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CONTINUITY INFORMATION  
       [0001]     The following is also based upon and claims priority to U.S. Provisional Application Ser. No. 60/521,692, filed Jun. 18, 2004. 
     
    
     BACKGROUND  
       [0002]     Control lines, such as individual or combined hydraulic, electric, or fiber control lines, are used in oil and gas wellbores to control downhole tools or to carry data related to measuring wellbore or environmental parameters. However, many obstacles to the deployment of a control line along the length of the wellbore exist. For example, packers are commonly deployed in wellbores and block the path down a wellbore. Moreover, if the control line is exposed on its exterior, the control line can be damaged as it is inserted and removed from the wellbore.  
         [0003]     Thus, there is a continuing need to address one or more of the problems stated above.  
       SUMMARY  
       [0004]     The present invention relates to a system and method to deploy control lines in wellbores. The control lines are deployed in a protected manner and, in some embodiments, serve to provide control line functionality through packers or other components.  
         [0005]     Advantages and other features of the invention will become apparent from the following drawing, description and claims. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0006]      FIG. 1  is a front elevation view taken in partial cross-section of a system according to one embodiment of the present invention;  
         [0007]      FIG. 2  illustrates a portion of one embodiment of the stinger illustrated in  FIG. 1 ;  
         [0008]      FIG. 3  illustrates an alternate embodiment of the stinger illustrated in  FIG. 1 ;  
         [0009]      FIGS. 4-6  illustrate additional alternative embodiments of the stinger illustrated in  FIG. 1 ;  
         [0010]      FIG. 7  is a front elevation view of an alternate embodiment of the system illustrated in  FIG. 1 ;  
         [0011]      FIG. 8  is an illustration of one embodiment of the sealing sleeve illustrated in  FIG. 7 ;  
         [0012]      FIGS. 9-10  are schematic illustrations s of a another embodiment of the system illustrated in  FIG. 1 ;  
         [0013]      FIG. 11  is an enlarged view of an embodiment of an engagement mechanism between the running tool and the completion illustrated in  FIGS. 9-10 ; and  
         [0014]      FIGS. 12-14  are schematic illustrations representing another embodiment of the present invention.  
     
    
     DETAILED DESCRIPTION  
       [0015]     The present invention generally relates to completions utilized in a well environment. The completions comprise one or more control lines.  
         [0016]     As used herein and unless otherwise noted, the term “control line” shall include all types of control lines, including hydraulic control lines, electric lines, wirelines, slicklines, optical fibers, and any cables that house or bundle such lines or fibers. Control lines may be used to control downhole device (such as any downhole tool—packers, flow control valves, etc), transmit information, or measure parameters.  
         [0017]      FIG. 1  illustrates a first embodiment of the present invention. A completion  10  is deployed in a wellbore  12 . The wellbore  12  may include casing  14  along a portion of its length, with the bottommost section  16  not cased. In alternative embodiments, the entire wellbore  12  is cased, or the entire wellbore  12  is not cased. The wellbore  12  extends from a subterranean location to a surface location, such as the surface of the earth (not shown). The wellbore  12  may be a land well or an offshore well. The wellbore  12  intersects at least one formation  13  from which fluids (such as hydrocarbons) are produced to the surface or into which fluids (such as water or treating fluids) are injected.  
         [0018]     A lower completion  18  is deployed in the wellbore  12 . The lower completion  18  includes a packer  20 , which seals and anchors the lower completion  18  to a surrounding wall, such as casing  14  (or wellbore wall if the wellbore is not cased). The surrounding wall/casing  14  also can comprise other components, such as an expandable tubing or sand screen. The lower completion  18  also includes a fluid communication component  22  providing fluid communication between the exterior of the lower completion  18  and the interior bore  24  of the lower completion  18 . In the embodiment illustrated in  FIG. 1 , fluid communication component  22  comprises a sand screen  26 . In other embodiments, fluid communication component  22  comprises an expandable sand screen, a flow control valve (such as a sleeve valve), at least one port, or other components.  
         [0019]     An upper completion  30  is deployed into the wellbore  12  and is inserted into the lower completion  18 . The upper completion  30  comprises a packer  32 , a stinger  34 , a control line  36 , and at least one flow port  39 . After the upper completion  30  is run into the well, the packer  32  is set against the casing  14  (or the wellbore wall if no casing  14  is present). The packer  32  seals and anchors the upper completion  30  to the casing  14 . An engagement section  38  is inserted into the bore  21  of the lower completion packer  20 . The stinger  34  extends into the lower completion bore  24  and may extend across the fluid communication component  22 . As shown in  FIG. 2 , the stinger  34  includes at least one flow port  39  that provides fluid communication between the exterior and interior of the stinger  34 . The at least one flow port  39  can be located in the side or a bottom of the stinger. The part of the stinger  34  including the at least one flow port  39  may comprise perforated or slotted pipe. In an alternative embodiment, the stinger  34  is deployed subsequent to the packer  32  and engagement section  38 .  
         [0020]     The control line  36  extends along at least part of the length of the stinger  34 . In one embodiment, the control line  36  extends along the length of the stinger  34  and across the fluid communication component  22 . The control line  36  typically extends upwards along the upper completion  30  and to the surface and is functionally connected to an acquisition unit  37 .  
         [0021]     In one embodiment as shown in  FIG. 1 , the control line  36  is deployed in the interior of the stinger  34 . The control line  36  crosses to the exterior of the upper completion  30  above the lower completion packer  20  and is fed through a by-pass port of the upper completion packer  32 . In other applications, control line  36  can extend toward or to the surface in the interior of the stinger.  
         [0022]     In another embodiment as shown in  FIG. 3 , the control line  36  extends along a recess  40  located in a wall of the stinger  34  and is directly fed through the by-pass port of the upper completion packer  32 . In the example illustrated, recess  40  is located on an exterior of stinger  34 , although it can be located within an interior. In one embodiment, the recess  40  extends substantially longitudinally along the stinger  34 . In another embodiment (not shown), the recess  40  extends helically up the stinger  34 . The recess  40  serves as a protection mechanism and protects the control line  36  when the upper completion  30  is run into or out of the wellbore  12  and lower completion  18 .  
         [0023]     In another embodiment illustrated in  FIG. 4 , stinger  34  comprises a perforated base pipe  90  and an outer shroud  92 . Base pipe  90  includes at least one opening  98  therethrough and is connected to the shroud  92  by way of attachments  94 . Shroud  92  also has at least one opening  99  therethrough and includes a recess  96  as previously described in relation to  FIG. 3 . The control line  36  extends along the recess  96 .  
         [0024]     In another embodiment as shown in  FIG. 5 , stinger  34  comprises perforated base pipe sections  90  (such as  90 A-D) and outer shroud sections  92  (such as  92 B and C). Each base pipe section  90  has a corresponding outer shroud section  92 , and each base pipe section  90  includes at least one opening  98  therethrough. Each shroud section  92  is rotationally engaged to its corresponding base pipe section  90  such as by having mating profiles  80 ,  82  that prevent axial movement therebetween. When the shroud section  92  and the base pipe section  90  are in correct rotational alignment, screws  84  are inserted through the shroud section  92  and are set against the base pipe section  90 , thereby locking the shroud section  92  to the base pipe section  90 . Each shroud section  92  includes a recess (such as the recess shown in  FIG. 3 ) to accommodate and protect the control line  36 .  
         [0025]     The embodiment of  FIG. 5  is particularly beneficial in manufacturing and assembling the stinger  34 . Each base pipe section  90  arrives with its corresponding shroud section  92  rotationally connected thereto. The stinger  34  is then assembled by threading the base pipe sections  90  together, such as at threads  86 . Next, the control line  36  is disposed within the recesses of adjoining shroud sections  92 . The shroud sections  92  can be rotationally shifted to enable such alignment. When the recesses of adjoining shroud sections  92  are aligned, each of the two shroud sections  92  is locked to its base pipe section  90  by the use of screws  84  as previously disclosed. The process is continued until the entire stinger  34  is assembled. This technique enables the use of regular threads  86  on base pipe sections  90 , as opposed to more costly premium threads.  
         [0026]     In another embodiment as shown in  FIG. 6 , stinger  34  comprises a perforated base pipe  90  and a split outer shroud  92 . Base pipe  90  includes at least one opening  98  therethrough. Shroud  92  also has at least one opening  99  therethrough. In this embodiment, shroud  92  is constructed of two sections  70 ,  71  that, combined, encircle the base pipe  90 . The shroud sections  70 ,  71  are pivotally joined at a pivot point  72  so the shroud  92  can be assembled onto the base pipe  90 . Base pipe  90  and shroud section  92  also contain halves  73 ,  74 , respectively, of a clamp  75  so that when shroud section  92  encircles base pipe  90 , the control line  36  is retained in the clamp  75 . A locking mechanism  76 , such as a set screw  77 , locks the shroud section  92  on the base pipe section  90 . A spacer or spacers  78  may be inserted to provide adequate centralization between the shroud section  92  and the base pipe section  90 .  
         [0027]     In one embodiment in which the control line  36  includes an optical fiber, the optical fiber  36  and acquisition unit  37  comprise a distributed temperature sensor system, such as the Sensa DTS systems sold by Sensor Highway Limited, Southampton, UK. Generally, pulses of light at a fixed wavelength are transmitted from the acquisition unit  37  through the fiber optic line  36 . At every measurement point in the line  36 , light is back-scattered and returns to the acquisition unit  37 . Knowing the speed of light and the moment of arrival of the return signal enables its point of origin along the optical fiber  36  to be determined. Temperature stimulates the energy levels of the silica molecules in the fiber line  36 . The back-scattered light contains upshifted and downshifted wavebands (such as the Stokes Raman and Anti-Stokes Raman portions of the back-scattered spectrum) which can be analyzed to determine the temperature at origin. In this way the temperature of each of the responding measurement points in the fiber line  36  can be calculated by the unit  37 , providing a complete temperature profile along the length of the fiber line  36 . This general fiber optic distributed temperature system and technique is known in the prior art.  
         [0028]     In another embodiment, control line  36  is connected to a sensor (not shown), which transmits its measurements to the acquisition unit  37  via the control line  36 . The sensor can be a hydraulic, mechanical, chemical, electrical, or optical sensor and can measure any downhole characteristic, including physical and chemical parameters of the well fluid and environment. For instance, the sensor can comprise a temperature sensor, a pressure sensor, a strain sensor, a flow sensor, or phase sensor. In another embodiment, fiber optic line  36  may be used to take a distributed strain measurement along the length of the fiber optic line(s)  36 .  
         [0029]     In one embodiment in which an optical fiber is included, the control line  36  comprises a conduit  42  and an optical fiber  39 . Instead of deploying the optical fiber  39  by itself or bundled in a cable and attaching it to the upper completion  30 , the optical fiber  39  can be deployed within a conduit  42  (see  FIG. 3 ). The conduit  42  may be located in the interior of stinger  34  and then crossed over to the exterior of stinger  34 , as shown in relation to the optical fiber  39  in  FIG. 1 . Or, the conduit  42  may be deployed within the recess  40  on, for example, the exterior of stinger  34  as shown and described in relation to  FIG. 3 .  
         [0030]     In one embodiment, conduit  42  is deployed with fiber optic line  39  already disposed therein. However, in another embodiment, conduit  42  is first deployed with the upper completion  30 , and fiber optic line  39  is thereafter installed in the conduit  42 . In this technique, fiber optic line  39  is pumped down conduit  42 . Essentially, the fiber optic line  39  is dragged along the conduit  42  by the injection of a fluid at the surface, such as injection of fluid (gas or liquid) by a pump. The fluid and induced injection pressure work to drag the fiber optic line  39  along the conduit  42 . This installation technique can be specially useful when a fiber optic line  39  requires replacement during an operation.  
         [0031]     The control line  36  may have a “J-shape”, wherein the control line  36  returns from the bottom of its extension along the stinger  34  and extends back at least partially to the surface, or a “U-shape”, wherein the control line  36  returns from the bottom of its extension along the stinger  34  and extends back completely to the surface. Either of these shapes is beneficial when the control line  36  includes an optical fiber  39  and the optical fiber  39  is used as part of a distributed temperature sensor system. Additionally, although one control line  36  is shown as being used in relation to the embodiment of  FIGS. 1-3 , it is understood that more than one control line  36  may be deployed with embodiments described herein.  
         [0032]     In operation, the lower completion  18  is deployed in the wellbore  12  and the packer  20  is set sealingly anchoring the lower completion  18  to the wellbore  12 . The upper completion  30  is then deployed and the packer  32  is set once the upper completion  30  is in the appropriate position (in an alternative embodiment, the stinger  34  is deployed subsequent to the packer  20  and engagement section  38 ). If the wellbore  12  is a producing wellbore, fluid flows from the formation  13 , into the wellbore  12 , through the fluid communication component  22 , into the lower completion interior bore  24 , through the at least one flow port  39 , and through the upper completion  30  to the surface. If the wellbore is an injection wellbore, fluid flows in the opposite direction from the surface and into the formation  13 . If the control line  36  and unit  37  comprise a distributed temperature sensor system, distributed temperature traces are taken along the length of the control line to provide the required information for the operator. If the control line  36  is used to control downhole devices, an operator may then activate such control. If the control line  36  transmits information to the surface, such information may then be transmitted.  
         [0033]      FIG. 7  illustrates another embodiment of the present invention. A completion  110  is deployed in a wellbore  112 . The wellbore  112  may or may not include casing  114 . The wellbore  112  extends from a subterranean location to, for example, the surface of the earth (not shown). The wellbore  112  may be a land well or an offshore well. The wellbore  112  intersects at least two formations  113 ,  115  from which fluids (such as hydrocarbons) are produced to the surface or into which fluids (such as water or treating fluids) are injected from the surface.  
         [0034]     A lower completion  118  is deployed in the wellbore  112 . The lower completion  118  includes at least two packers  120 ,  121 . Packer  120  seals and anchors the lower completion  118  to the casing  114  (or wellbore wall if the wellbore is not cased) above the upper formation  113 , and packer  121  seals and anchors the lower completion  118  to the casing  114  (or wellbore wall if the wellbore is not cased) between the upper formation  113  and the lower formation  115 . A third and bottommost packer  123  may also be used to seal and anchor the lower completion  118  below the lower formation  115 . Proximate each of the packers  120 ,  121 , the lower completion  118  also includes a fluid communication component  122 ,  125  providing fluid communication between the exterior of the lower completion  118  and the interior bore  124  of the lower completion  118 . In the embodiment illustrated in  FIG. 7 , fluid communication components  122 ,  125  comprise sand screens  126 ,  127 . In other embodiments, fluid communication components  122 ,  125  can comprise components, such as expandable sand screens, flow control valves (e.g., sleeve valves), at least one port, or combinations thereof.  
         [0035]     An upper completion  130  is deployed into the wellbore  112  and is inserted into the lower completion  118 . The upper completion  130  comprises a packer  132 , a stinger  134 , a control line  136 , two flow control components  139 ,  141 , and a sealing sleeve  143 . After the upper completion  130  is run into the well, the packer  132  is set against the casing  114  (or the wellbore wall if no casing  114  is present). The packer  132  seals and anchors the upper completion  130  to the casing  114 . The sealing sleeve  143  of the stinger  134  is inserted into the bore  145  of the lower completion packer  121  and provides a seal between the upper completion  130  and the lower completion  118 . The stinger  134  extends into the lower completion bore  124  and across upper fluid communication component  122  and may extend across the bottom fluid communication component  125 .  
         [0036]     The control line  136  extends along at least part of the length of the stinger  134 . In one embodiment, the control line  136  extends along the length of the stinger  134  and across the fluid communication components  122 ,  125  and flow control components  139 ,  141 . The control line  136  typically extends upwards along the upper completion  130  and to the surface and is functionally connected to an acquisition unit  137 .  
         [0037]     In this embodiment, the control line  136  extends along the exterior of the stinger  134 . The sealing sleeve  143 , which is shown in cross-section in  FIG. 8 , includes at least one by-pass port  151  longitudinally therethrough as well as seals  153  on its exterior. Seals  153  sealingly engage the lower completion packer bore  145 . The control line  136  is sealingly fed through the at least one sealing sleeve by-pass port  151  with the remainder of the unused by-pass ports  151  being sealed (unless otherwise used by other control lines). Above the sealing sleeve  145 , the control line  136  is directly sealingly fed through the by-pass port  155  of the upper completion packer  132 . In one embodiment, the stinger  134  includes a recess (such as the recess  40  of the embodiment described in relation to  FIGS. 1-3 ) used to protect the control line  136 . In another embodiment, the control line  136  (if it includes an optical fiber) and acquisition unit  137  comprises a distributed temperature sensor system as previously described in relation to the embodiment of  FIGS. 1-3 . In yet another embodiment, control line  136  is connected to a sensor (not shown) which transmits its measurements to the acquisition unit  137  via the control line  136 . The sensor can measure any downhole characteristic, including physical and chemical parameters of the well fluid and environment. For example, the sensor can comprise a temperature sensor, a pressure sensor, a strain sensor, a flow sensor, or phase sensor. Also, control line  136  may be used to take a distributed strain measurement along the length of the fiber optic line(s)  136 .  
         [0038]     In the embodiment in which control line  136  includes an optical fiber, instead of deploying the optical fiber by itself and attaching it to the upper completion  130 , the optical fiber can be deployed within a conduit as previously described in relation to the embodiment of  FIGS. 1-3 . Moreover, the fiber optic line may be deployed already housed within the conduit, or the fiber optic line may be pumped into the conduit once the upper completion  130  is installed, as described in relation to the embodiment of  FIGS. 1-3 . The control line  136  (and conduit if included) may also be “J-shaped” or “U-shaped.” In addition, although one control line  136  is shown, it is understood that more than one control line  136  may be deployed with this embodiment using the same techniques.  
         [0039]     In operation, the lower completion  118  is deployed in the wellbore  112  and the packers  120 ,  121 ,  123  are set to sealingly anchor the lower completion  118  to the wellbore  112 , providing zonal isolation between formations  113 ,  115 . The upper completion  130  is then deployed and the packer  132  is set once the sealing sleeve  143  is sealingly engaged to the packer bore  145 . If the wellbore  112  is a producing wellbore, fluid flows from the formation  113 , into the wellbore  112 , through the fluid communication component  122 , into the lower completion interior bore  124 , through the flow control component  139 , and into and through the upper completion  30  to the surface. Similarly, fluid flows from the formation  115 , into the wellbore  112 , through the fluid communication component  125 , into the lower completion interior bore  124 , through the flow control component  141 , and into and through the upper completion  30  to the surface. If the wellbore is an injection wellbore, fluid flows in the opposite direction from the surface and into the formations  113 ,  115 .  
         [0040]     The flow control components  139 ,  141  may comprise any downhole valve, such as sleeve valves, ball valves, or disc valves. The components  139 ,  141  may be remotely controlled (actuated) by additional control lines (hydraulic, electric, or fiber optic—also deployed through the by-pass ports of the sealing sleeve  143  and packer  132 ) or by wireless signals (pressure pulses, acoustic signals, electromagnetic signals, or seismic signals). Having a flow control component  139 ,  141  associated with each formation  113 ,  115  provides an operator with the ability to independently control flow to or from each formation.  
         [0041]     If the control line  136  and unit  137  comprise a distributed temperature sensor system, distributed temperature traces can be taken along the length of the control line to provide the required information for the operator, including information relevant to both formations  113 ,  115 . If the control line  136  is used to control downhole devices, an operator may then activate such control. If the control line  136  transmits information to the surface, such information may then be transmitted.  
         [0042]      FIGS. 9 and 10  illustrate another embodiment of the invention. A completion  210  is deployed in a wellbore  212 . The wellbore  212  may or may not include casing  214 . The wellbore  212  extends from a subterranean location to, for example, the surface of the earth (not shown). The wellbore  212  may be a land well or an offshore well. The wellbore  212  intersects a formation  213  from which fluids (such as hydrocarbons) are produced to the surface or into which fluids (such as water or treating fluids) are injected from the surface.  
         [0043]     Completion  210  may be a gravel pack completion including a sand screen  216 , perforated base pipe  218 , and packer  220 . The packer  220  seals and anchors the completion  210  against the casing  214 .  
         [0044]     A control line  222 , such as a hydraulic control line or conduit, extends from the surface along the completion  210  towards the packer  220 . At a point above the packer  220 , the control line  222  extends to a port  224 . Port  224  extends through completion  210 . On the interior of the completion  210 , port  224  is located in a groove  226  that extends longitudinally along a portion of the completion interior. As shown in  FIG. 9 , a sleeve  228  is located within groove  226  and initially covers port  224 . In one embodiment, sleeve  228  sealingly covers port  224 . When the sleeve  228  is in the position covering port  224 , a tool, such as a gravel pack service tool, may be deployed in the wellbore  112  and gravel pack  230  may be introduced therein. Once the gravel pack  230  is in place, an operator may place the wellbore  12  into production.  
         [0045]     At some point during the life of the wellbore  12 , the operator may wish to obtain a temperature trace of the wellbore  12 , such as by using the distributed temperature sensor system previously described in relation to the embodiments of  FIGS. 1-3 . If this is the case, a running tool  240  may be deployed in the wellbore  12  as shown in  FIGS. 10 and 11 . The running tool  240  engages sleeve  228  and displaces it along the profile  226 , as more clearly shown in  FIG. 11 .  
         [0046]     Running tool  240  includes a profile  242  that matches a profile  244  on the interior of sleeve  228 . Thus, when the two profiles  242 ,  244  come in contact, they mate and the running tool  240  moves sleeve  228  downwardly, thereby exposing the port  224 . The downward movement of sleeve  228  stops at the end of the groove  226  at which point the port  224  is fully exposed, and the port  224  is disposed between two seals  246  on the exterior of running tool  240 . At this position, a hydraulic control line  248  of running tool  240  is connected to and is in fluid communication with the port  224  and the control line  222 .  
         [0047]     At this location, a common path is formed between and including the hydraulic control lines  222 ,  248 . An optical fiber  250  may be pumped into the common path and through the port  224  as previously described in relation to the embodiment of  FIGS. 1-3 . Thus, a temperature trace may be obtained by an operator. The control line  248  may extend downwardly across the sand screen  216  to enable an operator to obtain the temperature trace across the screen  216  and formation  213 . Once the information is obtained, the optical fiber  250  may be removed from the control lines  222 ,  248  (such as by reversing pumping or pulling), and the running tool  240  may be removed from the wellbore  212 . When the running tool  240  is removed from the wellbore  212 , the sleeve  228  is returned to its position of  FIG. 9  (covering the port  224 ) by the continued interaction of the matching profiles  242 ,  244 . Upward movement of the sleeve  228  ends at the top of groove  226 , at which point the profiles  242 ,  244  disengage.  
         [0048]     Thus, with this embodiment, temperature traces can be taken in the wellbore  212  at different times during the life of the well. Although a gravel pack/sand control completion was described and illustrated, it is understood that this embodiment may be used with other types of completions in which intermittent use of temperature traces are desired. The completion need only include the groove, sleeve, and port (or similar mechanisms) as indicated. For instance, the releasable assembly of  FIGS. 9 and 10  may be used to implement the alternative embodiment described in relation to  FIGS. 1-3  wherein the stinger  34  is deployed subsequent to the packer  32  and engagement section  38 .  
         [0049]      FIGS. 12-14  illustrate another embodiment of the present invention. The completion  310  shown in  FIG. 12  is similar to the completion of  FIG. 1 , except that the completion  310  of  FIG. 12  is in a partially cased  314  deviated wellbore  312 . The lower completion  318  as shown includes an expandable sand screen  326 , although it may include other components such as a regular sand screen or other fluid communication components. The upper completion  330  includes a stinger  334  and a control line  336 , among other components. It is noted that other components and parts described in relation to the embodiment of  FIGS. 1-3  may also be included in the present embodiment.  
         [0050]     In the illustrated embodiment, the stinger  334  is adjustable so the control line  336  may be turned to a desired orientation, such as toward the bottom of the completion  310 . This is particularly useful when the control line  336  includes an optical fiber serving as part of a distributed temperature sensor system (as previously described). In this case, the bottom orientation of the optical fiber  336  serves to shield it from the production flow and thereby improve the temperature data. The present invention is particularly useful when the lower completion  318  includes expandable screens because placing a fiber  336  on the exterior of an expandable screen  336  is very difficult and often can lead to the fiber  336  being destroyed during the expansion process. One problem in utilizing a stinger  334  deployed control line  336  is that the data read by the fiber  336  inside the completion  310  may be clouded by the production flow moving past. Orienting the fiber  336  to the bottom of the completion  310  (assuming a deviated completion) can minimize the temperature error by shielding the fiber  336  from production flow.  
         [0051]      FIG. 13  illustrates one way to achieve the desired ability to orient the control line. In this Figure, the stinger  334  includes a recess  340  and the control line  336  is deployed along the recess  340  (similar to the recess  40  of  FIGS. 1-3 ). In the alternative shown in  FIG. 14 , the control line  336  is encased in a specially shaped encapsulation  350  and the stinger  334  comprises a standard, round pipe to shield the fiber from the production flow. The encapsulation is illustrated along an exterior of stinger  334 , but it also can be located in an interior of the stinger.  
         [0052]     With the use of either the embodiment of  FIG. 13  or  14 , the stinger  334  can be oriented by an orienting mechanism  360  (see  FIG. 12 ). The orienting mechanism  360  can be either electrical or mechanical. For instance, the orienting mechanism  360  can comprise an orientation guide  362  (such as muleshoe) on the lower completion  318  selectively mateable to a protrusion  364  on the upper completion  330  which when engaged rotates the upper completion  330  so that the control line  336  is proximate the bottom. Alternatively, an azimuthal wireline or LWD/MWD tool can be used to run the stinger  334  and properly orient the control line  336 .  
         [0053]     While the present invention has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention.

Summary:
A control line can be positioned in a downhole completion. For example, the control line can be deployed in a protected position along a stinger to reduce the potential for damaging the control line during installation, removal or operation.