Electromagnetic telemetry gap joint

Abstract

A downhole tool and a method of assembly. The sleeve is moved along a longitudinal axis of the first joint to radially surround an inner mandrel of the first joint extending along the longitudinal axis. The gap joint is moved along the longitudinal axis to be disposed about the extended portion of the inner mandrel, wherein the gap joint includes a non-conductive material. The gap joint is configured to electrically separate a first joint from a second joint of the downhole tool. The locking nut is fixedly connected to the inner mandrel so that the gap connector can be fixed to the sleeve.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of the earlier filing date of U.S. application serial number 63 / 481,602, filed on January 25, 2023, the entire disclosure of which is incorporated herein by reference. Background Art

[0003] In the resource recovery industry, a work string may be set in a borehole for drilling, formation testing, oil production, etc. The work string may have a bottom hole assembly (BHA) for performing various electrical tests downhole. The BHA may include a first joint and a second joint connected to each other. Typically, an insulator is set at the connection between the first joint and the second joint, usually within a threaded connection between adjacent joints. This insulator is not ideal because it is difficult to maintain and is easily damaged when the BHA is disassembled for inspection or maintenance purposes. Therefore, it is necessary to be able to connect adjacent joints in a more reliable and maintainable insulating configuration. Summary of the Invention

[0004] In one embodiment, a downhole tool for a bottom hole assembly for use in a wellbore is disclosed. The downhole tool includes a voltage source comprising a first pole electrically connected to a first portion of the bottom hole assembly and a second pole electrically connected to a second portion of the bottom hole assembly. The first portion and the second portion are electrically separated by a non-conductive material between the first portion and the second portion. The first portion includes a housing defining an exterior housing surface of the first portion, and the second portion includes an inner core shaft and a locking nut fixedly connected to the inner core shaft. The locking nut secures the non-conductive material to the housing.

[0005] In another embodiment, a method of assembling a downhole tool adapted for use in a wellbore is disclosed. The method includes: moving a sleeve along a longitudinal axis of a first joint to radially surround an inner mandrel of the first joint extending along the longitudinal axis; moving a gap joint along the longitudinal axis to be disposed around an extended portion of the inner mandrel, wherein the gap joint comprises a non-conductive material, the gap joint being configured to electrically isolate the first joint from a second joint of the downhole tool; and fixedly connecting a lock nut to the inner mandrel to secure the gap joint to the sleeve. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The following description should not be considered limiting in any way. Referring to the drawings, similar elements are numbered similarly:

[0007] Figure 1 A working string in an exemplary embodiment is shown;

[0008] Figure 2A side view of a portion of a bottom hole assembly of a work string is shown;

[0009] Figure 3 Shown Figure 2 a cross-sectional view of a portion of the bottom hole assembly shown in;

[0010] Figure 4 A close-up cross-sectional view of a downhole telemetry unit is shown, illustrating components thereof;

[0011] Figure 5A shows a side view of a bottom hole assembly depicting the electric field and the path of current flowing from one end of the bottom hole assembly to the other;

[0012] Figure 5B A downhole telemetry device is shown in an exploded view showing two separate and electrically isolated sides of the downhole telemetry device;

[0013] Figure 6 A method for assembling a bottom hole assembly in one embodiment is shown;

[0014] Figure 7 shows a close-up view of a portion including a friction pad in one embodiment;

[0015] Figure 8 The steps for preparing the push portion of the pretensioning device are shown;

[0016] Figure 9 shows a first step for preparing the pulling portion of the pretensioning device;

[0017] Figure 10 The second step for preparing the pulling portion of the pretensioning device is shown;

[0018] Figure 11 shows a side view of the pretensioning device in an assembled state; and

[0019] Figure 12 Shows the steps for securing a lock nut using a pre-tensioning device. DETAILED DESCRIPTION

[0020] A detailed description of one or more embodiments of the apparatus and methods disclosed herein is presented by way of example and not limitation with reference to the accompanying figures.

[0021] refer to Figure 1In the exemplary embodiment, a drilling system 100 is shown having a work string 102. The work string 102 can be a drill string, a production string, a completion string, a cable string, or any other suitable string used in industrial applications. The work string 102 extends from a platform 106 at a surface location 108 into a borehole 104 in a formation 105. The work string 102 includes a plurality of tubular joints 110 axially connected to one another. A bottom hole assembly (BHA 112) is disposed at the bottom end of the work string 102. The BHA 112 and the work string define an annulus 127 between the BHA 112 / work string 102 and an inner wall 128 of the borehole 104. The annulus 127 is typically filled with drilling mud pumped from the BHA 112 and the annulus 127. The BHA 112 includes a downhole telemetry device 114 that communicates with a surface telemetry device 116 at the platform 106. The downhole telemetry device 114 can transmit electromagnetic signals through the formation 105 and / or along the work string 102 for reception at the surface telemetry device 116. The downhole telemetry device 114 can also receive electromagnetic signals transmitted downhole by the surface telemetry device 116 along the work string 102 and / or through the formation 105. The downhole telemetry device 114 includes a gap 115 that electrically isolates the lower portion of the BHA 112 (the downhole section of the gap 115) from the upper portion of the BHA 112 (the uphole section of the gap 115) and the work string 102, which is typically electrically connected to the upper portion of the BHA via a threaded connection of conductive material commonly used for such operations. The surface telemetry device 116 can include and be connected to one or more antenna devices 118 that are connected to the formation 105 and are connected thereto.

[0022] By using a voltage source 117, the voltage source is electrically connected with its primary pole 122 to the BHA 112 located below the gap 115, and with its secondary pole 121 to the upper portion of the BHA 112 (the uphole section of the gap 115), and thus also to the work string 102. By alternating the polarity of the voltage source 117, an alternating electric field 120 and an alternating current can be induced into the formation, as depicted by the electric field lines 120 and depending on the conductivity of the surrounding wellbore fluid and the formation 105. The alternating current signal (and accordingly, the alternating electric field 120) propagates through the formation 105 and / or along the work string 102 and is detected by the antenna device 118 and the surface telemetry device 116.

[0023] Figure 2A side view 200 of a portion of the downhole telemetry system 114 of the BHA 112 is shown. The side view 200 includes a first joint 202 and a second joint 204 of the downhole telemetry system 114 connected by a gap joint 206. The first joint 202 may be an upper joint, and the second joint 204 may be a lower joint. Thus, when the work string 102 is positioned in the borehole 104, the first joint 202 is positioned uphole from the second joint 204. The first joint 202 includes a top portion 208 and a sleeve 210 disposed around the lower portion. The gap joint 206 includes a housing 212 that defines the outer diameter of the gap joint 206. The sleeve 210 is electrically isolated from the top portion 208 by a shoulder ring 214 and from the housing 212 by a shoulder ring 216.

[0024] Figure 3 Shown Figure 2 300 of a portion of the BHA 112 shown in FIG. The first joint 202 may include one or more compartments 302 that may include electronic components and / or batteries, capacitors, voltage sources, or other power sources that may be used to power elements in the second joint 204. In one embodiment, the second joint 204 may include various sensors and devices of the BHA 112 that may operate using power from a power source, such as a power source in the compartments 302 of the first joint 202. Shoulder rings 214, 216, and 428 ( Figure 4 ) is used to separate the electronic components to achieve axial isolation. The radial isolation is achieved by the components (ie, the top portion 208, the sleeve 210, the housing 212, the locking nut 422 ( Figure 4 ), the second joint 204) via the guide rings 230, 231, 232 and 233, 234, 235 ( Figure 4 ) and the inner core shaft 402 ( Figure 4 ) to achieve physical radial separation, thereby creating a non-conductive radial (air) gap. The guide rings 230, 231, 232, 233, 234 and 235 also center the components. The components of the gap joint 206 are Figure 3 Shown and referenced in Figure 4 Further detailed discussion.

[0025] Figure 4 A close-up cross-sectional view 400 of the gap joint 206 is shown, illustrating the components thereof. The first joint 202 includes an inner mandrel 402 surrounded by a sleeve 210. An extension portion 404 of the inner mandrel 402 extends axially beyond one end of the sleeve 210. The extension portion 404 includes a cylindrical bore 406 therethrough for flow of wellbore fluid (e.g., drilling mud). The outer surface of the extension portion 404 includes a threaded portion 408. The threaded portion 408 can be disposed along a tapered portion 410 of the extension portion 404.

[0026] The housing 212 is disposed around the extension 404. The housing 212 is an outer shell, such as a cylindrical shell, that includes an outer clamping shoulder 412 and an inner clamping shoulder 414. The outer clamping shoulder 412 includes a recess radially inward from the outer surface of the housing 212, which forms a ridge facing the first joint 202. The inner clamping shoulder 414 is formed at the inner surface of the housing 212 and includes a recess radially outward, which forms a ridge facing the second joint 204. The top end 416 of the housing 212 fits into the gap 437 between the extension 404 and the sleeve 210. The middle portion 418 of the housing 212 forms a gap 420 with the extension 404 of the inner core shaft 402. The gaps 437 and / or 420 can be filled with a fluid, such as drilling mud, air, or oil, which, in embodiments, can be an insulating fluid.

[0027] A locking nut 422 is disposed in a gap 420 between the housing 212 and the extension 404. The locking nut 422 is a housing, such as a cylindrical housing, that includes a threaded portion 424 along its inner surface and a groove portion 426 along its inner surface. The threaded portion 424 extends along a tapered portion 427 of the locking nut 422. The threaded portion 424 is threadably coupled to the threaded portion 408 of the extension 404 to mate the locking nut 422 with the extension 404. The taper angle of the threaded portion 424 of the locking nut 422 is the same as the taper angle of the threaded portion 408 of the extension 404.

[0028] In various embodiments, the locking nut 422 can be a housing, two half-shells, a snap ring, a bayonet connection, a pin, or the like. The locking nut 422 is sized to fit within the housing 212. Thus, the outer locking nut diameter is smaller than the outer housing surface diameter (i.e., the diameter of the outer surface of the housing 212) and can be smaller than the outer sleeve diameter (i.e., the diameter of the outer surface of the sleeve 210). Using a locking nut eliminates the need to separate the threads by a plastic or ceramic layer. Consequently, no insulating component (such as plastic, epoxy, etc.) is used as part of the load-bearing portion of the threaded portion 424. During assembly of the telemetry device 114, threaded portions (such as the threaded portion 424) are subject to high friction forces when connected at sufficiently high torque. During assembly of the telemetry device 114, such high friction forces can ultimately damage insulating components or coatings, which are typically materials weaker than steel. The present disclosure describes a telemetry device that includes a gap 115 and does not contain any insulating components or coatings that are subject to high friction forces during assembly or other processes. In particular, the present disclosure discloses a telemetry device that includes electrically isolated components, connectors, or portions (i.e., components, connectors, or portions separated by a non-conductive material) connected to one or more threads (such as threaded portions 424 and 408), wherein the mating surfaces of the one or more threads are in direct electrical contact without any conductive material or other insulating components disposed between the corresponding mating surfaces of the threads. In one or more embodiments, during assembly, no insulating components in the telemetry device 114 are subject to frictional forces that are zero or one thousandth or more (such as one thousandth or more, or even one hundredth or more) of the highest frictional force that occurs between any conductive components during assembly of the telemetry device 114. As a result, the downhole telemetry device 114 is structurally robust at high temperatures and provides high reliability and simplified maintenance.

[0029] Shoulder ring 216 is disposed in a radially inward recess between outer clamping shoulder 412 and sleeve 210. Inner shoulder ring 428 is disposed in a radially outward recess between inner clamping shoulder 414 and lock nut 422. Shoulder rings 214, 216, 428 are at least partially made of or coated with an insulating or non-conductive material, such as ceramic or another suitable insulating material or coating. Alternatively or in addition, one or more of clamping shoulders 412, 413 and 414, 415 may be at least partially made of or coated with an insulating material. One or more friction pads 439 may be disposed adjacent to and in contact with one or both of the one or more shoulder rings 214, 216, 428 and may contact one or more of the corresponding clamping shoulders 412, 413 and 414, 415. In one embodiment, a torque sleeve 489 may be disposed adjacent to friction pads 439 and / or shoulder ring 428. The torque sleeve 489 may include an anti-rotation element 491, such as a parallel wedge guided by a groove in the inner mandrel 402. The groove in the inner mandrel 402 may be parallel to the longitudinal axis of the inner mandrel 402 to allow the anti-rotation element 491 to move in an axial direction while preventing rotational movement of the torque sleeve 489 relative to the inner mandrel 402. Alternatively or in addition, the one or more friction washers 439 may include one or more similar anti-rotation elements that allow the one or more friction washers 439 to move in an axial direction while preventing rotational movement of the torque sleeve 489 relative to the inner mandrel 402. By means of the torque sleeve 489 and / or the anti-rotation element 491 or friction washers 439 on the torque sleeve 489, rotational friction movement on surfaces including non-conductive materials, such as the shoulder ring 428, may be prevented, thereby contributing to greater reliability of the gap joint 206.

[0030] The bottom end 430 of the housing 212 is coupled to the second connector 204. The pin end 432 of the second connector 204 fits into the gap 420 between the housing 212 and the extension 404 of the inner mandrel 402. A threaded portion 434 of the pin end 432 screws into a complementary threaded portion 436 on the bottom end 430 of the housing 212 to secure the second connector 204 to the housing 212. The pin end 432 includes a hole 438 therethrough. The tip 440 of the extension 404 includes an electrical contact 442 on its outer surface. When the pin end 432 is secured to the housing 212, the tip 440 is inserted into the hole 438, and the electrical contact 442 forms an electrical connection with a complementary electrical contact 444 on the inner surface of the pin end 432. The electrical contact 444 is further connected to the lower portion of the BHA 112. Electrical contacts 444 can provide power and communication between the electrical upper and lower portions, which are otherwise electrically isolated by gap 115 (i.e., one or more of gaps 437, 420, insulating shoulder rings 214, 216, 428, friction pads 439, and / or guide rings 230, 231, 232, 233, 234, 235). Second sub 204 includes holes (not shown) to route electrical wires from electrical contacts 444 to downhole electronics in the downhole section of gap 115 at BHA 112. Although two electrical contacts are shown, one contact may be sufficient to operate downhole telemetry device 114. If only one electrical contact 442 , 444 is used, it is used to electrically connect the main pole 122 (the connection to the casing ground of the lower portion of the BHA 112 ) to a voltage source 117 , which is located in a compartment 302 in the uphole section of the gap 115 , or may be located in a similar compartment in the lower portion of the BHA 112 .

[0031] More than one pair of electrical contacts 442 , 444 may be used to transmit power and / or information across the gap 115 , including bidirectional transmission to directional sensors or other sensors within the BHA 112 . Figure 2 5 preferably houses the power supply (e.g., battery, voltage source, capacitor) and communication electronics in a compartment 302 within the inner mandrel 402 and, when assembled, is covered by the sleeve 210. The secondary pole 121 (connected to the upper portion of the BHA 112 (the uphole section of the gap 115) is formed by connecting the EM electronics located in the compartment 302 to the steel body of the top section 208 (e.g., by using ground screws (not shown) within the compartment 302). Figure 1 ) to achieve connection with the grounding part of the shell 212 in the upper section of the well.

[0032] Main pole 122, located downhole in gap 115 and electrically connected to the lower portion of BHA 112, is connected to the EM electronics located in compartment 302 via at least one of electrical contacts 442, 444. This electrical contact, in turn, is connected to the housing ground of joint 204 (or any other component electrically connected to the lower portion of BHA 112) using, for example, a ground screw connected to the pin face of second joint 204 at compartment 302 (the seal area). Alternatively, the system can be connected to an AC generator instead of or in conjunction with other power sources (e.g., a voltage source, capacitor, battery). In one or more embodiments, the electronics compartment can be positioned downhole relative to gap 115 by swapping the male and female connections of telemetry device 114. While telemetry device 114 is discussed as using two electrical contacts 442, 444, in alternative embodiments, more than two electrical contacts may be used. In one or more embodiments, electrical contacts 442, 444 may be ring contacts.

[0033] Cap 446 can be located at tip 440, and internal insulating ring 448 can be arranged around cap 446. One or more surfaces of cylindrical hole 406, hole 438, internal insulating ring 448 and cap 446 can be coated or sleeved to provide insulation to prevent electrical short circuit between the first joint 202 and the second joint 204 due to the possible flow of charged fluid (e.g., charged wellbore fluid). In an alternative embodiment, cap 446 and / or internal insulating ring 448 can be made of insulating (i.e., non-conductive) material. Alternatively, an elongated non-conductive tube (e.g., plastic, rubber, ceramic) (not shown) can be assembled to the interior of telemetry device 114 to provide a long non-conductive path between the interior of gap 115 and the two electrical sides. Cap 446 carries insulating ring 448 in turn, and insulating ring is preferably also made of high-strength and non-conductive material, such as ceramic. The high strength of the insulating ring 448 forms a sealed cavity that resists downhole pressure, which can reach very high levels. Figures 2 to 4 As can be seen in FIG. 4 , one or more seals 419 may be used to provide a fluid-tight seal and enclose the compartment around the contact ring and gap member.

[0034] Figure 5AA side view 500 of downhole telemetry device 114 is shown, illustrating the electrical pathways that can be generated for telemetry. When the upper portion of BHA 112 is set to a defined and different voltage than the lower portion of BHA 112 (i.e., gap sub 206 and second sub 204), and assuming that the formation 105 and wellbore fluid have a certain conductivity, different electric fields and current paths exist to the wellbore and formation, as shown in FIG5 a. Electric fields 502 and 504 correspond to the short gap 115, while electric field 506 corresponds to the long gap 115. The existence of electric field 506 assumes that sleeve 210 is not connected to inner mandrel 402 (i.e., they are separated by shoulder rings 214, 216 and radial guide rings 230, 231), that the outer diameter of the sleeve is in direct contact with the wellbore fluid and / or formation, and that at least a portion of its outer surface is non-conductive (i.e., made of a non-conductive material or covered with a non-conductive coating). The length of gap 115 is a parameter that defines the quality of the gap joint and affects the quality of the electromagnetic telemetry generated by the different voltages connected to the upper and lower portions of BHA 112. For short-distance gaps using electric fields 502 and / or 504, the typical axial length of shoulder rings 214, 216 is between 1 mm and 50 mm. The length of gap 115 is primarily determined by the length of the isolated portion of sleeve 210 and can range from a few millimeters to over 2000 mm. For short-distance gaps, first and second electric fields 502, 504 can be generated that extend through the wellbore fluid and / or formation 105 over a relatively short distance. For long-distance gap arrangements, electric field 506 can be generated that extends through the wellbore fluid and / or formation 105 over a relatively long distance. For short-distance gap arrangements, first electric field 502 extends from casing 212 to sleeve 210, and second electric field 504 extends from sleeve 210 to top portion 208. Shoulder ring 214 and shoulder ring 216 provide electrical insulation between the respective components to allow the generation of first electric field 502 and second electric field 504. In this case, the actual electrical gap length is the sum of the lengths of shoulder rings 214 and 216. For a long-distance gap arrangement, electric field 506 extends from housing 212 of gap joint 206 to top portion 208 of first joint 202, bypassing sleeve 210 because the sleeve is electrically insulated by a non-conductive layer (not shown) on the exterior. The non-conductive layer can be made of a thermoplastic coating, paint, ceramic coating, metal passivation layer (e.g., phosphated, oxidized, oxide layer), etc. Such a layer provides a thin layer with a lower electrical conductivity than the surrounding wellbore fluid, thereby generating a long-distance gap 115.

[0035] Figure 5B Shown are an upper portion 550 and a lower portion 560 created by gap 115. Upper portion 550 is connected to the uphole end of BHA 112 and work string 102, and lower portion 560 is connected to the downhole end of BHA 112. Figure 5BThe upper and lower portions of the BHA 112 are shown at different electrical potentials (thereby creating a potential difference or voltage between them) and are typically physically connected internally via a metal-to-metal connection. For ease of reference, the upper and lower portions are shown disconnected. Specifically, the outer surface 551 of the upper portion 550 and the outer surface 561 of the lower portion 560 are at different electrical potentials and are in direct (electrical) contact with the drilling fluid in the annulus 127 and / or the inner wall 128 of the borehole 104. The upper portion 550 is electrically connected to one electrical potential via the secondary electrode 121. The lower portion 560 is electrically connected to a second electrical potential via the primary electrode 122. The sleeve 210 can be individually separated and electrically disconnected to achieve better gap performance. However, this is not required to create electrical gaps. Two electrically isolated portions of the BHA are established when the upper portion 550 and lower portion 560 of the BHA 112 are engaged by the clamping shoulders 412, 413 and 414, 415 (each separated by a corresponding shoulder ring 216 and 428) and the compressive loads generated by the lock nut 422. Axial, torsional, and bending loads are transferred through the clamping shoulders 412, 413 and 414, 415 and the corresponding shoulder rings 216 and 428.

[0036] Figures 5a and 5b depict electrical separation of the housing components. The housing components can be electrically connected to a voltage source 117 via corresponding connectors to poles 121 and 122. The higher the potential difference or voltage across gap 115, the greater the amplitude of the electric field and the current flowing through the formation, and the greater the signal (depicted by electric field lines 120). The maximum amplitude of the electric field across the gap and / or the current flowing through the formation depends on the conductivity of the formation and wellbore fluid, and is also limited by the power available to drive voltage source 117. The typical voltage across the gap ranges from 5V to 100V.

[0037] Figure 6 A method 600 for assembling the BHA 112, and more specifically the downhole telemetry device 114, in one embodiment is shown. In a first step (step 1), the shoulder ring 214 is slid onto the extension 404 of the inner mandrel 402. The sleeve 210 is then slid onto the extension 404 so that the shoulder ring 214 is sandwiched between the sleeve 210 and the top portion 208. The shoulder ring 214 provides electrical insulation axially between the top portion 208 and the sleeve 210. In a second step (step 2), the shoulder ring 216 is slid onto the extension 404. The housing 212 is then slid onto the extension 404 to sandwich the shoulder ring 216 between the housing 212 and the sleeve 210. The shoulder ring 216 provides electrical insulation axially between the housing 212 and the sleeve 210.

[0038] In the third step (step 3), the inner shoulder ring 428 is slid into the gap between the extension 404 and the housing 212. The locking nut 422 is slid over the extension 404 to sandwich the inner shoulder ring 428 between the locking nut 422 and the housing 212. The inner shoulder ring 428 provides electrical insulation axially between the locking nut 422 and the housing 212.

[0039] In a fourth step (step 4), a torque tool 602 is placed in the recessed portion 426 of the locking nut 422 and rotated to tighten the locking nut 422 onto the extension 404. When the locking nut 422 has been tightened to a specified or desired torque value, the torque tool 602 can be removed. Some or all components are centrally controlled by guide rings (such as non-conductive guide rings 230, 231, 232, 233, 234, 235), and therefore, there are no radial contact points between conductive surfaces (such as metal surfaces). The housing 212 is electrically isolated from the other components (208, 210, 422). In a fifth step (step 5), the second connector 204 can be threadedly attached to the female threads of the housing 212 and engaged to the extension 404 to form a seal with the non-conductive insulating ring 448.

[0040] In the fully assembled downhole telemetry device 114, torque is transmitted from the second joint 204 to the first joint 202 via the housing 212, the extension 404, the locking nut 422, the sleeve 210, etc. When the locking nut is connected to the extension 404, rotation may occur at the clamping shoulders 415 and / or 414 on either side of the inner shoulder ring 428 due to the smaller radius of the clamping shoulders 415 and / or 414 compared to other shoulders adjacent to the shoulder rings 214 and 216. In addition, the use of the locking nut 422 enables the use of one or more friction pads 439 between the elements along the outer radius (e.g., on either side of the shoulder rings 214 and 216). In various embodiments, the friction pads 439 may be ceramic rings, surface-coated metal rings, etc.

[0041] Friction pads 439 create high friction at the contact areas. Friction pads placed between adjacent components increase the torque transfer capacity between those components. In one embodiment, the torque transfer capacity using friction pads is four to eight times greater than the torque transfer capacity between lubricated contacts. Thus, friction pads reduce the shoulder compression required during assembly of telemetry device 114 to prevent slippage between components, such as between shoulder rings 214, 216, 428 and corresponding clamping shoulders 412, 413 and 414, 415. Because the shoulder compression requirement is lower during assembly of telemetry device 114, the contact pressure between shoulder rings 214, 216, 428 and adjacent components is lower, and the torque requirement for the internal lock nut is reduced, thereby reducing the space required for lock nut 422.

[0042] Figure 7 A close-up view 700 of a portion of a structure including, in one embodiment, a friction pad 702 (such as one or more of friction pads 439) is shown. The friction pad 702 is disposed between a first component 704 and a second component 706 and is typically compressed therebetween. In one or more embodiments, the first component 704 can be a shoulder ring (such as shoulder rings 214, 216, 428), and the second component 706 can be a clamping shoulder (such as clamping shoulders 412, 413 and 414, 415). The friction pad 702 can include a steel core 708 and a matrix layer 710, such as a relatively thin nickel matrix layer to form a nickel surface. Particles (e.g., diamond particles) 712 can be embedded in the matrix layer 710 and protrude outward from the friction pad 702. The particles 712 maintain a micro-gap 714 between the friction pad 702 and the first component 704 and / or the second component 706. The particles provide a high coefficient of friction between the friction pad 702 and the first component 704 and / or the second component 706. In the downhole telemetry device 114, the first component 704 may be one of the shoulder rings 214 and 216, and the second component 706 may be one of the housing 212, the sleeve 210, or the first joint 202 at the top portion 208.

[0043] Figures 8 to 12 A method for assembling a downhole telemetry device 114 using a pre-tensioning device 1001 is shown. The pre-tensioning device 1001 pushes the inner core shaft in a first direction while simultaneously pulling an outer component (i.e., sleeve 210, etc.) in a second direction opposite to the first direction. By applying tension to the inner core shaft 402, the locking nut 422 can be more easily secured to the inner core shaft 402 while reducing the torque required for assembly between the non-conductive component and other components when frictionally contacting.

[0044] Figure 8Step 800 is shown for preparing the push portion 1003 of the pretensioning device 1001. With the shoulder ring 216, housing 212, inner shoulder ring 428 and locking nut 422 sliding over the extension 404, the push rod receiver 802 and push plug 804 are installed in the locking nut 422.

[0045] Figure 9 1. The first step 900 for preparing the pulling portion 1005 of the pretensioning device 1001 is shown. A pulling housing 902, an inner cap 904, and an outer cap 906 are mounted on the exterior of the housing 212 and the first joint 202. The inner cap 904 and the outer cap 906 clamp the pulling housing 902 to the housing 212. The pulling housing 902 extends above the sleeve 210 and is clamped, threaded, or otherwise connected to the first joint 202 at the top portion 208. The pulling housing 902 includes a threaded portion 908.

[0046] Figure 10 A second step 1000 is shown for preparing the pulling portion 1005 of the pretensioning device 1001. An actuator device 1002 (such as a hydraulic actuator, an electric actuator, etc.) is threadedly secured to the pulling housing 902 at the threaded portion 908. The actuator device 1002 includes a push rod 1004. When the actuator device 1002 is secured in place, the push rod 1004 extends through the cylindrical bore 406 of the inner mandrel 402 to contact the push rod receiving portion 802.

[0047] Figure 11 A side view 1100 of the pretensioning device 1001 in an assembled state is shown. Actuation of the actuator device 1002 produces an extension of the extension portion 404 of the inner mandrel 402 (via pushing 1102) and / or a compression of the sleeve 210 (via pulling 1104).

[0048] Figure 12 A side view 1200 is shown illustrating the steps of securing the locking nut 422 using the pretensioning device 1001. With the extension 404 of the inner mandrel 402 extended and / or the sleeve 210 compressed, the torque tool 602 is used to apply the desired torque to the locking nut 422. Once the locking nut 422 is secured to the desired torque value, the torque tool 602 can be removed. The actuator device 1002 is deactivated to remove any tension (i.e., the push 1102 and pull 1104 are removed). The pretensioning device 1001 can then be disassembled and the BHA removed.

[0049] Advantages of the described configuration of the locking nut connection include a low-friction assembly of all components comprising insulating materials. The locking nut 422 can be assembled with minimal torque (e.g., by hand) and, therefore, with minimal sliding friction between the non-conductive components and the other components because the axial tension is generated by the pretensioning device 1001. In one or more embodiments, the telemetry device 114 can be assembled by torqueing the locking nut 422 onto the extension 404 of the inner core shaft 402 without generating friction on the shoulder ring 428 and / or friction washer 439 during assembly, with the friction being zero or one thousandth or more (such as one thousandth or more, or even one hundredth or more) of the highest friction that occurs between any conductive components during assembly of the telemetry device 114. In alternative embodiments, the telemetry device 114 can be assembled by torqueing the locking nut 422 onto the extension 404 of the inner core shaft 402 without generating any friction on the shoulder ring 428 and / or friction washer 439 or any other components comprising non-conductive materials.

[0050] Instead of using friction pads 702 on either side of the shoulder rings 214, 216, 428, the shoulder rings 214, 216, 428 can alternatively be coated with a high-friction coating, thereby embedding diamond particles 712 in the matrix layer 710. Thus, the coated shoulder rings 214, 216, 428 can be used without friction pads on either side, yet have similar advantages in terms of torque transfer capability. In alternative embodiments, in addition to using friction pads, any friction-enhancing coating, powder, particle, glue, epoxy, or adhesive can be used to increase torque transfer capability over a version without friction-enhancing components.

[0051] Some embodiments of the aforementioned disclosure are shown below:

[0052] Embodiment 1. A downhole tool having a bottom hole assembly for use in a wellbore. A voltage source includes a first electrode electrically connected to a first portion of the bottom hole assembly and a second electrode electrically connected to a second portion of the bottom hole assembly. The first portion and the second portion are electrically separated by a non-conductive material between the first portion and the second portion. The first portion includes a housing defining an exterior housing surface of the first portion, and the second portion includes an inner core shaft and a locking nut fixedly connected to the inner core shaft. The locking nut secures the non-conductive material to the housing.

[0053] Embodiment 2. A downhole tool according to any preceding embodiment, wherein the locking nut has an external locking nut diameter and the external housing surface has an external housing surface diameter that is greater than the locking nut diameter.

[0054] Embodiment 3. The downhole tool according to any preceding embodiment, further comprising at least one friction pad axially disposed between the housing and the second portion.

[0055] Embodiment 4. The downhole tool according to any of the preceding embodiments further includes a torque sleeve axially disposed between the locking nut and the non-conductive material, the torque sleeve including an anti-rotation element that prevents the torque sleeve from rotating relative to the inner core shaft.

[0056] Embodiment 5. A downhole tool according to any preceding embodiment, wherein the locking nut is fixedly connected to the inner core shaft by threads.

[0057] Embodiment 6. A downhole tool according to any preceding embodiment, wherein the locking nut secures the non-conductive material at least in part by clamping.

[0058] Embodiment 7. The downhole tool according to any preceding embodiment, wherein the friction pad comprises particles located at one or more surfaces of the friction pad.

[0059] Embodiment 8. A downhole tool according to any preceding embodiment, wherein the friction pad includes an anti-rotation element that prevents the friction pad from rotating relative to the inner core shaft.

[0060] Embodiment 9. A downhole tool according to any preceding embodiment, wherein the thread comprises two mating surfaces, and wherein the mating surfaces are in electrical contact.

[0061] Embodiment 10. The downhole tool according to any preceding embodiment, wherein the housing and / or the second portion directly contacts the drilling fluid in the annulus between the wall of the wellbore and the downhole tool.

[0062] Embodiment 11. The downhole tool according to any preceding embodiment, further comprising a sleeve, wherein the inner core shaft is disposed within the sleeve, and wherein the sleeve is electrically isolated from the inner core shaft.

[0063] Embodiment 12. A downhole tool according to any preceding embodiment, wherein the non-conductive material comprises one or more insulating rings.

[0064] Embodiment 13. A method of assembling a downhole tool adapted for use in a wellbore, the method comprising: moving a sleeve along a longitudinal axis of a first joint to radially surround an inner mandrel of the first joint extending along the longitudinal axis; moving a gap joint along the longitudinal axis to be disposed around an extended portion of the inner mandrel, wherein the gap joint comprises a non-conductive material, the gap joint being configured to electrically isolate the first joint from a second joint of the downhole tool; and fixedly connecting a lock nut to the inner mandrel to secure the gap joint to the sleeve.

[0065] Embodiment 14. The method according to any of the preceding embodiments further includes: compressing the sleeve and the gap joint relative to the inner core shaft and / or extending the inner core shaft relative to the gap joint; connecting the locking nut to the inner core shaft when the sleeve and the gap joint are compressed relative to the inner core shaft and / or when the inner core shaft is extended relative to the gap joint, respectively; and after connecting the locking nut, releasing the sleeve and the gap joint from compression relative to the inner core shaft and / or releasing the inner core shaft from extension relative to the gap joint, respectively.

[0066] Embodiment 15. The method of any preceding embodiment, wherein the locking nut has an external locking nut diameter and the gap joint has an external gap joint diameter that is greater than the external locking nut diameter.

[0067] Embodiment 16. The method of any preceding embodiment, wherein the gap joint comprises one or more friction pads.

[0068] Embodiment 17. The method of any preceding embodiment, wherein the gap joint comprises one or more torque sleeves, the one or more torque sleeves comprising an anti-rotation element that prevents the one or more torque sleeves from rotating relative to the inner core shaft.

[0069] Embodiment 18. The method of any preceding embodiment, wherein the locking nut is fixedly connected to the inner core shaft by threads, the threads including two mating surfaces, and wherein the mating surfaces are in electrical contact.

[0070] Embodiment 19. The method of any preceding embodiment, wherein the friction pad includes an anti-rotation element that prevents the friction pad from rotating relative to the inner core shaft.

[0071] Embodiment 20. A method according to any of the preceding embodiments, wherein during assembly of the downhole tool, the non-conductive material in the downhole tool is not affected by friction forces that are one percent or more of the highest friction forces occurring between any conductive components in the downhole tool.

[0072] The terms "insulating," "isolating," and "non-conductive" describe similar features in the context of electrically separating two or more components by high impedance and / or resistivity (e.g., greater than 100 ohms and / or 100 ohm-meters). Alternatively, these terms describe features in the context of electrical separation by high relative impedance and / or resistivity (e.g., 1000 times or more the resistance and / or resistivity of the separated components). Rings (such as shoulder rings, friction pads, guide rings, contact rings, etc.) are generally understood to include one or more ring segments that, when combined, can cover all or part of the circumference of the ring or ring segment.

[0073] While embodiments of the present disclosure are described with respect to telemetry devices, such as telemetry device 114, it should be understood that other applications benefit from highly reliable electrical separation of a first portion of a BHA from a second portion of the BHA. Such applications may include the design, manufacture, and operation of downhole resistivity tools, such as induction tools, laterolog tools, resistivity imagers, electromagnetic transient tools, and the like.

[0074] In the context of describing the present invention (particularly in the context of the appended claims), the use of the terms "a", "an", and "the", and similar references, should be interpreted as covering both the singular and the plural, unless otherwise indicated herein or clearly contradicted by the context. Furthermore, it should be noted that the terms "first", "second", etc., herein do not denote any order, quantity, or importance, but are used to distinguish one element from another. The terms "about", "substantially", and "approximately" are intended to include the degree of error associated with the measurement of a particular quantity, based on the equipment available at the time of filing the application. For example, "about" and / or "substantially" and / or "approximately" may include a range of ±8%, or 5%, or 2% of a given value.

[0075] The teaching content of the present disclosure can be used for multiple well operations.These operations can relate to using one or more treatment agents to treat the fluid, wellbore and / or equipment in the wellbore, such as production tubing, resident in the stratum, the stratum.The treatment agent can be in the form of liquid, gas, solid, semi-solid and their mixture.Illustrative treatment agents include but are not limited to fracturing fluid, acid, steam, water, brine, preservative, cement, permeability regulator, drilling mud, emulsifier, demulsifier, tracer, flow improver etc.Illustrative well operations include but are not limited to hydraulic fracturing, production increase, tracer injection, cleaning, acidizing, steam injection, water injection, cementing etc.

[0076] Although the present invention has been described with reference to one or more exemplary embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for its elements without departing from the scope of the present invention. In addition, many modifications may be made to adapt specific circumstances or materials to the teachings of the present invention without departing from the basic scope of the present invention. Therefore, it is intended that the present invention is not limited to the specific embodiments disclosed as the best mode for implementing the present invention, but that the present invention will include all embodiments falling within the scope of the claims. In addition, in the drawings and detailed description, exemplary embodiments of the present invention have been disclosed, and although specific terms have been adopted, unless otherwise indicated, they are used only in a general and descriptive sense, and not for the purpose of limitation, and the scope of the present invention is therefore not limited thereto.

Claims

1. A downhole tool (114) for a bottom hole assembly (112) for use in a wellbore (104), characterized in that: a voltage source (117) characterized in that a first pole (122) is electrically connected to a first portion of the bottom hole assembly (112), and a second pole (121) is electrically connected to a second portion of the bottom hole assembly (112), wherein the first portion and the second portion are electrically separated by a non-conductive material between the first portion and the second portion; wherein the first portion comprises a shell (212) defining an outer shell surface of the first portion, and wherein the second portion comprises an inner core shaft (402) and a locking nut (422) fixedly connected to the inner core shaft (402), wherein the locking nut (422) secures the non-conductive material to the shell (212).

2. The downhole tool (114) of claim 1, wherein the locking nut (422) has an external locking nut diameter and the external housing surface has an external housing surface diameter that is greater than the external locking nut diameter.

3. The downhole tool (114) of claim 1, further comprising at least one friction pad (439) disposed axially between the housing (212) and the second portion.

4. The downhole tool (114) according to claim 1 further includes a torque sleeve (489) axially arranged between the locking nut (422) and the non-conductive material, and the torque sleeve (489) includes an anti-rotation element (491) that prevents the torque sleeve (489) from rotating relative to the inner core shaft (402).

5. The downhole tool (114) of claim 3, wherein the friction pad (439) includes one or more particles (712) located at one or more surfaces of the friction pad (439).

6. The downhole tool (114) of claim 3, wherein the friction pad (439) includes an anti-rotation element (491) that prevents the friction pad (439) from rotating relative to the inner core shaft (402).

7. The downhole tool (114) according to claim 1, wherein the housing (212) and / or the second portion directly contacts the drilling fluid in the annulus (127) between the wall (128) of the wellbore (104) and the downhole tool (114).

8. The downhole tool (114) according to claim 1, further characterized by A sleeve (489), wherein the inner core shaft (402) is disposed within the sleeve (489), and wherein the sleeve (489) is electrically isolated from the inner core shaft (402).

9. A method of assembling a downhole tool (114) adapted for use in a wellbore (104), the method comprising: moving a sleeve (489) along a longitudinal axis of a first joint (202) to radially surround an inner core shaft (402) of the first joint (202) extending along the longitudinal axis; moving a gap joint (206) along the longitudinal axis to be disposed about an extended portion of the inner mandrel (402), wherein the gap joint (206) comprises a non-conductive material, the gap joint (206) being configured to electrically decouple the first joint (202) from a second joint (204) of the downhole tool (114); and A lock nut (422) is fixedly connected to the inner core shaft (402) to secure the gap joint (206) to the sleeve (489).

10. The method according to claim 9, further characterized in that: Compressing the sleeve (489) and the gap joint (206) relative to the inner core shaft (402) and / or extending the inner core shaft (402) relative to the gap joint (206); connecting the lock nut (422) to the inner core shaft (402) when the sleeve (489) and the gap joint (206) are compressed relative to the inner core shaft (402) and / or when the inner core shaft (402) is extended relative to the gap joint (206), respectively; as well as After connecting the locking nut (422), the sleeve (489) and the gap joint (206) are released from compression relative to the inner core shaft (402) and / or the inner core shaft (402) is released from extension relative to the gap joint (206).

11. The method of claim 9, wherein the lock nut (422) has an outer lock nut diameter and the gap joint (206) has an outer gap joint diameter that is greater than the outer lock nut diameter.

12. The method of claim 9, wherein the gap joint (206) includes one or more friction pads (439).

13. The method of claim 9, wherein the gap joint (206) comprises one or more torque sleeves (489), the one or more torque sleeves (489) comprising an anti-rotation element (491) that prevents the one or more torque sleeves (489) from rotating relative to the inner core shaft (402).

14. The method of claim 9, wherein the lock nut (422) is fixedly connected to the inner core shaft (402) by a thread (424), the thread including two mating surfaces, and wherein the two mating surfaces are in electrical contact.

15. The method of claim 12, wherein the one or more friction pads (439) include an anti-rotation element (491) that prevents the one or more friction pads (439) from rotating relative to the inner core shaft (402).

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