DIRECT CONTACT TELEMETRY SYSTEM FOR WIRED DRILL PIPE

Abstract

A wired drill string assembly, comprising a plurality of drill pipes extending from a surface into a wellbore. The plurality of drill pipes comprising a coaxial wired transmission line. The assembly comprising a downhole tool comprising a body having a first threaded connector and a second threaded connector, the first threaded connector being connected to one of the plurality of drill pipes. The downhole tool including one or more electrical components comprising a sensor coupled to the body and a signal transmitter configured to transmit a signal representing a measurement taken by the sensor. A first coaxial transmission line extending along the body and electrically connected to the coaxial wired transmission line and with the one or more electrical components. The first transmission line is electrically connected to the transmission wire by a first physical electrical contact on at least a portion of a first removable connector thread flank.

Description

BACKGROUND

In the oilfield, wellbores are created by boring a hole in the earth using a bottom-hole assembly (BHA) at the end of a drill string. The BHA, in turn, generally includes one or more measurement-while-drilling (MWD) devices, including sensors, which are communicable with equipment at the surface of the well. Such MWD devices may be employed to take “surveys” of the well drilling process, generally providing information related to direction (azimuth) and inclination of the BHA.

The devices that provide communication from the BHA to the surface are usually either pressure actuators, which send pressure pulses through the drilling mud (i.e., “mud pulse telemetry”), or electromagnetic transmitters that send electromagnetic pulses through the earth (“EM telemetry”). The transmitters for each of these types of signals generally use a large amount of power, and thus large batteries or a turbine generator may be provided in the BHA for powering these devices.

Recently, wired drill pipe has been employed to send communication signals via a wired connection directly to/from surface equipment. Communication via wired drill pipe may have increased power efficiency, and the devices that provide such communication at the BHA may not demand turbines or large batteries. In implementation, a wired drill pipe telemetry sub is connected to the top of a BHA, with the BHA providing the aforementioned MWD sensors. The communication devices within the wired drill pipe telemetry sub are connected to the MWD devices, which relay the information from the sensors to the surface. However, the BHA generally still includes mud pulse or EM telemetry transmitters, e.g., to provide backup or redundancy in communication abilities.

SUMMARY

This application presents a modification of the '927 reference. The prior art figures and related text are taken from said reference and are applicable to this application except when modified by this application. References '724 and '858 are also applicable to this application except when modified by this application.

This application presents a wired drill string assembly comprising a plurality of drill pipes and other drilling tools making up a drill string extending from a land surface, a sea surface, or a subsurface into a well or wellbore, the plurality of drill pipes comprising a wired transmission line electrically linking the components of the drill string.

The drill string may include a tool or a downhole tool that may comprise a tool body having a first threaded connector and a second threaded connector, the first threaded connector being connected to one of the plurality of drill pipes. The first threaded connector may be disposed within the box end of the tool body and the second threaded connector may be disposed within the pin end of the tool body. The respective threaded connectors may be suitable for attachment within the drill sting. The tool may be disposed intermediate the plurality of drill pipes, the first threaded connector being attached to the drill string above the tool and the second threaded connector being attached to the drill string below the tool. The tool may be attached to a BHA and a drill bit.

The tool or downhole tool may comprise one or more electrical components comprising one or more sensors within or coupled to the tool body and one or more signal transmitters and receivers configured to receive and transmit a signal representing a measurement taken by the sensors.

The tool or downhole tool may include a first and second transmission line extending along the tool body and electrically that may be connected to a transmission wire of the wired transmission line of the plurality of drill pipes and with the one or more electrical components. The first and second transmission lines, or either of them, may be electrically connected to the transmission wire of the wired transmission line by a first and second physical electrical insulated contact that may be mounted on a flank portion, or other portion, of a thread segment of the first or second threaded connector. The physical contact may extend along the thread segment up to about 180 degrees of one turn of a helical thread of the threaded connector. The threads of the tool and the adjoining drill pipes may be timed to assure alignment and physical electrical connection of the respective contact surfaces during joint makeup. When aligned the respective electrical contact surfaces of the contacts should physically contact one another and allow for the transmission of an electrical signal between connected tools along the drill string.

The first and second connector thread segments may be removeable from the respective connector threads. The respective connector thread segments may be compatible for inclusion within the tool's thread without compromising the integrity of the tool's thread as a whole. The respective connector thread segments may be attached to the respective threaded connectors by means of a detachable anchor. The detachable anchor may be a bolt, screw, or a clamp. The thread segments may be harder than the surrounding threads as measured on the Rockwell C scale. The hardness of the thread segments may be achieved by a hardening process before the thread segments may be attached to the threaded portion of the connector. Or it may be achieved by composing an alloy of materials resulting in a higher hardness than the threads of the tool's threaded connector. On the other hand, the connector thread segments may comprise a material equal or softer than the material of the adjacent threads. Hard polymers and plastics, or natural and synthetic rubbers, strengthened with metal and carbon fibers or meshes may be useful in the thread segments, especially if the hardened materials are electrically nonconducting. The tread segment may comprise a combination of metal and hardened polymers.

The respective physical electrical contacts of the downhole tool and the adjoining drill pipes may be electrically insulated from the downhole tool and the adjoining drill pipes. The insulation may be comprised of a polymer, a glass, or a rubber. The electrical contact may be molded within the insulating material before assembly into the connector thread segment. The connector thread segment may be electrically nonconductive, also. The first and second transmission lines may be electrically insulated within the tool body as part of the attachment to the tool body. The first and second physical electrical contacts may comprise an insulated electrically conductive insert mounted on the respective connector thread flanks. Or, the physical electrical contacts comprise an insulated electrically conductive cladding attached to the respective connector thread flanks.

The first and second transmission lines and the wired transmission line, respectively, each may comprise a coaxial cable comprising an electrically conductive sheath, a dielectric, and a center conductor. The electrically conductive sheath may comprise a steel tube, such as stainless steel tube. The sheath may comprise an electrically nonconductive outer protective covering as well. The dielectric may comprise an electrically nonconductive polymer. The polymer may comprise a volume of magnetically conductive electrically insulating (MCEI) fibers. The MCEI fibers may comprise ferrite fibers. The MCEI or ferrite fibers may comprise between 3% and 72% of the volume of the dielectric material. The volume of MCEI fibers may be sufficient to arrest the propagation of an electromagnetic field surrounding the energized coaxial cable. The enhanced dielectric may shield the cable from outside electrical interference from inside or outside the downhole tools. Also, the dielectric may comprise an open mesh embedded within the dielectric. The open mesh may comprise a metal wire or a polymeric fabric. The mesh may be electrically conductive or nonconducting. However, the mesh should be electrically isolated from the downhole tool body and the cable's center conductor and sheath. The coaxial cable may be compressed so that independent movement of the sheath, dielectric, and the center conductor may be arrested under the gravitational forces acting on the cable downhole. The open configuration of the mesh may allow the transmission of pressure from the sheath to the center conductor.

Embodiments of the present disclosure may provide a downhole tool. The downhole tool includes a body having a first connector and a second connector. At least the first connector is configured to be connected to a wired drill pipe. The downhole tool also includes one or more electrical components coupled to the body and configured to receive a first signal and transmit a second signal. The downhole tool further includes a first transmission line extending along the body to the first connector and electrically connected to the one or more electrical components. The first transmission line is configured to be electrically connected to a transmission wire of the wired drill pipe when the wired drill pipe is connected to the first connector.

Embodiments of the disclosure may further provide a wired drill string assembly. The assembly includes drill pipes extending from a surface into a wellbore and including a transmission line. The assembly also includes a downhole tool that includes a body having a first connector and a second connector, the first connector being connected to one of the drill pipes. The downhole tool also includes at least one electrical component including a sensor coupled to the body and a signal transmitter configured to transmit a signal representing a measurement taken by the sensor. The downhole tool further includes a first transmission line extending along the body and electrically connected to a transmission wire of the drill pipes and with the one or more electrical components.

The foregoing summary is intended merely to introduce a few of the aspects of the present disclosure, which are more fully described below. Accordingly, this summary should not be considered exhaustive.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure may be understood by referring to the following description and accompanying drawings that are used to illustrate some embodiments. In the drawings:

FIG. 1 is a diagram of the physical electrical connector system of the present disclosure.

(Prior Art) FIG. 2 illustrates a simplified, side, cross-sectional view of a wellsite system, including a first downhole tool and a second downhole tool, according to an embodiment.

(Prior Art) FIG. 3 illustrates a simplified, side, cross-sectional view of a downhole tool, which may be representative of an embodiment of either or both of first and second downhole tools, according to an embodiment.

(Prior Art) FIG. 4 illustrates a schematic view of a wired drill pipe assembly including the first downhole tool, according to an embodiment.

(Prior Art) FIG. 5 illustrates a schematic view of a wired drill pipe assembly including a distributed system of several of the second downhole tools, in addition to the first downhole tool, according to an embodiment.

(Prior Art) FIG. 6 illustrates a threaded connection of joined drill pipes.

(Prior Art) FIG. 7 is a diagram of a coaxial cable segment.

DETAILED DESCRIPTION

The following detailed description relates to FIG. 1 and (Prior Art) FIGS. 2-7.

Referring to (Prior Art) FIG. 2, this application presents a wired drill string assembly 134 comprising a plurality of drill pipes 136 and other drilling tools making up a drill string 134 extending from a land surface, a sea surface, or a subsurface into a well or wellbore, the plurality of drill pipes 136 comprising a wired transmission line 152 electrically linking the components of the drill string 134.

Referring to FIG. 1 and (Prior Art) FIG. 3, the drill string 134 may include a tool or a downhole tool 140 that may comprise a tool body 200 having a first threaded connector 202 and a second threaded connector 204, the first threaded connector 202 being connected to one of the plurality of drill pipes 136. A helical segment of threaded connector 202 is depicted in diagrammatic form in FIG. 1, ref 475. A helical segment of threaded connector 204 is depicted in diagrammatic form in FIG. 1, ref, 470. The first threaded connector 202 may be disposed within the box end of the tool body 200 and the second threaded connector 204 may be disposed within the pin end of the tool body 200. The respective threaded connectors 202, 204 may be suitable for attachment within the drill sting 134. The tool 140 may be disposed intermediate the plurality of drill pipes 136, the first threaded connector 202, box end, being attached to the drill string 134 above the tool 140 and the second threaded connector 204, pin end, being attached to the drill string 134 below the tool 140. The tool 140 may be attached to a BHA 150 and a drill bit 107.

The tool or downhole tool 140 may comprise one or more electrical components 206 comprising one or more sensors within or coupled to the tool body 200 and one or more signal transmitters and receivers configured to receive and transmit a signal representing a measurement taken by the sensors.

The tool or downhole tool 140 may include a first 208 and second 210 transmission line extending along the tool body 200 that may be physically electrically connected to a transmission wire of the wired transmission line 152 of the plurality of drill pipes 136 by the electrical contacts 410 and 465 and cables 405 and 460, respectively, and with the one or more electrical components 206. The first and second transmission lines 208/210, or either of them, may be electrically connected to the transmission wire of the wired transmission line 152 by a first 410 and second 465 physical electrical insulated contact that may be mounted on a flank portion 430, 440, or other portion, of a thread segment 425, 445 of the first 202 or second 204 threaded connector, respectively. The helical thread segments 475 and 470 may extend up to 180 degrees along one turn of the threaded connectors 202 and 204. Physical contacts 410, 465 may extend along the thread segment 430, 440 up to about 180 degrees of one turn of a helical thread of the threaded connectors 202, 204. The threads 202, 204 of the tool 140 and the adjoining drill pipes136 may be timed to assure alignment and physical electrical connection of the respective contact surfaces 410, 465 during joint makeup. When aligned the respective electrical contact surfaces 410, 465 of the contacts should physically contact one another and allow for the transmission of an electrical signal between connected tools along the drill string 134.

The first 425 and second 445 connector thread segments may be removeable from the respective connector threads 202/204. The respective connector thread segments 425, 445 may be compatible for inclusion within the tool's thread 202, 204 without compromising the integrity of the tool's thread as a whole. The respective connector thread segments 425, 445 may be attached to the respective threaded connectors 202, 204 by means of a detachable anchor 420, 450. The detachable anchor 420,450 may be a bolt, screw, or a clamp. The thread segments 425, 445 may be harder than the surrounding threads 202/204 as measured on the Rockwell C scale. The hardness of the thread segments 425/445 may be achieved by a hardening process before the thread segments may be attached to the threaded portion of the connector. Or it may be achieved by a composition, mixture or an alloy of materials resulting in a higher hardness than the threads of the tool's threaded connector 202, 204. On the other hand, the connector thread segments 425, 445 may comprise a material equal or softer than the material of the adjacent threads 202/204. Hard polymers and plastics, or natural and synthetic rubbers, strengthened with metal and carbon fibers or meshes may be useful in the thread segments 425/445, especially if the hardened materials are electrically nonconducting. The tread segments 425, 445s may comprise a combination of metal and hardened polymers.

The respective physical electrical contacts 410, 465 of the downhole tool 140 and the adjoining drill pipes 136 may be electrically insulated by insulation at 415, 455 from the thread segments 425, 445 and the downhole tool 140 and the adjoining drill pipes 136. The insulation may be comprised of a polymer, a glass, or a rubber. The electrical contacts 410, 465 may be molded within the insulating material 415, 455 before assembly into the connector thread segments 425, 445. The connector thread segments 425, 445 may be electrically nonconductive, also. The first and second transmission lines 208, 210, may be connected by cables 405, 460 to the first and second electrical contacts 410, 465. The transmission lines 208, 210 may be extensions of cables 405, 460, respectively. The first 410 and second 465 electrical contacts may be electrically insulated 415, 455 within the tool body 200 as part of the attachment to the tool body 200. The first and second physical electrical contacts 410, 465 may comprise an insulated electrically conductive insert 410, 465 mounted on the respective connector thread flanks 430440. Or the physical electrical contacts 410,465 may comprise an insulated electrically conductive cladding attached to the respective connector thread flanks 430, 440.

The first and second transmission lines 208, 210, the box transmission line 405, the pin transmission line 460, and the wired transmission line 152, respectively, each may comprise a coaxial cable (Prior Art) FIG. 7, at ref 300 comprising an electrically conductive sheath 305, a dielectric 315, and a center conductor 325. The electrically conductive sheath 305 may comprise a steel tube, such as stainless steel tube. The sheath 305 may comprise an electrically nonconductive outer protective covering as well. The dielectric 315 may comprise an electrically nonconductive polymer. The polymer may comprise a volume of magnetically conductive electrically insulating (MCEI) fibers. The MCEI fibers may enhance the dielectric and comprise ferrite fibers. The MCEI or ferrite fibers may comprise between 3% and 72% of the volume of the dielectric material. The volume of MCEI fibers may be sufficient to arrest the propagation of an electromagnetic field surrounding the energized coaxial cable 300. The enhanced dielectric 315 may shield the cable from electrical interference from inside or outside the downhole tools 140. Also, the dielectric 315 may comprise an open mesh 320 embedded within the dielectric 315. The open mesh 320 may comprise a metal wire or a polymeric fabric. The mesh 320 may be electrically conductive or nonconducting. However, the mesh 320 should be electrically isolated from the downhole tool body 200 and the cable's center conductor 325 and sheath 305. The coaxial cable 300 may be compressed so that independent movement of the sheath 305, dielectric 315, and the center conductor 325 may be arrested under the gravitational forces acting on the cable 300 downhole. The open configuration of the mesh 320 may allow the transmission of pressure from the sheath 305 to the center conductor 325.

(Prior Art) FIG. 6 is a representation of an engaged box and pin threads that may be found in drill pipe and drilling tools related to this disclosure.

(Prior Art) FIG. 7 is taken from FIG. 1 of the '858 reference and is incorporated herein by this reference.

The following detailed description of the (Prior Art) FIGS. 2-5 is taken from the '927 reference as modified by this disclosure.

The following describes several embodiments for implementing different features, structures, or functions of the present disclosure. Embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these embodiments are provided merely as examples and are not intended to limit the scope of the present disclosure. Additionally, the present disclosure may repeat reference characters (e.g., numerals) and/or letters in the various embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed in the Figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the embodiments presented below may be combined in any combination of ways, e.g., any element from one example embodiment may be used in any other example embodiment, without departing from the scope of the disclosure.

Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the present disclosure, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. In addition, unless otherwise provided herein, “or” statements are intended to be non-exclusive; for example, the statement “A or B” should be considered to mean “A, B, or both A and B.”

(Prior Art) FIG. 2 illustrates a cross-sectional view of a wellsite system 100 including one or more downhole tools, for example, a first downhole tool 140 and a second downhole tool 141, positioned in a wellbore 130, according to an embodiment. The wellbore 130 may extend from the surface 102 and may be fowled in a subsurface formation 132 by rotary drilling in any suitable manner For example, some embodiments may employ directional drilling.

The wellsite system 100 may include a platform and derrick assembly 104 positioned over the wellbore 130, with the derrick assembly 104 including a rotary table 106, a kelly 108, a hook 110, and a rotary swivel 112. In a drilling operation, a drill string assembly 134 may be rotated by the rotary table 106, which engages the kelly 108 at the upper end of the drill string assembly 134. The drill string assembly 134 may be suspended from the hook 110, attached to a traveling block (not shown), through the kelly 108 and the rotary swivel 112, which permits rotation of the drill string assembly 134 relative to the hook 110. In some embodiments, a top-drive drilling system may be employed.

Drilling fluid or mud 114 may be stored in a pit 116 formed at the wellsite. A pump 118 may deliver the drilling fluid 114 to the interior bore of the drill string assembly 134 via a port in the swivel 112, which causes the drilling fluid 114 to flow downwardly through the drill string assembly 134. The drilling fluid exits the drill string assembly 134 via ports in a drill bit 107 provided as part of a bottom-hole assembly (“BHA”) 150, and then circulates upwardly through the annulus region between the outside of the drill string assembly 134 and the wall of the wellbore 130. In this manner, the drilling fluid lubricates the drill bit 107 and carries formation cuttings up to the surface as it is returned to the pit 116 for recirculation. In some embodiments, the bottom-hole assembly (BHA) 150 may include a mud motor, a rotary steerable system (RSS) 151, and/or any other devices designed to facilitate drilling the wellbore 130 in the subsurface formation 132.

The drill string assembly 134 may include several lengths or “joints” of drill pipe 136, which are mechanically connected together, end-to-end (“made up”). In some embodiments, the drill pipe 136 may be wired drill pipe, which may also be provided with a transmission wire 152, e.g., entrained within a wall thereof, clamped to the pipes 136, or otherwise positioned to run along the drill string assembly 134. The transmission wire 152 may be made of several lengths of wire, e.g., one or more for each pipe 136. The segments of the transmission wire 152 within each pipe 136 may be connected together when the pipes 136 are made-up together, so as to allow control and/or power signals to proceed up and/or down the drill string assembly 134.

The first downhole tool 140 may be positioned between the distal-most pipe 136 (i.e., farthest in the wellbore 130 from the surface 102) and the BHA 150. The second downhole tool 141 may be positioned between any two drill pipes 136 along the drill string assembly 134, between the surface 102 and the BHA 150.

With continuing reference to (Prior Art) FIG. 2, (Prior Art) FIG. 3 illustrates a schematic, side, cross-sectional view of the first downhole tool 140, according to an embodiment. Although the first downhole tool 140 is illustrated, it will be appreciated that the second downhole tool 141 may have substantially the same construction. The first downhole tool 140 may generally include a body or “sub” 200, which may have a generally cylindrical shape, and may provide a bore 201 therethrough. Further, the body 200 may have first and second connectors 202, 204 at either axial end thereof. For example, the first connector 202 may provide a box end, configured to receive and couple to a pin end of a superposed tubular (e.g., one of the pipes 136), and the second connector 204 may provide a pin end, which may be received around and coupled to a box end of a subjacent tubular (e.g., one of the pipes 136 or the BHA 150). Accordingly, the first connector 202 may be oriented “uphole” (i.e., toward the surface 102 when deployed in the wellbore 130), and the second connector 204 may be oriented “downhole” (i.e., downward, away from the surface 102). In one embodiment, the second connector 204 may provide a pin end. In another embodiment, the second connector 204 may include an extender having one or several conductors and connected to the electrical component of the downhole tool.

The downhole tool 140 may also include one or more electrical components 206, illustrated in a simplified, schematic form in (Prior Art) FIG. 3. The electrical components 206 may be coupled to the body 200, and may, for example, reside at least partially within the outer diameter of the body 200, between the inner and outer diameter thereof. In other embodiments, the electrical components 206 may be on the exterior of the body 200 or within the bore 201 therethrough. The body 200 may also include a first transmission line 208 and/or a second transmission line 210. The first and second transmission lines 208, 210 may extend along (e.g., within) the body 200 and may be electrically connected to the electrical components 206. In particular, the first transmission line 208 may extend upward along the body 200 to the first connector 202, while the second transmission line 210 may extend downward along the body 200 to the second connector 204. Accordingly, when a wired tubular (e.g., drill pipe 136, BHA 150, etc.) is coupled with the first or second connector 202, 204, an electrical contact thereof may be electrically connected to either of the first or second transmission lines 208, 210, and thus to the electrical components 206, in addition to being mechanically coupled to the body 200. In some embodiments, the downhole tool 140 may also include a battery (e.g., coupled to the electrical components 206, the first or second connector 202, 204, and/or in the body 200). The battery may be configured to power or draw power from various parts of the downhole tool 140 and/or the BHA 150. For example, in some embodiments, the battery in the downhole tool 140 may provide power through the second connector 204 to the rest of the BHA 150, or the battery may draw power from the BHA 150 through the second connector 204.

In some embodiments, the electrical components 206 may include one or more sensors, a signal receiver, signal transmitter, and one or more processors. The one or more sensors may include direction and inclination sensors (e.g., inclinometers and/or magnetometers) and/or any other MWD sensors or the like. In an embodiment, the sensors may include sensors capable of detennining an orientation of the tool face, or any other relevant orientation. In an embodiment, the sensors may include a gamma ray measurement device. The signal receiver may be configured to receive one or more signals via either of the transmission lines 208, 210, and the signal transmitter may be configured to generate and transmit one or more signals via either or the transmission lines 208, 210. It will be appreciated that the transmitter and receiver may be provided by a single electrical component.

In some embodiments, the second transmission line 210 may be omitted, and the first downhole tool 140 may provide an end-of-the line for the communication along the transmission wire 152 of the drill string assembly 134. Such an embodiment may provide for communication by the sensors of the electrical components 206 with equipment at the surface 102, and/or vice versa. In embodiments including the second transmission line 210, however, the electrical components 206 may be configured as a tool bus for inter-tool communication. That is, a down going signal from the equipment at the surface 102 may be received at the first downhole tool 140 and relayed thereby to the BHA 150, potentially after being processed by the first downhole tool 140. The BHA 150 may then adjust a drilling parameter, such as a rate of rotation, tool face angle, etc. in response to (e.g., as directed by) the down going signal.

Accordingly, measurements taken by the sensors within the electrical components 206, or external sensors, or sensors within separate components (e.g., the BHA 150), may be conveyed through a wired drill pipe uplink from the first downhole tool 140 to the surface 102, or to the BHA 150. Such information may be used to adjust the operation of directional drilling. When such measurements are conveyed, the raw sensor data may be transmitted and/or secondary or processed measurements, such as an estimate of rotation speed, a detection of stick slip, or shock and vibration, among potentially others, may be transmitted.

With continuing reference to (Prior Art) FIG. 2, (Prior Art) FIG. 4 illustrates a schematic view of the drill string assembly 134 including the first downhole tool 140, according to an embodiment. As mentioned above, the first downhole tool 140 may be made up to the distal-most pipe 136, to provide a connection to the BHA 150. As shown, the BHA 150 may be provided with the RSS 151 and the drill bit 107, although other components may also be provided. In some embodiments, the RSS 151 may be substituted with a mud motor, or any other device capable of imparting rotation to the drill bit 107 tubular within the wellbore 130.

The first downhole tool 140 may serve to collect and to transmit survey data to the surface 102 via the wired drill pipes 136. Accordingly, during a drilling operation, one or more surveys may be taken, e.g., at predetermined time, depth, etc. intervals. The sensors of the first downhole tool 140 may take measurements during such surveys and may communicate signals representing this information to the transmitter. The transmitter, in turn, may transmit a signal representing the measurements taken by the sensors to the surface via the transmission wire 152 of the wired drill pipe 136.

As will be appreciated, separate MWD sensors may be omitted from the BHA 150, as the functionality thereof may be provided by the sensor(s) of the first downhole tool 140, thereby decreasing the size and complexity of the BHA 150, in at least some examples. In other embodiments, the BHA 150 may include separate sensors. Further, by removing power-intensive communication devices (e.g., mud pulse actuators, EM transmitters, etc.) from the BHA 150, the sensors in the first downhole tool 140 may be positioned closer to the drill bit 107, which may facilitate accurately gauging the direction, inclination, etc., of the drill bit 107.

Furthermore, the first downhole tool 140 may be employed to facilitate logging-while-drilling (“LWD”). In such case, the first downhole tool 140, specifically the electrical components 206 (Prior Art) FIG. 3 thereof, may act as a bus master in a tool bus, such that the first downhole tool 140 may obtain LWD data points (and/or other measurements) from the RSS 151, and relay such data points to the surface 102 via the wired drill string assembly 134, e.g., along with the MWD data collected using the sensors of the first downhole tool 140.

(Prior Art) FIG. 5 illustrates a schematic view of the drill string assembly 134 including a plurality of second downhole tools 141 as well as the first downhole tool 140, according to an embodiment. The second downhole tools 141 may each be constructed generally similarly to the downhole tool 140 of (Prior Art) FIG. 3. Further, the distribution of the second downhole tools 141 along the drill string assembly 134 may be at uniform, patterned, or otherwise varied intervals.

In some embodiments, the second downhole tools 141 may include respective sensors 400, 402, 404. The sensors 400, 402, 404 may be incorporated within the body 200 (Prior Art) FIG. 3 of the second downhole tools 141, e.g., as part of the electrical components 206 (Prior Art) FIG. 3 thereof. In other embodiments, the sensors 400, 402, 404 may be external (e.g., coupled) thereto. Further, the sensors 400, 402, 404 may be configured to measure direction and/or inclination parameters, torque, acceleration and/or velocity (e.g., rotational), shock, vibration, and/or the like, at the different locations along the drill string assembly 134. For example, the measurements from the sensors 400, 402, 404 may be employed to detect certain downhole conditions, such as stick-slip, drill pipe curvature information along the drill string assembly 134, etc. Accordingly, the orientation, curvature, trajectory, and other conditions relevant to the drilling operations may be measured at several nodes along the drill string assembly 134, rather than solely at or near to the BHA 150. This may provide a more complete picture of the operation of the drill string assembly 134.

The electrical components 206 of the second downhole tool 141 may also include a signal generator, in addition to or as part of the signal transmitter. The signal generator may be configured to communicate with the signal receiver to receive an upgoing or down going signal from another of the downhole tools 140, 141, the surface 102, the BHA 150, or from another component, and generate a signal configured to re-transmit the received signal via the transmission wire 152. In addition, the signal generator may be configured to add information to the upgoing or down going signals, e.g., to transmit one or more signals representing measurements taken by the plurality of sensors 400, 402, 404. The added signals may be transmitted sequentially to the received signals or may be multiplexed therewith.

In some embodiments, the downhole tools 140, 141 may be configured as a tool bus for inter-tool communication. Thus, a down going signal from the surface may be received and relayed by the second downhole tools 141, to the first downhole tool 140, and ultimately to the BHA 150. The BHA 150 may then adjust a drilling parameter, such as a rate of rotation, tool face angle, etc. in response to (e.g., as directed by) such down going signals. Further, in some embodiments, commands from either or both of the first and second downhole tools 140, 141 may be sent via downlink through the wired drill pipes 136 to the BHA 150, for direct control thereof.

Accordingly, it will be appreciated that by decoupling the sensors from the MWD envelope (e.g., constraining the sensors to the connector sub between wired drill pipe and the MWD equipment) may allow for increased data collection in the drill string assembly 134, e.g., at a plurality of locations.

The foregoing has outlined features of several embodiments so that those skilled in the art may better understand the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.

Claims

1. A wired drill string assembly, comprising: a plurality of drill pipes extending from a surface into a wellbore, the plurality of drill pipes comprising a wired transmission line; anda downhole tool comprising: a body having a first threaded connector and a second threaded connector, the first threaded connector being connected to one of the plurality of drill pipes;one or more electrical components comprising a sensor coupled to the body and a signal transmitter configured to transmit a signal representing a measurement taken by the sensor;a first transmission line extending along the body and electrically connected to a transmission wire of the wired transmission line of the plurality of drill pipes and with the one or more electrical components, and whereinthe first transmission line is electrically connected to the transmission wire of the wired transmission line by a first physical electrical contact mounted on a flank of a first threaded connector thread segment.

2. The wired drill string assembly of claim 1, wherein a second transmission line is electrically connected to the transmission wire of the wired transmission line by a second physical electrical contact mounted on a flank of a second threaded connector thread segment.

3. The wired drill string assembly of claim 1, wherein the first and second connector thread segments are removable.

4. The wired drill string assembly of claim 1, wherein the first physical electrical contact is opposed to a physical electrical contact on a thread flank of the adjoining drill pipe of the wired drill string assembly.

5. The wired drill string assembly of claim 1, wherein the second physical electrical contact is opposed to a physical electrical contact on a thread flank of an adjoining drill pipe of the wired drill string assembly.

6. The wired drill string assembly of claim 1, wherein the respective physical electrical contacts of the downhole tool and the adjoining drill pipes are electrically insulated from the downhole tool and the adjoining drill pipes.

7. The wired drill string assembly of claim 1, wherein the first and second physical electrical contacts comprise an insulated electrically conductive insert mounted on the respective connector thread flanks.

8. The wired drill string assembly of claim 1, wherein the first and second physical electrical contacts comprise an insulated electrically conductive cladding attached to the respective connector thread flanks.

9. The wired drill string assembly of claim 1, wherein the respective physical electrical contacts are electrically connected to transmission lines on or within the body of the downhole tool.

10. The wired drill string assembly of claim 1, wherein the first and second transmission lines and the wired transmission line, respectively, each comprise a coaxial cable comprising an electrically conductive sheath, a dielectric, and a center conductor.

11. The wired drill string assembly of claim 1, wherein dielectric comprises a polymer comprising a volume of ferrite fibers.

12. The wired drill string assembly of claim 1, wherein the dielectric comprises an embedded mesh.

13. The wired drill string assembly of claim 1, wherein the dielectric comprises an embedded electrically conductive mesh.

14. The wired drill string assembly of claim 1, wherein the dielectric comprises an embedded electrically nonconductive mesh.

15. The wired drill string assembly of claim 1, wherein the electrically conductive mesh and the electrically nonconductive mesh, respectively, are electrically isolated from the center conductor and the sheath.

16. The wired drill string assembly of claim 1, wherein the wired transmission line is under sufficient compression that independent movement of the sheath, dielectric, and center conductor is abated under the gravitational forces of the drill string downhole.

17. The wired drill string assembly of claim 1, wherein the respective connector thread segments are electrically nonconductive.

18. The wired drill string assembly of claim 1, wherein the physical electrical contacts of the respective connector thread segments are rotationally timed to align in opposition to the physical electrical contacts on the thread segments of the adjoining drill pipes.

19. The wired drill string assembly of claim 1, wherein the respective connector thread segments comprise a removable anchor attachment to their respective helical thread forms.

20. The wired drill string assembly of claim 1, wherein the respective connector thread segments comprise a hardness as measured on the Rockwell C scale higher than a hardness of the adjacent connector threads.