ELECTROMAGNETIC TELEMETRY GAP SUB

BACKGROUND

In the resource recovery industry, a work string can be disposed in a borehole for drilling, formation testing, oil production, etc. The work string can have a bottomhole assembly (BHA) for performing various electrical tests downhole. The BHA can include a first sub and a second sub connected to each other. Typically, an insulation is provided at a connection between the first sub and the second sub, generally within a threaded connection between adjacent subs. This insulation is not ideal as it is difficult to maintain and tends to get destroyed when the BHA is disassembled for inspection or maintenance purposes. There is therefore a need to be able to connect adjacent subs in an insulated configuration that is more reliable and maintainable.

SUMMARY

In an embodiment, a downhole tool of a bottomhole assembly for use in a wellbore is disclosed. The downhole tool includes a voltage source including a first pole electrically connected to a first portion of the bottomhole assembly and a second pole electrically connected to a second portion of the bottomhole assembly. The first portion and the second portion are electrically separated by electrically nonconductive material between the first portion and the second portion. The first portion includes a housing defining an outer housing surface of the first portion and the second portion includes an inner mandrel and a lock nut fixedly connected to the inner mandrel. The lock nut secures the nonconductive material to the housing.

In another embodiment, a method of assembling a downhole tool suitable for use in a wellbore The method includes moving a sleeve along a longitudinal axis of a first sub to radially surround an inner mandrel of the first sub that extends along the longitudinal axis, moving a gap sub along the longitudinal axis to be disposed around an extended section of the inner mandrel wherein the gap sub includes nonconductive material, the gap sub configured to electrically separate the first sub from a second sub of the downhole tool, and fixedly connecting a lock nut to the inner mandrel to secure the gap sub against the sleeve.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 shows a work string in an illustrative embodiment;

FIG. 2 shows a side view of a section of a bottomhole assembly of the work string;

FIG. 3 shows a cross-sectional view of the section of the bottomhole assembly shown in FIG. 2;

FIG. 4 shows a close-up cross-sectional view of the downhole telemetry device showing the components therein;

FIG. 5A shows a side view of the bottomhole assembly depicting electrical fields and pathways for current flow from one end of the bottomhole assembly to another;

FIG. 5B depicts the downhole telemetry device in an exploded view, showing the two separate and electrically insulated sides of the downhole telemetry device;

FIG. 6 illustrates a process for assembling the bottomhole assembly in an embodiment;

FIG. 7 shows close up view of a section including a friction shim, in an embodiment;

FIG. 8 illustrates a step for preparing a push section of the pre-tension device;

FIG. 9 illustrates a first step for preparing a pull section of the pre-tension device;

FIG. 10 illustrates a second step for preparing the pull section of the pre-tension device;

FIG. 11 shows a side view of the pre-tension device in an assembled state; and

FIG. 12 illustrates a step for securing the lock nut using the pre-tension device.

DETAILED DESCRIPTION

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.

Referring to FIG. 1, a drilling system 100 with a work string 102 is shown in an illustrative embodiment. The work string 102 can be a drill string, a production string, a completion string, a wireline string, or any other suitable string for industrial applications. The work string 102 extends into a borehole 104 in an earth formation 105 from a platform 106 at a surface location 108. The work string 102 includes a plurality of string subs 110 axially connected to each other. A bottomhole assembly (BHA 112) is disposed at a 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 the inner wall 128 of the borehole 104. The annulus 127 is typically filled with drilling mud that is pumped from BHA 112 and 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 send an electromagnetic signal through the earth formation 105 and/or along the work string 102 to be received at the surface telemetry device 116. The downhole telemetry device 114 can also receive an electromagnetic signal that is transmitted downhole along the work string 102 and/or through the earth formation 105 by the surface telemetry device 116. The downhole telemetry device 114 includes a gap 115, electrically isolating a lower part of the BHA 112 (downhole of the gap 115) from an upper part of the BHA 112 (uphole of the gap 115) and the work string 102, which is electrically connected to the upper part of the BHA, generally by threaded connections of conductive material typically used for such operation. The surface telemetry device 116 may include and be connected to one or more antenna devices 118, connected to and with the earth formation 105.

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

FIG. 2 shows a side view 200 of a section of the downhole telemetry device 114 of the BHA 112. The side view 200 includes a first sub 202 of the downhole telemetry device 114 and a second sub 204 of the downhole telemetry device 114 connected by a gap sub 206. The first sub 202 can be an upper sub and the second sub 204 can be a lower sub. Thus, the first sub 202 resides uphole of the second sub 204 when the work string 102 is disposed in the borehole 104. The first sub 202 includes a top section 208 and sleeve 210 disposed around a lower section. The gap sub 206 includes a housing 212 defining the outer diameter of the gap sub 206. The sleeve 210 is electrically isolated from the top section 208 by a shoulder ring 214 and is electrically isolated from the housing 212 by a shoulder ring 216.

FIG. 3 shows a cross-sectional view 300 of the section of the BHA 112 shown in FIG. 2. The first sub 202 can include one or more compartments 302 that may include electronic components and/or batteries, capacitors, voltage sources, or other power supplies that can be used to power elements in the second sub 204. In an embodiment, the second sub 204 can include various sensors and devices of the BHA 112 that may operate by using power from the power supplies, such as power supplies in compartments 302 of the first sub 202. Shoulder rings 214, 216 and 428 (FIG. 4) are used to separate electronic components to account for axial isolation. Radial isolation is achieved by physical radial separation of components (i.e., top section 208, sleeve 210, housing 212, lock nut 422 (FIG. 4), second sub 204) from an inner mandrel 402 (FIG. 4) via guide rings 230, 231, 232 and 233, 234, 235 (FIG. 4), which create a nonconductive radial (air) gap. The guide rings 230, 231, 232, 233, 234 and 235 also centralize components. Components of the gap sub 206 are shown in FIG. 3 and discussed in further detail with respect to FIG. 4.

FIG. 4 shows a close-up cross-sectional view 400 of the gap sub 206 showing the components therein. The first sub 202 includes an inner mandrel 402 surrounded by sleeve 210. An extended section 404 of the inner mandrel 402 extends axially beyond an end of the sleeve 210. The extended section 404 includes a cylindrical bore 406 therethrough for flow of a wellbore fluid, such as a drilling mud, for example. An outer surface of the extended section 404 includes a threaded section 408. The threaded section 408 can be disposed along a tapered section 410 of the extended section 404.

The housing 212 is disposed around the extended section 404. The housing 212 is a 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 radially inward recess from an outer surface of the housing 212 that forms a ridge that faces toward the first sub 202. The inner clamping shoulder 414 is formed at the inner surface of the housing 212 and includes a radially outward recess that forms a ridge that faces toward the second sub 204. A top end 416 of the housing 212 fits in a gap 437 between the extended section 404 and the sleeve 210. A middle section 418 of the housing 212 forms a gap 420 with the extended section 404 of the inner mandrel 402. Gaps 437 and/or 420 may be filled with a fluid, such as drilling mud, air, or oil which may be an insulating fluid in embodiments.

A lock nut 422 is disposed in the gap 420 between the housing 212 and the extended section 404. The lock nut 422 is a shell, such as a cylindrical shell that includes a threaded section 424 along its inner surface and a groove section 426 along its inner surface. The threaded section 424 is along a tapered section 427 of the lock nut 422. The threaded section 424 threadingly couples to the threaded section 408 of the extended section 404 in order to mate the lock nut 422 to the extended section 404. A tapering angle of the threaded section 424 of the lock nut 422 is the same as the tapering angle of the threaded section 408 of the extended section 404.

In various embodiments, the lock nut 422 can be a shell, two half shells, snap rings, a bayonet connection, pins, etc. Lock nut 422 is sized so that it can be installed inside housing 212. Accordingly, the outer lock nut diameter is smaller than outer housing surface diameter (i.e., the diameter of the outer surface of housing 212) and may be smaller than outer sleeve diameter (i.e., the diameter of the outer surface of sleeve 210). Use of a lock nut eliminates the need to separate threads via a plastic or ceramic layer. No insulating components, such as plastics, epoxy, etc., are therefore used as part of the load-bearing portions of threaded section 424. Threaded sections, such as threaded section 424, need to withstand high friction forces when connected with sufficiently high torque while assembling telemetry device 114. Such high friction forces while assembling telemetry device 114 eventually can destroy insulating components or coatings which are typically weaker materials than steel. The current disclosure describes a telemetry device including a gap 115 without any insulating components or coatings that are subject to high friction forces during assembly or otherwise. In particular, the current disclosure discloses a telemetry device that includes electrically separated components, subs, or portions (i.e., components, subs, or portions that are separated by nonconductive material) that are connected with one or more threads, (such as threaded sections 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 component disposed between the corresponding mating surfaces of the threads. In one or more embodiments, there is no insulating component in the telemetry device 114 that is subject to a friction force during assembly that is 0.1 per mille or higher (such as one per mille or higher or even one percent or higher) of the highest friction force that occurs between any of the conductive components during assembly of the telemetry device 114. The downhole telemetry device 114 is therefore structurally strong at high temperatures and provides high reliability and simple maintenance.

Shoulder ring 216 is disposed in the radially inward recess between the outer clamping shoulder 412 and the sleeve 210. An inner shoulder ring 428 is disposed in the radially outward recess between the inner clamping shoulder 414 and the lock nut 422. Shoulder rings 214, 216, 428 are at least partially made from or coated with an insulating or nonconductive material, such as ceramics or other 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 from or coated with an insulating material. One or more friction shims 439 may be disposed adjacent to, and in contact with, one or both one or more of shoulder rings 214, 216, 428 and may be in contact with one or more of corresponding clamping shoulders 412, 413 and 414, 415. In one embodiment, a torque sleeve 489 can be disposed adjacent to the friction shims 439 and/or shoulder ring 428. Torque sleeve 489 can include an anti-rotation element 491, such as a parallel key which is guided by a groove in inner mandrel 402. The groove in 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 at the same time preventing a rotational movement of torque sleeve 489 relative to the inner mandrel 402. Alternatively, or in addition, one or more friction shims 439 may include one or more similar anti-rotation elements that allow the one or more friction shims 439 to move in an axial direction while at the same time preventing a rotational movement of torque sleeve 489 relative to the inner mandrel 402. By torque sleeve 489 and/or anti-rotation elements 491 on torque sleeve 489 or friction shims 439, a rotational frictional movement on surfaces comprising nonconductive materials (such as shoulder ring 428) can be prevented, thereby contributing to a higher reliability of the gap sub 206.

A bottom end 430 of the housing 212 couples to the second sub 204. A pin end 432 of the second sub 204 fits in the gap 420 between the housing 212 and the extended section 404 of the inner mandrel 402. A threaded section 434 of the pin end 432 screws into a complementary threaded section 436 on the bottom end 430 of the housing 212 to secure the second sub 204 to the housing 212. The pin end 432 includes a bore 438 therethrough. A tip 440 of the extended section 404 includes electrical contacts 442 on its outer surface. When the pin end 432 is secured to the housing 212, the tip 440 is inserted into the bore 438 and the electrical contacts 442 form an electrical connection to complementary electrical contacts 444 on an inner surface of the pin end 432. Electrical contacts 444 are further connected to the lower section of the BHA 112. The electrical contacts 444 can provide power and communication between the electrically upper section and lower section which are otherward electrically isolated by the gap 115 (i.e., one or more of gap 437, gap 420, insulating shoulder rings 214, 216, 428, friction shim(s) 439 and/or guide rings 230, 231, 232, 233, 234, 235). Second sub 204 includes a bore (not shown) to guide the wires from the electrical contacts 444 to downhole electronic components at the BHA 112 downhole of the gap 115. Although two electrical contacts are shown, one contact may be sufficient for operating of the downhole telemetry device 114. If only one electrical contact 442, 444 is used, it is used for electrically connecting the primary pole 122 (the connection to the housing ground of the lower part of the BHA 112) to the voltage source 117, which is located in compartment 302, uphole of the gap 115, or may be located in similar compartments in the lower part of the BHA 112.

More than one pair of electrical contacts 442, 444 can be used in order to transfer power and/or information across the gap 115, including to and from a directional or other sensor inside the BHA 112. The downhole telemetry device depicted in FIGS. 2 to 5 preferably houses power supplies (e.g., batteries, voltage sources, capacitors) and communication electronics in the compartments 302 within inner mandrel 402 and covered by the sleeve 210 when assembled. Connection to the housing 212 ground of the uphole section is made by connecting EM electronics located in compartment 302 to the steel body of the top section 208 (e.g., by use of a ground screw (not shown) inside compartment 302), creating a secondary pole 121 (FIG. 1), connected to the upper part of the BHA 112 (uphole of the gap 115).

The primary pole 122, which is downhole of the gap 115 and in electrical connection to the lower part of the BHA 112, is connected to the EM electronics, located in compartment 302, through at least one of the electrical contacts 442, 444, which are in turn connected to the housing ground of sub 204 (or any other component electrically to the lower part of the BHA 112), using, for example, a ground screw connected to the pin face of second sub 204 at the compartment 302 (sealed area). Alternatively, as a power source, the system can be connected to an alternator either instead of or in addition to other power supplies (e.g., voltage sources, capacitors, batteries). In one or more embodiments, by swapping pin and box connections of the telemetry device 114, the electronic compartment can be positioned at a downhole location with respect to the gap 115. While the telemetry device 114 is discussed as using two electrical contacts 442, 444, more than two electrical contacts can be used in alternative embodiments. Electrical contacts 442, 444 may be ring contacts in one or more embodiments.

A cap 446 can be located at the tip 440 and an internal insulation ring 448 can be disposed around the cap 446. One or more surfaces of the cylindrical bore 406, the bore 438, the internal insulation ring 448, and the cap 446 can be coated or sleeved to provide insulation against electrical shorting between the first sub 202 and the second sub 204 due to the possible flow of an electrically charged fluid (e.g., charged wellbore fluid), therebetween. In an alternative embodiment, the cap 446 and/or the internal insulation ring 448 can be made of an insulating (i.e., nonconductive) material. Alternatively, an elongated, nonconductive tube (e.g., plastic, rubber, ceramics) (not shown) can be fitted into the inside of the telemetry device 114 to provide a long nonconductive path at the inside and between both electrical sides of the gap 115. The cap 446 in turn carries the insulating ring 448, preferably also made from a high strength and nonconductive material, such as ceramics. The high strength of insulation ring 448 creates a sealed cavity that resists the downhole pressure, which can reach high levels. As can be seen on in FIGS. 2-4, one or more seals 419 can be used to provide a fluid tight seal and an enclosed compartment around the contact rings and gap components.

FIG. 5A shows a side view 500 of the downhole telemetry device 114 depicting electrical pathways that can be produced for telemetry. When setting the upper part of the BHA 112 to a defined and different voltage than the lower part of the BHA 112 (i.e., gap sub 206 and second sub 204), and assuming the earth formation 105 and wellbore fluid have some conductivity, different electrical fields and current pathways to the wellbore and the formation exist, as depicted in FIG. 5a. Electrical fields 502, 504 correspond to a short distance gap 115, while electrical field 506 corresponds to a long distance gap 115. The existence of the electrical field 506 assumes the sleeve 210 is not connected to the inner mandrel 402 (i.e., they are separated by shoulder rings 214, 216 and radial guide rings 230, 231) and that the outer diameter of the sleeve is in direct contact with the wellbore fluid and/or formation and at least a portion of it is nonconductive at the outer surface (i.e., is made of nonconductive material or covered with a nonconductive coating). The length of gap 115 is one parameter defining the quality of a gap sub and affecting the quality of electromagnetic telemetry generated by the different voltages connected to the upper part and lower part of the BHA 112. For a short distance gap in which electrical fields 502 and/or 504 are used, a typical axial length of shoulder rings 214, 216 is between 1 mm and 50 mm. The length of the gap 115 is primarily determined by the length of the isolated portion of the sleeve 210 and can range from a few mm to over 2000 mm. For a short distance gap, first electrical field 502 and second electrical field 504 can be generated that extend over a relatively short distance through the wellbore fluid and/or the earth formation 105. For a long distance gap setup, an electrical field 506 can be generated that extends over a relatively long distance through the wellbore fluid and/or the earth formation 105. For the short distance gap setup, the first electrical field 502 extends from housing 212 to sleeve 210 and the second electrical field 504 extends from sleeve 210 to top section 208. The shoulder ring 214 and shoulder ring 216 create electrical insulation between the respective components in order to allow for the creation of the first electrical field 502 and second electrical field 504. In this scenario, the actual electrical gap length is a sum of the lengths of shoulder ring 214 and 216. For the long distance gap setup, an electrical field 506 extends from the housing 212 of the gap sub 206 to the top section 208 of the first sub 202, bypassing the sleeve 210, since the sleeve is electrically insulated by a nonconductive layer on the outside (not shown). Nonconductive layers can be made from thermoplastic coatings, paint, ceramic coating, passive layers of metal (e.g., phosphated, oxidated, oxide layer), etc. Such layers provide a thin layer having lower conductivity than the surrounding wellbore fluid, thereby creating the long distance gap 115.

FIG. 5B shows upper part 550 and lower part 560 that are created by the gap 115. The upper part 550 connects to an uphole end of the BHA 112 and the work string 102 and the lower part 560 connects to a downhole end of the BHA 112. FIG. 5B displays the upper and lower parts of the BHA 112 that are on different electrical potentials (thus creating an electrical potential difference or voltage between them)—and are physically connected internally, typically by metal-to-metal connections. The upper and lower parts are shown disconnected for ease of reference. In particular, the outer surface 551 of the upper part 550 and outer surface 561 of the lower part 560 are on the different electrical potentials and in direct (electrical) contact with the drilling fluid in the annulus 127 and/or the inner wall 128 of the borehole 104. Upper part 550 is electrically connected to one electrical potential through secondary pole 121. Lower part 560 is electrically connected to a second electrical potential through primary pole 122. The sleeve 210 can be separated and electrically disconnected individually for better gap performance. However, this is not required to create the electrical gap. When joining upper part 550 and lower part 560 of the BHA 112 by means of clamping shoulders 412, 413 and 414, 415, each separated by respective shoulder rings 216 and 428 and compressive load created by the lock nut 422, two electrically insulated parts of the BHA are established. Axial, torsional and bending loads are transferred through the clamping shoulders 412, 413 and 414, 415, and respective shoulder rings 216 and 428.

FIGS. 5a and 5b depict the electrical separation of the housing components. The housing components can be electrically connected to voltage source 117 by respective connectors to poles 121 and 122. The higher the electrical potential difference or voltage across the gap 115, the greater the amplitude of the electrical field and the current flowing through the formation, and the greater the signal (depicted by electric field lines 120). The maximum magnitude of the electrical field and/or current flowing through the formation across the gap depends on the conductivities of the formation and the wellbore fluid and is also limited by the power available for driving the voltage source 117. Typical voltages across the gap range from 5 V to 100 V.

FIG. 6 illustrates a process 600 for assembling the BHA 112 and more particularly, the downhole telemetry device 114, in an embodiment. In a first step (Step 1), shoulder ring 214 is slid over the extended section 404 of the inner mandrel 402. The sleeve 210 is then slid over the extended section 404 so that the shoulder ring 214 is sandwiched between the sleeve 210 and the top section 208. The shoulder ring 214 provides electrical insulation axially between the top section 208 and the sleeve 210. In a second step (Step 2), shoulder ring 216 is slid over the extended section 404. The housing 212 is then slid over the extended section 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.

In a third step (Step 3), inner shoulder ring 428 is slid into the gap between the extended section 404 and the housing 212. Lock nut 422 is slid over the extended section 404 to sandwich the inner shoulder ring 428 between the lock nut 422 and the housing 212. The inner shoulder ring 428 provides electrical insulation axially between the lock nut 422 and the housing 212.

In a fourth step (Step 4), a torque tool 602 is placed in the groove section 426 of the lock nut 422 and rotated to fasten the lock nut 422 to the extended section 404. When the lock nut 422 has been fastened to within a specified or desired torque value, the torque tool 602 can be removed. Some or all components are centralized by guide rings, such as nonconductive guide rings 230, 231, 232, 233, 234, 235, and therefore have no radial contact points between electrically 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 sub 204 can be threadingly attached to the box thread of housing 212 and engaged to extended section 404 to create a seal with the nonconductive insulation ring 448.

In the completely assembled downhole telemetry device 114, the torque is transferred from the second sub 204 to the first sub 202 via the housing 212, the extended section 404, lock nut 422, sleeve 210, etc. While making up the lock nut connection to the extended section 404, rotation can occur at clamping shoulders 415 and/or 414 on either side of the inner shoulder ring 428 due to their smaller radius compared to the other shoulders adjacent to shoulder rings 214 and 216. Moreover, use of the lock nut 422 enables the use of one or more friction shims 439 between elements along the outer radius (for example, at either side of shoulder rings 214 and 216). In various embodiments, the friction shims 439 can be ceramic rings, surface coated metallic rings, etc.

The friction shims 439 create high friction at the areas of contact. Friction shims placed between adjacent parts increase the torque capacity between these components. In an embodiment, the torque capacity using friction shims is between 4× and 8× the torque capacity between greased contacts. The friction shims therefore reduce the required shoulder compression during assembly of telemetry device 114 to avoid slippage between components, such as between shoulder rings 214, 216, 428 and corresponding clamping shoulders 412, 413 and 414, 415. With the lower requirements for shoulder compression during assembly of telemetry device 114 and thus the contact pressure of shoulder rings 214, 216, 428 and adjacent components, the torque requirements of the internal lock nut is reduced, thereby reducing the required space of lock nut 422.

FIG. 7 shows close up view 700 of a section including a friction shim 702 (such as one or more of friction shims 439), in an embodiment. The friction shim 702 is disposed, and generally compressed, between a first component 704 and a second component 706. 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 may be a clamping shoulder (such as clamping shoulders 412, 413 and 414, 415). The friction shim 702 may include a steel core 708 and a matrix layer 710, for example a relatively thin layer of a Nickel matrix to create a Nickel surface. Microparticles (e.g., diamond microparticles) 712 may be embedded in the matrix layer 710 and protrude outward from the friction shim 702. The microparticles 712 maintain a microgap 714 between the friction shim 702 and the first component 704 and/or the second component 706. The microparticles provide a high coefficient of friction between the friction shim 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, the second component 706 may be one of the housing 212, sleeve 210, the first sub 202 at the top section 208.

FIGS. 8-12 shows a process for assembling the downhole telemetry device 114 using a pre-tension device 1001. The pre-tension device 1001 pushes the inner mandrel in a first direction while simultaneously pulling the outer components (i.e., sleeve 210, etc.) in a second direction opposite the first direction. With the tension applied to the inner mandrel 402, the lock nut 422 can be more easily secured to the inner mandrel 402 while reducing required torque for assembly between nonconductive components and other components when in frictional contact.

FIG. 8 illustrates a step 800 for preparing a push section 1003 of the pre-tension device 1001. With the shoulder ring 216, housing 212, inner shoulder ring 428, and lock nut 422 slid over the extended section 404, a push rod receptacle 802 and push plug 804 are installed in the lock nut 422.

FIG. 9 illustrates a first step 900 for preparing a pull section 1005 of the pre-tension device 1001. A pull housing 902, inner cap 904 and outer cap 906 are installed over the outside of the housing 212 and first sub 202. The inner cap 904 and outer cap 906 clamp the pull housing 902 to the housing 212. The pull housing 902 extends over the sleeve 210 and is clamped, screwed, or otherwise connected to the first sub 202 at the top section 208. The pull housing 902 includes a threaded section 908.

FIG. 10 illustrates a second step 1000 for preparing the pull section 1005 of the pre-tension device 1001. An actuator device 1002 (such as a hydraulic actuator, electric actuator, etc.) is threadingly secured to the pull housing 902 at the threaded section 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 receptacle 802.

FIG. 11 shows a side view 1100 of the pre-tension device 1001 in an assembled state. Actuation of the actuator device 1002 creates an elongation of the extended section 404 of the inner mandrel 402 (via push 1102) and/or a compression of the sleeve 210 (via pull 1104).

FIG. 12 shows a side view 1200 that illustrates a step for securing the lock nut 422 using the pre-tension device 1001. With the extended section 404 of the inner mandrel 402 elongated and/or the sleeve 210 compressed, the torque tool 602 is used to apply a desired torque to the lock nut 422. Once the lock 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., remove push 1102 and pull 1104). The pre-tension device 1001 can then be disassembled and the BHA removed.

An advantage of the described make up of the lock nut connection includes a low friction force assembly of all components that include insulated material. The lock nut 422 can be assembled with minimum torque (for example, by hand) and therefore with minimum sliding friction between nonconductive components and other components since the axial tension is created by the pre-tension device 1001 instead. In one or more embodiments, the telemetry device 114 can be assembled by torquing lock nut 422 to extended section 404 of the inner mandrel 402 without creating a friction force on shoulder ring 428 and/or friction shim 439 during assembly that is 0.1 per mille or higher (such as one per mille or higher or even one percent or higher) of the highest friction force that occurs between any of the conductive components during assembly of the telemetry device 114. In alternate embodiments, the telemetry device 114 can be assembled by torquing lock nut 422 to extended section 404 of the inner mandrel 402 without creating any friction force on shoulder ring 428 and/or friction shim 439 or any other component including nonconductive material.

As opposed to using friction shims 702 on either side of shoulder rings 214, 216, 428, shoulder rings 214, 216, 428 can alternatively be coated with a high friction coating, embedding diamond particles 712 in a matrix layer 710. Coated shoulder rings 214, 216, 428 can thus be used without friction shims on either side but with similar advantages regarding torque capacity. In an alternate embodiment, instead of using friction shims, any friction increasing coating, powder, particles, glue, epoxy, adhesive can be used to increase the torque capacity over a version without friction enhancing components.

Set forth below are some embodiments of the foregoing disclosure:

Embodiment 1. A downhole tool of a bottomhole assembly for use in a wellbore. A voltage source includes a first pole electrically connected to a first portion of the bottomhole assembly and a second pole electrically connected to a second portion of the bottomhole assembly. The first portion and the second portion are electrically separated by electrically nonconductive material between the first portion and the second portion. The first portion includes a housing defining an outer housing surface of the first portion and the second portion includes an inner mandrel and a lock nut fixedly connected to the inner mandrel. The lock nut secures the nonconductive material to the housing.

Embodiment 2. The downhole tool of any prior embodiment, wherein the lock nut has an outer lock nut diameter and the outer housing surface has an outer housing surface diameter that is larger than the lock nut diameter.

Embodiment 3. The downhole tool of any prior embodiment, further including at least one friction shim disposed axially between the housing and the second portion.

Embodiment 4. The downhole tool of any prior embodiment, further including a torque sleeve disposed axially between the lock nut and the nonconductive material, the torque sleeve including an anti-rotation element that prevents rotation of the torque sleeve relative to the inner mandrel.

Embodiment 5. The downhole tool of any prior embodiment, wherein the lock nut is fixedly connected to the inner mandrel by a thread.

Embodiment 6. The downhole tool of any prior embodiment, wherein the lock nut secures the nonconductive material at least partially by clamping.

Embodiment 7. The downhole tool of any prior embodiment, wherein the friction shim includes microparticles at one or more surfaces of the friction shim.

Embodiment 8. The downhole tool of any prior embodiment, wherein the friction shim includes an anti-rotation element that prevents rotation of the friction shim relative to the inner mandrel.

Embodiment 9. The downhole tool of any prior embodiment, wherein the thread includes two mating surfaces and wherein the mating surfaces are in electrical contact.

Embodiment 10. The downhole tool of any prior embodiment, wherein the housing and/or the second portion are in direct contact with a drilling fluid in an annulus between a wall of the wellbore and the downhole tool.

Embodiment 11. The downhole tool of any prior embodiment, further including a sleeve, wherein the inner mandrel is disposed within the sleeve and wherein the sleeve is electrically isolated from the inner mandrel.

Embodiment 12. The downhole tool of any prior embodiment, wherein the nonconductive material includes one or more insulating rings.

Embodiment 13. A method of assembling a downhole tool suitable for use in a wellbore. The method includes moving a sleeve along a longitudinal axis of a first sub to radially surround an inner mandrel of the first sub that extends along the longitudinal axis, moving a gap sub along the longitudinal axis to be disposed around an extended section of the inner mandrel wherein the gap sub includes nonconductive material, the gap sub configured to electrically separate the first sub from a second sub of the downhole tool, and fixedly connecting a lock nut to the inner mandrel to secure the gap sub against the sleeve.

Embodiment 14. The method of any prior embodiment, further including compressing the sleeve and the gap sub relative to the inner mandrel and/or extending the mandrel relative to the gap sub, connecting the lock nut to the mandrel while the sleeve and gap sub is compressed relative to the inner mandrel and/or while with the mandrel is extended relative to the gap sub, respectively, and releasing, after connecting the lock nut, the sleeve and the gap sub from compression relative to the inner mandrel and/or the mandrel from extension relative to the gap sub, respectively.

Embodiment 15. The method of any prior embodiment, wherein the lock nut has an outer lock nut diameter and the gap sub has an outer gap sub diameter that is larger than the outer lock nut diameter.

Embodiment 16. The method of any prior embodiment, wherein the gap sub includes one or more friction shims.

Embodiment 17. The method of any prior embodiment, wherein the gap sub includes one or more torque sleeves, the one or more torque sleeves including an anti-rotation element that prevents rotation of the one or more torque sleeves relative to the inner mandrel.

Embodiment 18. The method of any prior embodiment, wherein the lock nut is fixedly connected to the inner mandrel by a thread that includes two mating surfaces, and wherein the mating surfaces are in electrical contact.

Embodiment 19. The method of any prior embodiment, wherein the friction shim includes an anti-rotation element that prevents rotation of the friction shim relative to the inner mandrel.

Embodiment 20. The method of any prior embodiment, wherein during assembling the downhole tool no nonconductive material in the downhole tool is subject to a friction force that is one percent or higher of the highest friction force that occurs between any of the conductive components in the downhole tool.

The terms “insulating,” “isolating,” “insulation”, “isolation”, and “nonconductive” describe similar features in the context of electrical separation of two or more components by a high resistance and/or resistivity (e.g., larger than 100 ohms and/or 100 ohm-meter). Alternatively, these terms describe features in the context of electrical separation by a high relative resistance and/or resistivity (e.g., a resistance and/or resistivity that is 1000 or more times higher than the separated components). Rings (such as shoulder rings, friction shims, guide rings, contact rings, etc.) are generally understood to include one or more ring segments that in combination may cover the whole or a portion of the circumference of the ring or ring segment.

While the embodiments in this disclosure are described with respect to a telemetry device, such as telemetry device 114, it is understood that other applications that benefit from a highly reliable electrical separation of a first portion of the BHA from a second portion of the BHA. Such applications may include the design, manufacturing, and operation of downhole resistivity tools, such as induction tools, laterolog tools, resistivity imaging tools, electromagnetic transient tools, etc.

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% or 5%, or 2% of a given value.

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 wellbore, and/or equipment in the wellbore, 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.

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.

ELECTROMAGNETIC TELEMETRY GAP SUB

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Provisional Applications (1)