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BACKGROUND 
       [0001]    Current practice for completing downhole structures, particularly deepwater wells, involves stimulating, hydraulic fracturing, frac packing and/or gravel packing one or more zones and then landing a fluid isolation valve, typically a ball valve system, above the treated zones. The fluid isolation valve temporarily blocks fluid flow so that an upper completion string can be run and connect the treated zones to surface for enabling production after the fluid isolation valve is opened. Although such systems do generally work for their intended purposes, they are not without limitations. For example, these known ball-type fluid isolation valves do not provide an efficient and reliable system for periodically replacing portions of the upper completion, and may require wireline intervention, hydraulic pressuring, or the running and/or manipulation of a designated tool to control the fluid isolation valve. For example, artificial lift systems (e.g., electric submersible pumping systems or ESPs), are increasingly desirable, particularly for use in deepwater wells. Accordingly, advances in downhole valve technology, at times referred to as “mechanical barriers”, particularly for deepwater wells and/or for enabling more reliable and efficient replacement of upper completion systems and components, are always well received by the industry. 
       SUMMARY 
       [0002]    A completion system, including a lower completion initially fluidly open; a production string having a removable plug configured to impede fluid flow through the production string, the removable plug being run in with the production string; and an intermediate completion assembly coupling the lower completion to the production string, the intermediate completion assembly having a packer device and a barrier valve, the packer device operatively arranged to be set by pressurizing fluid in the production string against the removable plug, the barrier valve operatively arranged for selectively impeding fluid flow between the production string and the lower completion after the removable plug is removed. 
         [0003]    A method of completing a borehole including running a production string having a removable plug disposed therewith downhole, an intermediate completion assembly disposed with the production string; coupling the production string to a lower completion with the intermediate completion assembly, the lower completion initially fluidly open; impeding fluid flow between the production string and the lower completion with the removable plug; setting a packer device by pressurizing fluid in the production string against the removable plug; removing the removable plug; and impeding fluid flow between the production string and the lower completion with a barrier valve of the intermediate completion assembly. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0004]    The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike: 
           [0005]      FIG. 1  is a partial cross-sectional view of a completion system in which an intermediate assembly is being engaged with a lower completion; 
           [0006]      FIG. 1A  is an enlarged view of the area circled in  FIG. 1 ; 
           [0007]      FIG. 2  is a partial cross-sectional view of the completion system of  FIG. 1  in which the intermediate assembly is engaged with the lower completion; 
           [0008]      FIG. 3  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; 
           [0009]      FIG. 3A  is an enlarged view of the area circled in  FIG. 3 ; 
           [0010]      FIG. 4  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; 
           [0011]      FIG. 5  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; 
           [0012]      FIG. 6  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; 
           [0013]      FIG. 7  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; 
           [0014]      FIG. 8  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; 
           [0015]      FIG. 9  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; 
           [0016]      FIG. 10  is a partial cross-sectional view of a completion system according to another embodiment disclosed herein; and 
           [0017]      FIG. 11  is a partially cross-sectional view of a completion system according to another embodiment disclosed herein. 
       
    
    
     DETAILED DESCRIPTION 
       [0018]    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. 
         [0019]    Referring now to  FIG. 1 , a completion system  10  is shown installed in a borehole  12  (cased, lined, open hole, etc.). The system  10  includes a lower completion  14  including a gravel or frac pack assembly  16  (or multiples thereof for multiple producing zones) that is isolated from an upper completion  18  of the system  10  by a fluid loss or fluid isolation valve  20 . The gravel or frac pack assembly  16  and the valve  20  generally resemble those known and used in the art. That is, the gravel or frac pack assembly  16  enables the fracturing of various zones while controlling sand or other downhole solids, while the valve  20  takes the form of a ball valve that is transitionable between a closed configuration (shown in  FIG. 1 ) and an open configuration (discussed later) due to cycling the pressure experienced by the valve  20  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  20 . Additionally, it is to be appreciated that the lower completion  14  could include components and assemblies other than, or in addition to, the frac pack and/or gravel pack assembly  16 , such as for enabling stimulation, hydraulic fracturing, etc. 
         [0020]    The system  10  also includes a work string  22  that enables an intermediate completion assembly  24  to be run in. Essentially, the assembly  24  is arranged for functionally replacing the valve  20 . That is, while the valve  20  remains physically downhole, the assembly  24  assumes or otherwise takes off at least some functionality of the valve  20 , i.e., the assembly  24  provides isolation of the lower completion  14  and the formation and/or portion of the borehole  12  in which the lower completion  14  is positioned. Specifically, in the illustrated embodiment, the assembly  24  in the illustrated embodiment is a fluid loss and isolation assembly and includes a barrier valve  26  and a production packer or packer device  28 . 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  26  is shown in more detail in  FIG. 1A . Initially, as shown in  FIGS. 1 and 1A , a shifting tool  30  holds a sleeve  32  of the barrier valve  26  in an open position by an extension  34  of the shifting tool  30  that extends through the packer  28 . The term “shifting tool” is used broadly and encompasses seal assemblies and devices that allow relative movement or shifting of the sleeve  32  other than the tool  30  as illustrated. When the sleeve  32  is in its open position, a set of ports  36  in the sleeve  32  are axially aligned with a set of ports  38  in a housing or body  40  of the barrier valve  26 , thereby enabling fluid communication through the barrier valve  26 . Of course, movement of the sleeve  32  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  22 . In the illustrated embodiment, a shroud  44  is radially disposed with the barrier valve  26  for further controlling and/or regulating the flow rate, pressure, etc. of fluid, i.e., by redirecting fluid flow from the lower completion  14  out into the chamber formed by the shroud  44 , and back into the barrier valve  26  via the ports  36  and  38  when the valve  26  is open. In the illustrated embodiment, the extension  34  of the shifting tool  30  (and/or the sleeve  32 ) includes a releasable connection  46  for enabling releasable or selective engagement between the tool  30  and the sleeve  32 . For example, the connection  46  could be formed by a collet, spring-loaded or biased fingers or dogs, etc. 
         [0021]    A method of assembling and using the completion  10  according to one embodiment is generally described with respect to  FIGS. 1-9 . As illustrated in  FIG. 1 , the work string  22  with the assembly  24  is initially run in for connection to the lower completion  14 , thereby providing a fluid pathway to surface and enabling production. For example, while circulating fluids in the borehole  12 , the assembly  24  can be properly positioned by lowering the work string  22  until circulation stops. After noting the location and slacking off on the work string, the assembly  24  is landed at the lower completion  14 , as shown in  FIG. 2 . Once landed at the lower completion  14 , the production packer  28  is set, e.g., via hydraulic pressure in the work string  22 , thereby isolating and anchoring the assembly  24 . At this point, the barrier valve  26  is open and an equalizing port  48  between the interior of the work string  22  and an annulus  50  is closed by the extension  34  of the shifting tool  30 . 
         [0022]    As illustrated in  FIG. 3 , the work string  22  can then be pulled out in order to axially misalign the ports  36  and  38 , which closes the barrier valve  26 . That is, as shown in more detail in  FIG. 3A , communication through the port  38  and into the barrier valve  26  is prevented by a pair of seal elements  52  sealed against the sleeve  32 . As also shown in more detail in  FIG. 3A , pulling out the work string  22  slightly also opens the equalizing port  48 , enabling the packer  28  to be tested on the annulus  50  and/or down the work string  22 . 
         [0023]    As depicted in  FIG. 4 , by again slacking off on the work string  22 , the barrier valve  26  re-opens (e.g., taking the configuration shown in  FIG. 1A ) and pressure can be cycled in the work string  22  for opening the fluid loss valve  20 . Next, as shown in  FIG. 5 , the work string  22  is pulled out of the borehole  12 . Pulling out the work string  22  first shifts the sleeve  32  into its closed position (e.g., as shown in  FIG. 3A ) for the barrier valve  26 . Then due to the packer  28  anchoring the assembly  14 , continuing to pull out the work string  22  disconnects the tool  30  from the sleeve  32  at the releasable connection  46 . 
         [0024]    In order to start production, a production string  54  is run and engaged with the assembly  24  as shown in  FIGS. 6 and 7 . The production string  54  includes a shifting tool  56  similar to the tool  30 , i.e., arranged with a releasable connection to selectively open and close the barrier valve  26  by manipulating the sleeve  32 . In this way, the production string  54  is first landed at the assembly  24  and the tool  30  extended through the packer  28  for shifting the sleeve  32  to open the barrier valve  26 . Once the barrier valve  26  is opened, a tubing hanger supporting the production string  54  is landed and fluid from the downhole zones, i.e., proximate to the frac or gravel pack assembly  16 , can be produced. In the illustrated embodiment the production string  54  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. 
         [0025]    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  18  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  58  and shifting open a hydraulic sliding sleeve  60  of the production string  54 . Advantageously, if the production string  54  or other portions in the upper completion  18  (i.e., up-hole of the assembly  24 ) needs to be removed, removal of that portion will “automatically” revert the barrier valve  26  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  54 , the work string  22 , etc., will also shift the sleeve  32  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  28  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  20 . 
         [0026]    A replacement string, e.g., a new production string resembling the string  54 , can be run back down into the same intermediate completion assembly, e.g., the assembly  24 . 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. 8 and 9  an additional or subsequent intermediate completion assembly  24 ′ is run in on a work string  22 ′ for engagement with the original assembly  24 . As noted above with respect to the valve  20 , the subsequent assembly  24 ′ essentially functionally replaces the original assembly  24 . That is, the subsequent assembly  24 ′ substantially resembles the original assembly  24 , including a barrier valve  26 ′ for preventing fluid loss, a production packer  28 ′ for reestablishing isolation, and a sleeve  32 ′ that is manipulated by a shifting tool  30 ′ on the work string  22 ′. It should be appreciated that the aforementioned components associated with the assembly  24 ′ include prime symbols, but otherwise utilize the same base reference numerals as corresponding components described above with respect to the assembly  24 , and the above descriptions generally apply to the corresponding components having prime symbols and of the assembly  24 ′ (even if unlabeled), unless otherwise noted. 
         [0027]    Unlike the assembly  24 , the assembly  24 ′ has a shifting tool  62  for shifting the sleeve  32  of the original assembly  24  in order to open the barrier valve  26 , which was closed by the shifting tool  56  when the production string  54  was pulled out. As long as the assembly  24 ′ remains engaged with the assembly  24 , the tool  62  will mechanically hold the barrier valve  26  in its open position. In this way, the assembly  24 ′ can be stacked on the assembly  24  and the barrier valve  26 ′ will essentially take over the fluid loss functionality of the barrier valve  26  of the assembly  24  by holding the barrier valve  26  open with the tool  62 . It is to be appreciated that any number of these subsequent assemblies  24 ′ could continue to be stacked on each other as needed. For example, a new one of the assemblies  24 ′ 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  24 ′ (as previously described with respect to the assembly  24  and the production string  54 ), 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  24  and the shifting tool  62 ). 
         [0028]    The shifting tool  30 ′ also differs from the shifting tool  30  to which it corresponds. Specifically, the shifting tool  30 ′ includes a seat  64  for receiving a ball or plug  66  that is dropped and/or pumped downhole. By blocking flow through the seat  64  with the plug  66 , fluid pressure can be built up in the work string  22 ′ suitable for setting and anchoring the production packer  28 ′. That is, pressure was able to be established for setting the original packer  28  because the fluid loss valve  20  was closed, but with respect to  FIGS. 8 and 9  the valve  20  has since been opened and fluid communication established with the lower completion  14  as described previously. 
         [0029]    After setting the packer  28 ′, the string  22 ′ can be pulled out, thereby automatically closing the sleeve  32 ′ of the barrier valve  26 ′ as previously described with respect to the assembly  24  and the work string  22  (e.g., by use of a releasable connection). As previously noted, the original barrier valve  26  remains opened by the shifting tool  62  of the subsequent assembly  24 ′. As the assembly  24 ′ has essentially taken over the functionality of the original assembly  24  (i.e., by holding the barrier valve  26  constantly open with the tool  62 ), a new production string, e.g., resembling the production string  54 , can be run in essentially exactly as previously described with respect to the production string  54  and the assembly  24 , but instead engaged with the assembly  24 ′. That is, instead of manipulating the barrier valve  26 , the shifting tool (e.g., resembling the tool  56 ) of the new production string (e.g., resembling the string  54 ) will shift the sleeve  32 ′ of the barrier valve  26 ′ open for enabling production of the fluids from the downhole zones or reservoir. 
         [0030]    It is again to be appreciated that any number of the assemblies  24 ′ can continue to be run in and stacked atop one another. For example, this stacking of the assemblies  24 ′ 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  24 ′ and isolating the fluid in the lower completion  14 . 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  24 ,  24 ′, 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. 
         [0031]    It is noted that the fluid loss valve  20  can be substituted, for example, by the assembly  24  being run in on a work string resembling the work string  22 ′ as opposed to the work string  22 . For example, as shown in  FIG. 10 , a modified system  10   a  includes the assembly  24  being run in on the work string  22 ′. In this way, fluid pressure suitable for setting the original packer  28  can be established by use of the ball seat  64  and the plug  66  instead of the valve  20 . Accordingly, as illustrated in  FIG. 10 , the fluid loss valve  20  is rendered unnecessary or redundant by use of the system  10   a,  as the plug  66  and the seat  64  of the work string  22 ′ enable suitable pressurization for setting the packer  28 , and the tool  30 ′ of the work string  22 ′ enables control of the barrier valve  26  such that the assembly  24  can completely isolate the lower completion  14 . After isolating the lower completion  14 , a production string, e.g., the string  54 , subsequent intermediate assemblies, etc., can be run in and interact with the assembly  24  as described above. 
         [0032]    As another example, a modified system  10   b  is illustrated in  FIG. 11 . The system  10   b  is similar to the system  10   a  in that a separate fluid isolation valve for the lower completion  14 , e.g., the valve  20 , is not necessary and instead the system  10   b  can be run in for initially isolating the lower completion  14 . Unlike the system  10   a,  the system  10   b  is capable of being run-in immediately on the production string  54  without the need for the work string  22 ′ of the system  10   a.  Specifically, the system  10   b  is run-in with a plug  66 ′ already located in a shifting tool  56 ′ of the production string  54 . The tool  56 ′ resembles the tool  56  with the exception of being arranged to hold the plug  66 ′ therein for blocking fluid flow therethrough. By running the plug  66 ′ in with the system  10   b,  the plug  66 ′ does not need to be dropped and/or pumped from surface, as this would be impossible for various configurations of the production string  54 , e.g., if the string  54  includes ESPs or other components or assemblies that would obstruct the pathway of a dropped plug down through the string. The plug  66 ′ 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  28 , the plug  66 ′ can be removed and enable production through the string  54 . In one embodiment the plug  66 ′ 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  66 ′ is made from a controlled electrolytic material, such as made commercially available by Baker Hughes, Inc. under the tradename IN-TALLIC®. Once the plug  66 ′ is removed, the system  10   b  would function as described above with respect to the system  10 . 
         [0033]    It is thus noted that the current invention as illustrated in  FIGS. 1-9  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  20  (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  10  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. 
         [0034]    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  20 , that requires some separate intervention and/or operation to close the valve during workovers, or, alternatively, according to the systems  10   a  or  10   b,  which not only initially isolate a lower completion, e.g., the lower completion  14 , but additionally include a barrier valve, e.g., the barrier valve  26 , that automatically closes upon pulling out the upper completion, as described above. 
         [0035]    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 lower completion initially fluidly open. A production string is included having a removable plug configured to impede fluid flow through the production string. The removable plug is run in with the production string. An intermediate completion assembly is included that couples the lower completion to the production string. The intermediate completion assembly has a packer device and a barrier valve. The packer device is operatively arranged to be set by pressurizing fluid in the production string against the removable plug. The barrier valve is operatively arranged for selectively impeding fluid flow between the production string and the lower completion after the removable plug is removed. A method of completing a borehole is also included.