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CROSS REFERENCE 
       [0001]    This application is a continuation-in-part of U.S. Non-provisional application Ser. No. 12/961,954 filed on Dec. 7, 2010, which patent application is incorporated by reference herein in its entirety. 
     
    
     BACKGROUND 
       [0002]    In the downhole drilling and completion industry, there is often need to contain fluid within a formation during various operations. Conventionally, a mechanical barrier is put in the system that can be closed to contain the formation fluid when necessary. One example of a system known in the art will use a valve in operable communication with an Electric Submersible Pump (ESP) so that if/when the ESP is pulled from the downhole environment, formation fluids will be contained by the valve. While such systems are successfully used and have been for decades, in an age of increasing oversight and fail safe/failure tolerant requirements, additional systems will be well received by the art. 
       SUMMARY 
       [0003]    A completion system, including a barrier valve transitionable between an open position and a closed position; and an upper completion operatively coupled with the barrier valve for mechanically transitioning the barrier valve to the closed position when the upper completion is withdrawn. 
         [0004]    A method of operating a completion system, including withdrawing an upper completion, the upper completion operatively coupled to a barrier valve for controlling operation of the barrier valve; and closing the barrier valve mechanically due to the withdrawing. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0005]    The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike: 
           [0006]      FIG. 1  is a schematic view of a stackable multi-barrier system; 
           [0007]      FIG. 2  is a schematic view of the system of  FIG. 1  in partial withdrawal from the borehole; 
           [0008]      FIG. 3  is a schematic view of a new stackable multi-barrier system engaged with the remains of the system illustrated in  FIG. 1 ; 
           [0009]      FIG. 4  depicts a quarter cross sectional view of a portion of a hydraulically actuated valve employed in the stackable multi-barrier system of  FIGS. 1-3 ; 
           [0010]      FIG. 5  is a partial cross-sectional view of a completion system in which an intermediate assembly is being engaged with a lower completion; 
           [0011]      FIG. 5A  is an enlarged view of the area circled in  FIG. 5 ; 
           [0012]      FIG. 6  is a partial cross-sectional view of the completion system of  FIG. 1  in which the intermediate assembly is engaged with the lower completion; 
           [0013]      FIG. 7  is a partial cross-sectional view of the completion system of  FIG. 1  in which a barrier valve of the intermediate assembly is closed for testing a packer of the intermediate assembly; 
           [0014]      FIG. 7A  is an enlarged view of the area circled in  FIG. 7 ; 
           [0015]      FIG. 8  is a partial cross-sectional view of the completion system of  FIG. 1  in which a fluid isolation valve for the lower completion is opened; 
           [0016]      FIG. 9  is a partial cross-sectional view of the completion system of  FIG. 1  in which a work string on which the intermediate assembly was run-in is pulled out, thereby closing the barrier valve of the intermediate assembly; 
           [0017]      FIG. 10  is a partial cross-sectional view of the completion system of  FIG. 1  in which a production string is being run-in for engagement with the intermediate assembly; 
           [0018]      FIG. 11  is a partial cross-sectional view of the completion system of  FIG. 1  in which the production string is engaged with the intermediate assembly for opening the barrier valve and enabling production from the lower completion; 
           [0019]      FIG. 12  is a partial cross-sectional view of the completion system of  FIG. 1  in which the production string has been pulled out, thereby closing the barrier valve of the intermediate assembly and a subsequent intermediate assembly is being run-in for engagement with the original intermediate assembly; and 
           [0020]      FIG. 13  is a partial cross-sectional view of the completion system of  FIG. 1  in which the subsequent intermediate assembly is stacked on the original intermediate assembly; 
           [0021]      FIG. 14  is a partial cross-sectional view of a completion system according to another embodiment disclosed herein; and 
           [0022]      FIG. 15  is a partially cross-sectional view of a completion system according to another embodiment disclosed herein. 
       
    
    
     DETAILED DESCRIPTION 
       [0023]    A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures. 
         [0024]    Referring to  FIG. 1 , a stackable multi-barrier system  10  is illustrated. Illustrated is a portion of a lower completion  12 , a packer  14  and a portion of an upper completion  16 . One of ordinary skill in the art will be familiar with the lower completion  12  and the packer  14  and the concept of an upper completion  16  in operable communication therewith. In the illustrated embodiment an electric submersible pump (ESP)  18  is included in the upper completion  16 , which is a device well known to the art. Between the illustrated ESP  18  and the lower completion  12  however, one of ordinary skill in the art will be surprised to see a number of mechanical barriers  20 ,  22  (sometimes referred to herein as “valves”) that is greater than one. As illustrated in the figures hereof there are two but nothing in this disclosure should be construed as limiting the number of mechanical barriers to two. Rather more could also be added, if desired. 
         [0025]    In one embodiment the more downhole valve  20  is a hydraulically actuated valve such as an ORBIT™ valve available commercially from Baker Hughes Incorporated, Houston Tex. and the more uphole valve  22  is a mechanically actuated valve such as a HALO™ valve available from the same source. It will be appreciated that these particular valves are merely exemplary and may be substituted for by other valves without departing from the invention. 
         [0026]    Control lines  24  are provided to the valve  20  for hydraulic operation thereof. In the illustrated embodiment the lines also have a releasable control line device  28  in line therewith to allow for retrieval of the upper completion  16  apart from the lower completion  12 . Also included in this embodiment of the system  10  is a stroker  30  that may be a hydraulic stroker in some iterations. 
         [0027]    The components described function together to manage flow between the lower completion  12  and the upper completion  16 . This is accomplished in that the valve  20  is settable to an open or closed position (and may be variable in some iterations) based upon hydraulic fluid pressure in the control line  24 . The valve  22  is opened or closed based upon mechanical input generated by movement of the upper completion  16 , or in the case of the illustration in  FIG. 1 , based upon mechanical movement caused by the stroker  30  that is itself powered by hydraulic fluid pressure. Of course, the stroker  30  could be electrically driven or otherwise in other embodiments. In any condition, the valve  22  is configured to close upon withdrawal of the upper completion  16 . In normal production, both of the valves  20  and  22  will remain open unless there is a reason to close them. Such a reason occurs, for example, when it is required to retrieve the upper completion  16  for some reason. One such reason is to replace the ESP  18 . Regardless of the reason for closure, employment of the system  10  in a completion string provides more than one mechanical barrier  20 ,  22  at an uphole extent of the lower completion  12 . The barriers when closed prevent fluid flow after the upper completion is retrieved. 
         [0028]    Attention is directed to releasable control line devices  28  and  FIG. 2 . During a withdrawal of the upper completion  16 , the control lines  24  are subjected to a tensile load. The releasable control line devices will release at a threshold tensile load and seal the portion of the control lines  24  that will remain in the downhole environment as a part of the lower completion string  12 . The valve  20 , if not already closed, is configured to close in response to this release of the control lines  24 . This will complete the separation of the upper completion  16  from the lower completion  12  and allow retrieval of the upper completion  16  to the surface. With more than one mechanical barrier  20 ,  22  in place at the uphole extent of the lower completion  12 , there is improved confidence that fluids will not escape from the lower completion  12 . Important to note here briefly is that the system  10  also includes provision  44  for allowing the reopening of the valve  20  using tubing pressure after the upper completion  16  is reinstalled. This will be addressed further hereunder. 
         [0029]    In order to restore production, another system  110  is attached at a downhole end of upper completion  16  and run in the hole. This is illustrated in  FIG. 3 . The original system  10  has components such as packer  14 , valves  20  and  22  and control lines  24  are seen at the bottom of the drawing and a new system  110  stackable on the last is shown. The new system  110  includes a packer  114  valve  120 , valve  122 , lines  124 , stroker  13 , ESP  118  and releasable hydraulic line device  128 . In essence each of the components of system  10  is duplicated in system  110 . Moreover, it should be understood that the process of pulling out and stabbing in with new systems can go on ad infinitum (or at least until practicality dictates otherwise). 
         [0030]    Since the valves  20  and  22  will be in the closed position, having been intentionally closed upon preparing to retrieve the upper completion  16 , they will need to be opened upon installation of the new system  110 . This is accomplished by stabbing a mechanical shiftdown  142  into valve  22  and setting packer  114 . The mechanical shiftdown  142  mechanically shifts the valve  22  to the open position. It should be pointed out that, in this embodiment, the mechanical shiftdown  142  does not seal to the valve  22  and as such the inside of the upper completion  16  is in fluidic communication with annular space  146  defined between the packers  14  and  114 . Applying pressure to the tubing at this point will result in a pressure buildup that will act on the valve  20  through the string uphole thereof since all valves thereabove,  22 ,  120  and  122  are in the open position. Referring to  FIG. 4 , a view of valve  20  illustrates the provision  44  that includes a port  52  in operable communication with an optional shifter  50 . The shifter  50  is configured to open the port  52  in response to retrieval of the upper completion  16 . As illustrated the shifter  50  in this embodiment is a sleeve that is automatically actuated upon retrieval of the upper completion  16 . More specifically, when upper completion  16  begins to move uphole, the provision  44  is shifted to the open position. When the provision  44  is in the open position tubular fluid pressure is in communication with the port  52 . The port  52  includes an openable member  54  such as a burst disk or similar that when opened provides fluid access to an atmospheric chamber  56 . The member  54  opens upon increased tubing pressure and allows fluid to fill the atmospheric chamber  56 . Fluid in the atmospheric chamber causes one or more pistons  58  to urge the valve  20  to the open position. In one embodiment, ratcheting devices (not shown) may be provided in operable communication with the one or more pistons  58  to prevent the pistons from moving in a direction to allow the valve to close by serendipity at some later time. It may also be that the valve  20  itself is configured to be locked permanently open by other means if the atmospheric chamber floods. 
         [0031]    The foregoing apparatus and method for its use allows for the retrieval and replacement of an upper completion without the need for a wet connection. It will be further appreciated in view of the below that certain components, aspects, features, elements, etc. of the above described embodiments can be utilized in other completion systems. For example, as disclosed above, features of the system  10  can be used to enable barrier valves of other systems to “automatically” close when the upper completion is pulled out, i.e., transition to a closed position based upon mechanical movement of the upper completion as taught above. 
         [0032]    Referring now to  FIG. 5 , a completion system  210  is shown installed in a borehole  1 &amp;&amp; (cased, lined, open hole, etc.). The system  210  includes a lower completion  214  including a gravel or frac pack assembly  216  (or multiples thereof for multiple producing zones) that is isolated from an upper completion  218  of the system  210  by a fluid loss or fluid isolation valve  220 . The gravel or frac pack assembly  216  and the valve  220  generally resemble those known and used in the art. That is, the gravel or frac pack assembly  216  enables the fracturing of various zones while controlling sand or other downhole solids, while the valve  220  takes the form of a ball valve that is transitionable between a closed configuration (shown in  FIG. 5 ) and an open configuration (discussed later) due to cycling the pressure experienced by the valve  220  or other mechanical means, e.g., through an intervention with wireline or tubing. Of course, known types of fluid loss valves other than ball valves could be used in place of the valve  220 . Additionally, it is to be appreciated that the lower completion  214  could include components and assemblies other than, or in addition to, the frac pack and/or gravel pack assembly  216 , such as for enabling stimulation, hydraulic fracturing, etc. 
         [0033]    The system  210  also includes a work string  222  that enables an intermediate completion assembly  224  to be run in. Essentially, the assembly  224  is arranged for functionally replacing the valve  220 . That is, while the valve  220  remains physically downhole, the assembly  224  assumes or otherwise takes off at least some functionality of the valve  220 , i.e., the assembly  224  provides isolation of the lower completion  214  and the formation and/or portion of the borehole  212  in which the lower completion  214  is positioned. Specifically, in the illustrated embodiment, the assembly  224  in the illustrated embodiment is a fluid loss and isolation assembly and includes a barrier valve  226  and a production packer or packer device  228 . By packer device, it is generally meant any assembly arranged to seal an annulus, isolation a formation or portion of a borehole, anchor a string attached thereto, etc. The barrier valve  226  is shown in more detail in  FIG. 5A . Initially, as shown in  FIGS. 5 and 5A , a shifting tool  230  holds a sleeve  232  of the barrier valve  226  in an open position by an extension  234  of the shifting tool  230  that extends through the packer  228 . The term “shifting tool” is used broadly and encompasses seal assemblies and devices that allow relative movement or shifting of the sleeve  232  other than the tool  230  as illustrated. When the sleeve  232  is in its open position, a set of ports  236  in the sleeve  232  are axially aligned with a set of ports  238  in a housing or body  240  of the barrier valve  226 , thereby enabling fluid communication through the barrier valve  226 . Of course, movement of the sleeve  232  for enabling fluid communication is not limited to axial, although this direction of movement conveniently corresponds with the direction of movement of the work string  222 . In the illustrated embodiment, a shroud  244  is radially disposed with the barrier valve  226  for further controlling and/or regulating the flow rate, pressure, etc. of fluid, i.e., by redirecting fluid flow from the lower completion  214  out into the chamber formed by the shroud  244 , and back into the barrier valve  226  via the ports  236  and  238  when the valve  226  is open. In the illustrated embodiment, the extension  234  of the shifting tool  230  (and/or the sleeve  232 ) includes a releasable connection  246  for enabling releasable or selective engagement between the tool  230  and the sleeve  232 . For example, the connection  246  could be formed by a collet, spring-loaded or biased fingers or dogs, etc. 
         [0034]    A method of assembling and using the completion  210  according to one embodiment is generally described with respect to  FIGS. 5-13 . As illustrated in  FIG. 5 , the work string  222  with the assembly  224  is initially run in for connection to the lower completion  214 , thereby providing a fluid pathway to surface and enabling production. For example, while circulating fluids in the borehole  212 , the assembly  224  can be properly positioned by lowering the work string  222  until circulation stops. After noting the location and slacking off on the work string, the assembly  224  is landed at the lower completion  214 , as shown in  FIG. 6 . Once landed at the lower completion  214 , the production packer  228  is set, e.g., via hydraulic pressure in the work string  222 , thereby isolating and anchoring the assembly  224 . At this point, the barrier valve  226  is open and an equalizing port  248  between the interior of the work string  222  and an annulus  250  is closed by the extension  234  of the shifting tool  230 . 
         [0035]    As illustrated in  FIG. 7 , the work string  222  can then be pulled out in order to axially misalign the ports  236  and  238 , which closes the barrier valve  226 . That is, as shown in more detail in  FIG. 7A , communication through the port  238  and into the barrier valve  226  is prevented by a pair of seal elements  252  sealed against the sleeve  232 . As also shown in more detail in  FIG. 7A , pulling out the work string  222  slightly also opens the equalizing port  248 , enabling the packer  228  to be tested on the annulus  250  and/or down the work string  222 . 
         [0036]    As depicted in  FIG. 8 , by again slacking off on the work string  222 , the barrier valve  226  re-opens (e.g., taking the configuration shown in  FIG. 5A ) and pressure can be cycled in the work string  222  for opening the fluid loss valve  220 . Next, as shown in  FIG. 9 , the work string  222  is pulled out of the borehole  212 . Pulling out the work string  222  first shifts the sleeve  232  into its closed position (e.g., as shown in  FIG. 7A ) for the barrier valve  226 . Then due to the packer  228  anchoring the assembly  214 , continuing to pull out the work string  222  disconnects the tool  230  from the sleeve  232  at the releasable connection  246 . 
         [0037]    In order to start production, a production string  254  is run and engaged with the assembly  224  as shown in  FIGS. 10 and 11 . The production string  254  includes a shifting tool  256  similar to the tool  230 , i.e., arranged with a releasable connection to selectively open and close the barrier valve  226  by manipulating the sleeve  232 . In this way, the production string  254  is first landed at the assembly  224  and the tool  230  extended through the packer  228  for shifting the sleeve  232  to open the barrier valve  226 . Once the barrier valve  226  is opened, a tubing hanger supporting the production string  254  is landed and fluid from the downhole zones, i.e., proximate to the frac or gravel pack assembly  216 , can be produced. In the illustrated embodiment the production string  254  takes the form of an artificial lift system, particularly an ESP system for a deepwater well, which are generally known in the art. However, it is to be appreciated that the current invention as disclosed herein could be used in non-deepwater wells, without artificial lift systems, with other types of artificial lift systems, etc. 
         [0038]    Workovers are a necessary part of the lifecycle of many wells. ESP systems, for example, are typically replaced about every 8-10 years, or some other amount of time. Other systems, strings, or components in the upper completion  218  may need to be similarly removed or replaced periodically, e.g., in the event of a fault, damage, corrosion, etc. In order to perform the workover, reverse circulation may be performed by closing a circulation valve  258  and shifting open a hydraulic sliding sleeve  260  of the production string  254 . Advantageously, if the production string  254  or other portions in the upper completion  218  (i.e., up-hole of the assembly  224 ) needs to be removed, removal of that portion will “automatically” revert the barrier valve  226  to its closed position, thereby preventing fluid loss. That is, the same act of pulling out the upper completion string, e.g., the production string  254 , the work string  222 , etc., will also shift the sleeve  232  into its closed position and isolate the fluids in the lower completion. This eliminates the need for expensive and additional wireline intervention, hydraulic pressure cycling, running and/or manipulating a designated shifting tool, etc. The packer  228  also remains in place to maintain isolation. This avoids the need for expensive and time consuming processes, such as wireline intervention, which may otherwise be necessary to close a fluid loss valve, e.g., the valve  220 . 
         [0039]    A replacement string, e.g., a new production string resembling the string  254 , can be run back down into the same intermediate completion assembly, e.g., the assembly  224 . Alternatively, if a long period of time has elapsed, e.g., 8-10 years as indicated above with respect to ESP systems, it may instead be desirable to run in a new intermediate completion assembly, as equipment wears out over time, particularly in the relatively harsh downhole environment. For example, as shown in  FIGS. 12 and 13  an additional or subsequent intermediate completion assembly  224 ′ is run in on a work string  222 ′ for engagement with the original assembly  224 . As noted above with respect to the valve  220 , the subsequent assembly  224 ′ essentially functionally replaces the original assembly  224 . That is, the subsequent assembly  224 ′ substantially resembles the original assembly  224 , including a barrier valve  226 ′ for preventing fluid loss, a production packer  228 ′ for reestablishing isolation, and a sleeve  232 ′ that is manipulated by a shifting tool  230 ′ on the work string  222 ′. It should be appreciated that the aforementioned components associated with the assembly  224 ′ include prime symbols, but otherwise utilize the same base reference numerals as corresponding components described above with respect to the assembly  224 , and the above descriptions generally apply to the corresponding components having prime symbols and of the assembly  224 ′ (even if unlabeled), unless otherwise noted. 
         [0040]    Unlike the assembly  224 , the assembly  224 ′ has a shifting tool  262  for shifting the sleeve  232  of the original assembly  224  in order to open the barrier valve  226 , which was closed by the shifting tool  256  when the production string  254  was pulled out. As long as the assembly  224 ′ remains engaged with the assembly  224 , the tool  262  will mechanically hold the barrier valve  226  in its open position. In this way, the assembly  224 ′ can be stacked on the assembly  224  and the barrier valve  226 ′ will essentially take over the fluid loss functionality of the barrier valve  226  of the assembly  224  by holding the barrier valve  226  open with the tool  262 . It is to be appreciated that any number of these subsequent assemblies  224 ′ could continue to be stacked on each other as needed. For example, a new one of the assemblies  224 ′ could be stacked onto a previous assembly between the acts of pulling out an old upper completion or production string and running in a new one. In this way, the newly run upper completion or production string will interact with the uppermost of the assemblies  224 ′ (as previously described with respect to the assembly  224  and the production string  254 ), while all the other intermediate assemblies are held open by the shifting tools of the subsequent assemblies (as previously described with respect to the assembly  224  and the shifting tool  262 ). 
         [0041]    The shifting tool  230 ′ also differs from the shifting tool  230  to which it corresponds. Specifically, the shifting tool  230 ′ includes a seat  264  for receiving a ball or plug  266  that is dropped and/or pumped downhole. By blocking flow through the seat  264  with the plug  266 , fluid pressure can be built up in the work string  222 ′ suitable for setting and anchoring the production packer  228 ′. That is, pressure was able to be established for setting the original packer  228  because the fluid loss valve  220  was closed, but with respect to  FIGS. 12 and 13  the valve  220  has since been opened and fluid communication established with the lower completion  214  as described previously. 
         [0042]    After setting the packer  228 ′, the string  222 ′ can be pulled out, thereby automatically closing the sleeve  232 ′ of the barrier valve  226 ′ as previously described with respect to the assembly  224  and the work string  222  (e.g., by use of a releasable connection). As previously noted, the original barrier valve  226  remains opened by the shifting tool  262  of the subsequent assembly  224 ′. As the assembly  224 ′ has essentially taken over the functionality of the original assembly  224  (i.e., by holding the barrier valve  226  constantly open with the tool  262 ), a new production string, e.g., resembling the production string  254 , can be run in essentially exactly as previously described with respect to the production string  254  and the assembly  224 , but instead engaged with the assembly  224 ′. That is, instead of manipulating the barrier valve  226 , the shifting tool (e.g., resembling the tool  256 ) of the new production string (e.g., resembling the string  254 ) will shift the sleeve  232 ′ of the barrier valve  226 ′ open for enabling production of the fluids from the downhole zones or reservoir. 
         [0043]    It is again to be appreciated that any number of the assemblies  224 ′ can continue to be run in and stacked atop one another. For example, this stacking of the assemblies  224 ′ can occur between the acts of pulling out an old production string and running a new production string, with the pulling out of each production string “automatically” closing the uppermost one of the assemblies  224 ′ and isolating the fluid in the lower completion  214 . In this way, any number of production strings, e.g., ESP systems, can be replaced over time without the need for expensive and time consuming wireline intervention, hydraulic pressure cycling, running and/or manipulation of a designated shifting tool, etc. Additionally, the stackable nature of the assemblies  224 ,  224 ′, etc., enables the isolation and fluid loss hardware to be refreshed or renewed over time in order to minimize the likelihood of a part failure due to wear, corrosion, aging, etc. 
         [0044]    It is noted that the fluid loss valve  220  can be substituted, for example, by the assembly  224  being run in on a work string resembling the work string  222 ′ as opposed to the work string  222 . For example, as shown in  FIG. 12 , a modified system  210   a  includes the assembly  224  being run in on the work string  222 ′. In this way, fluid pressure suitable for setting the original packer  228  can be established by use of the ball seat  264  and the plug  266  instead of the valve  220 . Accordingly, as illustrated in  FIG. 14 , the fluid loss valve  220  is rendered unnecessary or redundant by use of the system  210   a , as the plug  266  and the seat  264  of the work string  222 ′ enable suitable pressurization for setting the packer  228 , and the tool  230 ′ of the work string  222 ′ enables control of the barrier valve  226  such that the assembly  224  can completely isolate the lower completion  214 . After isolating the lower completion  214 , a production string, e.g., the string  254 , subsequent intermediate assemblies, etc., can be run in and interact with the assembly  224  as described above. 
         [0045]    As another example, a modified system  210   b  is illustrated in  FIG. 15 . The system  210   b  is similar to the system  210   a  in that a separate fluid isolation valve for the lower completion  214 , e.g., the valve  220 , is not necessary and instead the system  210   b  can be run in for initially isolating the lower completion  214 . Unlike the system  210   a , the system  210   b  is capable of being run-in immediately on the production string  254  without the need for the work string  222 ′ of the system  210   a . Specifically, the system  210   b  is run-in with a plug  266 ′ already located in a shifting tool  256 ′ of the production string  254 . The tool  256 ′ resembles the tool  256  with the exception of being arranged to hold the plug  266 ′ therein for blocking fluid flow therethrough. By running the plug  266 ′ in with the system  210   b , the plug  266 ′ does not need to be dropped and/or pumped from surface, as this would be impossible for various configurations of the production string  254 , e.g., if the string  254  includes ESPs or other components or assemblies that would obstruct the pathway of a dropped plug down through the string. The plug  266 ′ is arranged to be degradable, consumable, disintegrable, corrodible, dissolvable, chemically reactable, or otherwise removable so that once it has been used for providing the hydraulic pressure necessary to set the packer  228 , the plug  266 ′ can be removed and enable production through the string  254 . In one embodiment the plug  266 ′ is made from a dissolvable or reactive material, such as magnesium or aluminum that can be removed in response to a fluid deliverable or available downhole, e.g., acid, brine, etc. In another embodiment, the plug  266 ′ is made from a controlled electrolytic material, such as made commercially available by Baker Hughes, Inc. under the tradename IN-TALLIC®. Once the plug  266 ′ is removed, the system  210   b  would function as described above with respect to the system  210 . 
         [0046]    It is thus noted that the current invention as illustrated in  FIGS. 5-13  is suitable as a retrofit for systems that are in need of a workover, i.e., need to have the upper completion replaced or removed, but already includes a valve resembling the fluid loss valve  220  (e.g., a ball valve or some other type of valve used in the art that requires wireline intervention, hydraulic pressure cycling, the running and/or manipulation of designated shifting tools, etc., in order to transition between open and closed configurations). Alternatively stated, the system  210  enables downhole isolation of a lower completion for performing a workover, i.e., removal or replacement of an upper completion, without the need for time consuming wireline or other intervention. 
         [0047]    In view of the foregoing it is to be appreciated that new completions can be installed with a valve, e.g., the fluid loss valve  220 , that requires some separate intervention and/or operation to close the valve during workovers, or, alternatively, according to the systems  210   a  or  210   b , which not only initially isolate a lower completion, e.g., the lower completion  214 , but additionally include a barrier valve, e.g., the barrier valve  226 , that automatically closes upon pulling out the upper completion, as described above. 
         [0048]    While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited. Moreover, the use of the terms first, second, etc. do not denote any order or importance, but rather the terms first, second, etc. are used to distinguish one element from another. Furthermore, the use of the terms a, an, etc. do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced item.

Summary:
A completion system, including a barrier valve transitionable between an open position and a closed position. An upper completion is operatively coupled with the barrier valve for mechanically transitioning the barrier valve to the closed position when the upper completion is withdrawn. A method of operating a completion system is also included.