Patent Publication Number: US-11021947-B2

Title: Sensor bracket positioned on a movable arm system and method

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     This application claims priority to and the benefit of U.S. Provisional Application Ser. No. 62/522,351 filed Jun. 20, 2017, titled “SENSOR BRACKET SYSTEM AND METHOD,” the full disclosure of which is hereby incorporated herein by reference in its entirety for all purposes. 
    
    
     BACKGROUND 
     1. Field of Invention 
     This disclosure relates in general to oil and gas tools, and in particular, to systems and methods for sensor configurations in downhole logging tools. 
     2. Description of the Prior Art 
     In oil and gas production, various measurements are conducted in wellbores to determine characteristics of a hydrocarbon producing formation. These measurements may be conducted by sensors that are carried into the wellbore on tubulars, for example, drilling pipe, completion tubing, logging tools, etc. Multiple measurements may be performed along different locations in the wellbore and at different circumferential positions. Often, the number of measurements leads to the deployment of several downhole tools, thereby increasing an overall length of the string, which may be unwieldy or expensive. Further, arranging sensors to conduct the measurements along the tubulars may negatively impact the measurement because the sensor may not be properly arranged within a flow stream. 
     SUMMARY 
     Applicant recognized the problems noted above herein and conceived and developed embodiments of systems and methods, according to the present disclosure, for sensor deployment systems. 
     In an embodiment, a system for positioning a sensor within a flow path of a wellbore annulus includes a work string extending into the wellbore annulus from a surface location. The system also includes a moveable arm on the work string, the arm transitioning between a first position at a first radial location and a second position at a second radial location, the first radial location being closer to a tool string axis than the second radial location. The system further includes a bracket coupled to the arm, the bracket being pivotable about a pivot axis substantially perpendicular to the tool string axis, wherein the bracket supports the sensor and transitions the sensor from a stored position to a deployed position when the arm moves to the second radial location. 
     In another embodiment, a system for mounting a sensor to an arm of a downhole tool includes a first finger extending from a first end to a second end, a second finger extending from the first end to the second end and parallel to the first finger, a base coupling the first finger to the second finger, and a holster coupled to at least one of the first finger or the second finger, the holster having a void space for receiving at least a portion of the sensor and positioning the sensor along a holster axis. 
     In an embodiment, a system for securing a sensor to a downhole tool includes an arm forming at least a portion of the downhole tool, the arm being movable between a stored position at a first radial position and an extended position at a second radial position, wherein the first radial position is closer to a tool string axis than the second radial position. The system also includes a bracket secured to the arm at a pivot axis, the bracket being rotatable about the pivot axis between a first position and a second position, the bracket comprising a holster having a void region for receiving the sensor, the holster positioning the sensor along a holster axis. Additionally, the holster axis is substantially parallel to the tool string axis when the holster is in the first position and the holster axis is arranged at an angle relative to the tool string axis when the holster is in the second position. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present technology will be better understood on reading the following detailed description of non-limiting embodiments thereof, and on examining the accompanying drawings, in which: 
         FIG. 1  is a schematic elevation view of an embodiment of a wellbore system, in accordance with embodiments of the present disclosure; 
         FIG. 2  is an isometric view of an embodiment of a downhole tool, in accordance with embodiments of the present disclosure; 
         FIG. 3  a front isometric view of an embodiment of a bracket, in accordance with embodiments of the present disclosure; 
         FIG. 4  is a top plan view of an embodiment of a bracket, in accordance with embodiments of the present disclosure; 
         FIG. 5  is front isometric elevational view of an embodiment of a bracket, in accordance with embodiments of the present disclosure; 
         FIG. 6  is a bottom isometric view of an embodiment of a bracket, in accordance with embodiments of the present disclosure; 
         FIG. 7  is a rear perspective view of an embodiment of a bracket in a stowed position, in accordance with embodiments of the present disclosure; and 
         FIG. 8  is a rear perspective view of an embodiment of a bracket in a deployed position, in accordance with embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The foregoing aspects, features and advantages of the present technology will be further appreciated when considered with reference to the following description of preferred embodiments and accompanying drawings, wherein like reference numerals represent like elements. In describing the preferred embodiments of the technology illustrated in the appended drawings, specific terminology will be used for the sake of clarity. The present technology, however, is not intended to be limited to the specific terms used, and it is to be understood that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose. 
     When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Any examples of operating parameters and/or environmental conditions are not exclusive of other parameters/conditions of the disclosed embodiments. Additionally, it should be understood that references to “one embodiment”, “an embodiment”, “certain embodiments,” or “other embodiments” of the present invention are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Furthermore, reference to terms such as “above,” “below,” “upper”, “lower”, “side”, “front,” “back,” or other terms regarding orientation are made with reference to the illustrated embodiments and are not intended to be limiting or exclude other orientations. 
     Embodiments of the present disclosure include systems and methods to perform downhole measurements in oil and gas formations. In certain embodiments, a downhole tool includes a plurality of extendable arms to arrange one or more sensors in a wellbore annulus to measure one or more characteristics of fluid (e.g., gas, liquid, solid, or a combination thereof) flowing through the annulus. The extendable arms may include a bracket to position the sensors outwardly from a body of the tool and into a flow path. In embodiments, the bracket is rotatable about an axis to enable rotational movement relative to movement of the extendable arms. That is, as the extendable arms are moved radially outward from the body, the bracket may pivot about the axis to position the sensors in the flow path. In certain embodiments, the bracket is configured to hold two different sensors, thereby enabling a larger number of sensors to be positioned on the tool and potentially reducing the length of the logging tools utilized in the well. 
       FIG. 1  is a schematic elevation view of an embodiment of a wellbore system  10  that includes a work string  12  shown conveyed in a wellbore  14  formed in a formation  16  from a surface location  18  to a depth  20 . The wellbore  14  is shown lined with a casing  22 , however it should be appreciated that in other embodiments the wellbore  14  may not be cased. In various embodiments, the work string  12  includes a conveying member  24 , such as an electric wireline, and a downhole tool or assembly  26  (also referred to as the bottomhole assembly or “BHA”) attached to the bottom end of the wireline. The illustrated downhole assembly  26  includes various tools, sensors, measurement devices, communication devices, and the like, which will not all be described for clarity. In various embodiments, the downhole assembly  26  includes a downhole tool  28  having extendable arms, which will be described below, for positioning one or more sensors into the annulus of the wellbore  14 . In the illustrated embodiment, the downhole tool  28  is arranged in a horizontal or deviated portion  30  of the wellbore  14 , however it should be appreciated that the downhole tool  28  may also be deployed in substantially vertical segments or the wellbore  14 . 
     The illustrated embodiment further includes a fluid pumping system  32  at the surface  18  that includes a motor  34  that drives a pump  36  to pump a fluid from a source into the wellbore  14  via a supply line or conduit. To control the rate of travel of the downhole assembly, tension on the wireline  14  is controlled at a winch  38  on the surface. Thus, the combination of the fluid flow rate and the tension on the wireline may contribute to the travel rate or rate of penetration of the downhole assembly  16  into the wellbore  14 . The wireline  14  may be an armored cable that includes conductors for supplying electrical energy (power) to downhole devices and communication links for providing two-way communication between the downhole tool and surface devices. In aspects, a controller  40  at the surface is provided to control the operation of the pump  36  and the winch  38  to control the fluid flow rate into the wellbore and the tension on the wireline  12 . In aspects, the controller  40  may be a computer-based system that may include a processor  42 , such as a microprocessor, a storage device  44 , such as a memory device, and programs and instructions, accessible to the processor for executing the instructions utilizing the data stored in the memory  44 . 
     In various embodiments, the downhole tool  28  may include extendable arms that include one or more sensors attached thereto. The arms enable the sensors to be arranged within the annulus, which may be exposed to a flow of fluid that may include hydrocarbons and the like moving in an upstream direction toward the surface  18 . In various embodiments, the arms enable a reduced diameter of the downhole tool  28  during installation and removal procedures while still enabling the sensors to be positioned within the annulus, which may provide improved measurements compared to arranging the sensors proximate the tool body. As will be described below, in various embodiments the sensors may be communicatively coupled to the controller  40 , for example via communication through the wireline  24 , mud pulse telemetry, wireless communications, wired drill pipe, and the like. Furthermore, it should be appreciated that while various embodiments include the downhole tool  28  incorporated into a wireline system, in other embodiments the downhole tool  28  may be associated with rigid drill pipe, coiled tubing, or any other downhole exploration and production method. 
       FIG. 2  is an isometric perspective view of an embodiment of the downhole tool  28  including a plurality of extendable arms  60  (e.g., arms) arranged in an extended or deployed position. As illustrated in  FIG. 2 , the arms  60  are radially displaced from a tool string axis  62 . The illustrated embodiment includes six arms  60 , but it should be appreciated that in other embodiments more or fewer arms  60  may be included. For example, there may be one, two, three, four, five, ten, or any other reasonable number of arms  60  arranged on the downhole tool  28 . In the illustrated embodiment, the arms  60  are arranged circumferentially about a circumference  64  of the tool  28  and are evenly spaced apart. However, in other embodiments, the arms  60  may not be evenly spaced apart. It should be appreciated that the spacing may be particularly selected based on anticipated downhole conditions. By arranging the arms  60  circumferentially about the downhole tool  28 , the entire or substantially the entire annulus surrounding the downhole tool  28  may be analyzed using the arms  60  (e.g., using sensors coupled to the arms). Therefore, if flow at an upper portion were different than flow at a lower portion, for example, the different arms  60  would be arranged to monitor and report such flow characteristics to inform future wellbore activities. Furthermore, if fluid compositions were different along the annulus, the arrangement of the sensors circumferentially around the tool  28  may enable detection and measurement of the different fluid characteristics. 
     In various embodiments, a pair of bulkheads  66  are positioned at first and second ends  68 ,  70  of the downhole tool  28 . For clarity with the discussion, the first end  68  may be referred to as the uphole side while the second end  70  may be referred to as the downhole side, however this terminology should not be construed as limiting as either end of the downhole tool  28  may be the uphole or downhole end and such arrangement may be determined by the orientation of the sensors coupled to the arms  60 . Each of the illustrated bulkheads  66  include apertures  72  which may be utilized to route or otherwise direct cables coupled to the sensors arranged on the arms  60  into the tool body for information transmission to the surface  18 , for example to the controller  40 . It should be appreciated that each bulkhead  66  may include a predetermined number of apertures  72 , which may be based at least in part on a diameter  74  of the downhole tool  28 . Accordingly, embodiments of the present disclosure provide the advantage of enabling more sensors than traditional downhole expandable tools because of the presence of the pair of bulkheads  66 . As will be described below, traditional tools may include a single bulkhead and a moving pivot block to facilitate expansion and contraction of arms for moving the sensors into the annulus. The end with the moving pivot block typically does not include a bulkhead due to the lateral movement of the pivot block along the tool string axis  62 , which increases the likelihood that cables are damaged because of the increased movement. 
     In various embodiments, the one or more sensors may include flow sensors to measure speed of flow, composition sensors to determine the amount of gas or liquid in the flow, and/or resistivity sensors to determine the make of the flow (e.g., hydrocarbon or water). Additionally, these sensors are merely examples and additional sensors may be used. The bulkhead  66  may receive a sensor tube, cable, or wire coupled to the one or more sensors and includes electronics to analyze and/or transmit data received from the sensors to the surface. The illustrated bulkheads  66  are fixed. That is, the illustrated bulkheads  66  move axially with the downhole tool  28  and do not translate independently along the tool string axis  62 . As a result, the cables coupled to the sensors may be subject to less movement and pulling, which may increase the lifespan of the cables. 
       FIG. 2  further illustrates a pair of pivot blocks  76  arranged on the downhole tool  28 . In the illustrated embodiment, the pivot blocks  76  are positioned between the bulkheads  66 . Further, each pivot block  76  of the pair of pivot blocks  76  is positioned proximate a respective bulkhead  66 . That is, each of the pivot blocks  76  may be closer to one of the bulkheads  66 . The pivot blocks  76  are coupled to the arms  60  at both ends to drive movement of the arms  60  between the illustrated expanded position, a stored position (not shown), and intermediate radial positions therebetween. The illustrated pivot blocks  76  include channels  78  to direct the sensor tube, cable, wire, or the like coupled to the one or more sensors toward the bulkhead  66 , for example toward the aperture  72 . It should be appreciated that, in various embodiments, there are an equal number of channels  78  and apertures  72 . However, there may be more or fewer channels  78  and/or apertures  72 . The illustrated pivot blocks  76  are fixed and do not move independently along the tool string axis  62 . Rather, the pivot blocks  76  move with the tool string as the downhole tool  28  is inserted and removed from the wellbore  14 . As described above, movement of the pivot blocks  76  in traditional systems may fatigue or position the cables such that damage may occur. However, providing a fixed position for the pivot blocks  76  protects the cables by reducing the amount of movement or flexion they may be exposed to. 
     The illustrated embodiment includes the arms  60  having a first segment  80  coupled to the pivot block  76 A and a second segment  82  coupled to the pivot block  76 B. The first and second segments  80  may be rotationally coupled to the respective pivot blocks  76  via a pin or journal coupling  84 . However, pin and/or journal couplings are for illustrative purposes only and any reasonable coupling member to facilitate rotational movement of the first and second segments  80 ,  82  may be utilized. As will be described in detail below, rotational movement of the first and second segments  80 ,  82  move the arms  60  radially outward from the tool string axis  62 . In various embodiments, a degree of relative motion of the first and second segments  80 ,  82  may be limited, for example by one or more restriction components, to block over-rotation of the first and second segments  80 ,  82 . Furthermore, other components of the arms  60  may act to restrict the range of rotation of the first and second segments  80 ,  82 . 
     The arms  60  further include a link arm  86 , which is also coupled to the pivot block  76 . As illustrated, the first and second segments  80 ,  82  are coupled to a respective far end  88  of the respective pivot block  76  while the link arm  86  is coupled to a respective near end  90  of the respective pivot block  76 . The far end  88  is closer to the bulkhead head  66  than the near end  90 . The link arm  86  is further coupled to the pivot block  76  via a pin or journal coupling  92 , which may be a similar or different coupling than the coupling  84 . The link arms  86  extend to couple to a telescoping section  94 , for example via a pin or journal coupling  96 . As illustrated, the first and second segments  80 ,  82  also coupling to the telescoping section  94 , for example via a pin or journal coupling  98 , at opposite ends. 
     It should be understood that, in various embodiments, the illustrated couplings between the first and second segments  80 ,  82 , the link arms  86 , the telescoping section  94 , and/or the pivot block  76  may enable rotation about a respective axis. That is, the components may pivot or otherwise rotate relative to one another. In certain embodiments, the couplings may include pin connections to enable rotational movement. Furthermore, in certain embodiments, the components may include formed or machined components to couple the arms together while further enabling rotation, such as a rotary union or joint, sleeve coupling, or the like. 
     In the embodiment illustrated in  FIG. 2  where the arms  60  are arranged in the expanded position, the combination of the first segment  80 , the second segment  82 , the link arms  86 , and the telescoping section  94  generally form a parallelogram. As will be described in detail below, the telescoping section  94  includes a first section  100  and a second section  102  that are moveable relative to one another in response to rotation of the first and second segments  80  and/or link arms  86 . In other words, the telescoping section  94  moves between an expanded position and a collapsed position based on the radial position of the arm  60  (e.g., one or more components of the arm  60 ). 
     In embodiments, properties of the arms  60 , such as a length of the first segment  80 , a length of the second segment  82 , a length of the link arm  96 , or a length of the telescoping section  94  may be particularly selected to control the radial position of the telescoping portion  94  with respect to the tool string axis  62 . For example, the length of the first and second segments  80 ,  82  and the link arm  86  directly impact the radial position of the telescoping portion  94 . In this manner, the position of the telescoping portion  94 , and therefore the sensors coupled to the telescoping portion  94 , may be designed prior to deploying the downhole tool  28 . Furthermore, any number of sensors may be arranged on the arms. It should be appreciated that the sensors are not illustrated in  FIG. 2  for clarity. In various embodiments, each arm  60  contains three sensors (e.g., flow, resistivity, composition), thereby performing a total of 18 different measurements with the illustrated downhole tool  28 . The downhole tool  28  illustrated in  FIG. 2  enables measurements at various locations in the annulus around the downhole tool  28 , thereby providing information about flow characteristics at various circumferential positions in the annulus. As opposed to using multiple downhole tools over a vast length of a drill string, the illustrated downhole tool  28  measures and records flow conditions at a particular location in the wellbore  14  over substantially the entire annulus. In certain embodiments, the sensor tubes coupling the one or more sensors to the bulkheads  66  may be equally divided. In other embodiments, more or fewer sensor tubes may be coupled to one bulkhead  66 . 
       FIGS. 3-8  depict various views of an embodiment of a bracket  120  for holding one or more sensors to the arms  60 . In various embodiments, the bracket  120  is rotatably coupled to the arms  60  to thereby pivot relative to the arm  60  and move the sensors into a flow path, as will be described in detail below. 
       FIG. 3  is a front isometric view of an embodiment of the bracket  120 . The illustrated bracket  120  includes a spine  122  extending along a length  124  of the bracket  120 . The spine  122  may provide structural rigidity to the bracket  120  for coupling to the arm  60 . The illustrated spine  122  includes a gap  126  arranged between a first finger  128  and a second finger  130 . In various embodiments, but not visible in  FIG. 3 , the first finger  128  and second finger  130  are coupled together. As will be described in detail below, the first and second fingers  128 ,  130  may include a varying thickness body portion that is particularly selected to reduce the weight of the bracket  120 , enable multiple bracket  120  arrangements on the downhole tool  28 , and provide sufficient strength to accommodate the wellbore environment. 
     In various embodiments, a pivot axis  132  extends through holes  134  formed through the first and second fingers  128 ,  130  at a first end  136  of the bracket  120 . The first end  136  is arranged opposite the length  124  from the second end  138 , which includes holsters  140 . The illustrated embodiment includes a pair of holsters  140 , however it should be appreciated that, in various embodiments, there may be more of fewer holsters  140 . For example, there may be 1, 3, 4, 5, or any other reasonable number of holsters  140 . 
     The illustrated holsters  140  are substantially cylindrical and include an opening  142  extending through an outer shell  300  of the holsters  140  to enable one or more sensors to be installed within the holsters  140 . By way of example, the openings  142  may be particularly selected to accommodate sensor tubes that are coupled to the sensors. The tubes may be pressure containing housings that facilitate data transmission to the bulkhead  66 . In the illustrated embodiment, the openings  142  extend along a length  144  of the holsters  140  from a first distal axial ends  302  and a second distal axial end  304 . However, it should be appreciated that in various embodiments the openings  142  may not spend the entire length  144 . Moreover, while the illustrated openings  142  are arranged along a side of the holsters  140 , in other embodiments the openings  142  may be along a bottom, a top, or any other reasonable location of the holsters  140 . 
     In the embodiment illustrated in  FIG. 3 , the holsters  140  are not the same size. That is, the length  144 A for the holster  140 A is longer than the length  144 B for the holster  140 B. The length  144  for the respective holsters  140  may be particularly selected based on the anticipated sensor to be arranged within the holster  140 . In various embodiments, the lengths  144 A,  144 B may be equal. Moreover, in certain embodiments, the length  144 B may be larger than the length  144 A. Accordingly, it should be appreciated that the illustrated holsters  140 A,  140 B are for illustrative purposes only and are not intended to limit the disclosure. 
     In various embodiments, the holsters  140  may be biased toward the openings  142  in order to secure or clamp around the sensors installed therein. As a result, the holsters  140  will secure the sensors in place, even in the presence of wellbore conditions. In various embodiments, the bracket  120  is formed from a metal, plastic, composite material, or combination thereof. In certain embodiments, the bracket  120  may be a machined or cast piece. In certain embodiments, the bracket may be formed from manufacturing techniques, such as laser sintering of metal powder. Reducing the number of hard edges may ease manufacturing. Additionally, in other embodiments, the holsters  140  may be separately attached to the spine  122 , for example via weld metal, fasteners, or any other reasonable method. 
     In various embodiments, the bracket  120  includes beveled edges  146  along various components of the bracket  120 . For example, the first and second fingers  128 ,  130  include beveled edges  146  along the length  124 . Furthermore, the holsters  140  include beveled edges  146  at respective coupling regions  148  where the holsters  140  are joined to the fingers  128 ,  130 . It should be appreciated that the beveled edges  146  may improve flow characteristics of the bracket  120  without the annulus, thereby reducing turbulence at the sensors. Furthermore, the beveled edges  146  may improve the strength of the bracket  120  by distributing forces over a curved area, rather than a straight area. 
       FIG. 4  is a top plan view of an embodiment of the bracket  120 . The illustrated embodiment includes a base  160  extending between the first and second fingers  128 ,  130 , coupling them together. In the illustrated embodiment, a length  162  of the base  160  is less than the length  124  of the bracket  120 . As a result, the weight of the bracket  120  may be reduced. In operation, the spine member  122  is arranged on the first segment  80 , the second segment  82 , the link arm  86 , and/or the telescoping section  94 . As such, the spine member  122  may facilitate in providing additional rigidity and strength to the arm  60 . Furthermore, a width  164  of the base may be particularly selected to facilitate coupling the bracket  120  to the arm  60 . 
     In the illustrated embodiment, the first end  136  includes the mounting heads  166 . The mounting heads  166  include the holes  134  that extend therethrough. In the illustrated embodiment, a mounting head thickness  168  is larger than a finger thickness  170 . Accordingly, there is additional rigidity and strength at the coupling point to the arm  60 . It should be appreciated that the additional strength enables the bracket  120  to support the sensor within the flow path in wellbore conditions. 
     Further illustrated in  FIG. 4  are chamfers  172  arranged along leading and trailing edges of the holsters  140 . As described above, in various embodiments certain features, such as the beveled edges  146 , may be incorporated into the bracket  120  to improve aerodynamics within the flow path. For example, the chamfers  172  reduce the cross-sectional flow area of the bracket  120 , thereby reducing the likelihood of disturbing the flow in the annulus. It should be appreciated that the chamfers  172  may not be uniform on the leading and trailing edges. Additionally, each holster  140  may have different chamfers  172 . In embodiments, a flow meter may be positioned proximate the bracket  120 . By reducing the disturbance, the flow meter may measure more accurate characteristics of the flow. 
     The different lengths  144 A,  144 B of the respective holsters  140 A,  140 B are illustrated in  FIG. 4 . As described above, in various embodiments the lengths  144 A,  144 B may be particularly selected based on the type of sensors that will be arranged within the holsters  140 A. As a result, different brackets  120  may be formed for certain sensors or sensor pairs, which simplifies installation procedures for operators. 
       FIG. 5  is a front isometric elevational view of the bracket  120 . As illustrated, the spine  122  is generally “U” shaped and includes the base  160  coupling the first finger  128  to the second finger  130 . In the illustrated embodiment, the mounting heads  166  also include the beveled edges  146  that extend along the length  124 . Furthermore, the beveled edges  146  are illustrated at the coupling regions  148 . In the illustrated embodiment, the beveled edge  146 A has a different radius than the beveled edge  146 B. However, it should be appreciated that in other embodiments they may be the same. 
     In various embodiments, a height  180  of the spine  122  is less than a height  182  of the holsters  140 . The various heights  180 ,  182  may be particularly selected based on design and operating conditions. For example, the height  182  of the holsters  140  may be at least partially dependent on the size and shape of the sensors. Furthermore, the height  180  of the spine  122  may be at least partially dependent on the size and shape of the arms  60 . 
     The illustrated holsters  140  are substantially cylindrical with a void region  184  extending therethrough. The void region  184  receives the sensor. The illustrated holsters  140  includes notches  186  formed along a circumferential extend  188  of the holsters  140 . In the illustrated embodiment, the holster  140 A includes the notch  186 A on the leading edge while the holster  140 B includes the notch  186 B on the trailing edge. It should be appreciated that, in other embodiments, the position of the notches may be swapped or may be the same. The respective notches  186  may facilitate installation and removal of the sensors by providing a region of flexion along the holsters  140 . 
       FIG. 6  is a rear isometric view of an embodiment of the bracket  120 . As described above, the pair of holsters  140  are arranged at the second end  138  of the bracket  120 . The illustrated base  160  ends substantially at the holsters  140 , however it should be appreciated that in other embodiments the base  160  may extend to the end of the holsters  140 . The illustrated base  160  further includes a bowed portion  190  for coupling to the holsters  140 . As described above, in various embodiments transmitting forces along curved edges, rather than straight edges, may better distribute forces and improve the reliability and longevity of the bracket  120 . 
       FIG. 7  is a rear perspective view of an embodiment of the bracket  120  coupling a sensor  200  to the arm  60 . The illustrated bracket  120  is in a stowed position such that a bracket axis  202  is substantially aligned with an arm axis  204 . As illustrated, the bracket  120  is coupled to the arm  60  at the mounting head  166 , for example via a pin or other coupling to enable rotation about the pivot axis  132 . The first finger  128  is arranged within a recess  206  formed in the arm  60 . In various embodiments, the recess  206  is sized to accommodate the first finger  128  (e.g., a depth of the recess is approximately equal to the finger thickness  170 ). The spine  122  extends around an under side of the arm  60  such that the second finger  130  is arranged on an opposite side of the arm  60 . As such, the bracket  120  may be closely positioned to the arm  60 . In various embodiments, the beveled edges  146  provide a gap or space between the arm  60  and the bracket  120 , thereby reducing friction between the components. 
     The sensor  200  is arranged within the void region  184  and extends toward the first end  136 . Furthermore, a sensor tube  208  extends from the second end  138 . As described above, in various embodiments the opening  142  enables the sensor tube  208  to be threaded through the holster  140 . For example, in operation, the sensor  200  may be installed from the leading end. First, the sensor tube  208  may be threaded through the opening  142  and then the sensor body is positioned within the holster  140 . The sensor tube  208  may be routed to the bulkhead  66  for data transmission to the surface  18 . As will be described below, as the arm  60  moves between the stored position and the deployed position, the sensor  200  may move axially along a holster axis  210 , which may be substantially parallel to the bracket axis  202 . In certain embodiments, the sensor  200  may have a freedom of axial movement of approximately 10 percent of the sensor length. However, it should be appreciated that the dimensions of the holster  140  may be particularly selected to allow axial movement of approximately 5 percent of the sensor length, approximately 15 percent of the sensor length, or any other reasonable percentage of the sensor length. Providing room for axial movement may reduce forces applied to the sensor tube  208 , which may increase the longevity of the sensor tube and hence the reliability of data transfer to the bulkhead  66 . 
       FIG. 8  is a rear perspective view of the bracket  120  in the deployed position. In the illustrated embodiment, the bracket  120  is coupled to the telescoping section  94 , for example to the first section  100 , and rides or moves along with the link arm  86 . That is, as the arm  60  transitions to the extended position the bracket  120  may drop such that the second end  138  moves radially inward toward the tool string axis  62 . As a result, the sensors  200  are arranged within the flow path through the annulus. Movement of the bracket  120  is enabled via rotation about the pivot axis  132 . As described above, in various embodiments the telescoping section  94  remains substantially parallel to the tool string axis  62  as the arm  60  moves to the extended position. In contrast, the holster axis  210  transitions such that it is arranged at an angle  220  relative to the tool string axis  62  when the bracket is in the deployed position. 
     In various embodiments, the bracket  120  may be coupled or otherwise arranged along the link arm  86  such that movement of the link arm  86  is substantially translated to the bracket  120 . For example, the bracket  120  may move toward the deployed position as the link arm  86  moves toward the extended position and the bracket  120  may move toward the stowed position as the link arm  86  moves toward the stored position. In various embodiments, the chamfers, bevels, and other features may facilitate coupling or interaction between the various components. For example, the beveled edges  146  may guide the bracket  120  back into the stowed position. 
     Although the technology herein has been described with reference to particular embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the present technology. It is therefore to be understood that numerous modifications may be made to the illustrative embodiments and that other arrangements may be devised without departing from the spirit and scope of the present technology as defined by the appended claims.