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CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims priority to U.S. Provisional Application having Ser. No. 62/146,731, which was filed on Apr. 13, 2015, U.S. Provisional Application having Ser. No. 62/146,877, which was filed on Apr. 13, 2015, and U.S. Provisional Application having Ser. No. 62/147,139, which was filed on Apr. 14, 2015. Each of these priority provisional applications is incorporated herein by reference in its entirety. 
     
    
     BACKGROUND 
       [0002]    During drilling, information is sometimes transmitted to the surface from instruments within the wellbore, and/or from the surface to downhole instruments. For example, signals may be transmitted to or from measuring-while-drilling (MWD) equipment, logging-while-drilling (LWD) equipment, steering equipment, or other equipment. Such information may assist operators in the task of efficiently drilling a wellbore by providing information related to tool-face orientation and/or formation composition, and allowing commands and configuration of the downhole instruments, among other possible uses. 
         [0003]    The drill string may extend thousands of feet, and transmitting data over this distance, below the surface, may present challenges. One way such transmission has been effected is through the use of mud-pulse telemetry. In mud-pulse telemetry, a pressure spike or modulated sine wave representing a bit of data is generated in the drilling mud from a mud-pulse generator in the drill string. The pressure spike or modulated sine wave is detected by a pressure sensor at or near the surface, allowing bits of data to be related through the mud. While this communication technique has proven effective, the transmission rate may be relatively slow, on the order of single digit bits-per-minute. Moreover, the signal-to-noise ratio can be low, because the pressure spike or modulated sine wave may be attenuated once it reaches the surface. Furthermore, the noise may high due to the proximity of machinery, such as mud pumps. 
         [0004]    Electromagnetic (“e-mag”) signal transmission has also been employed. In such communication, an electromagnetic signal is generated in the downhole equipment, which travels through the formation and is detected by sensors (e.g., voltmeters) at the surface, and then returns through the drill pipe to the source, completing the circuit. However, the effectiveness of this type of signal transmission depends partially on the formation properties. If, for example, the wellbore penetrates a salt layer, the electromagnetic transmissions may be unable to reach the surface at proper amplitude. 
         [0005]    Various other types of downhole communication have also been proposed and/or implemented. Wired drill pipe, for example, has been proposed, and has the potential to obviate the challenges experienced with wireless signal transmission. However, because each pipe includes a wire connector that is prone to failure, if one connector in one pipe among the potentially thousands of pipes fails, the entire assembly can be rendered inoperative. 
       SUMMARY 
       [0006]    Embodiments of the disclosure may provide an apparatus for delivering tools within a drill string. The apparatus may include an instrument line including a mechanically resistant external structure with an internal cavity. The instrument line may be configured to be deployed into the drill string. The apparatus may include one or more isolated wires positioned within the internal cavity. The apparatus may also include one or more tools removably coupled to the instrument line and positionable within the drill string. The one or more tools may be configured to provide measurements of conditions within a wellbore via the one or more isolated wires. 
         [0007]    Embodiments of the disclosure may also include a junction module for coupling sections of an instrument line positioned within a drill string. The junction module may include an upper connection coupled to a first section of the instrument line. The junction module may also include a swivel coupled to the upper connection. The junction module may include a main compartment coupled to the junction swivel. The main compartment may include one or more of mechanical devices, electronics, sensors, and actuators. The junction module may also include an anchor section coupled to the main compartment. The anchor section may be configured to anchor at least one of the first section or the second section within the drill string. The junction module may include a lower connection coupled to the second section of the instrument line. 
         [0008]    Embodiments of the disclosure may include a method for deploying an instrument line into a drill string in a wellbore. The method may include receiving an installation device coupled to the instrument line into a drilling device through an entry port. The method may include sealing the entry port using a sealing device coupled to the drilling device. The method may include drilling at least a portion of the wellbore using the drilling device, the drilling device being connected to the drill string. The method may include lowering the installation device and the instrument line through the drill string while drilling the wellbore and while sealing the entry port. 
         [0009]    The foregoing summary is not intended to be exhaustive, but is provided merely to introduce a subset of the aspects of the present disclosure. These and other aspects are presented in greater detail below 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the present teachings and together with the description, serve to explain the principles of the present teachings. In the figures: 
           [0011]      FIG. 1  illustrates a simplified, schematic view of a drilling rig system, according to an embodiment. 
           [0012]      FIG. 2  illustrates a side, schematic view of a tool deployment assembly, according to an embodiment. 
           [0013]      FIG. 3A  illustrates a first side view of a top drive of the drilling rig system, according to an embodiment. 
           [0014]      FIG. 3B  illustrates a second side view of the top drive of the drilling rig system, according to an embodiment. 
           [0015]      FIGS. 4A and 4B  illustrate conceptual, side, schematic views of a well site including the drilling rig, in which various downhole instruments may be used, according to an embodiment. 
           [0016]      FIG. 5  illustrates a conceptual, side, schematic view of the instrument coupled to the instrument line, according to an embodiment. 
           [0017]      FIG. 6  illustrates a cross-sectional view of the instrument line in the bore of the drill string, according to an embodiment 
           [0018]      FIG. 7  illustrates a flowchart of a method for deploying a tool within a drill string, according to an embodiment. 
           [0019]      FIGS. 8A and 8B  illustrate conceptual, side, schematic views of a well site including the drilling rig, in which multiple instrument lines may be used, according to an embodiment. 
           [0020]      FIG. 9  illustrates a conceptual, side, schematic view of a junction module as a network node, according to an embodiment. 
           [0021]      FIGS. 10A and 10B  illustrate conceptual, side, schematic views of a connection between the junction module and instrument lines, according to an embodiment. 
           [0022]      FIGS. 11A and 11B  illustrate conceptual, side, schematic views of a passive connection between junction modules and instrument lines, according to an embodiment. 
           [0023]      FIGS. 12A and 12B  illustrate partial cross-sectional views of examples of a locating module, according to an embodiment. 
           [0024]      FIG. 13  illustrates a flowchart of a method for deploying a multi-section instrument line within a drill string, according to an embodiment. 
           [0025]      FIG. 14  illustrates a schematic view of a computing system, according to an embodiment. 
       
    
    
     DETAILED DESCRIPTION 
       [0026]    Reference will now be made in detail to specific embodiments illustrated in the accompanying drawings and figures. In the following detailed description, numerous specific details are set forth in order to provide a thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known methods, procedures, components, circuits, and networks have not been described in detail so as not to unnecessarily obscure aspects of the embodiments. 
         [0027]    It will also be understood that, although the terms first, second, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, a first object could be termed a second object or step, and, similarly, a second object could be termed a first object or step, without departing from the scope of the present disclosure. 
         [0028]    The terminology used in the description of the invention herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used in the description of the invention and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof. Further, as used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context. 
         [0029]      FIG. 1  illustrates a schematic view of a drilling rig  100 , according to an embodiment. The drilling rig  100  includes a drilling apparatus  102  and a drill string  104  coupled thereto. The drilling apparatus  102  may include any type of drilling device, such as a top drive to support and rotate the drill string  104  or any other device configured to support, lower, and rotate the drill string  104 , which may be deployed into a wellbore  106 . In the illustrated embodiment, the drilling apparatus  102  may also include a travelling block  105 , which may include of one or more rotating sheaves. 
         [0030]    The drilling rig  100  may also include a rig floor  108 , from which a support structure (e.g., including a mast)  110  may extend. A slips assembly  109  may be disposed at the rig floor  108 , and may be configured to engage the drill string  104  so as to enable a new stand of tubulars to be added to the drill string  104  via the drilling apparatus  102 . 
         [0031]    A crown block  112  may be coupled to the support structure  110 . Further, a drawworks  114  may be coupled to the rig floor  108 . A drill line  116  may extend between the drawworks  114  and the crown block  112 , and may be received through the sheaves of the travelling block  105 . Accordingly, the position of the drilling apparatus  102  may be changed (e.g., raised or lowered) by spooling or unspooling the drilling line  116  from the drawworks  114 , e.g., by rotation of the drawworks  114 . 
         [0032]    The drilling rig  100  may also include an instrument line  120 , which may be received through the drilling apparatus  102  and into the drill string  104 . The instrument line  120  may be spooled on an instrument line spool  122 , and may be received at least partially around a line sheave  124  between the instrument line spool  122  and the drilling apparatus  102 . In an embodiment, the instrument line spool  122  may be coupled to the rig floor  108  as shown, but in other embodiments, may be positioned anywhere on the rig  100  or in proximity thereto. Furthermore, in some embodiments, the line sheave  124  may be installed below the crown block  112 . It may also be installed on the side of the crown-block  112 . In such an embodiment, a guide may be installed above the entry port  220  to align the instrument line  120  from the sheave  124  with the bore of the shaft  204  and the drill-sting  104 . In another embodiment, the sheave  124  can be attached directly onto the drilling apparatus  102 . In such an embodiment, the spooling of the line spool  122  may be synchronize with the rotation of the drawworks  114 . 
         [0033]    The instrument line  120  may be connected to a downhole instrument  126 , which may be deployed into the interior of the drill string  104 , as will be described in greater detail below. The drill string  104  may be rotated while the instrument line  120  is deployed in the drill string  104 . The rotation may induce twisting of the instrument line  120 . Accordingly, the instrument  126  and/or a lower portion of the instrument line  120  may, in some embodiments, include a swivel, allowing for relative rotation between the instrument  126  and the instrument line  120 . In such an embodiment, the instrument  126  may also be connected to the rotating drill string  104 . 
         [0034]    In an embodiment, the position of the downhole instrument  126  may be changed (e.g., raised or lowered) by spooling or unspooling the instrument line  120  from the instrument line spool  122 . The downhole instrument  126  may be any type of instrument, such as a logging device, which may include one or more geophones, acoustic receivers, torque sensors, strain gauges, accelerometers, gyroscope, current probe, voltmeters, and/or the like. Further, the instrument line  120  may provide for wired communication with a controller  128 , e.g., without calling for wires to be formed as a part of the drill pipe making up the drill string  104 . 
         [0035]      FIG. 2  illustrates an enlarged, partial, schematic view of the drilling rig  100 , according to an embodiment. As shown, the drilling apparatus  102  may be suspended from the rig floor  108  via interaction with the travelling block  105 , the crown block  112 , and the drilling line  116  that is spooled on the drawworks  114 . 
         [0036]    In addition, the drilling apparatus  102  may include a drilling device  200 , e.g., a top drive. The drilling device  200  may include a housing  202  and a shaft  204 , which may be coupled to and extend out of the housing  202 . In particular, the shaft  204  may be rotatably coupled to the housing  202  via a thrust bearing  206 . The shaft  204  may be drive to rotate by a motor  207 , which may be coupled to and/or disposed within the housing  202 . Further, the shaft  204  may be connected to the drill string  104 , such that rotation of the shaft  204  may cause the drill string  104  to rotate. Such rotation may be employed for drilling the well in rotary mode, as well as controlling orientation of the drill string  104  while drilling the well in sliding mode with a down-hole motor or turbine, allowing potential deviation of the wellbore  106  to the correct azimuth. By such connection between the shaft  204  and the drill string  104 , at least a portion of the weight of the drill string  104  may be supported by the housing  202 , which transmits the weight to the rig floor  108  via the crown block  112  and the support structure  110 , as well as the drawworks  114 . The drilling device  200  may also include one or more rollers  208  (four are shown) or sliding guides, which may transmit reactionary torque loads to the support structure  110 . The housing  202  may further include an entry port  210 , through which the instrument line  120  and the instrument  126  may be received. 
         [0037]    Further, the drilling apparatus  102  may include a sealing device  220 , through which the instrument line  120  and the instrument  126  may be received into the entry port  210 . The sealing device  220  may be coupled to the housing  202  of the drilling device  200 , and may be movable therewith. The sealing device  220  may have (e.g., be able to be operated in) at least three configurations. In an open configuration, the sealing device  220  may be configured to receive the instrument  126  therethrough. In a first, sealed configuration (illustrated in  FIG. 2 ), the sealing device  220  may be configured to receive and seal with the instrument line  120 . The instrument line  120  may be able to slide relative to the sealing device  220  when the sealing device  220  is in the first configuration, but fluid may be prevented from proceeding through the entry port  210  by the sealing device  220 . In a second, sealed configuration, the sealing device  220  may completely seal the entry port  210 , e.g., when the instrument line  120  is not received therethrough. Thus, the sealing device  220  may function similarly to a blowout preventer does for the drill string  104 , serving to control access into the entry port  210 . The different configurations may be reached based on a position of an annular “preventer” or seal of the sealing device  220 , as will be described in greater detail below. 
         [0038]    The entry port  210  may communicate with an interior  250  of the shaft  204 , e.g., via a conduit  253  within the housing  202 . The shaft  204  may be rotatably coupled to the conduit  253  via swivel  254 , as shown. Accordingly, the instrument line  120 , when received through the entry port  210 , may proceed through the conduit  253  and into the shaft  204 , and then into the drill string  104 . 
         [0039]    The drilling device  200  may also receive a flow of drilling mud via a mud conduit  260 . The mud conduit  260  may communicate with the conduit  253  within the housing  202 , and thus the mud conduit  260  may be in fluid communication with the entry port  210 , as well as the interior  250  of the shaft  204  and the drill string  104 . The sealing device  220  may serve to prevent mud flow up through the entry port  210  in either or both of the first and second configurations thereof. 
         [0040]    The drilling apparatus  200  may further include a line-pusher  265 . The line-pusher  265  may be configured to apply a downwardly-directed force on the instrument line  120 , which may cause the instrument line  120  to be directed downward, through the sealing device  220 , the entry port  210 , the conduit  253 , the interior  250  of the shaft  204 , and through at least a portion of the drill string  104 , so as to deploy the instrument  126  ( FIG. 1 ) therein. Further, the line-pusher  265  may be coupled to the housing  202  of the drilling device  200  and may be movable therewith. In an embodiment, the line-pusher  265  may be directly attached to the sealing device  220 , e.g., such that the sealing device  220  is positioned between the housing  202  and the line-pusher  265 . As such, the line-pusher  265  may be configured to push the instrument line  120  through the entry port  210  via the sealing device  220 . 
         [0041]    The line-pusher  265  may be employed to overcome initial fluid resistance provided by the drilling mud coursing through the mud conduit  260 . Further, the line-pusher  265  may provide for rapid deployment of the instrument line  120  through the drill string  104 , e.g., at a similar rate, or even faster than, the velocity of the drilling mud therein, and thus the line-pusher  265  may overcome drag forces of the instrument  126  and the drilling line  116  in contact with the mud and with the bore of the drill string  104 . 
         [0042]    The line-pusher  265  may also be used to retract the instrument line  120  and the instrument  126  out of the drill string  104 , e.g., by reversing direction and pushing the instrument line  120  upwards, away from the entry port  210 . The retracted instrument line  120  may thus be spooled on the instrument line spool  122 , e.g., with minimum pull force by the instrument line spool  122 . 
         [0043]    The drilling apparatus  102  may also include a pivotable guide  270 , through which the instrument line  120  may be received. The pivotable guide  270  may be positioned, as proceeding along the line  120 , between the line sheave  124  and the line-pusher  265 . The pivotable guide  270  may be movable across a range of positions, for example, between a first position, shown with solid lines, and a second position, shown with dashed lines. In the first position, the pivotable guide  270  may direct the instrument line  120  between the sheaves of the crown block  112  and between the sheaves of the travelling block  105  and toward the entry port  210 . In the second position, the pivotable guide  270  may direct the instrument line  120  away from the entry port  210 . For example, the second position may be employed when raising the drilling device  200  so as to accept a new stand of tubulars on the drill string  104  and/or when initially running the instrument  126  and the instrument line  120  into the entry port  210 , as will be described in greater detail below. 
         [0044]      FIGS. 3A and 3B  illustrates two partial side views of the drilling apparatus  102 , specifically showing additional details of the sealing device  220  and the line-pusher  265 , among other things, according to an embodiment. As illustrated, the sealing device  220  and the line-pusher  265  may be positioned between two sets of sheaves  306 ,  308  of the travelling block  105 , and thus may be positioned to receive the instrument line  120  and feed the instrument line  120  to the entry port  210 . 
         [0045]    Further, the sealing device  220  may include an annular seal (e.g., an annular “preventer”)  300  and one or more rams (two shown:  302 ,  304 ). The annular seal  300  may be movable in response to a command, e.g., radially inwards and outwards. Accordingly, the annular seal  300  may be moved outwards to receive the instrument line  120  and inwards to seal the entry port  210 . 
         [0046]    The ram  302  may be a pipe ram or a shear ram, and the ram  304  may be a blind ram. In an embodiment, the ram  304  being a blind ram may allow the sealing device  220  to close the entry port  210  when the instrumented line  120  is not present in the sealing device  220 . Such situation may occur during drilling operations when usage of the instrument line  120  and/or the instrument  126  is not desired. The change of sealing configuration may occur in response to a remote control with a minimum time delay. Such configuration control may be implemented using a hydraulics system, which apply oil pressure on actuators via manually or computer-controlled valves. In the embodiment in which the ram  302  is a pipe ram, the pipe ram  302  may be used to seal accurately against the instrumented line  120 , for example, in situations in which the inside of the drill string  104  is at high pressure. The pipe rams also may support the instrument  120  line within the drill string  104 , and thus may serve as a back-up if the line-pusher  265  is temporarily incapable of supporting the instrumented line within the drill sting  104 . The ram  302  acting as a shear ram or the ram  304  acting as a shear/blind rams may sever the instrument line  120  when pressure inside the drill string  104  reaches a high value. 
         [0047]    Furthermore, an in-line blowout preventer (IBOP) may be installed along the shaft  204 . The IBOP may ensure high pressure containment when high formation pressure may be applied inside the top of the drill string  104 . Such IBOP ensures isolation of the bore of the drill string  104  from the rotary seal inside the swivel  254  as well as the flexible hose which delivers the fluid to the conduit  260 . With the insertion of the instrument line through the IBOP, the IBOP may not be able to close. Thus, the system  100  may include a push-bar, which can be inserted in the entry port to push downwards the sheared instrument line  120 . 
         [0048]    When the IBOP closes, the instrument line  120  is sheared by the ram  304 . Then the bottom of the upper part of the cut instrument line is pulled upward, letting the blind ram  304  close the bore the entry port  210 . The cut upper part of the instrument line may then be removed from the entry port  210  and the line pusher  265 . In some embodiments, the ram  302  may be a blind ram, providing pressure containment after closing, as soon as the bottom of the upper part of the cut instrument line  120  is lifted above the ram  302 . A push-bar may then be delivered by the pilotable guide in the line pusher  265 . The line pusher grabs the push-bar, the annular seal  300  is open to let the push-bar enter in the entry port  210 , while a blind ram  304  or  302  is closed. The annular seal of the IBOP may be actuated against the push bar. The blind ram  304  (or optionally  302 ) is open to allow the passage of the lower part the push-bar. Then the push-bar is pushed downwards by the line pusher  265  to push the lower part of the cut instrument line below the IBOP of the shaft  204 . Then the push bar is pulled upwards outside the IBOP which may be closed to contain pressure in the drill-string  104  below the IBOP. 
         [0049]    In some embodiments, the cut lower part of the instrument line  120  may not bounce upwards after being pushed below the IBOP, as its weight keeps it down. This allows safe closing of the IBOP. In some applications, one or more techniques may be employed to prevent the cut lower part of the instrumented line  120  from bouncing back in the IBOP. For example, a flow valve may be installed below the IBOP at the bottom of the shaft  204 . After the push-bar has pushed the instrument line below the IBOP, above the flow valve, this flow valve may be closed to pinch and hold the cut instrument line  120 , thereby prohibiting bounce upwards of this line. In another embodiment, the push-bar may have a device at its bottom which would stay in the bore of the flow line (either the shaft  204  or the bottom bore of the IBOP) due to friction system with the bore or by a latching system which may engage a dog into a groove of the bore of the flow line below IBOP. When the IBOP has been closed, the push-bar may be pulled upwards by the line pusher  265 . When the push-bar has been raised above the blind ram  304 , the blind ram  304  may be closed. Then the push-bar may be removed out of the entry port  220 . 
         [0050]    The actuation of the annular seal  300 , the rams  302 ,  304 , as well as the control of the pivotable guide  270  and the delivery/recovery of the push-bar may be performed by various actuators which can be remote controlled. The PLC  310  of  FIG. 3B  may perform such control. 
         [0051]    Further, the line-pusher  265  may include two or more tracks or “caterpillars”  307 ,  309 , which may engage and move the instrument line  120  into and/or out of the entry port  210 . The tracks  307 ,  309  may include links, rollers, or any other structure capable of engaging the instrument line  120  and, e.g., through the friction created by such an engagement, force the instrument line  120  downwards into the entry port  210 , or to pull the instrument line  120  upwards, out of the entry port  210 , as the tracks  307 ,  309  are moved. The tracks  307 ,  309  may have shapes to match the circular pattern of the instrument line  120 , allowing distributed contact between the tracks  307 ,  309  with the instrument line  120  for high friction while keeping the local contact pressure to an acceptable level for the instrument line  120 . The high friction allows to the “caterpillars” to apply fair push or pull force onto the instrument line  120 . 
         [0052]    In the illustrated embodiment, the shaft  204  is connected to a gear  318 , which meshes with a gear  320  that is connected to a motor shaft  322 . The motor shaft  322  is rotated by the motor  207 , and such rotate is transmitted to the shaft  204  via the meshing gears  318 ,  320 . In this embodiment, the motor  207  is coupled to the housing  202 , while mounts  324 ,  326  support the shaft of pinion gear  320 . 
         [0053]    The drilling apparatus  102  may also include a controller  310 , which may be coupled to the housing  202  and movable therewith, or otherwise in communication with the drilling device  200 . The controller  310  may receive commands, e.g., from the controller  128  ( FIG. 1 ) via a control line  312 , but in some embodiments, may be autonomous. Further, the controller  310  may control the operation of the line-pusher  265 , e.g., to control when the line-pusher  265  operates to feed the instrument line  120  through the entry port  210 . The controller  310  may also operate to control the sealing device  220 , e.g., to control when the annular seal  300  moves radially and to control the operation of one or both rams  302 ,  304 . The controller  310  may further control or monitor the power to the motor  207  via a power line  314 , so as to control when, and at what speed, the motor  207  rotates the shaft  204 . 
         [0054]    In embodiments, the instrument line  120  may be or include a metallic tube such as a hydraulic line with one or more internal wires therein (e.g., electrical or fiber optic wires) for communication and/or transmission of power. The instrument line  120  may have a diameter from approximately 1/16 inch to approximately 1 inch or from approximately ⅛ inch to approximately ½ inch. The instrument line  120  may transmit signals to and from one or more instruments  126  or other devices coupled thereto. The instrument line  120  may transmits power to and from one or more instruments  126  or other devices coupled thereto. 
         [0055]    The instrument line  120  may have an adequate torsional resistance to resist friction torque (e.g., due to rotation of the drill string): the circular metallic section may provide such resistance. The instrument line  120  may also have a smooth outer surface or approximately smooth outer surface, which may lead to lower friction than a conventional cable. The instrument line  120  may be compatible with an injection head and with the caterpillar, described above. 
         [0056]    The instrument line  120  may be configured to transmit measurement data as a single cable application or a continuous cable application. For example, the instrument line  120  may transmit logging data to the rig. One or more downhole instruments  126 , delivered by the instrument line  120 , may be any type of instrument, such as a wireline logging tool or a logging-while-drilling (“LWD”) tool, a measurement-while-drilling (“MWD”) tool, a geophone, an acoustic receiver, a torque sensor, and/or the like. The downhole instrument  126  may be configured to obtain measurements in the wellbore  106 , and the measurements may be or include current measurements, voltage differential measurements, rotational measurements (e.g., local instantaneous RPM of the drill string  104 ), radial shocks, local elastic deformation measurements (e.g., axial and torsion), steel acoustic transmission measurements (e.g., “CBL-type”), and the like. In addition, the downhole instrument  126  may include a clamping system that serves as a “REW free-point indicator.” In another example, the instrument line  120  may be used to recover mud pulse telemetry data from a measuring-while-drilling tool. 
         [0057]      FIGS. 4A and 4B  illustrate conceptual, side, schematic views of a well site including the drilling rig  100 , in which various downhole instruments may be used, according to embodiments. For example,  FIG. 4A  illustrates a conceptual, side, schematic view of the well site  400 , in which a logging tool  402  may be used, according to an embodiment. As illustrated, the drill string  104  with the instrument line  120  therein may be run into the wellbore  106 . The wellbore  106  may include a vertical portion, a deviated portion, and a horizontal portion. The logging tool  402  may be coupled to the instrument line  120  and positioned within the drill string  104 , for example, at a deviated portion. 
         [0058]    A bottom-hole assembly (“BHA”)  404  may be coupled to a lower end of the drill string  104 . The BHA  404  may be or include several downhole tools above a drill bit  406 . The downhole tools may be or include a rotary steerable system, a motor, and one or more MWD/LWD tools  408 . The drilling rig may also include a fluid reservoir  410  (e.g. mud) and a pump  412  for cycling the fluid through the drill string  104  via a fluid line  416 . While not illustrated, the drill string  104  may include one or more tools or substitutes (“subs”), such as MWD and LWD, shock and vibration reduction tools, agitator tools, drilling motor, rotary steerable system (“RSS”), etc. The one or more tools or subs may be coupled to the drilling string at any location (e.g., in the BHA  404 ) to assist in the drilling process. In some embodiments, the drill string  104  may include a universal bore hole orientation (“UBHO”) sub. The UBHO sub may axially and rotational fix one or more downhole electronics packages within the drill string  104 . For example, the UBHO sub may include one or more steering tools, one or more gyroscopes, one or more MWD or LWD tools, e.g., MWD/LWD tools  408 , etc. 
         [0059]    The logging tool  402  may be configured to measure one or more formation properties and/or physical properties, as the wellbore  106  is being drilled or at any time thereafter. For example, the logging tool  402  may take measurements such as D&amp;I measurements in the deviated portion of the wellbore (i.e., the dogleg), gyroscope, gamma ray measurements, RPM measurements (e.g., local instantaneous drill string RPM measurements) and the like. Likewise, for example, the formation properties may include resistivity, density, porosity, sonic velocity, gamma rays, and the like. Additionally, for example, the physical properties may include pressure, temperature, wellbore caliper, wellbore trajectory, a weight-on-bit, torque-on-bit, vibration, shock, stick slip, and the like. In at least one embodiment, the logging tool  402  may include a swivel  418 , as discussed in more detail below. 
         [0060]    The logging tool  402  may transmit data (e.g., formation properties, physical properties, etc.) from within the wellbore  106  up to a computer system  420 . The instrument line  120  may be made of a metallic tube (such as a hydraulic line) with one or more internal wires  422  therein (e.g., electrical or fiber optic wires) for communication. For example, the logging tool  402  may be coupled to the computer system  420  by one or more internal wires  422 . Additionally, power may be supplied to the logging tool  402  via the one or more internal wires  422 . 
         [0061]    In another example,  FIG. 4B  illustrates a conceptual, side, schematic view of the well site  450 , in which a for MWD telemetry reception tool  452  may be used, according to an embodiment. In some embodiments, the MWD  458  may be installed in the BHA  454 . As illustrated, the drill string  104  with the instrument line  120  therein may be run into the wellbore  106 . The wellbore  106  may include a vertical portion, a deviated portion, and a horizontal portion. The MWD telemetry reception tool  452  may be coupled to the instrument line  120  and positioned within the drill string  104 . For example, the MWD telemetry reception tool  452  may be positioned in the vertical portion of the wellbore. In some embodiments, the MWD telemetry reception tool  452  may be positioned below the vertical portion of the well-bore. The MWD telemetry reception tool  452  may be coupled to the instrument line  120  by a swivel (not show), as described below. 
         [0062]    A BHA  454  may be coupled to a lower end of the drill string  104 . The BHA  454  may be or include several downhole tools above a drill bit  456 . The downhole tools may be or include a rotary steerable system, a motor, and one or more MWD/LWD tools  458 . The drilling rig may also include a fluid reservoir  460  (e.g. mud) and a pump  462  for circulating the fluid through the drill string  104  via a fluid line  464 . While not illustrated, the drill string  104  may include one or more tools or subs, such as MWD and LWD, shock and vibration reduction tools, agitator tools, drilling motor, RSS, etc. The one or more tools or subs may be coupled to the drilling string at any location (e.g., in the BHA  454 ) to assist in the drilling process. In some embodiments, the drill string  104  may include a UBHO sub. The UBHO sub may axially and rotational fix one or more downhole electronics packages within the drill string  104 . For example, the UBHO sub may include one or more steering tools, one or more gyroscopes, one or more MWD or LWD tools, e.g., MWD/LWD tools  458 , etc. 
         [0063]    The MWD/LWD tools  458  may be configured to measure one or more physical properties as the wellbore  106  is being drilled or at any time thereafter. The formation properties may include resistivity, density, porosity, sonic velocity, gamma rays, and the like. The physical properties may include pressure, temperature, wellbore caliper, wellbore trajectory, a weight-on-bit, torque-on-bit, vibration, shock, stick slip, and the like. The measurements and data from the MWD/LWD tools  458  may be transmitted upwards to the MWD telemetry reception tool  452  for relay to the surface, for example, the computer  466  via the one or more wires  468 . For example, the MWD/LWD tools  458  may send a telemetry signal  470  (e.g. mud pulse telemetry signal) to the MWD telemetry tool  452  for relay to the surface. Additionally, power may be supplied to the MWD telemetry reception tool  452  via the one or more internal wires  468 . 
         [0064]    The MWD telemetry reception tool  452  may group the sets of data from the MWD/LWD tools  458  and the MWD telemetry reception tool  452  and prepare the data for transmission to the surface after proper encoding. The MWD telemetry reception tool  452  may improve signal reception and/or increase the data rate from the MWD tools  458 . Such process may occur while drilling or during any operation associated with drilling program. Periodically, drill-pipe may have to be added or removed of the drill-string  104 . Before such addition/removal of pipe, the instrument line  120  and the MWD telemetry reception tool  452  must be removed. During the period of absence of instrument  452  and instrument line  120  at the proper location in the drill-string  104 , there is a blind period: no data may be received via this communication system involving the MWD telemetry reception tool  452 , if the drilling continues for no NPT (None-Productive time). This blind period may be about 0.5% of the drill time, or a NPT of 0.5% may be imposed. The drilling rig  100  may also include one or more devices  472  and communication lines  474  to collect data from the MWD/LWD tools  458  in the wellbore  106 , involving mud-pulse telemetry. In some other embodiment, surface reception sensor may be provided near/at the rig to receive MWD e-mag telemetry. 
         [0065]      FIG. 5  illustrates a conceptual, side, schematic view of the instrument  500  coupled to the instrument line  120 , according to an embodiment. The instrument  500  may include an electronics section  502 , a tool head  504 , and a swivel  506 . 
         [0066]    The electronics section  502  may include any electronics or electrical components that may be used during the operations. The electronics section  502  may be sealed at a pressure that assists in the operations of the electronics or electrical components, for example, approximately atmospheric pressure. For example, the electronics section  502  may include measurement system equivalent to LWD tools (e.g., logging tool  402 ), and/or MWD telemetry tools (e.g. MWD telemetry reception tool  452 ), control modules, communication devices, and the like. For example, the electronics section  502  may also include a network node. The network node may be used to decode and re-encode in one or two directions, for example, data transmitted downhole from the surface and/or data received from instruments in the wellbore  106  and transmitted to the surface. Data collected within the electronics section may also be added to the data transmitted by the network node. For example, data from an accelerometer or a magnetometer (e.g., for rotation) may be added to the data that is decoded or re-encoded. In another example, data relating to pipe stretch and twist may be added to the data that is decoded or re-encoded. The data transmission may be from the surface (e.g., the computer  128  to the instrument (e.g., logging tool  402 ), and/or MWD telemetry tools (e.g. MWD telemetry reception tool  452 ) so that the instrument may perform requested tasks and operate under proper setting and controls. The electronics section  502  may also include a power source. The power source may be any type of power source such as a battery, a rechargeable battery, and the like. For example, the power may be supplied through the instrument line to drive the power source and provide power to the electronics section  502  and other components in the wellbore  106 , for example, the BHA. The power source may provide power if the instrument  500  is disconnected from the surface power system. 
         [0067]    The swivel  506  may be positioned between the instrument line  120  and the electronics section  502 . The swivel  506  may allow the electronics section  502  to rotate while the instrument line  120  does not rotate. This may allow the electronics section  502  to rotate with the drill string  104 . 
         [0068]    The swivel  506  may also support the axial load generated by the instrument  500 . For example, the swivel  506  may include thrust bearing  508 . The swivel  506  may also include lubrication  510  (e.g. oil) within a cavity of the swivel  506  and surround the thrust bearing  508 . The swivel  506  may also include rotary connection  512  for signal transmission. The rotary connection  512  may allow for signal and/or power transmission for each wire in the instrument line and for grounding the tubing, while the swivel is submitted to relative rotation form its top and bottom. For example, the rotary connection  512  may be rotary contact or a rotary split transformer. 
         [0069]      FIG. 6  illustrates a cross-sectional view  600  of the instrument line  120  in the bore of the drill string  104 , according to an embodiment. The drill string  104  may rotate about a central longitudinal axis  602 . As shown, the drill string  104  rotates clockwise direction  604 ; however, in other embodiments, the drill string  104  may rotate counterclockwise direction. The instrument line  120  may move (e.g., whirl) within the bore of the drill string  104  as the drill string  104  rotates, as shown by the arrows  606 . The instrument line  120  may be pulled to the low side by gravitational forces. 
         [0070]    In the examples described above, the hydraulic drag on the instrument line  120  may be up to twice the weight of the instrument line  120 . The Euler buckling length may be about 100 ft at the top of the instrument line  120  and about 10 ft at the bottom of the instrument line. When sufficiently rigid with its external metal tube, the instrument line  120  may not pack within the bore of the drill string if/when it fails unlike conventional cables. 
         [0071]    In the examples described above, the instrument line  120  may be able to transmit data to and from the rig from approximately 5 kbits/second to approximately 100 kbits/second or more without a repeater. The instrument line  120  may be connected to one or more modems. The instrument line  120  may use two frequency bandwidths: one for downlinking and one for uplinking. The instrument line  120  may be used for point-to-point communication (e.g., as a REW application) or a network system with a plurality of distributed nodes. In at least one embodiment, the instrument line  120  may transmit power (e.g., up to about 100 watts). 
         [0072]      FIG. 7  illustrates a flowchart of a method  700  for deploying the instrument  126  into the drill string  104  deployed into the wellbore  106 , according to an embodiment. For example, the method may be utilized to deploy include LWD tools (e.g., logging tool  402 ), MWD telemetry tools (e.g. MWD telemetry reception tool  452 ), described above. Although the present method  700  is described with reference to the drilling rig  100  discussed above, it will be appreciated that this is merely an example, and embodiments of the method  700  may be applied using other structures. 
         [0073]    The method  700  may begin with receiving an instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) in the drilling device  200 , as at  702 . This may include, for example, receiving the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) and the instrument line  120  down between the sheaves of the crown block  112 , between the sheaves of the travelling block  105 , through the line-pusher  265 , through the sealing device  220 , and into the entry port  210  of the housing  202 . In a specific embodiment, the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) may be positioned in the interior  250  of the shaft  204 , or in the conduit  253 . 
         [0074]    The method  700  may also include sealing the entry port  210  using the sealing device  220 , as at  704 . For example, the annular seal  300  of the sealing device  220  may extend radially inward from an open position, which allows the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) to pass through, to a first, sealed configuration, in which the annular seal  300  engages and seals with the instrument line  120 . 
         [0075]    The method  700  may include receiving a flow of mud past the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ), as at  706 . The method  700  may then proceed to lowering the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) into the drill string  104 , as at  708 . At least a part of this lowering may be accomplished by pushing the instrument line  120  using the line-pusher  265 , although at least a part of this pushing may also or instead rely on drag effect generated by the flowing mud or even only gravity effect. Further, the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) may be lowered (e.g., pushed) to a predetermined depth within the drill string  104 . In addition, while the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) is being lowered, the instrument line spool  122  may unspool the instrument line (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) therefrom, so as to allow the line  116  to be extended down into the drill string  104 . The unspooling of the instrument line  120  may be coordinated, e.g., synchronized, with the pushing by the line-pusher  265 . Such lowering may occur rapidly, e.g., to minimize “blind” time during deployment during which the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) is not in position to transmit data. For example, such lowering may occur at about 5, about 10, about 15, or about 20 meters per second. 
         [0076]    In an embodiment, the method  700  may include lowering the drilling device  200 , e.g., by unspooling drilling line  116  from the drawworks  114 , as at  710 . In some embodiments, lowering the drilling device  200  may occur at the same time as the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) is being pushed into the drill string  104 , and thus the pushing of the drill string  104  may take into account the change in position of the drilling device  200 . 
         [0077]    Prior to, during, or after lowering the drilling device  200 , the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) may be moved into one or more predetermined positions and employed to collect data (e.g., formation, seismic, drill-pipe stress, torque, stick-slip, seismic, gyroscopic, nuclear magnetic resonance, or any other type of data), as at  712 , which may be sent to the one or more surface controllers  128 , e.g., via the instrument line  120 . Further, data may be collected by the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) as transmitted from the surface via the instrument line  120 , e.g., for purposes of configuration of sensors of the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) or for relay to other equipment of the drill string  104 , such as the steering components of the bottom-hole assembly (not shown). The instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) and the instrument line  120  may be present in the bore the drill-string  104  during drilling operation involving movement of the drill-string, including rotation and axial movement of the drill-string  104 . The instrument line may be twisted due friction generated by the rotation of the drill-string  104  onto the instrument line  120  and even on the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ). 
         [0078]    The method  700  may also include raising the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) to a position within the drilling device  200 , e.g., within the shaft  204  or within the conduit  253 , as at  714 . This may occur rapidly, for example, at least about 5, about 10, or about 15 meters per second, or more. For example, this may be conducted in response to the drilling device  200  reaching a predetermined elevation with respect to the rig floor  108 , e.g., when the drilling device  200  is at or near to its lower end range of movement. The axial movement of the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) may occur when other axial movement may be imposed on the drill-string  104 . In some embodiments, the axial movement of the system may be synchronized so that the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) stays at a relative constant position within the drill-string  104 , by synchronizing the movement of the drawwork  114  and the line spool  122 . In other applications, the instrument may be kept at the same position versus the earth, while the drill-string  104  is moving axially in the well-bore. 
         [0079]    Once the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) is above the drill string  104 , the shaft  204  may be disconnected from the drill string  104 , as at  716 . Thereafter, a new stand of one or more tubulars may be added to the drill string  104  and attached to the new stand, as at  718 . The method  700  may return to lowering the instrument  126  at  708 , and the sequence may repeat. 
         [0080]    In one example of the method  700 , fluid (e.g., mud) may be pumped through the bore of the drill string at about 20 ft/sec. The instrument line  120  may be run into the drill string at about 40 ft/second depending on buckling and the effects of gravity. The instrument line  120  may be pulled out of the drill string at about 30 ft/second depending on erosion. In one example, the instrument line  120  may be a metallic tube having a diameter of ¼ inch, and the instrument line  120  may be 4000 ft long. The weight of the instrument line  120  may be about 450 lbs, and the friction factor may be 30%. At an inclination angle of 10 degrees, the torsion stress may be about 1100 PSI, and there may be about 3 twisting turns (e.g., at the bottom). At an inclination angle of 90 degrees, the torsion stress may be about 6300 PSI, and there may be about 17 twisting turns (e.g., at the bottom). 
         [0081]    The instrument line  120 , which is 4000 ft in this example, may be run into the drill string in 90 seconds. During this 90 seconds, the following activities may occur on the drilling rig: 15 seconds for torque on connection, 15 seconds to go out of the slips, 15 seconds to go on-bottom, 30 seconds for surveying, and 15 seconds of additional time for the instrument line  120  to reach the installation depth. The instrument line  120  may be pulled out of the drill string in 2 minutes. During this 2 minutes, the following activities may occur on the drilling rig: 30 seconds for circulation off-bottom, 15 seconds to go in-slip, 15 seconds to un-torque the drill string, 45 seconds for lifting the hook at the top of the mast, and 15 seconds of extra time for retrieval of the instrument line  120 . The total loss time for operation of the instrument line  120  may be about 30 seconds per connection. The user may be blind (no information from down-hole as the instrument (e.g., logging tool  402  and/or MWD telemetry reception tool  452 ) is not at the correct position within the drill-string  104 ) for about 45 seconds after drilling is restarted and for about 15 seconds before the end of the drilling period. With a rate of penetration of about 90 ft/hour, one “triple” may be added every hour. In another example, it may take about 30 seconds per triple or per 60 minutes of drilling. The average readiness may be 99.3% of the total drilling time. 
         [0082]    The instrument line  120  may resist friction torque. For example, if the wellbore includes a horizontal portion that is about 8000 ft long, the shear stress on the instrument line  120  may be about 12000 PSI, and there may be up to about 66 turns of twisting. The instrument line  120  may be able to slide fast within the wellbore when lubricated. This may reduce friction, wear, and damage to communication line or a rubber seal wrapped thereabout. 
         [0083]      FIGS. 8A and 8B  illustrate conceptual, side, schematic views of a well site including the drilling rig  100 , in which multiple instrument lines may be used, according to an embodiment. For example,  FIG. 8A  illustrates a conceptual, side, schematic view of the well site  800 , in which two instrument lines may be used, according to an embodiment. As illustrated, the drill string  104  with an instrument line (e.g. instrument line  120 ) including a first section  802  and a second section  804  therein may be run into the wellbore  106 . The wellbore  106  may include a vertical portion, a deviated portion, and a horizontal portion. A BHA  806  may be coupled to a lower end of the drill string  104 . The BHA  806  may be or include several downhole tools above a drill bit  808 . The downhole tools may be or include a rotary steerable system, a motor, and one or more MWD and LWD tools. The drilling rig may also include a fluid reservoir  810  (e.g. mud) and a pump  812  for cycling the fluid through the drill string  104  via a fluid line  814 . While not illustrated, the drill string  104  may include one or more tools or subs, such as MWD and LWD, shock and vibration reduction tools, agitator tools, drilling motor, RSS, etc. The one or more tools or subs may be coupled to the drilling string at any location (e.g., in the BHA  806 ) to assist in the drilling process. In some embodiments, the drill string  104  may include a UBHO sub. The UBHO sub may axially and rotational fix one or more downhole electronics packages within the drill string  104 . For example, the UBHO sub may include one or more steering tools, one or more gyroscopes, one or more MWD or LWD tools, etc. 
         [0084]    To couple the first section  802  and the second section  804  of the instrument line, a junction module  816  may be coupled to an upper end of the second section  804  of the instrument line. The junction module  816  may include one or more anchors that are configured to expand radially-outward to contact an outer tubular (e.g., the drill string  104 ). A fishing module  818  may be coupled to a lower end of the first section  802  of the instrument line. The fishing module  818  may be coupled to the junction module  816 . In an embodiment, the fishing module  818  and the junction module  816  may be able to transmit power and/or data to and from one another. The fishing module  818  may include a swivel that allows the fishing module  818  to rotate with respect to the instrument line. 
         [0085]    A logging tool  820  may be coupled to a lower portion of the second section  804  of the instrument line and positioned within the drill string  104 . The logging tool  820  may be configured to measure one or more formation properties and/or physical properties, as the wellbore  106  is being drilled or at any time thereafter. For example, the logging tool  820  may take measurements such as D&amp;I measurements in the deviated portion of the wellbore (i.e., the dogleg), gamma ray measurements, RPM measurements (e.g., local instantaneous drill string RPM measurements), and the like. Likewise, for example, the formation properties may include resistivity, density, porosity, sonic velocity, gamma rays, and the like. Additionally, for example, the physical properties may include pressure, temperature, wellbore caliper, wellbore trajectory, a weight-on-bit, torque-on-bit, vibration, shock, stick slip, and the like. 
         [0086]    The logging tool  820  may transmit data (e.g., formation properties, physical properties, etc.) from within the wellbore  106  up to a computer system  822 . The first section  802  and the second section  804  of the instrument line may be or include a metallic line with one or more internal wires  824  therein (e.g., electrical or fiber optic wires) for communication. For example, the logging tool  820  may be coupled to the computer system  822  by one or more wires  824 . 
         [0087]    In at least one embodiment, there may be a wet, stabbable electrical coupler between the junction module  816  and the fishing module  818 . The coupler may be an inductive coupler such as a LWD data latch. Telemetry through the coupler may be conducted at high frequencies (e.g., above 50 kilohertz). Power (e.g., AC power) may be transmitted through the coupler at 50 or 60 hertz. 
         [0088]    In embodiments, one or more of the sections of the instrument line may be installed in the wellbore  106  while one or more sections are removed from the wellbore  106 . For example, one or more anchors may be set for the junction module  816 . The fishing module  818  may be disconnected from the junction module  816  after the anchors are set. The first section  802  of the instrument line may then be tripped out of the wellbore  106 , while the second section  804  with the logging tool  820  and junction module  816  remains inside the drill-sting  104  When removing some section of instrument line (e.g.,  852 ), the anchor of the junction module (just below the removed instrument line must be set to hold the junction module (e.g.,  866 ) at the proper location in the drill-string as well as supporting the weight of the instrument line below that junction module. 
         [0089]    One or more of the sections of the instrument line may be removed from the wellbore  106 . The removed section may be in the range of the bit drilled interval. This may be, for example, 4000 feet deep. Although two sections of the instrument line are shown, it will be appreciated that more sections may be used (e.g., five sections). The instrument may have the same length or different lengths. 
         [0090]    To place a section of the instrument line or of the junction module  816  and the fishing module  818  or the logging tool  820  within the drill string  104 , a centralizer may be used for the first section  802  of the instrument line, the second section  804  of the instrument line, the junction module  816 , or the fishing module  818 . The centralizer may be a bow-spring centralizer. The centralizer may generate at least some radial pre-compression. The centralizer may keep the sections of the instrument line or associated devices (e.g.,  816 , 818 ,  820 ) positioned in the center of the drill string  104 . This may allow for no (or minimal) contact between the sections of the instrument line or associated devices (e.g.  816 , 818 ,  820 ) and the drill string  104 . The centralizer may also prevent the sections of the instrument line from whirling in horizontal portions of the wellbore  106 . As such, it may also prevent damage to the sections of the instrument line due to rotary friction. The centralizer may deform to become substantially flat. The centralizer may have a substantially smooth leading edge. In at least one embodiment, the centralizer may be run through the blow-out preventer when being run into the wellbore  106 . 
         [0091]    In another example,  FIG. 8B  illustrates another conceptual, side, schematic view of the well site  850 , in which multiple instrument lines may be used, according to embodiments. As illustrated, the drill string  104  with an instrument line (e.g. instrument line  120 ) including a first section  852 , a second section  854 , and a third section  856  therein may be run into the wellbore  106 . The wellbore  106  may include a vertical portion, a deviated portion, and a horizontal portion. A BHA  858  may be coupled to a lower end of the drill string  104 . The BHA  858  may be or include several downhole tools above a drill bit. The downhole tools may be or include a rotary steerable system (“RSS”)  859 , a motor, and one or more MWD tools or LWD tools, described below. The drilling rig may also include a fluid reservoir  860  (e.g. mud) and a pump  862  for cycling the fluid through the drill string  104  via a fluid line  864 . While not illustrated, the drill string  104  may include one or more tools or subs, such as MWD and LWD, shock and vibration reduction tools, agitator tools, drilling motor, RSS etc. The one or more tools or subs may be coupled to the drilling string at any location (e.g., in the BHA  858 ) to assist in the drilling process. In some embodiments, the drill string  104  may include a UBHO sub. The UBHO sub may axially and rotational fix one or more downhole electronics packages within the drill string  104 . For example, the UBHO sub may include one or more steering tools, one or more gyroscopes, one or more MWD or LWD tools, etc. 
         [0092]    To couple the first section  852  and the second section  854  of the instrument line, a junction module  866  may be coupled to an upper end of the second section  854  of the instrument line. The junction module  866  may include one or more anchors that are configured to expand radially-outward to contact an outer tubular (e.g., the drill string  104 ). A fishing module  868  may be coupled to a lower end of the first section  852  of the instrument line. The fishing module  868  may be coupled to the junction module  866 . In at least one embodiment, the fishing module  868  and the junction module  866  may be able to transmit power and/or data to and from one another. The fishing module  868  may include a swivel that allows the fishing module  868  to rotate with respect to the instrument line. 
         [0093]    To couple the second section  854  and the third section  856  of the instrument line, a junction module  870  may be coupled to an upper end of the third section  856  of the instrument line. The junction module  870  may include one or more anchors that are configured to expand radially-outward to contact an outer tubular (e.g., the drill string  104 ). A fishing module  872  may be coupled to a lower end of the second section  854  of the instrument line. The fishing module  872  may be coupled to the junction module  870 . In at least one embodiment, the fishing module  872  and the junction module  870  may be able to transmit power and/or data to and from one another. The fishing module  872  may include a swivel that allows the fishing module  872  to rotate with respect to the instrument line. 
         [0094]    The BHA  858  may include one or more MWD/LWD tools  874 . The LWD tool  874  may be coupled to a lower portion of the third section  856  of the instrument line by a BHA interconnect  876  and a fishing module  878 . The LWD tool  874  may be configured to measure one or more formation properties and/or physical properties, as the wellbore  106  is being drilled or at any time thereafter. For example, the MWD/LWD tool  874  may take measurements such as D&amp;I measurements in the deviated portion of the wellbore gamma ray measurements, RPM measurements (e.g., local instantaneous drill string RPM measurements) axial load in the BHA (called WOB) and down-hole torque applied on the bit, and the like. Likewise, for example, the formation properties may include resistivity, density, porosity, sonic velocity, gamma rays, and the like. Additionally, for example, the physical properties may include pressure, temperature, wellbore caliper, wellbore trajectory, a weight-on-bit, torque-on-bit, vibration, shock, stick slip, and the like. 
         [0095]    The LWD/MWD tools  874  may transmit data (e.g., formation properties, physical properties, etc.) from within the wellbore  106  up to a computer system  880 . The first section  852 , the second section  854 , and the third section  856  of the instrument line may be or include a metallic line with one or more internal wires  882  therein (e.g., electrical or fiber optic wires) for communication. For example, the LWD/MWD tool  874  may be coupled to the computer system  880  by the one or more wires  882 . The sections of the instrument line may provide one-way or two-way communication between the surface computer  880 - and the BHA  858 . The communication form the surface system  880  to the down-hole BHA (e.g. MWD/LWD and RSS) allows to change some configurations in these tools (IE setting of sensor or acquisition system in these tools) as well as transmitting some commands to these tools (e.g inclination and azimuth to RSS  859 , or special acquisition sequence of LWD tools). 
         [0096]    In at least one embodiment, there may be a wet, stabbable electrical coupler between the junction modules  866 ,  870  and the fishing module  868 ,  872 . The coupler may be an inductive coupler such as a LWD data latch. Telemetry through the coupler may be conducted at high frequencies (e.g., above 50 kilohertz). Power (e.g., AC power) may be transmitted through the coupler at a lower frequency such 50 or 60 hertz. 
         [0097]    In some embodiments, one or more of the sections of the instrument line may be installed in the wellbore  106  while one or more sections are removed from the wellbore  106 . For example, one or more anchors may be set for the junction module  866 ,  870 . The fishing module  868  may be disconnected from the junction module  870  after the anchors of the junction module  870  are set. The first section  852  (or first section  852  and second section  854 ) of the instrument line may then be tripped out of the wellbore  106 . Similar process may apply at the lower fishing module  872 ) and junction module  870 . 
         [0098]    One or more of the sections of the instrument line may be removed from the wellbore  106 . The removed section may be in the range of the bit drilled interval. This may be, for example, 4000 feet. This may occur in vertical and/or low inclination portions of the wellbore, as opposed to horizontal portions. Although 3 sections of the instrument line are shown, it will be appreciated that more sections may be used (e.g., 5 sections). The instrument lines may have the same length or different lengths. 
         [0099]    To place a section of the instrument line within the drill string  104 , a centralizer may be used for the first section  852  of the instrument line or associated devices (e.g.,  816 , 818 ), the second section  854  of the instrument line or associated devices (e.g.,  870 , 872 ,  878 ), the third section  856  of the instrument line, the junction module  866 ,  870 , or the fishing module  868 ,  872 . The centralizer may be a bow-spring centralizer. The centralizer may generate at least some radial pre-compression. The centralizer may keep the sections of the instrument line positioned in the center of the drill string  104 . This may allow for no (or minimal) contact between the sections of the instrument line and the drill string  104 . The centralizer may also prevent the sections of the instrument line from whirling in horizontal portions of the wellbore  106 . As such, it may also prevent damage to the sections of the instrument line due to rotary friction. The centralizer may deform to become substantially flat. The centralizer may have a substantially smooth leading edge. In at least one embodiment, the centralizer may be run through the sealing system  220  when being run into the wellbore  106 . 
         [0100]      FIG. 9  illustrates a conceptual, side, schematic view of a junction module  900  as a network node, according to an embodiment. As illustrated, the junction module  900  may include an upper section  902 . The upper section  902  may include an inductive coupler  904  (male part), fishing neck  906 , and an un-coupler  908 . The inductive coupler  904  can be configured to inductively transfer signal and/or power to and from the junction module  900 . The fishing neck  906  can be configured to provide connection point for the upper end of the junction module  900 . For example, the fishing neck  906  may provide a connection point for fishing tools, instrument lines, junction modules, and the like. The un-coupler  908  can be configured to uncouple devices from the fishing neck  906 , as discussed further below. 
         [0101]    The junction module  900  may include a swivel  910  coupled to a lower portion of the upper section  902 . The swivel  910  may be positioned between the upper section  902  and the electronics section  912 . The swivel  910  may allow the junction module  900  to rotate while sections of the instrument line, connected to the junction module, do not rotate. This may allow the junction module  900  to rotate with the drill string  104 . 
         [0102]    The swivel  910  may also support the axial load generated by the junction module  900  or sections of the instrument line. For example, the swivel  910  may include thrust bearing  914 . The swivel  910  may also include lubrication  916  (e.g. oil) within a cavity of the swivel  910  and surround the thrust bearing  914 . The swivel  910  may also include rotary connection  918 . The rotary connection  918  may allow for transmission of signal and/or power transmission for each wire in the instrument line and for grounding the tubing. For example, the rotary connection  918  may be rotary contact or a rotary split transformer. 
         [0103]    The electronics section  912  may include any electronics or electrical components requirement during the operations. The electronics section  912  may be sealed against the down-hole pressure to allow the operations of the electronics or electrical components, for example, approximately atmospheric pressure. For example, the electronics section  912  may include logging tools, MWD telemetry tools (described above), control modules, communication devices, and the like. For example, the electronics section  912  may also include a network node. The network node may be used to decode and re-encode in one or two directions, for example, data transmitted downhole from the surface and/or data received from instruments in the wellbore  106  and transmitted to the surface. Data collected from LWD/MWD type measurements within the electronics section may also be added to the data transmitted by the network node. For example, data from an accelerometer or a magnetometer (e.g., for rotation) may be added to the data that is decoded or re-encoded. In another example, data relating to pipe stretch and twist may be added to the data that is decoded or re-encoded. The electronics section  912  may also include a power source  920 . The power source  920  may be any type of power source such as a battery, a rechargeable battery, and the like. For example, the power may be supplied through the instrument line to charge the power source and provide power to the electronics section  912  and other components in the wellbore  106 , for example, the BHA. The power source may provide power if the junction module  900  is disconnected from the surface. 
         [0104]    The junction module  900  may include an anchor section  922 . The anchor section  922  may be configured to anchor the junction module  900  (and any attached sections of instrument line) to an interior of the drill string  104 . The anchor section  922  may include one or more articulated anchors  924 , one or more solenoids  926 , and one or more biasing members  928 . The articulated anchors  924  may be configured to expand radially-outward and engage with the interior surface of the drill string  104 . In some embodiments, the articulated anchors  924  may be configured to contract upon contact with a shoulder or other member inside the drill string  104 . The solenoids  926  may be configured to cause the articulated anchors  924  to expand or contract by moving the instrument axially in the bore of the drill-sting  104 , and lock the articulated anchors  924  in a position. The biasing member  928 , for example, bow springs, may provide force radially-outward on the articulated anchors  924 . In some embodiments, the biasing member  928  may be removed and solenoids  926  or other motors may provide a force radially-outward on the articulated anchors  924 . The articulate anchors  924  has such bidirectional design so that when the junction module  900  moves axially in the bore of the drill-string, the anchor (when not set and not locked by the solenoid) may retract when the extremity of the anchor enters in contact with a change of diameter in the drill-sting (such as shoulder or change of bore in the drill-pipe tool-joint). 
         [0105]    The junction module  900  may include a lower section  930 . The lower section  930  can include an inductive coupler  932  (female part) and one or more grabbing fingers  934 . The inductive coupler  932  can be configured to inductively transfer signal and/or power to and from the junction module  900 . The grabbing fingers  934  can be configured to provide connection point for the lower end of the junction module  900 . For example, the fishing neck  906  may provide a connection point for fishing tools, instrument lines, junction modules, and the like. 
         [0106]    While described above as having a “male” connection in the upper end of the junction module  900  and a “female” connection as the lower end of the junction module  900 , the junction module  900  may have “female” connection in the upper end of the junction module  900  and a “male” connection as the lower end of the junction module  900 . 
         [0107]    In examples described above, the junction module  900  may be decoupled from the instrument line  120 . This may be done via network control or slick-line mechanical techniques. Once decoupled, the instrument line  120  may be retrieved at the pipe connection. 
         [0108]      FIGS. 10A and 10B  illustrate conceptual, side, schematic views of a connection between the junction module  900  and instrument lines, according to an embodiment. More particularly,  FIG. 10A  shows the lower end of one section of the instrument line  120  decoupled from the upper end of the junction module  900 , and the lower end of the junction module  900  decoupled from the upper end of another section of the instrument line  120 . The lower end of one section of the instrument line  120  having a female fishing tool  1004  coupled thereto and the upper end of another section of the communication cable having a male fishing neck  1002  coupled thereto. As illustrated  FIG. 10B  shows the lower end of one section of the instrument line  120  coupled to the upper end of the junction module  900 , and the lower end of the junction module  900  coupled to the upper end of another section of the instrument line  120 . The instrument line  120  may have a fishing tool coupled thereto. The fishing tool at the “active inserted line” may be decoupled in the wellbore  106 . 
         [0109]    The communication line and the junction module may form or include a network with a repeater. This may be a similar configuration as the multiple sections of the communication line discussed above. There may be a continuous data-latch to measuring-while-drilling and logging-while-drilling. This may enable the detection of faults in the network. 
         [0110]      FIGS. 11A and 11B  illustrate conceptual, side, schematic views of a passive connection between junction modules and instrument lines, according to an embodiment. More particularly,  FIG. 11A  shows the lower end of one section of the instrument line  120  having a female fishing tool  1102  coupled thereto and the upper end of another section of the communication cable having a male fishing neck  1104  coupled thereto. As illustrated in  FIG. 11B , the female fishing tool  1102  may couple to the male fishing neck  1102 . The female fishing tool  1102  may couple to the male fishing neck  1102  may include inductive couplers to inductively transfer signal and/or power between the instrument lines  120 . The embodiment shown in  FIGS. 11A and 11B  may provide more attenuation. 
         [0111]      FIGS. 12A and 12B  illustrate partial cross-sectional views of examples of a locating module, according to an embodiment.  FIG. 12A  illustrates a partial cross-sectional view of examples of a locating module  1200 , according to an embodiment. The locating module  1200  may include landing groove  1210 . A latching dog may be installed on the of the junction module  900  (as illustrated in  FIG. 9 ) and replace the anchor  922  (as illustrated in  FIG. 9 ) and may allow locking of the latching dog in a landing groove  1210  on the locating module  1200 . The latching dog may be released when desired by an operator at the surface: the latching dog is then radially pushed against the bore of the drill-sting  104  to possibly enter into the landing groove  1210  of the locating module  1200  when the junction module  900  passes across the locating module  1200 . With locating module  1200 , the latching dog may be released when the junction module  900  is still above the locating module  1200 . The latching dogs will stop against an axial stop  1220  of the locating module  1200 . The release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually. The latching dog may be chamfered so that the junction module  900  may be pulled upwards in the drill-string without catching upon an obstruction in the bore of the drill-sting  104 . 
         [0112]      FIG. 12B  illustrates a partial cross-sectional view of examples of a locating module  1230 , according to an embodiment. The locating module  1230  may include landing groove  1240 . A latching dog may be installed on the of the junction module  900  (as illustrated in  FIG. 9 ) and replace the anchor  922  (as illustrated in  FIG. 9 ) and may allow locking of the latching dog in a landing groove  1240  on the locating module  1230 . The latching dog may be released when desired by an operator at the surface: the latching dog is then radially pushed against the bore of the drill-sting  104  to possibly enter into the landing groove  1240  of the locating module  1230  when the junction module  900  passes across the locating module  1230 . With locating module  1230 , the latching dog may be released when the junction module  900  is still above the locating module  1230 . The latching dogs will stop against an axial stop  1220  of the locating module  1230 . The release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually. The latching dog may be chamfered so that the junction module  900  may be pulled upwards in the drill-string without catching upon an obstruction in the bore of the drill-sting  104 . With the locating module  1230 , The release may be triggered when the latching dog of the junction module  900  has passed below the locating module  1230 . The release mechanism may be triggered via telemetry (e.g., from the surface). This may include a one time activation, and it may be reset manually. The latching dog may be chamfered so that the junction module  900  may be pulled upwards in the drill-string without catching upon an obstruction in the bore of the drill-sting  104 . 
         [0113]    The locating module  1200  or  1230  may be designed as part of the drill-string  104 . The junction module  900  may be configured to latch or couple into the locating module. A different section of the instrument line may “hang” from the bottom of the network module. A “coiled pig tail” may be positioned at the lower end of each section of the instrument line. The pig tail may be a coil and/or spring that account for the mismatch in length between the instrument line and the distance between successive locating modules of the drill string. When using locating module  1200  or  1230 , the bore of the locating module may be larger than the bore of the drill-sting  104 . This provides more annular space between the junction module  900  and the bore of the locating module  1200  or  1230  so that the mud flow does not have too high velocity and floor erosion is limited. 
         [0114]      FIG. 13  illustrates a flowchart of a method  1300  for deploying an instrument line with multiple lines into the drill string  104  deployed into the wellbore  106 , according to an embodiment. For example, the method  1300  may be utilized to deploy include an instrument line described above in  FIGS. 8A and 8B . Although the present method  1300  is described with reference to the drilling rig  100  discussed above, it will be appreciated that this is merely an example, and embodiments of the method  1300  may be applied using other structures. Moreover, additional action may be preformed during method  1300 , for example, those described for method  700   
         [0115]    The method  1300  may begin with receiving a section of an instrument line in the drilling device  200 , as at  702 . This may include, for example, receiving the section of the instrument line  120  (and optionally an instrument) down between the sheaves of the crown block  112 , between the sheaves of the travelling block  105 , through the line-pusher  265 , through the sealing device  220 , and into the entry port  210  of the housing  202 . In a specific embodiment, the section of the instrument line  120  may be positioned in the interior  250  of the shaft  204 , or in the conduit  253 . 
         [0116]    The method  1300  may also include sealing the entry port  210  using the sealing device  220 , as at  1304 . For example, the annular seal  300  of the sealing device  220  may extend radially inward from an open position, which allows the instrument  126  to pass through, to a first, sealed configuration, in which the annular seal  300  engages and seals with the instrument line  120 . 
         [0117]    The method  1300  may include receiving a flow of mud past the section of the instrument line  120 , as at  1306 . The method  1300  may then proceed to lowering the section of the instrument line  120  into the drill string  104 , as at  1308 . At least a part of this lowering may be accomplished by pushing the section of the instrument line  120  using the line-pusher  265 , although at least a part of this pushing may also or instead rely on mud pressure. Further, the section of the instrument line  120  may be lowered (e.g., pushed) to a predetermined depth within the drill string  104 . In addition, while the instrument  126  is being lowered, the instrument line spool  122  may unspool the section of the instrument line  120  therefrom, so as to allow the line  116  to be extended down into the drill string  104 . The unspooling of the instrument line  120  may be coordinated, e.g., synchronized, with the pushing by the line-pusher  265 . Reverse process may be considered to extract the instrument line and associated junction module and tools out of the drill-string. 
         [0118]    Once the section of the instrument line is positioned, the method  1300  may include anchoring the section of the instrument line, as at  1310 . For example, anchoring devices of the instrument line may be activated to anchor the instrument line to the interior of the drill string  104 . The anchoring devices may be activated by electrical signals from the surface and/or activated by mechanical devices. 
         [0119]    For example, referring to  FIG. 9 , the junction module  900  may include the anchor section  922  may include one or more articulated anchors  924 , one or more solenoids  926 , and one or more biasing members  928 . Once activated, the solenoids  926  may cause the articulated anchors  924  to expand and lock the articulated anchors  924  in a position. The biasing member  928 , for example, bow springs, may provide force radially-outward on the articulated anchors  924 . 
         [0120]    The method  1300  may include detaching the section of the instrument line, as at  1312 . An installation tool used to deliver the instrument line may be detached from the section of the instrument line. The detachment may be activated by electrical signals from the surface and/or activated by mechanical devices. 
         [0121]    For example, referring to  FIGS. 9, 10A, and 10B , the female fishing tool  1004  may be coupled to the junction module  900  at the fishing neck  906 . Once activated, the un-coupler  908  may force the grabbing fingers of the female fishing tool  1104  apart so that female fishing tool  1104  can be decoupled from the fishing neck  906 . 
         [0122]    The method  1300  may include removing the installation tool, as at  1314 . The method  1300  may include determining if additional sections of instrument line should be installed, as at  1316 . If additional sections are to be installed, the method  1300  may return to  1302 . 
         [0123]    In some embodiments, the methods of the present disclosure may be executed by a computing system.  FIG. 14  illustrates an example of such a computing system  1400 , in accordance with some embodiments. The computing system  1400  may include a computer or computer system  1401 A, which may be an individual computer system  1401 A or an arrangement of distributed computer systems. The computer system  1401 A includes one or more analysis modules  1402  that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these various tasks, the analysis module  1402  executes independently, or in coordination with, one or more processors  1404 , which is (or are) connected to one or more storage media  1406 . The processor(s)  1404  is (or are) also connected to a network interface  507  to allow the computer system  1401 A to communicate over a data network  1409  with one or more additional computer systems and/or computing systems, such as  1401 B,  1401 C, and/or  1401 D (note that computer systems  1401 B,  1401 C and/or  1401 D may or may not share the same architecture as computer system  501 A, and may be located in different physical locations, e.g., computer systems  1401 A and  1401 B may be located in a processing facility, while in communication with one or more computer systems such as  1401 C and/or  1401 D that are located in one or more data centers, and/or located in varying countries on different continents). 
         [0124]    A processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device. 
         [0125]    The storage media  1406  may be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of  FIG. 14  storage media  1406  is depicted as within computer system  1401 A, in some embodiments, storage media  1406  may be distributed within and/or across multiple internal and/or external enclosures of computing system  1401 A and/or additional computing systems. Storage media  1406  may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLU-RAY® disks, or other types of optical storage, or other types of storage devices. Note that the instructions discussed above may be provided on one computer-readable or machine-readable storage medium, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture may refer to any manufactured single component or multiple components. The storage medium or media may be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution. 
         [0126]    In some embodiments, the computing system  1400  contains one or more rig control module(s)  1408 . In the example of computing system  1400 , computer system  1401 A includes the rig control module  1408 . In some embodiments, a single rig control module may be used to perform some or all aspects of one or more embodiments of the methods disclosed herein. In alternate embodiments, a plurality of rig control modules may be used to perform some or all aspects of methods herein. 
         [0127]    The computing system  1400  is one example of a computing system; in other examples, the computing system  1400  may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of  FIG. 14 , and/or the computing system  1400  may have a different configuration or arrangement of the components depicted in  FIG. 14 . The various components shown in  FIG. 14  may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits. 
         [0128]    Further, the steps in the processing methods described herein may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of protection of the invention. 
         [0129]    The foregoing description, for purpose of explanation, has been described with reference to specific embodiments. However, the illustrative discussions above are not intended to be exhaustive or to limit the invention to the precise forms disclosed. Many modifications and variations are possible in view of the above teachings. Moreover, the order in which the elements of the methods described herein are illustrate and described may be re-arranged, and/or two or more elements may occur simultaneously. The embodiments were chosen and described in order to best explain the principals of the invention and its practical applications, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated.

Summary:
An apparatus for delivering tools within a drill string may include an instrument line including a mechanically resistant external structure with an internal cavity. The instrument line may be configured to be deployed into the drill string. The apparatus may include one or more isolated wires positioned within the internal cavity. The apparatus may also include one or more tools removably coupled to the instrument line and positionable within the drill string. The one or more tools may be configured to provide measurements of conditions within a wellbore via the one or more isolated wires.