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You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND 
       [0001]    Operators perform completion operations during the life of a well to access hydrocarbon reservoirs at various elevations. Completion operations may include pressure testing the tubing, setting a packer, activating safety valves, or manipulating sliding sleeves. In certain operations, it may be desirable to isolate one portion of the completion from another. Typically, an isolation valve having an internal ball valve is disposed in the completion to isolate portions of the well. One example of such an isolation valve is the completion isolation valve (CIV) from Weatherford. 
         [0002]      FIG. 1A  shows a completion isolation valve  10  in an opened condition with the ball valve  20  allowing flow through the valve&#39;s bore  12 . When running a tool string through the open valve  10 , operators insert a profiled stinger  30  on the end of the tool string into the valve  10  as shown in  FIG. 1B . The stinger  30  engages dogs  16  in the valve  10 . Downward movement of the stinger  30  engaged by the dogs  16  then moves a shifting mechanism  14  to lock the internal ball valve  20  open. Once the valve  10  is opened, a tool string can be passed through the valve  10  to work on the lower completion. To remove the tool string, operators lift the profiled stinger  30  at the end of the string back into the valve  10 . As shown in  FIG. 1C , the stinger  30  raised in the upward direction closes the internal ball valve  20  by engaging the dogs  16  as the stinger  30  passes up through the valve  10 . 
         [0003]    Although effective in isolating portions of a completion, valves using internal ball valves have several drawbacks. For example, ball valves require a large wall thickness to house it. The increased wall thickness required by a ball mechanism makes it have either a smaller ID or a larger OD than the flapper designs. To overcome such drawbacks, isolation valves have been developed that use flappers to isolate portions of a completion. One example of such a valve having dual flappers is the Optibarrier available from Weatherford and disclosed in U.S. patent application Ser. No. 11/761,229, entitled “Dual Flapper Barrier Valve,” which is incorporated herein by reference in its entirety. 
         [0004]    In many valves used downhole, operators use shifting sleeve profiles to mechanically actuate the valve open and closed. Unfortunately, operators deploying a tool downhole to mechanically actuate the valve may inadvertently miss engaging the profile during run in. In such a circumstance, the tool string may slip through and run into the closed valve, damaging the closure device and rendering the valve inoperable. To avoid this, operators must pay careful attention while running a tool in the hole so as not to damage any downhole valves. 
         [0005]    The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above. 
       SUMMARY 
       [0006]    A downhole valve has one or more flappers for closing off the valve, and a no-go actuation mechanism protects the one or more flappers from damage. When the one or more flappers of the valve are closed, the no-go mechanism prevents a tool from passing into the valve and causing damage to the one or more flappers. Yet, the passable no-go mechanism is used to open the valve&#39;s one or more flappers when the tool string is forced into the valve. When the valve has been successfully opened, then the no-go mechanism is moved out of the way of the tool string so the tool string can pass through the valve. Operators use a shifting profile in the valve only in the upward direction to mechanically return the valve to the closed position. 
         [0007]    In one implementation, the protected valve has a bore with a closure disposed therein. The closure can include one flapper, or the closure can include dual flappers (i.e., upper and lower flappers) disposed in the bore. For the dual flapper arrangement, the flappers are rotatable in opposing directions between opened and closed positions in the bore. 
         [0008]    When the valve deploys downhole, a tool may be deployed into the valve either intentionally or unintentionally. For example, the tool may be a stinger on the end of a tool string intended to reach a portion of the wellbore below the valve. Alternatively, the deployed tool can be any arbitrary tool inadvertently deployed by operators into the closed valve. In either case, the tool engages against at least one dog extendable into the valve&#39;s bore as the tool moves downhole into the valve while closed. The tool engaged against the dog shifts a sleeve while the tool moves downhole. The closure is automatically actuated with the sleeve from the closed condition to the opened condition before the tool moves downhole to the closure. For the closure having dual flappers, for example, the flappers rotate open before the tool moves downhole to the flappers, and the lower flapper preferably rotates open before the upper flapper. 
         [0009]    For hydraulic actuated downhole valves, hydraulic pressure may be used or exhausted, depending on the design, to allow the one or more flappers to go closed. Once the flapper has closure, the no-go mechanism is once again realized. For the mechanically operated downhole valves, however, operators use a shifting profile in the valve only in the upward direction to mechanically return the valve to the closed position. If the tool is a stinger intentionally deployed into the valve, for example, then the stinger can be used to close the valve as the stinger is pulled uphole through the valve. In particular, a shoulder on the stinger engages against a profile in the sleeve as the stinger moves uphole through the open valve. The sleeve with the stinger engaged against the profile shifts uphole and automatically closes the closure. For example, the flappers rotate closed with the shifting of the sleeve with the upper flapper preferably closing before the lower flapper. 
         [0010]    The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIGS. 1A-1C  show a completion isolation valve having an internal ball valve actuated by a stinger according to the prior art. 
           [0012]      FIG. 2  is a cross-sectional view of a downhole valve according to the present disclosure in a run-in condition with first and second flappers open. 
           [0013]      FIG. 3  shows the downhole valve of  FIG. 2  in an initial closing stage. 
           [0014]      FIG. 4  shows the downhole valve of  FIG. 2  in a closed condition. 
           [0015]      FIGS. 5A-5C  show details of the downhole valve of  FIG. 2  when a tool is passed therethrough while the valve is in the closed condition. 
       
    
    
     DETAILED DESCRIPTION 
       [0016]    A downhole valve  100  in  FIG. 2  forms part of a completion assembly (not shown) with the tool&#39;s upper sub  102  connected to an upper completion and the tool&#39;s lower sub  108  connected to a lower completion. In use, the valve  100  isolates the upper and lower completions from one another using a closure device, shown here as including a first (upper) flapper  150  and a second (lower) flapper  160 . The upper flapper  150  controls pressure from below the valve  100  when closed and opens downwards into the tool&#39;s bore  104 , while the lower flapper  160  control pressure from above the valve  100  when closed and opens upwards into the tool&#39;s bore  104 . 
         [0017]    The flappers  150 / 160  are shown in open positions in  FIGS. 2 and 3  and are shown in closed positions in  FIG. 4 . The actual opening and closing of the flappers  150 / 160  uses a predetermined sequence that considers the impact that debris in the well may have on the valves&#39; operation. Upper and lower flow tubes  140 / 180 , an actuating sleeve  110 , and a shift and lock mechanism  130  open and close the flappers  150 / 160  according to the predetermined sequence. A similar procedure for opening and closing the flappers  150 / 160  is described in detail in incorporated application Ser. No. 11/761,229. 
         [0018]    In operation, the upper flapper  150  is closed first to protect the lower flapper  160  from debris that may be dropped in the wellbore from above to the valve  100 . To close the upper flapper  150 , operators deploy a stinger or shifting tool  200  as shown in  FIG. 3  into the valve  100 . The stinger  200  has a plurality of fingers  202  that mate with actuating sleeve  110 &#39;s profile  112  so the sleeve  110  can be pulled toward the upper sub  102 . In moving upward, flexible ribs  117  on the actuating sleeve  110  push past a surrounding lower rim  107  defined in the tool&#39;s bore  102 . As the sleeve  110  then moves further upward, the shift and lock mechanism  130  unlocks the flappers  150 / 160  and moves the upper flow tube  140  away from the lower flow tube  180 . Once the upper flow tube  140  passes the upper flapper  150 , the newly freed upper flapper  150  rotates by a spring (not shown) around a pivot point and seals against a valve seat  155  to isolate pressure below the flapper  150  as shown in  FIG. 4 . 
         [0019]    As the shifting tool  200  urges the sleeve  110  further toward the upper sub  102 , a latch  152  can be activated to secure the upper flapper  150  in the closed position but may allow the upper flapper  150  to crack open if necessary. After the upper flapper  150  is closed, upward movement of the shifting tool  200  continues to urge the actuating sleeve  110  toward the upper sub  102 . The upper flapper  150  and its seat  155  connect by a cage  170  to the lower flapper  160  and its seat  165 . With the continued urging of the sleeve  110 , the lower flapper  160  and seat  165  also move upward. At the same time, the lower flapper  160  moves away from its flow tube  180 , thereby allowing a spring (not shown) to pivot the flapper  160  against its seat  165  to seal pressure from above. 
         [0020]    Thereafter, the actuating sleeve  110  being urged closer to the upper sub  102  causes the flappers  150 / 160  to lock in place by actuating the shift and lock mechanism  130 . As shown in  FIG. 4 , the shift and lock mechanism  130  has a series of intermediate sleeves  132 / 134 , dogs  136 , and slots for locking in position as the actuating sleeve  110  shifts the mechanism  130 . As shown, the actuating sleeve  110  interacts via dogs and slots with an inner intermediate sleeve  134  that couples to the upper flow tube  140 . This inner intermediated sleeve  134  is biased by a spring  120  and interacts via dogs and slots with an outer intermediate sleeve  132  that couples to the upper flapper&#39;s seat  155 . In this way, shifting and locking of the mechanism  130  using the actuating sleeve  110  moves the flow tube  140  relative to the upper seat  155  and moves the cage  170  relative to the lower flow tube  180  so that the upper and lower flappers  150 / 160  can be opened and closed. 
         [0021]    Once the flappers  150 / 160  are closed as shown in  FIG. 4 , it is desirable to protect them from damage by downhole tools being inadvertently or intentionally passed through the valve  100  while in the closed condition. For this reason, the valve  100  has a passable no-go mechanism to protect the flappers  150 / 160  once closed. As shown in  FIG. 5A , an arbitrary downhole tool  210  that is inadvertently or intentionally passed into the valve  100  will engage a series of dogs  115  disposed in the upper sleeve  110  before reaching the closed flappers  150 / 160 . With the valve  100  closed as shown in  FIG. 5A , these dogs  115  have moved away from corresponding recesses  105  defined in the surrounding housing  102 . Thus, the dogs  115  extend into the valve&#39;s bore  104  and can engage the downhole tool  210  passing through the closed valve  100  from above. 
         [0022]    When the tool  210  engages the dogs  115 , the tool  210  may be initially prevented from passing further into the closed valve  100 , thereby preventing inadvertent damage to the closed flappers  150 / 160 . In particular, downward movement of the tool  210  against the extended dogs  115  must push the ribs  117  on the sleeve  110  past an upper rim  109  near the dog&#39;s slots  105 . This initial catch of the ribs  117  on the rim  109  may indicate to operators that the valve  100  is closed and that passage of the tool  210  could be harmful. 
         [0023]    In any event, continued force of the downhole tool  210  against the dogs  115  may eventually move the ribs  117  past rim  109 . In this instance, the engaged dogs  115  for the tool  210  to move the sleeve  110 , manipulate the shift and lock mechanism ( 130 ;  FIG. 2 ), and open the flappers  150 / 160  before the tool  210  can reach the closed flappers  150 / 160  and cause damage. This form of opening may occur, for example, when operators inadvertently force the arbitrary downhole tool  210  through the closed valve  100  without realizing the valve  100  is closed. Alternatively, operators may intentionally be opening the valve  100  to reach the lower completion below the valve  100 , in which case the tool  200  may actually be a stinger or the like that is purposefully used to open the valve  100 . 
         [0024]    Regardless of why the tool  210  is passed through the closed valve  100 , the lower flapper  150  opens first in the opening sequence. Initially, the downhole tool  210  pushes the upper sleeve  110  downward in the tool  100  by engaging the dogs  115  and forces the ribs  117  on the sleeve  110  past the upper rim  109  as discussed above. As a result, the shift and lock mechanism  130  unlocks the flappers  150 / 160 . Next as shown in  FIG. 5A , pressure on both sides of the lower flapper  160  equalizes when ports  167  on the lower seat  165  align with slots  182  formed in the flow tube  180  as the sleeve  110  moves downward. (See also  FIG. 4 ). Thereafter, further movement of the sleeve  110  downward causes the lower flapper  160  to meet its flow tube  180 , and further movement downward subsequently causes the lower flapper  160  to open and fit in the annulus between the flow tube  180  and the surrounding housing  106 . 
         [0025]    After the lower flapper  160  opens, the upper flow tube  140  moves toward the upper flapper  150  as the shift and lock mechanism  130  is manipulated by the downward moving tool  210 . Before the flow tube  140  contacts the upper flapper  150 , pressure on both sides of the flapper  150  may be equalized. Thereafter, the flow tube  140  meets the upper flapper  150  and pivots it to the open position. Subsequently, the flappers  150 / 160  are locked in place by further manipulation of the shift and lock mechanism  130 . 
         [0026]    Once opened as shown in  FIG. 5B , the downhole tool  210  can pass through the valve  100  while the flappers  150 / 160  remain open. In this way, the flappers  150 / 160  can be opened to prevent damage when operators either intentionally or accidentally pass the tool  210  into the valve  100 . Advantageously, the valve  100  has an internal bore  104  that is larger than available with a ball valve, because the disclosed valve  100  uses the dual flappers  150 / 160 . 
         [0027]    Closing the flappers  150 / 160  uses the procedure outlined previously. As shown in  FIG. 5C , for example, fingers  222  on a stinger or other tool  220  can engage the upper sleeve&#39;s profile  112  so that the sleeve  110  can be pulled upward in the valve  100  to initiate the closing procedure for the valve  100  outlined previously for the mechanically operated downhole valve  100 . For a hydraulic actuated downhole valve, hydraulic pressure may be used or exhausted, depending on the design, to allow the flappers  150 / 160  to go closed. Once the flappers  150 / 160  have closed, the no-go mechanism is once again realized. 
         [0028]    Although the actuating sleeve  110 , profile  112 , dogs  115 , slot  105 , etc. of the present disclosure have been discussed in connection with the valve  100  having dual flappers  150 / 160 , it will be appreciated with the benefit of the present disclosure that these features can be used for a valve having a single flapper. In addition, the teachings of the present disclosure can be used in a fail-safe type of safety valve (as represented by the disclosed valve  100 ) and can be used in a hydraulic type of safety valve. 
         [0029]    For example, a suitable example of a fail-safe type of safety valve having a single flapper that can use the disclosed features is the SSSV (Subsurface Safety Valve) available from Weatherford—the Assignee of the present disclosure. The SSSV has a single flapper and uses a hydraulic opening piston and a spring closure mechanism. As another example, a suitable example of a hydraulic type of safety valve having a single flapper that can use the disclosed features is the DDV™ (Downhole Deployment Valve) available from Weatherford—the Assignee of the present disclosure. The DDV has a single flapper and uses a hydraulic opening piston and a hydraulic closing piston. In either case, the protected opening of the flapper can use the same components and procedures outlined above with reference to the dual flapper valve, although without the added complexity of having to open the second flapper. 
         [0030]    The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Summary:
A downhole valve has a closure device (e.g., one or more flappers) for closing off the valve. A no-go actuation mechanism protects the flappers from damage. When the flappers are closed, the mechanism prevents a tool from passing into the valve and causing damage to the flappers. Yet, the mechanism may open the valve&#39;s flappers when the tool string is forced into the valve. When the valve has successfully opened, then the mechanism moves out of the way of the toolstring so it can pass through the valve. For the mechanically operated valves, operators use a shifting profile in the valve only in the upward direction to return the valve to the closed position. For hydraulic actuated valves, hydraulic pressure may be used or exhausted, depending on the design, to allow the flappers to go closed. Once the flappers have closed, the no-go mechanism is once again realized.