Patent Publication Number: US-11035200-B2

Title: Downhole formation protection valve

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to U.S. Provisional Patent Application having Ser. No. 62/473,920, which was filed Mar. 20, 2017. This priority application is hereby incorporated by reference in its entirety into the present application to the extent consistent with the present application. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     This section introduces information from the art that may be related to or provide context for some aspects of the technique described herein and/or claimed below. This information is background facilitating a better understanding of that which is disclosed herein. This is a discussion of “related” art. That such art is related in no way implies that it is also “prior” art. The related art may or may not be prior art. The discussion is to be read in this light, and not as admissions of prior art. 
     Hydrocarbons such as petroleum (i.e., “oil”) and natural gas (i.e., “gas”) are routinely extracted from wells in a producing geological formation (i.e., “formation”). New fields that have not been producing long may possess a sufficiently high formation pressure that the hydrocarbons can easily reach the earth&#39;s surface unassisted through the wellbore. However, many fields have been producing long enough (i.e., are “mature”) such that formation pressures are insufficient for this to happen in enough quantity to make the well economical. The art has therefor developed a number of techniques for assisting the hydrocarbons to the surface. 
     One of these techniques is the use of an electronic submersible pump, or “ESP”. The hydrocarbons will enter the wellbore and form what is called a “fluid column”. The wellbore typically has also previously been fractured, or “fracked”, to facilitate the hydrocarbons flow out of the formation. The ESP is attached to the end of a production string and run into the hole. It is positioned below the surface of the fluid column and above the fractures, if any, whereupon it pumps the hydrocarbons to the surface. 
     The ESP eventually has to be run out of the wellbore. The hydrocarbons frequently contain contaminants, such as sediment, that damage the ESP over time. Sometimes the ESP is old such that it has a short lifetime expectancy when run into the wellbore and it has to be replaces or repaired. Sometimes there are issues with the wellbore itself. And sometimes there is some other need for a workover of the well that means the ESP has to be run out. Whatever the reason, the ESP is run out at some point. 
     The hydrocarbons need to be retained within the wellbore while the ESP is run out of the wellbore. Some wells include pressure control equipment at the surface for this purpose. More, commonly, prior to running out the ESP, the operator pumps “kill fluid” into the wellbore. The kill fluid forms another column within the wellbore above the fluid column of hydrocarbons. The hydrostatic pressure exerted column of kill fluid is greater than the pressure exerted by the hydrocarbons. The kill fluid thus keeps the hydrocarbons from rising in the well without the need for surface pressure control equipment. 
     This kill process can sometimes nevertheless yield some negative consequences. For example, it is possible to damage the formation if the kill fluid exerts too much pressure. One particular negative consequence is that sometimes the kill fluid may overcome the hydrocarbons and enter the formation. This contaminates the reservoir and has other negative consequences. 
     The presently disclosed technique is directed to resolving, or at least reducing, one or all of the problems mentioned above. Even if solutions are available to the art to address these issues, the art is always receptive to improvements or alternative means, methods and configurations. Thus, there exists and need for technique such as that disclosed herein. 
     SUMMARY 
     In a first aspect, a bidirectional formation protection valve, comprises: a tubular body having an inner diameter defining a fluid flow path therethrough and being adapted to be sealably disposed within a wellbore; an uphole valve disposed within the inner diameter of the tubular body to control fluid flow therethrough, the uphole valve being biased to close the fluid flow path against a first pressure and adapted to be opened upon receiving a stinger in the inner diameter, and a downhole valve disposed within the inner diameter of the tubular body to control fluid flow therethrough, the downhole valve being biased to close the fluid flow path against a second pressure and adapted to be opened upon receiving a stinger in the inner diameter. The first and second pressures are an uphole pressure from kill fluids and a downhole pressure from formation fluids. In some embodiments, the first pressure is the uphole pressure and the second pressure is the downhole pressure. In other embodiments, the first pressure is the downhole pressure and the second pressure is the uphole pressure. 
     In a second aspect, a bidirectional formation protection valve comprises a tubular body having an inner diameter defining a fluid flow path therethrough and being adapted to be sealably disposed within a wellbore. An uphole valve is disposed within the inner diameter of the tubular body to control fluid flow therethrough. The uphole valve is biased to close the fluid flow path against uphole pressure and adapted to be opened upon receiving a stinger in the inner diameter. A downhole valve is also disposed within the inner diameter of the tubular body. The downhole valve controls fluid flow therethrough and is biased to close the fluid flow path against downhole pressure. It is furthermore adapted to be opened upon receiving a stinger in the inner diameter. 
     In a third aspect, a method for use in producing hydrocarbons from a well comprises: receiving a stinger disposed below an electronic submersible pump into a closed bidirectional formation protection valve emplaced in a wellbore in a manner isolating wellbore fluids from formation fluids. An uphole valve disposed within the inner diameter of the tubular body to control fluid flow therethrough is opened through engagement with the stinger as the stinger is received. A downhole valve disposed within the inner diameter of the tubular body downhole of the uphole valve to control fluid flow therethrough is also opened through engagement with the stinger as the stinger is received. The engagement of the stinger with the uphole end of the bidirectional formation protection valve is scaled. The opened downhole valve is closed as the stinger is retrieved and the opened uphole valve is closed as the stinger is retrieved. 
     In a fourth aspect, a method for use in producing hydrocarbons from a well, comprise emplacing a closed bidirectional formation protection valve in a wellbore in a manner isolating wellbore fluids from formation fluids outside the bidirectional formation protection valve. A stinger is disposed below an electronic submersible pump in a string. The string is run into the wellbore to position the pump in the wellbore and to stab the stinger into the bidirectional formation protection valve and open the bidirectional formation protection valve to fluid flow from the formation. The string is nm out of the wellbore to close the bidirectional formation protection valve to block fluid flow from the formation while isolating the formation fluid from the wellbore fluids. 
     The above paragraphs in this section present a simplified summary of the presently disclosed subject matter in order to provide a basic understanding of some aspects thereof. The summary is not an exhaustive overview, nor is it intended to identify key or critical elements to delineate the scope of the subject matter claimed below. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description set forth below. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The invention may be understood by reference to the following description taken in conjunction with the accompanying drawings, in which like reference numerals identify like elements, and in which: 
         FIG. 1  depicts one particular embodiment of a downhole formation protection valve as deployed in an exemplary wellbore during production. 
         FIG. 2  is a hook up drawing depicting in partially sectioned, plan views selected portions of a running string including the formation protection valve for emplacing the formation protection valve in the formation. 
         FIG. 3A - FIG. 3C  conceptually illustrate the emplacement of the formation protection valve. 
         FIG. 4  is a hook up drawing depicting in partially sectioned views of elected portions of the production string of  FIG. 1  in conjunction with the formation protection valve as part of an assembly for producing hydrocarbons. 
         FIG. 5A - FIG. 5C  conceptually illustrate running in and out the production string while the formation protection valve is emplaced. 
         FIG. 6  depicts the formation protection valve in greater detail in a partially sectioned, plan view. 
         FIG. 7A - FIG. 7D  depict the formation protection valve of  FIG. 6  in greater detail as it is opened by the down stroke of the stingers while running in the production string. 
         FIG. 8A - FIG. 8B  illustrate the top bleeder valve. 
         FIG. 9A - FIG. 9C  illustrate the bottom bleeder valve. 
     
    
    
     While the invention is susceptible to various modifications and alternative forms, the drawings illustrate specific embodiments herein described in detail by way of example. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION 
     Illustrative embodiments of the subject matter claimed below will now be disclosed. In the interest of clarity, not all features of an actual implementation are described in this specification. It will be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort, even if complex and time-consuming, would be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. 
       FIG. 1  depicts one particular embodiment of a downhole formation protection valve (“FPV”)  100  as deployed in an exemplary well  105  during production. The well  105  is only partially shown. More particularly, the FPV  100  is disposed in a wellbore  110  below the fluid level  115  of the fluid column  120  and above the perforations  125  in the formation  130 . The fluid column  120  comprises at least hydrocarbons such as oil and gas. 
     The perforations  125  are optional although it is anticipated that most wells  105  will have been fracked to create such perforations  125 . Where present, they may be created by an earlier fracking operation that perforated not only the formation  130 , but also the well casing  135 . Again, it is anticipated that most wells  105  will be cased wells rather than open holes. Fracking is well known to the art and any suitable fracking technique known to the art may be used to create the perforations  140  in the casing  135  and perforations  125  in the formation  130 . Similarly, the casing of wells  125  is well known in the art and any suitable casing technique may be used to place the casing  135  in the well  105 . 
     The perforations  125 ,  140  are created at a depth in the wellbore  110  coincident with the reservoir  145  in the formation  130  as is well known in the art. The perforations  125 ,  140  facilitate the movement of hydrocarbons from the reservoir  145  into the wellbore  110  to form the fluid column  120 . Thus, the depth at which the perforations are  125 ,  140  are created will be implementation specific. Some embodiments may include more than one set of perforations  125 ,  140  at the same or different depths. The fluid level  115  is a function of a number of parameters well known to the art that are unique to the wellbore  110 , the formation  130 , the reservoir  145 , and the hydrocarbons. The depth at which the fluid level  115  resides will therefor also be implementation specific. 
     The FPV  100  is fluidly sealed within the wellbore  110  a sealing mechanism  150 . The sealing mechanism  150  in the illustrated embodiment is a hydraulic packer as is well known in the art. However, other types of packers, and even other types of scaling mechanisms may be used in alternative embodiments. Thus, the sealing mechanism  150 ) is, by way of example and illustrate, but one means for sealing the annulus  160  between FPV  100  and the casing  135  to fluid flow. 
     Note that the fluid level  115  is above the FPV  100  in  FIG. 1 . That is because the fluid column  120  exists within the wellbore  110  prior to the installation of the FPV  100 . Thus, when the sealing mechanism  150  is actuated to seal fluid flow through the annulus  160 , there is still fluid above the sealing mechanism  150  and, hence, the FPV  100 . The FPV  100  is therefore emplaced below the fluid level  115  but above the perforations  125 ,  140  in  FIG. 1 . 
       FIG. 1  also includes a production string  165  already run into the wellbore  110 . For the most part, the composition and constitution of the production string  165  will be driven by the individual needs of the operator in light of the individual characteristics of the well  105  in a manner well known to the art. However, of pertinence to the presently disclosed technique, and in a sharp departure from the known art, the production string  165  terminates in an ESP  170  beneath which a stinger  175  is disposed. The ESP  170  is positioned below the fluid level  115  in the illustrate embodiment and, again, above the perforations  125 ,  140 . Thus, the ESP  170  is submerged in the fluid column  120  in conventional fashion. The production string  165  also includes a check valve  180 . 
     As will be further described below, the stinger  175  engages the FPV  100  as it is run into the wellbore  110 . This engagement results in the stinger  175  opening the FPV  100  to establish a fluid flow path between that portion of the wellbore  110  below the sealing mechanism  150  and the surface (not shown). More particularly, the ESP  170  pumps the hydrocarbons below the sealing mechanism  150  through the stinger  175  and up through the production string  165  to the surface. During this operation, because the annulus  160  is scaled by the sealing mechanism  150 , no hydrocarbons rise through the wellbore  110  other than through the stinger  175  and drill string  165 . 
     Also as will be described further below, when the production string  165 , including the ESP  170  and stinger  175 , is run out of the wellbore  170 , the stinger  175  disengages from the FPV  100  on its way out. This disengagement closes the FPV  100 . At this point, fluid flow through the annulus  160  is sealed by the sealing mechanism  150  fluid flow through the FPV  100  is closed by the FPV  100  itself. 
     Thus, hydrocarbons in the reservoir  145 —i.e., formation fluids—are prevented from flowing up the wellbore  110  past the FPV  100 . At the same time, kill fluids (not shown) previously pumped into the wellbore  110  to kill the well  105  cannot flow downward past the FPV  100  into the formation  130 . This is also prevented by the seal from the sealing mechanism  150  and the FPV  100 . Thus, the kill fluids and the formation fluids are isolated from one another when the ESP is run out of the wellbore  110 . 
     Thus, in one aspect of the technique disclosed herein, method for use in producing hydrocarbons from a well comprises emplacing a closed bidirectional FPV  100  in a wellbore in a manner isolating wellbore fluids, such as kill fluids, from formation fluids outside bidirectional FPV  100 . A stinger  175  is disposed below an ESP  170  in a string  165 . The string  165  is run into the wellbore  110  to position the ESP  170  in the wellbore  110  and to stab the stinger  175  into the bidirectional FPV  100  and open the bidirectional FPV  100  to fluid flow from the formation  130 . Eventually, the string  165  is run out of the wellbore  110  to close the bidirectional FPV  100  to block fluid flow from the formation  130  while isolating the formation fluid from the wellbore fluids. 
     Turning now to  FIG. 2 , selected portions of a running string  200  (not otherwise shown) for emplacing the FPV  100  in the formation  130 , both first seen in  FIG. 1 , is shown. The running string  200  comprises a sub  210  by which a running stinger  175 ′ is disposed. The running string  200  further comprises a running sub  215 , the FPV  100 , and a packer  220  terminated by a pump out sub  225 . 
     The running sub  215  is, in the illustrated embodiment, an on/off tool. However, many suitable alternative embodiments are known to the art. For example, in one alternative embodiment not shown the running sub  215  comprises an anchor latch sub and a polished bore receptacle (“PBR”). The anchor latch sub includes a production type collet mechanism and a debris barrier. The debris barrier prevents debris from settling into and possibly fowling the FPV  100  when the well is shut in. The PBR provides a sealing bore for the stinger seals  230  on the tongue  232  of the stinger  175  to prevent annular debris. It also accommodates later tubing movement of the production string during heat up and operation. In general, though, the running sub  215  may be any suitable tool known to the art with a running profile. 
     The packer  220  of the illustrated embodiment is a conventional, hydraulically set packer. As is usual for such packers, it includes a plurality of rubber sealing elements  235  that can be expanded by the pump out sub  225  when in place to seal the annulus  160  around the packer  220  from fluid flow. However, any suitable packer or sealing tool known to the art may be used. Some embodiments may not even choose to utilize and separate packing tool and instead incorporate this annulus sealing capability into the FPV  100 . 
     The FPV  100  is a bidirectional formation protection valve. It comprises a tubular body  240  having an inner diameter  242  defining a fluid flow path  244  therethrough and being adapted to be sealably disposed within a wellbore—e.g., the wellbore  110 . In the illustrated embodiment, the FPV  100  is adapted to be sealably disposed in two ways that work in conjunction as described below. First, the tubular body  240  is so adapted by threading the downhole end  246  of the inner diameter  242  to receive the packer  220  and, in operation, actually engaging the packer assembly  220 . Second, the tubular body  240  is also so adapted by being designed to sealably seat and threadably engage the production stinger  175 . 
     The FPV  100  further comprises an uphole valve  250  disposed within the inner diameter  242  of the tubular body  240  to control fluid flow therethrough. The uphole valve  250  is biased to close the fluid flow path  244  against a first pressure and adapted to be opened upon receiving the stinger  175  in the inner diameter  242 . The FPV  100  also includes a downhole valve  260  disposed within the inner diameter  242  of the tubular body  240  to control fluid flow therethrough. The downhole valve  260  is biased to close the fluid flow path  244  against a second pressure and adapted to be opened upon receiving the stinger  175  in the inner diameter  240 . 
     The first and second pressures are an uphole pressure from kill fluids (not yet shown) and a downhole pressure from formation fluids in the fluid column  120 , shown in  FIG. 1 . In the illustrated embodiment, the first pressure is the uphole pressure and the second pressure is the downhole pressure. However, alternative embodiments may differ. For example, in some embodiments, the first pressure may be the downhole pressure while the second pressure may be the uphole pressure. 
     Still referring to  FIG. 2 , the running sub  215  and packer  220  also define respective fluid flow paths  270 ,  272  that align with the fluid flow path  244  of the FPV  100  when assembled as described above. The running sub  215  and packer  220  are also emplaced with the FPV  100  as alluded to above and will be discussed above. Thus, the running sub  215  and packer  220  can be considered a part of the tubular body  240  when assembled and, hence, a part of the FPV  100  for purposes of emplacement and production. 
       FIG. 3A - FIG. 3C  conceptually illustrate the emplacement of the FPV  100 . The running string  200  is assembled at the surface. This includes the subassembly  200  and the assembly  205 . Each of the running stringer  210 , the running sub  215 , the FPV  100 , and the packer  220 —all shown in  FIG. 2 —are threaded together. These threaded connections form fluid tight seals. This assembly will depend to some degree on implementation of the various components. These variations will be readily appreciated by those ordinarily skilled in the art having the benefit of this disclosure. 
     Once assembled, the running string  200  is run into the wellbore  110  as shown in  FIG. 3A  until it is positioned as desired. Once positioned, the packer  220  is set and the rubber sealing elemental  235  extended to seal the annulus  160  as shown in  FIG. 3B . What constitutes a desirable position will be implementation specific depending on a number of factors such as the height of the fluid column  120 , the placement of the perforations  125 ,  140 , the intended composition of the production string, and the composition and length of the assembly  200  being emplaced. One driving consideration is that the ESP  170  should be below the fluid level  115 . The FPV  100  should also be located above the perforations  125 ,  140 . 
     Once the FPV  100  is emplaced, the running stinger  175 ′ is disengaged from the running sub  215  and run out of the wellbore  110  as shown in  FIG. 3C . The way in which the disengagement is performed will depend on the implementation of the running sub  215  in a manner known to the art. 
       FIG. 4  depicts selected portions of the production string  165 , first seen in  FIG. 1 , in partially sectioned views in conjunction with the FPV  100 . Note that, when the production string  165  is run into the wellbore  110  the running sub  215 . FPV  100 , and packer  220  are already emplaced as shown in  FIG. 3C . Furthermore, the packer  220  is already set, also as shown in  FIG. 3C . 
     The production stinger  175  includes, in this particular embodiment, the check valve  185 . The check valve  185  is run below and attached to the ESP  170 , which is not shown in  FIG. 4 . When the ESP  170  stops during production, the check valve  185  will close. This prevents any fluid and/or debris in the wellbore  110  for settling back into the formation  130  when the production stinger  175  is in place and the FPV  100  is open. The check valve  185  is a one-way flow device. When the ESP  170  is operating, the check valve  185  and the FPV  100  are open and flowing. When the ESP  170  is shut down, the FPV  100  remains open but the check valve  185  closes. 
     The production stinger  175  has several functions during production. The production stinger  175  has a plurality of seals  400  on the tongue  405  thereof. These seals  400  prevent fluid and/or debris in the wellbore  110  for settling back into the formation though the annulus between the tongue  405  and the inner diameter  242  of the FPV  100 . In the illustrated embodiment, the seals are elastomeric O-rings such as are known to the art. However, alternative embodiments may use alternative sealing mechanisms. Thus, the elastomeric O-rings are, by way of example and illustration, but one means for sealing the annulus. 
     The seals  400  are located on the tongue  405  so that when the production stinger  175  is seated on the running sub  215  as shown in  FIG. 5B  they are located within the inner diameter  242  of the FPV  100  but above the uphole valve  250 . This positioning helps protect the seals  400  from wear that would otherwise be incurred traveling through one or more of the uphole valve  250  and the downhole valve  260  as the production stinger  175  is stroked into the FPV  100 . Thus, it increases the life expectancy of the seals  400  and extends the periods between retrievals for their replacement. 
     However, such positioning is not required. Some embodiments may position the seals  400  on the tongue  405  so that they are stroked past both the uphole valve  250  and the downhole valve  260  while remaining within the inner diameter  242  of the FPV  100 . This would have the salutary effect of preventing debris from entering the FPV  100  from below. However, this is offset by the reduced lifetime expectancy of the seals  400  due to the increased wear traveling through the uphole valve  250  and the downhole valve  260 . 
     The production stinger  175  also wipes though the debris barrier in the running sub  215 . The production stinger  175  also functions as the mechanical device that opens the FPV  100  as described below. Note that the production stinger  175  does not engage the running sub  215 . The production stinger  175  furthermore provides the flow conduit for production, keeping debris out of the inner working of the FPV  100 . 
       FIG. 5A - FIG. 5C  conceptually illustrate running in and out the production string  165  while the FPV  100  is emplaced. Turning now to  FIG. 5A , which illustrates running in the production string  165 , the well is killed at this point and the wellbore is filled with kill fluids  500 . Recall that the FPV  100  is emplaced and closed and that the sealing mechanism  150  is in place. In this particular embodiment, that means the packer  220  is set and the rubber sealing elements  235  are extended and secured against the inner diameter of the casing  135 . Thus, the formation fluids  505  in the fluid column  120  are isolated from the kill fluids  510  by the scaling mechanism  150  and the closure of the FPV  100 . 
     The production string  165  is run into the well bore  110  until the production stinger  175  seats on the running sub  215  as shown in  FIG. 5B . The manner in which the seating occurs will be implementation specific. In the illustrated embodiment, the production stinger  165  threadably engages the running sub  215  by virtue of the mating threads  425 ,  430 , both shown in  FIG. 4 . Also as shown in  FIG. 4 , the inner diameter  435  of the running sub  215  is contoured to conform to the outer diameter  440  of the production stinger  175 . The engagement is created by rotating the production stinger  175  from the surface as it is stroked downward until the production stinger  175  is fully seated. 
     The down stroke of the tongue  405  of the production stinger  175  as the production stinger  175  is seated on the running sub  215  opens the FPV  100 . More particularly, as it proceeds downward, the tongue  405  opens the uphole valve  250  and then the downhole valve  260 . When the FPV  100  is open and the production stinger  175  is sealably seated on the running sub  215 , a sealed fluid flow path is then opened to the surface for the formation fluids  505  to rise and be delivered. Note that the kill fluids  510  in the wellbore  110 , if any, are still isolated from the formation fluids  505  by operation of the sealing elements  235 . Production then proceeds in accord with conventional practice as shown in  FIG. 5B . 
     There will eventually be a need to trip the ESP  170  or some other portion of the production string  165  out of the wellbore  110 . This may be for replacement or repair of the ESP  170 , or for some other part of the production string  165 , or even retrieval of the FPV  100 . The reason is not material for present purposes. 
     At this point, the production string  165  is installed as shown in  FIG. 5B . The well is killed such that kill fluids  510  are introduced into the wellbore  110  if not already present. The production stinger  175  is then disengaged from the running sub  215 . This will typically be the inverse of the engagement and, so, will also be implementation specific. In the illustrated embodiment, the running sub  215  is an on/off tool with a threaded engagement, and so the disengagement comprises rotating the production string  165  from the surface to break the threaded connection. In alternative embodiments using, for example, an anchor latch sub, disengagement may be by shearing the latches in accordance with conventional practice. 
     Note that, as discussed above, the kill fluids  515  and the formation fluids  505  are isolated from one another in  FIG. 5B . This isolation is maintained as the production string  165  is disengaged from the running sub  215  by the seals  400  on the tongue  405  on the interior diameter of the FPV  100  and the running sub  215 . As the production stinger  175  strokes upward and out of the FPV  100 , the downhole valve  260  closes to seal off the formation fluids from entering the FPV  100 . As the production stinger  175  continues stroking upward, the uphole valve  250  closes to prevent the kill fluids  515  from entering the FPV  100 . 
     Thus, the FPV seals in both directions—i.e., it is bidirectional—as the production string  165  is retrieved. By the time the seal effected by the seals  400  breaks, one or both of the uphole valve  250  and the downhole valve  260  are closed in order to maintain the isolation between the kill fluids  515  and the formation fluids  505 . The entire production string  165  is then retrieved while leaving the FPV  100  emplaced as is shown in  FIG. 5C . 
     The interaction of the production stinger  175  and the FPV  100  in opening and closing the uphole valve  250  and downhole valve  260  shall now be discussed in greater detail.  FIG. 6  depicts the FPV  100  in greater detail in a partially sectioned, plan view.  FIG. 7A - FIG. 7D  are details of  FIG. 6  as indicated therein.  FIG. 7A - FIG. 7D  depict the FPV  100  of  FIG. 6  in greater detail as it is opened by the down stroke of the stingers while running in the production string. 
     As shown in  FIG. 6 , prior to engagement with the stinger  175 , the uphole valve  250  and the downhole valve  260  are both closed. The uphole valve  250  is biased closed by the operation of the spring  600 . As the tongue  405  of the production stinger  175  engages the trip dogs  700 , shown in  FIG. 7A , a bleeder valve  800 , shown in  FIG. 8A - FIG. 8B , opens to equalize pressure across the upper closure member  705  of the uphole valve  250 . Referring now to  FIG. 8A - FIG. 8B , the bleeder valve  800  opens with a running arm  805  activated when the stinger  175  enters the bore (ID) of the FPV body, sliding the spring loaded dogs  700  down the ID, creating force to pivot first the bleeder arm  805  to compress the pin  810  and bleed off pressure, then the flapper lid  705 . 
     Returning to  FIG. 7A , as the production stinger  175  continues to stroke downward and engage the trip dogs  700 , the weight of the production string  165  settles on them. This compresses the spring  600 , and forces the trip dogs  700  downward while opening the upper closure member  705  as shown in  FIG. 7B . As the trip dogs  700  journey downward they reach a profile  710 , whereupon they are forced outward by the weight of the production string  165  through the production stinger  175 . Once the trip dogs  700  are in the outward position, the production stinger  175  strokes downward and through the upper closure member  705 . 
     Turning now to  FIG. 7C , as the production stinger  175  continues its stroke downward, a bleeder valve  900 , shown in  FIG. 9A - FIG. 9C , opens to equalize pressure across the lower closure member  715  of the downhole valve  260 . The bleeder valve  900  comprises a flat spring  905  and a pin  910 , the flat spring  905  as first shown in  FIG. 9B . As the production stringer  175  strokes downward, it compresses the spring  905  to force the pin  910  downwardly as shown in  FIG. 9C  to equalize the pressure on both sides of the lower closure member  715 . The production stinger  175  then continues to stroke downward until it engages the closure member  715  of the downhole valve  260 . The weight of the production string  165  causes the closure member  715  to open and permit the production stinger  175  to further its downward stroke. 
     As the production stinger  175  strokes through the downhole valve  260 , the FPV  100  is open and in position for production of the formation fluids  505 , shown in  FIG. 5C , as shown in  FIG. 71 ). Note that, because the running sub  225  remains installed with the emplaced FPV  100 , retrieval of the running sub  225 . FPV  100 , and the packer  220  can be readily performed. Retrieval is essentially that same as emplacement, described above, except that it is performed in reverse. 
     Thus, in accordance with one aspect of the presently disclosed technique, a method for use in producing hydrocarbons from a well comprises receiving a stinger  175  disposed below an ESP  170  into a closed bidirectional FPV  100  emplaced in a wellbore  110  in a manner isolating wellbore fluids  500  from formation fluids  505 . An uphole valve  250  disposed within the inner diameter  242  of the tubular body  240  is opened to control fluid flow therethrough through engagement with the stinger  175  as the stinger  175  is received. A downhole valve  260  is also disposed within the inner diameter  242  of the tubular body  240  downhole of the uphole valve  250  and is opened to control fluid flow therethrough through engagement with the stinger  175  as the stinger  175  is received. The engagement of the stinger  175  with the uphole end of the bidirectional FPV  100  is sealed. Subsequently, the opened downhole valve  260  is closed as the stinger  175  is retrieved followed by the opened uphole valve  250  closing as the stinger  175  is retrieved. 
     Some of the terms used herein are relative terms. For example, the terms “uphole” and “downhole” are relative to the surface and the bottom of the wellbore. All such relative terms are to be construed in the context of the structures and operations described herein relative the orientation of the bidirectional formation protection valve in its orientation in the wellbore in its intended use. 
     This concludes the detailed description. The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below.