the drill string in an alternate embodiment;

[0010] FIG.6 shows an axial cross-sectional view of the drilling tubular in an alternate embodiment;

[0011] FIG.7 shows an axial cross-sectional view of the drilling tubular of FIG.6 with the sensor extended and the fluid displacer retracted.

[0012] FIG.8 shows an axial cross-sectional view of the drilling tubular of FIG.6 with the sensor in an extended position and the fluid displacer in an extended position;

[0013] FIG.9 shows a flowchart or a method for obtaining a measurement in a borehole using the drill string disclosed herein;

[0014] FIG.10 shows a cross-sectional view of the tubular body in another embodiment; and

[0015] FIG.11 shows a cross-sectional view of the tubular body of FIG. 10 with the rib in an extended position. DETAILED DESCRIPTION

[0016] A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures.

[0017] FIG.1 shows a schematic diagram of a system for performing downhole operations. As shown, the system is a drilling system 10 that includes a drill string 20 having a drilling assembly 90, also referred to as a bottomhole assembly (BHA), conveyed in a borehole 26 penetrating an earth formation 60. At least a portion of the borehole 26 may be65NUL-509925-WO-2 (INT1021PCT) stabilized with a casing 24 or a liner (not shown). The drilling system 10 includes a conventional derrick 11 erected on a floor 12 that supports a rotary table 14 that is rotated by a prime mover, such as an electric motor (not shown), at a desired rotational speed. The drill string 20 includes a drilling tubular 22, such as a drill pipe, extending downward from the rotary table 14 into the borehole 26. A disintegration device 50, such as a drill bit attached to the end of the BHA 90, disintegrates the geological formations when it is rotated to drill the borehole 26. The drill string 20 is coupled to surface equipment such as systems for lifting, rotating, and / or pushing, including, but not limited to, a drawworks 30 via a kelly joint 21, swivel 28 and line 29 through a pulley 23. In some embodiments, the surface equipment may include a top drive (not shown). During the drilling operations, the drawworks 30 is operated to control the weight on bit, which affects the rate of penetration. The operation of the drawworks 30 is well known in the art and is thus not described in detail herein.

[0018] During drilling operations a suitable drilling fluid 31 (also referred to as the “mud”) from a source or mud pit 32 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 passes into the drill string 20 via a desurger 36, fluid line 38 and the kelly joint 21. The drilling fluid 31 is discharged at the borehole bottom 51 through an opening in the disintegration device 50. The drilling fluid 31 circulates uphole through the annular space 27 between the drill string 20 and the borehole 26 and returns to the mud pit 32 via a return line 35. A sensor S1 in the fluid line 38 provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string 20 respectively provide information about the torque and the rotational speed of the drill string. Additional sensors may be configured at the surface (e.g., as part of the drilling system 10 and / or disposed downhole) and can include, without limitation, a gas tomographic sensor configured to monitor gas content and composition of the drilling fluid 31 while circulating the drilling fluid. Some such sensors may be configured with longer response times (minutes) than via detection using BHA embedded sensors and transmission via Electromagnetic Telemetry (seconds). Additionally, one or more sensors associated with line 29 are used to provide the hook load of the drill string 20 and about other desired parameters relating to the drilling of the borehole 26. The system may further include one or more downhole sensors 70 located on the drill string 20 and / or the BHA 90.

[0019] In some applications the disintegration device 50 is rotated by only rotating the drill pipe from the surface. However, in other applications, a drilling motor 55 (for example, a mud motor) disposed in the drilling assembly 90 is used to rotate the disintegration device 50 and / or to superimpose or supplement the rotation of the drill string65NUL-509925-WO-2 (INT1021PCT) 20. In either case, the rate of penetration (ROP) of the disintegration device 50 into the earth formation 60 for a given formation and a given drilling assembly largely depends upon the weight on bit and the drill bit rotational speed. In one aspect of the embodiment of FIG.1, the drilling motor 55 is coupled to the disintegration device 50 via a drive shaft (not shown) disposed in a bearing assembly 57. The drilling motor 55 rotates the disintegration device 50 when the drilling fluid 31 passes through the drilling motor 55 under pressure. The bearing assembly 57 supports the radial and axial forces of the disintegration device 50, the downthrust of the drilling motor and the reactive upward loading from the applied weight on bit. Stabilizers 58 coupled to the bearing assembly 57 and / or other suitable locations act as centralizers for the drilling assembly 90 or portions thereof.

[0020] One or more surface control units 40 can be configured to receive signals from the downhole sensors 70 and devices via a transducer 43, such as a pressure transducer, placed in the fluid line 38, as well as from sensors S1, S2, S3 (and other surface sensors), hook load sensors, RPM sensors, torque sensors, downhole sensors, and any other sensors used in the system and processes such signals according to programmed instructions provided to the surface control units 40. The surface control units 40 can be configured to display desired drilling parameters and other information on one or more associated display / monitor 42 for use by an operator at the rig site to control the drilling operations. The surface control units 40 may include a computer, memory for storing data, computer programs, models and algorithms accessible to a processor in the computer, a recorder, such as tape unit, memory unit, etc. for recording data and other peripherals. The surface control units 40 also may include simulation models for use by the computer to processes data according to programmed instructions. The surface control units are configured to respond to user commands entered through a suitable device, such as a keyboard. The surface control units 40 can be configured to activate alarms 44 when certain unsafe or undesirable operating conditions occur.

[0021] The drilling assembly 90 also contains other sensors and devices or tools for providing a variety of measurements relating to the formation surrounding the borehole and for drilling the borehole 26 along a desired path. Such devices may include a device for measuring the formation resistivity, conductivity, or permittivity near and / or in front of the drill bit or around the BHA 90, a gamma ray device for measuring the formation gamma ray intensity, a nuclear device for measuring nuclear radiation from the earth formation 60 (such as alpha-, beta-, gamma, x-ray, quantum particles) in response to radiation emitted to the earth formation 60 from a nuclear transmitter (not shown) included in the BHA 90, an65NUL-509925-WO-2 (INT1021PCT) acoustic device for measuring acoustic waves from the earth formation 60 in response to emitted acoustic energy to the earth formation 60 from an acoustic transmitter or actuator (not shown) included in the BHA 90, an NMR device for measuring nuclear magnetic signals in response to static and dynamic magnetic fields emitted into the earth formation 60 from the BHA 90, and devices for determining the inclination, azimuth and position of the drill string.

[0022] A resistivity measurement device 64, made according to an embodiment described herein, may be coupled at any suitable location, including above a lower kick-off subassembly or steering unit 62, for estimating or determining formation properties, such as but not limited to the resistivity of the formation near or in front of the disintegration device 50 or at other suitable locations. As another example, an inclinometer 74 and a gamma ray device 76 may be suitably placed for respectively determining the inclination of the BHA and the formation gamma ray intensity. Any suitable inclinometer and gamma ray device may be utilized. In addition, an azimuth device (not shown), such as a magnetometer or a gyroscopic device, may be utilized to determine the drill string azimuth. Such devices are known in the art and therefore are not described in detail herein. In the above-described exemplary configuration, the drilling motor 55 transfers power to the disintegration device 50 via a shaft that also enables the drilling fluid to pass from the drilling motor 55 to the disintegration device 50. In an alternative embodiment of the drill string 20, the drilling motor 55 may be coupled below the resistivity measuring device 64 or at any other suitable place.

[0023] Still referring to FIG.1, other logging-while-drilling (LWD) devices (generally denoted herein by numeral 77), such as devices for measuring formation porosity, permeability, density, rock properties, fluid properties, etc. may be placed at suitable locations in the drilling assembly 90 for providing information useful for evaluating the subsurface formations along borehole 26. Such devices may include, but are not limited to, temperature measurement tools, pressure measurement tools, borehole diameter measuring tools (e.g., a caliper), acoustic tools, nuclear tools, nuclear magnetic resonance tools and formation testing and sampling tools.

[0024] The above-noted devices transmit data to a downhole telemetry system 72, which in turn transmits the received data uphole to the surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 and transmits such received signals and data to the appropriate downhole devices. In one aspect, a mud pulse telemetry system may be used to communicate data between the downhole sensors 70 and devices and the surface equipment during drilling operations. A transducer 43 placed65NUL-509925-WO-2 (INT1021PCT) in the fluid line 38 (e.g., mud supply line) may be configured to detect the mud pulses responsive to the data transmitted by the downhole telemetry system 72.

[0025] The transducer 43 may be configured to generate electrical signals in response to the mud pressure variations and transmits such signals via a conductor 45 to the surface control unit 40. In other aspects, any other suitable telemetry system may be used for two- way data communication (e.g., downlink and uplink) between the surface and the BHA 90.

[0026] A resistivity measurement device 64 may be provided that includes, for example, a plurality of antennas including, for example, transmitters 66a or 66b and / or receivers 68a or 68b. Resistivity can be one formation property that is of interest in making drilling decisions. Those of skill in the art will appreciate that other formation property tools can be employed with or in place of the resistivity measurement device 64.

[0027] Although FIG.1 is shown and described with respect to a drilling operation, those of skill in the art will appreciate that similar configurations, albeit with different components, can be used for performing different downhole operations. For example, wireline, wired pipe, liner drilling, reaming, coiled tubing, and / or other configurations can be used as known in the art. Further, production configurations can be employed for extracting and / or injecting materials from / into earth formations. Thus, the present disclosure is not to be limited to drilling operations but can be employed for any appropriate or desired downhole operation(s).

[0028] FIG.2 shows a schematic cross-sectional illustration of a signal-transparent tubular 200 in accordance with an embodiment of the present disclosure. The signal- transparent tubular 200 may be a section of drilling tubular, liner, casing, or other downhole tubular, such as a signal-transparent tubular of United States Patent No.12,065,887, issued to Baker Hughes Oilfield Operations LLC, the contents of which are incorporated herein by reference. The signal-transparent tubular 200 includes a first tubular connector 202 and a second tubular connector 204 arranged at opposite ends of the signal-transparent tubular 200. Between the first tubular connector 202 and the second tubular connector 204 is a signal- transparent portion 206, having signal-transparent windows 212, a first high-strength portion 208, and a second high-strength portion 210. The signal-transparent portion 206, the first high-strength portion 208, and the second high-strength portion 210 are substantially unitary with high-strength material extending substantially continuously between the tubular connectors 202, 204.

[0029] As shown, in this embodiment, each signal-transparent window 212 includes an embedded sensor 214. The embedded sensors 214 may be of various types, such as65NUL-509925-WO-2 (INT1021PCT) sensors for electric and / or magnetic fields that would benefit from the electric and / or magnetic properties of the material of the signal-transparent tubular 200. Alternatively, or in addition, the embedded sensors 214 may be sensitive to nuclear radiation, electromagnetic signals and / or acoustic signals. The embedded sensors may include or incorporate one or more combinations of sensors / detectors, such as a magnetic field sensor (magnetometer) and / or a gravity sensor (accelerometer) in combination with one or more of a sensor that is sensitive to electromagnetic fields, acoustic waves, and / or nuclear radiation. Such a combination may enable an ability to sense or detect a formation property in various directions and to determine the direction of the sensing at the time. Advantageously, from such a data set, images of the formation surrounding the borehole can be determined. In an alternate embodiment, one or more signal-transparent windows 212 may include one or more of a transponder, a repeater, a receiver, a transmitter, an actuator, a responder, a scintillator that alone or in combination may be used to transmit, receive, repeat, or respond to signals from or to one location downhole to or from another location downhole or from or to one location downhole to or from a location at the surface. Those of skill in the art will appreciate that transponders, repeaters, receivers, and responders will include sensors configured to receive signals that are to be transmitted, repeated, or responded to.

[0030] In one non-limiting embodiment, the sensors 214 may be sensitive to vibration, such as accelerometers, vibration sensors, or similar. Vibration sensitive sensors may be connected to actuators (not shown) that are configured to actuate and dampen or decrease vibration based on the measurements of the vibration sensitive sensors. Alternatively, or in addition, the signal-transparent windows 212 in the signal-transparent tubular 200 may be filled with vibration dampening materials, such as elastomer. In one non- limiting embodiment, vibration sensitive sensors and / or actuators may be at least partially included (e.g., embedded) within the vibration dampening material within the signal- transparent windows 212.

[0031] The sensors 214 (inclusive of detectors, transponders, repeaters, receivers, transmitters, actuators, responders, etc.) may be electrically connected to a controller 216 by an electrical connection 218. As shown in FIG.2, the electrical connection 218 may be terminated within the signal-transparent tubular 200. Alternatively, or in addition, the electrical connection may terminate at the ends of the signal-transparent tubular, so as to connect to corresponding electrical connections to subs, tubes, pipes, or BHA segments (e.g., by connectors, contact rings, means for inductive, capacitive, or electromagnetic resonant65NUL-509925-WO-2 (INT1021PCT) coupling, etc.) that are connected to the signal-transparent tubular 200 above or below the signal-transparent tubular 200.

[0032] The electrical connection 218 may provide power and / or data communication to the sensors 214, such as between the sensors 214 and the controller 216 and / or to / from a location outside the signal-transparent tubular 200. The electrical connection 818 may include a metallic conduit. For example, the electrical connection 218 may include a wire or bus or a more complex arrangement (e.g., a circuit, such as a flexible circuit harness or a flexible circuit board). In one non-limiting embodiment, more than one sensor may be connected to the electrical connection 218 by multiple electrical lines 221 that branch from the electrical connection 218 to provide power and / or data to or from the sensors 214. As another example, a more complex arrangement may include additional components such as amplifiers, analog-digital converters, resistors, capacitors, inductors, etc.

[0033] In some embodiments, the electrical connection 218 may be installed or arranged within the composite material of the signal-transparent tubular 200 or a wall of the signal-transparent tubular 200 and / or in direct contact with the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200. The electrical connection 218 may only be partially in direct contact with the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200 (e.g., only portions of the electrical connection 218 may be in direct contact with the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200) or the electrical connection 218 may be completely in direct contact with the material of the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200. In such an embodiment, no portion of the one or more surfaces of the electrical connection 218 is in contact with anything but the material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200.

[0034] In some embodiments, the electrical connection 218 may be embedded into the composite material of the signal-transparent tubular 200 or the wall of the signal- transparent tubular 200. For example, an electrical connection, such as a wire, a harness, or a circuit board may be embedded into the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200 by vacuum injection processing, hand lay-up, wet compression molding, pultrusion, or winding. In some embodiments, and as shown, a sensor 230 may be provided that includes at least a portion of the wire, the harness, or the circuit board that is embedded into the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200. For example, an electrical65NUL-509925-WO-2 (INT1021PCT) conduit may be arranged and configured to effectively act as an electrode, such as an electrode to measure voltages and / or currents. In one embodiment, if the signal-transparent tubular 200 is utilized as an electromagnetic telemetry tool, the tubular connectors 202, 204 may act as electrodes for the electromagnetic telemetry tool. Alternatively, separate electrodes (not shown) may be included in the signal-transparent tubular 200.

[0035] Advantageously, electrodes of the electromagnetic telemetry tool may be connected by the electrical connection 218 to provide means via a voltage or power supply (not shown) that may be connected to or included in the controller 216 to provide and / or control a power or voltage difference to the electrodes of the electromagnetic telemetry tool. As known in the art, electromagnetic telemetry tools benefit from a large distance between electrodes where the material between the electrodes is not conductive or is low conductive (e.g., less conductive than the material of the electrodes, e.g., 100 or 10,000 times less conductive than the material of the electrodes). This can be easily accomplished by one or more of the portions 208, 210, and 206. For example, the distance of metallic electrodes that are separated by non-conductive or low-conductive material may be larger than 10 cm, such as larger than 1 m. In other words, the distance of metallic electrodes that are separated by non-conductive or low-conductive material may be more than 30%, 50%, or even 70% of the length of the signal-transparent tubular 200.

[0036] Alternatively, in some embodiments, the wire may be wound in one or more turns 232 (shown in FIG. 2) within the composite material of the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200 to effectively act as a sensor 230, such as an antenna coil 235 or an antenna toroid 240 (FIG. 2 and inset illustration thereof), such as a coil / toroid that is embedded in and / or surrounded by the composite material of the signal- transparent tubular 200 or the wall of the signal-transparent tubular 200. In such an approach, the signal-transparent tubular 200 or the wall of the signal-transparent tubular 200 may include magnetic material or cores 245, such as hard magnetic material or soft magnetic material (e.g., ferrites) that are arranged and configured to guide magnetic field lines that are created by electrical current flowing through the antenna coil 235 and / or the antenna toroid 240. The controller 216 may further be connected to various other electronics to enable the storage, transmission, and / or processing of data and / or information obtained at the sensors 214. Alternatively, in some embodiments, the controller 216 may be directly configured to store, transmit, and / or process data and / or information obtained from the sensors 214 (e.g., the controller 216 can include electronic storage media, processors, transceivers, and the like).65NUL-509925-WO-2 (INT1021PCT)

[0037] The configuration shown in FIG. 2 also illustrates a connection between the high-strength portions 208, 210 and the respective tubular connectors 202, 204. In this illustrative embodiment, the connection between the high-strength portions 208, 210 and the respective tubular connectors 202, 204 is by clamping mechanisms 220, 222. The clamping mechanisms 220, 222 may fixedly connect to one or both of the high-strength portions 208, 210 and the respective tubular connectors 202, 204. Alternatively, or in addition, the connection between the high-strength portions 208, 210 and the respective tubular connectors 202, 204 may be by welding to or fastening to form a rigid and fixedly-connected signal- transparent tubular 200. The connections provided by the clamping mechanisms 220, 222 (or other types of attachment mechanisms) are sufficiently structural strong to enable the transmission of torque and weight from one part to another and thus enable active drilling operations to be used by a drill string that the signal-transparent tubular 200 is a part of.

[0038] Because the signal-transparent tubular 200 may be a portion of a drill string, the signal-transparent tubular 200 defines a flow path 224 therethrough. The flow path 224 of the signal-transparent tubular 200 passes through the first tubular connector 202, the first high-strength portion 208, the signal-transparent portion 206, the second high-strength portion 210, and the second tubular connector 204. As discussed above, a drilling mud may be conveyed through the signal-transparent tubular 200. Accordingly, the drilling mud, during operation, may directly contact the materials of the tubular connectors 202, 204, the high-strength portions 208, 210, and the signal-transparent portion 206. That is, in some embodiments, the signal-transparent portion 206 may directly form a portion of the signal- transparent tubular 200 that includes the flow path 224.

[0039] Although described above with respect to sensors and signal-transparent portions of a drill string section (e.g., drilling tubular) or other downhole tubular, such description is not to be limiting. For example, the above described sensors may be combined with and / or replaced by actuators, and the transparent portions may be actuator-transparent portions that are used to form an actuator-transparent downhole tubular. In such embodiments, the actuators may be piezo-actuators / sensors, high frequency electromagnets, magnetostrictive actuators, bio-actuators, etc. In some such embodiments, the actuators can provide sensor displacement compensation or provide constructive or destructive interference conditions during sensor displacement / movement. Further, in some embodiments, wave manipulators (e.g., corners, gaps, double gaps, etc.) with the natural frequency of wave fields may be employed. In some such examples, a comparison of the measured versus the predicted wave forms may be performed, with the predicted wave form being the actuator65NUL-509925-WO-2 (INT1021PCT) frequency, with adaptive screening of interference ranges being used. The transparent portions of the actuator-transparent tubular may be transparent to a characteristic or property of the respective actuator.

[0040] Further, in some embodiments and configurations, a signal-transparent tubular may be connected to an actuator-transparent tubular to form a section of a drill string. In some such embodiments, the actuator of the actuator-transparent tubular may be selected and configured to interfere or otherwise interact with a sensor of a signal-transparent tubular. Electrostriction (Piezo effect) is a property of electrical non-conductors, or dielectrics, which causes them to change shape under the application of an electric field very fast. Device that employ the magnetostrictive effect can convert magnetic energy into kinetic energy, or the reverse, for high frequency applications as well. This may be achieved through the implementation of the embodiments shown and described in FIG.6 or variations thereof.

[0041] FIG.3 is an axial cross-sectional view 300 of the drilling tubular 22 at the selected axial location of the drill string 20. The drilling tubular 22 includes a body 302 having a body outer radius. The body 302 can be made of a high strength material (e.g. magnetic steel, non-magnetic steel, titanium, etc.). A hollow bore 304 can pass through the body 302 along a longitudinal axis to allow for the flow of fluids. A cavity 306 is formed in an outer surface of the body 302 at a selected azimuthal location and extends radially inward to a selected radial depth within the body 302. A sensor 307 is disposed in the cavity 306. A displacement device 308 disposed in the cavity 306 can be activated to move the sensor 307 along a radial line of the body 302. When the displacement device 308 is in a deactivated state, an outer surface 310 of the sensor 307 is flush or substantially flush with the outer surface of the body 302. When the displacement device 308 is activated, the sensor 307 is moved radially outward to extend beyond the outer surface of the body 302.

[0042] A cover sleeve 312 is disposed around the body 302 at the axial location of the sensor 307 and shields the sensor 307 from the borehole environment, such as from earth formation 60 or from annulus 506 between wall 330 of borehole 26 and outer surface of cover sleeve 312 or drilling tubular 22. The cover sleeve 312 can be made of high strength material (e.g., steel, non-magnetic steel, titanium, ceramic, plastic, non-magnetic or magnetic composites, etc.). The cover sleeve 312 includes a first azimuthal section 314 and a second azimuthal section 316. The first azimuthal section 314 extends circumferentially from a first section boundary 318 to a second section boundary 320. The first azimuthal section 314 does not cover the cavity 306. The second azimuthal section 316 extends circumferentially from the first section boundary 318 to the second section boundary 320 to cover the cavity 306.65NUL-509925-WO-2 (INT1021PCT) The cover sleeve has a single outer radius OR. That is, the outer surface of the cover sleeve has a circular shape. The first azimuthal section 314 has a first inner radius (indicated by IR1) that may be substantially the same as the outer radius of the body 302. In one embodiment, the thickness of the first azimuthal section 314 is constant, as indicated by first thickness t1. The second azimuthal section 316 has a second thickness t2that is less than the first thickness t1 of the first azimuthal section 314. Due to its lower thickness t2, the second azimuthal section 316 is more transparent to signals, for example electro-magnetic signals, acoustic signals, and / or nuclear particles or radiation. In contrast, the first azimuthal section 314 due to its relatively larger first thickness t1compared to the second azimuthal section 316 is less transparent to measurement signal but provide a higher mechanical strength. As a consequence, the first azimuthal section 314, due to its relatively larger thickness t1, also provides a shielding of sensor 307 against signals that would otherwise arrive at sensor 307 from directions other than from second azimuthal direction 316. As shown in FIG. 3, the second azimuthal section 316 includes an arch 322 that extends outward from the body 302 to create a hollow space 324 between the body 302 and the arch 322. from the first section boundary 318, the hollow space 324 is characterized in that it includes a vacuum or a material that is different from the material of cover sleeve 312 and / or body 302. For example, hollow space 324 may be filled with a liquid or gas (e.g., drilling fluid, oil, water, air, or other suitable fluid or gas), a foam filled with liquid or gas, a sponge filled with liquid or gas, or an elastomer. The arch is able to withstand high external pressures of the borehole due to its shape. The sensor 307 can be extended into the hollow space 324 during a sensing operation. The ends of the arch 322 occur at the first section boundary 318 and the second section boundary 320 and therefore at the first inner radius IR1of the cover sleeve 312. Arch 322 is characterized in that second inner radius varies over the length of arch 322 (arc length) between the first section boundary 318 and second section boundary 320. The arch 322 extends radially outward to reach a second inner radius IR2of the cover sleeve 312 at the top 326 of the arch 322 (corresponding to second thickness t2of cover sleeve 312). For example, as shown, the inner radius may increase monotonically along the length of arch 322 from the first inner radius IR1 at the first section boundary 318 until it reaches the second inner radius IR2at the top 326 of the arch 322 and then decreases monotonically along the length of arch 322 from the second inner radius IR2 at the top 326 of the arch 322 until it reaches the first inner radius IR1at the second section boundary 320. Those skilled in the art will understand that the monotonic increase and decrease between first and second section boundary 318, 320 that leads to the arch-shape of the inner surface of cover sleeve 312, while advantageous, is65NUL-509925-WO-2 (INT1021PCT) an example and other shapes of the inner surface of cover sleeve 312 between the first inner radius IR1 and the second inner radius IR2 are possible. For example, the transition from the first inner radius IR1to the second inner radius IR2may be step-wise. That is, at first boundary 318, the inner radius may jump from the first inner radius IR1 to the second inner radius IR2and at the second section boundary, the inner radius may jump back to the first inner radius IR1. The drilling tubular 22 and cover sleeve 312 are disposed in the borehole with a gap between the cover sleeve 312 and a wall 330 of the borehole 26, such as annulus 506.

[0043] FIG. 4 shows an axial cross-sectional view 400 of the drilling tubular 22 at the selected axial location of the drill string 20 with the sensor 307 in an extended position. The displacement device 308 is activated, thereby causing the sensor 307 to move radially outward towards arch 322. In one embodiment, the outer surface 310 of the sensor 307 is flush with the arch 322 (i.e., at the second inner radius IR2, cf. FIG.3). In the extended position, the distance between the sensor 307 and the earth formation 60 is at a minimum, thereby reducing the amount of interference caused by the cover sleeve 312.

[0044] FIG. 5 shows an axial cross-sectional view 500 of the drilling tubular 22 at the selected axial location of the drill string 20 in an alternate embodiment. The sensor 307 is shown in an extended position. A fluid displacer 502 is located on an outer surface of the cover sleeve 312. The fluid displacer 502 is made of a material that is different than that the material of the cover sleeve 312. The fluid displacer 502 partially or completely displaces borehole fluids from the region 504 and thereby allows better measurements to be taken by the sensor 307 of the formation. The fluid displacer 502 is disposed within the second azimuthal section 316 and covers a portion or all of the second azimuthal section 316 when in an inflated state. The fluid displacer 502 can be a flexible displacer or a rigid displacer. A flexible displacer can be inflated to fill a gap or region 504 in an annulus 506 between the cover sleeve 312 and a wall 330 of the borehole 26. A pump 508 is disposed at a location within the body 302 of the drilling tubular 22. A fluid line 510 connects the pump 508 to the flexible displacer. The pump 508 can be activated to inflate the flexible displacer and can be turned off to allow the fluid displacer 502 to deflate. When the fluid displacer 502 is a rigid displacer, a hydraulic piston can be used to extend the rigid displacer to fill the gap or region 504 in the annulus 506 between the cover sleeve 312 and the wall 330 of the borehole 26.

[0045] The fluid displacer 502 can include a component 512 for reducing interference with the environment, such as with the wall 330 of the borehole 26. In an embodiment, the component 512 is a wear-resistant coating or shield on the outer surface of the fluid displacer65NUL-509925-WO-2 (INT1021PCT) 502 that comes between the fluid displacer 502 and the wall 330 of the borehole 26 when the fluid displacer 502 is inflated. The wear-resistant coating prevents abrasion or wear of the fluid displacer 502 by the wall 330 of the borehole 26. The wear-resistant coating can be made of a nanoparticle composite material. The material of the fluid displacer 502, the material of the shield, and the material of the hydraulic fluid can all contribute to a screen for the signal from the formation and calculations can be made to correct the measurements by accounting for the presence of these materials in signal processing.

[0046] FIG. 6 shows an axial cross-sectional view 600 of the drilling tubular 22 in an alternate embodiment. The body 302 includes a plurality of cavities at different circumferential locations. In one embodiment, the cavities are at the same axial location. As shown in the illustration, the body 302 includes three cavities 602a, 602b, 602c. The sensors are shown in a retracted position. The first cavity 602a includes first sensor 604a and first displacement device 606a. The second cavity 602b includes second sensor 604b and second displacement device 606b. The third cavity 602c includes third sensor 604c and third displacement device 606c. The cover sleeve 312 has a first arch 608a forming a first hollow space 610a over the first cavity 602a, a second arch 608b forming a second hollow space 610b over the second cavity 602b, and a third arch 608c formed a third hollow space 610c over the third cavity 602c. Each sensor 604a, 604b, 604c can be extended into their respective hollow spaces, either independently or simultaneously. Fluid displacers 614a, 614b, 614c can be located at the outer surface of the cover sleeve 312 at the azimuthal locations of their respective cavities 602a, 602b, 602c. Referring to the first cavity 602a for illustrative purposes, the first sensor 604a and the fluid displacer 614a are in a retracted position, with a gap 616 between its outer surface and the wall 330 of the borehole 26. A pump 618 and fluid conduit 620 are configured to move fluid into a piston 622 associated with the fluid displacer 614a. In one or more embodiments, the fluid displacer 614a can be inflated when its associated sensors 604a is extended. The fluid displacer 614a is a solid or rigid material. A hydraulic piston 622 can be located in the tubular at a location that does not interfere with obtaining measurements at the corresponding sensor. In another embodiment, the fluid displacer 614a can be flexible (e.g., inflatable / deflatable) and operated by pump 618.

[0047] FIG.7 shows an axial cross-sectional view 700 of the drilling tubular 22 of FIG.6 with the sensors 604a, 604b, 604c extended and the fluid displacers 614a, 614b, 614c extended but still providing gaps 616a, 616b, 616c, respectively, between fluid displacers 614a, 614b, 614c and the wall 330 of borehole 26. FIG.8 shows an axial cross-sectional view 800 of the drilling tubular 22 of FIG.6 with the sensors 604a, 604b, 604c in an65NUL-509925-WO-2 (INT1021PCT) extended position and the fluid displacer 614a, 614b, 614c in an extended position and closing the gaps 616a, 616b, 616c in FIG.7. That is, in FIG.8, fluid displacers 614a, 614b, 614c are shown to be in direct contact with the wall 330 of borehole 26. The pump 618 flows a fluid into the hydraulic piston 622 to extend the fluid displacer 614a against the wall 330 of the borehole 26. The fluid displacers 614a, 614b and 614c operated in the same manner in FIGS.6, 7 and 8. While FIG.7 and FIG.8 are shown with open or closed gaps 616a, 616b, 616c between fluid displacer 614a, 614b, 614c wall 330 of borehole 26, respectively, those skilled in the art will appreciate that not all of the fluid displacer 614a, 614b, 614c may be in the same state. That is, while one of the fluid displacer 614a, 614b, 614c may be in an extended position with one of the gaps 616a, 616b, 616c closed, another of the fluid displacer 614a, 614b, 614c may be in an extended position with the corresponding gap of the gaps 616a, 616b, 616c still open. Similarly, while one on of the fluid displacer 614a, 614b, 614c may be in an extended position (with the gaps 616a, 616b, 616c closed or open), another one of fluid displacer 614a, 614b, 614c may be in a retracted position.

[0048] FIG.9 shows a flowchart 900 or a method for obtaining a measurement in a borehole using the drill string disclosed herein. In box 902, the drill string is disposed in a borehole. The drill string includes a sensor in a body of the drill string and a cover sleeve over the sensor forming a hollow space between the drill string and the cover sleeve. In box 904, the sensor extends from a first radius position to a second radius position within the hollow space. In box 906, a measurement is obtained with the sensor at the second radial position. In box 908, the sensor is retracted from the hollow space back into the cavity of the body.

[0049] FIG. 10 shows a cross-sectional view 1000 of the body 302 in another embodiment. The drilling tubular 22 includes a body 302 having a body outer radius. A hollow bore 304 can pass through the body 302 along a longitudinal axis to allow for the flow of fluids. The body 302 may include the cavity 306 and the sensor 307 disposed in the cavity 306. The cover sleeve 312 is disposed around the body 302 at the axial location of the sensor 307 and shields the sensor 307 from the borehole environment. The cover sleeve 312 includes a first azimuthal section 1002 and a second azimuthal section 1004. The first azimuthal section 1002 extends circumferentially from a first section boundary 1006 to a second section boundary 1008 and does not cover the cavity 306. The second azimuthal section 1004 extends circumferentially from the first section boundary 1006 to the second section boundary 1008 and covers the cavity 306. The cover sleeve 312 has an inner radius IR, such as a single inner radius IR. The first azimuthal section 1002 of the cover sleeve 31265NUL-509925-WO-2 (INT1021PCT) has a first outer radius (indicated by OR1), such as a single first outer radius, and a first thickness t1. The second azimuthal section 1004 has a variable thickness between first section boundary 1006 and second section boundary 1008 and has a minimum thickness t2being less than the first thickness t1 of the first azimuthal section 1002. The minimum thickness t2is associated with a second outer radius (indicated by OR2) of cover sleeve 312. The outer surface of the second azimuthal section 1004 is depressed inward to create a hollow space 1010 between the cover sleeve 312 and the wall 330 of the borehole 26 (as noted, “hollow” in this context may refer to being occupied by material other than cover sleeve 312, for example, being occupied by drilling fluid). The minimum thickness t2(less than the first thickness t1) occurs at or close to the azimuthal location of the sensor 307.

[0050] The body 302 includes a rib 1020 that is located diametrically opposite the sensor. The rib 1020 is shown in a retracted position within a recess of the cover sleeve 312. A pump 1022 is included in the body 302. The pump 1022 pumps fluid through a fluid line 1024 to a hydraulic piston 1026 to control a fluid pressure at the piston. By increasing the fluid pressure, the hydraulic piston 1026 pushes outward on the rib 1020 to cause the rib 1020 to move to an extended position.

[0051] FIG. 11 shows a cross-sectional view 1100 of the body 302 of FIG. 10 with the rib 1020 in an extended position. By extending the rib 1020 outward and against the wall 330 of the borehole 26, the sensor 307 opposite the rib is pushed against the opposite wall, thereby reducing a distance between sensor 307 and formation 60.

[0052] Set forth below are some embodiments of the foregoing disclosure:

[0053] Embodiment 1. A work string configured to obtain a measurement in a borehole in an earth formation. The work string includes a tubular body, a cavity in the tubular body at a selected axial location, a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity, and a sensor in the cavity.

[0054] Embodiment 2. The work string of any prior embodiment, wherein an inner surface of the cover sleeve in the second azimuthal section forms an arch that forms a hollow core radially outside of the cavity.

[0055] Embodiment 3. The work string of any prior embodiment, further comprising a displacement device in the cavity for extending the sensor radially.

[0056] Embodiment 4. The work string of any prior embodiment, further comprising a fluid displacer in the second azimuthal section on an outer surface of the cover sleeve.65NUL-509925-WO-2 (INT1021PCT)

[0057] Embodiment 5. The work string of any prior embodiment, wherein the fluid displacer includes at least one of: (i) a wear-resistant material; and (ii) a nanoparticle composite material.

[0058] Embodiment 6. The work string of any prior embodiment, further comprising a pump in the tubular body for pumping a fluid into the fluid displacer.

[0059] Embodiment 7. The work string of any prior embodiment, further comprising an extendable rib on the cover sleeve diametrically opposite the sensor.

[0060] Embodiment 8. The work string of any prior embodiment, wherein the hollow space is filled with at least one of: (i) a liquid; (ii) a gas; (iii) a foam; (iv) a sponge; and (v) an elastomer.

[0061] Embodiment 9. A method of obtaining a measurement in a borehole in an earth formation. A work string is disposed in the borehole, the work string including a tubular body, a cavity in the tubular body at a selected axial location, a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity, and a sensor in the cavity. A measurement is obtained using the sensor.

[0062] Embodiment 10. The method of any prior embodiment, wherein an inner surface of the cover sleeve in the second azimuthal section forms an arch that forms a hollow space radially outside of the cavity.

[0063] Embodiment 11. The method of any prior embodiment, wherein the cavity includes a displacement device, the method further comprising activating the displacement device to extend the sensor radially.

[0064] Embodiment 12. The method of any prior embodiment, wherein the work string further comprises a fluid displacer in the second azimuthal section, the method further comprising inflating the fluid displacer into an annulus over the second section.

[0065] Embodiment 13. The method of any prior embodiment, wherein the fluid displacer includes at least one of: (i) a wear-resistant material; and (ii) a nanoparticle composite.

[0066] Embodiment 14. The method of any prior embodiment, further comprising extending a rib on the cover sleeve diametrically opposite the sensor against a wall of the borehole.65NUL-509925-WO-2 (INT1021PCT)

[0067] Embodiment 15. The method of any prior embodiment, wherein the hollow space is filled with at least one of: (i) a liquid; (ii) a gas; (iii) a foam; (iv) a sponge; and (v) an elastomer.

[0068] The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms “about”, “substantially” and “generally” are intended to include the degree of error associated with measurement of the particular quantity based upon the equipment available at the time of filing the application. For example, “about” and / or “substantially” and / or “generally” can include a range of ± 8% of a given value.

[0069] The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a borehole, and / or equipment in the borehole, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

[0070] While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.

Claims

65NUL-509925-WO-2 (INT1021PCT) What is claimed is:

1. A work string configured to obtain a measurement in a borehole in an earth formation, comprising: a tubular body; a cavity in the tubular body at a selected axial location; a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity; and a sensor in the cavity.

2. The work string of claim 1, wherein an inner surface of the cover sleeve in the second azimuthal section forms an arch that forms a hollow space radially outside of the cavity.

3. The work string of any of claims 1 and 2, further comprising a displacement device in the cavity for extending the sensor radially.

4. The work string of any of claims 1-3, further comprising a fluid displacer in the second azimuthal section on an outer surface of the cover sleeve.

5. The work string of claim 4, wherein the fluid displacer includes at least one of: (i) a wear-resistant material; and (ii) a nanoparticle composite material.

6. The work string of any of claims 4 and 5, further comprising a pump in the tubular body for pumping a fluid into the fluid displacer.

7. The work string of any of claim 1-6, further comprising an extendable rib on the cover sleeve diametrically opposite the sensor.

8. The work string of claim 2, wherein the hollow space is filled with at least one of: (i) a liquid; (ii) a gas; (iii) a foam; (iv) a sponge; and (v) an elastomer.

9. A method of obtaining a measurement in a borehole in an earth formation, comprising: disposing a work string the borehole, the work string including a tubular body; a cavity in the tubular body at a selected axial location; a cover sleeve that covers the tubular body at the selected axial location, the cover sleeve having a first azimuthal section having a first thickness and a second azimuthal section having a second thickness less than the first thickness, wherein the second azimuthal section covers the cavity; and65NUL-509925-WO-2 (INT1021PCT) a sensor in the cavity; and obtaining the measurement using the sensor.

10. The method of claim 9, wherein an inner surface of the cover sleeve in the second azimuthal section forms an arch that forms a hollow space radially outside of the cavity 11. The method of any of claims 9 or 10, wherein the cavity includes a displacement device, the method further comprising activating the displacement device to extend the sensor radially.

12. The method of any of claims 9-11, wherein the work string further comprises a fluid displacer in the second azimuthal section, the method further comprising inflating the fluid displacer into an annulus over the second section.

13. The method of claim 12, wherein the fluid displacer includes at least one of: (i) a wear-resistant material; (ii) a nanoparticle composite.

14. The method of any of claims 9-13, further comprising extending a rib on the cover sleeve diametrically opposite the sensor against a wall of the borehole.

15. The method of claim 9, wherein the hollow space is filled with at least one of: (i) a liquid; (ii) a gas; (iii) a foam; (iv) a sponge; and (v) an elastomer.

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