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TECHNICAL FIELD 
     The invention relates generally to a tool for use in production of in-situ fluid from a hydrocarbon producing formation and, more particularly, to a system and associated method for controlling the flow of in-situ fluid in a production well, including the setting and extraction of an electrical submersible pump (“ESP”) run on a line. 
     BACKGROUND OF THE INVENTION 
     The present invention relates to an apparatus installed downhole in a well bore for improving well control while servicing or replacing submersible pumps or other well flow control equipment. The use of submersible pumps and other equipment designed to improve well flow is commonly used to increasing the rate of production of wells that otherwise produce very slowly. However, pumps and other similar equipment suffer from a limited lifespan in relation to other well components, with pumps generally having a life about one-quarter that of other well components. 
     Such limited life components require frequent repair and/or replacement, and therefore such components must be withdrawn from the well at the end of their useful service life. Such removal requires that a well be opened; without means to close off the well or kill the well, the removal resulting in loss of well fluid into the surrounding environment, which is an undesirable occurrence. To prevent such spillage, various efforts have been made including the installation of valves or ball chokes beneath the pump. These efforts have been plagued by a variety of problems, including suffering from damage upon being pulled and run back into the hole, from low confidence in positioning, or an inability to function due to buildup in the well. A need therefore exists for a more reliable system of well control which is easily operated, resistant to damage, and not subject to time-consuming periods of waiting due to low confidence in downhole position. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cross-sectional view of a flow nipple illustrated in accordance with a preferred embodiment of the present invention; 
         FIG. 2  is a top end view of the flow nipple of  FIG. 1 ; 
         FIG. 3  is a side view of a lock body in accordance with a preferred embodiment of the present invention; 
         FIG. 4  is a cross-sectional view of the lock body of  FIG. 3 ; 
         FIG. 5  is a top view of the lock body of  FIG. 3 ; 
         FIG. 6  is a side view of the lock body of  FIG. 3  rotated 90 degrees about the longitudinal axis; 
         FIG. 7  is a cross-sectional view of the lock body illustrated in  FIG. 6 ; 
         FIG. 8  is a top view of a latching finger of the present invention; 
         FIG. 9  is a cross-sectional side view of the latching finger of  FIG. 8 ; 
         FIG. 10  is a bottom view of the latching finger of  FIG. 8 ; 
         FIG. 11  is a cross-sectional side view of a fully assembled seal stem of the present invention; 
         FIG. 12  is a side view of a tubular sub-assembly of the present invention; 
         FIG. 13  is a cross-sectional side view of the tubular sub-assembly of  FIG. 12  rotated 90 degrees about its longitudinal axis; 
         FIG. 14  is a cross-sectional view of the sub-assembly of  FIG. 12  as taken along line A; 
         FIG. 15  is a cross-sectional side view of a seal stem inserted into the tubular sub-assembly of  FIG. 12 ; 
         FIG. 16  depicts a side view and a cross-sectional side view of a releasing probe for the present invention; 
         FIG. 17  is a side view of a lock body in accordance with another preferred embodiment of the present invention; 
         FIG. 18  is a cross-sectional view of the lock body of  FIG. 17 ; 
         FIG. 19  is a side view of the lock body of  FIG. 17  rotated 90 degrees about the longitudinal axis; and 
         FIG. 20  is a cross-sectional view of the lock body illustrated in  FIG. 19 . 
     
    
    
     SUMMARY OF THE INVENTION 
     The present invention provides a well control apparatus for circulating various fluids in a downhole environment, such as kill mud and production fluids in an electric submersible pump, more commonly known in the field as an ESP. In a preferred embodiment, the present well control apparatus may comprise a tubular seal stem that can be inserted into a tubular sub-assembly. The combination of the devices allows for the circulation of fluids in a controlled manner, and may be set above a downhole ESP such that the ESP is secured off of the present well control apparatus, typically with the well control apparatus one joint above the ESP along a tubing string. During use, the well control apparatus allows for the pumping of fluids by the downhole ESP through a plurality of ports located on side walls of the tubular sub-assembly. These ports may be sealed by the insertion of the seal stem into the sub-assembly, with the seal stem secured in place by a series of latching fingers located in recesses along the sides of the seal stem. The latching fingers may be disengaged for retrieval of the seal stem, or may be sheared off in the event the latching fingers become stuck for one reason or another. 
     DETAILED DESCRIPTION 
     Referring to  FIGS. 1-18 , a downhole well control tool is provided which comprises a number of discrete elements. In  FIG. 1 , therein is shown a cross-sectional view of a metallic flow nipple  100  which comprises a tubular structure with a plurality of exterior lateral channels  120 . The plurality of lateral channels circumscribe the exterior surface of the flow nipple  100 , which one of ordinary skill in the art will understand may be used for locating sealing gaskets or o-rings. Alternatively, the lateral channels  120  provide a more rigid and stable gripping surface for retrieval of the flow nipple  100  via a retrieval tool. The flow nipple  100  has a generally hollow interior with substantially smooth internal surfaces which do not impede the flow of fluid within. At a top end of the flow nipple  100 , a male threaded connector  110  is provided for threaded connection to other components of the well control tool, namely a tubular lock body  200 . 
     Referring next to  FIG. 2 , a top view of the flow nipple  100  is provided and illustrates the generally cylindrical construction of the flow nipple, with the top of the flow nipple  100  having threaded connector  110  having a generally smaller diameter than the bottom of the flow nipple  100 . 
     Turning to  FIG. 3 , a side view of a lock body  200  is shown illustrating how a latching finger  300  is inserted into a latching finger recess  220  disposed within the side of lock body  200 . Lock body  200  has a pair of latching fingers  300  disposed into a pair of latching finger recesses  220 , with a latching finger  300  placed on either side of lock body  200 . Thus, in  FIG. 3 , only one of the latching finger recesses  220  is shown, with the other recess  220  on an opposite side of the lock body  200  and obstructed from view. The latching finger recesses  220  each extend along the side of the lock body  200  in a longitudinal direction and further contain through-holes  215  which extend from the exterior of lock body  200  to the interior, such that the exterior and interior are in fluid communication. The addition of through-holes  215  to the sides of the lock body  200  provides additional area for fluid flow through the well control tool, and further enhances the flow through and pump through capability of the tool. 
     The latching finger recesses  220  each further include a spring wall  224  (not shown), which provides an area for locating an end of a latch spring  327 . As shown in  FIG. 3 , a latching finger  300  has been located within latching finger recess  220 , and is pivotally held in place within the latching finger recess  220  by way of a latching pin  329 . The latching pin  329  extends first through a pin channel  222  on one side of latching finger recess  220 , next through a pin channel  322  that extends through the width of the latching finger  300 , and then through a matching pin channel  222  located on an opposite side of latching finger recess  220 . The use of the latching pin  329  and pin channels  222  and  322  allows for the securing of the latching finger  300  into the latching finger recess  220  as well as pivotal movement of the latching finger  300  within the latching finger recess  220 . Additional details regarding the structure and function of the latching finger  300  will be further discussed below. 
     The lock body  200  further includes a neck  235  which provides for fluid flow through the lock body  200  and connects the primary portion of the lock body  200  with a flange  237  at the top of lock body  200 . The flange  237  is essentially a protruding ridge section of the lock body  200  that allows for improved fishing and retrieval of the tool by providing a greater area for a fishing or overshot tool to latch onto or grab lock body  200 . In a preferred embodiment of the present invention, a series of plunges  239  may be located on the top of the flange  237  to facilitate easy identification of the tool type when viewed from above. This makes it relatively easy to determine the qualities and characteristics of the tool without having to fully retrieval and extract the tool from the wellbore. Different versions of the well control tool may have different plunges or other shapes or patterns etched into the top of flange  237  to facilitate quick identification of the tool version or tool type. Flange  237  may further incorporate a pair of pinning mounts  241  (only one shown) located on either sides of the flange  237 , in which a running tool pin or other suitable device may be mounted thereto. While optional, the pinning mounts  241  provide additional functionality to the lock body  200  in that a greater variety of tools may be used in conjunction with the well control tool. 
     Next, at  FIG. 4 , therein is shown a cross-sectional view of the lock body  200 . In the view of the well control tool shown in  FIG. 4 , the spring wall  224  may be more clearly seen wherein a spring located in the latching finger  300  may be pressed against the spring wall  224  to provide a tension to a top end of the latching finger  300 . Additionally, two flow tracks  230 , which are located on opposite sides of the lock body  200  and oriented approximately 90 degrees from the latch finger recess  220  are shown extending a substantial length of the lock body  200 . Specifically, in the embodiment shown in  FIG. 4 , flow tracks  230  extend from an area of the lock body  200  below the latch finger recesses  220  and up into the neck  235 . The extended length of the flow tracks  230  provides a substantial area for fluid to flow, and further improves the flow of fluids through the well control tool in relation to other previously available tools. In conjunction with the through-holes  215 , maximum flow through and pump through capability for the well control tool may be achieved. At the bottom of the lock body  200 , a female threaded connector  210  may be seen. Female threaded connector  210  may be used for threaded connection to the flow nipple  100  by threaded engagement with the male threaded connector  110 . By threadedly connecting the flow nipple  100  and lock body  200 , a fully assembled seal stem  400  may be formed. 
     At  FIG. 5 , a top view of the lock body  200  is shown, illustrating the relative diameters of the flange  237  as well as the main portion of the lock body  200 . Plunges  239  are also shown as they would appear from above, illustrating the ability to quickly identify the tool based on the plunge pattern. 
     Referring now to  FIGS. 6 and 7 , the lock body  200  of  FIGS. 3 and 4  has been rotated ninety degrees about its longitudinal axis. As previously described, lock body  200  comprises a pair of flow tracks  230  oriented longitudinally along the side of the lock body  200  between the latching fingers recesses  220 , with a flow track  230  located on opposite sides of the lock body  200 . Flow tracks  230  extend from an area near the bottom of the lock body  200  and extend up through the neck  235  of the lock body  200 , with the flow tracks  230 , extending through the tubular body from its exterior surface to its interior surface, thereby providing for fluid communication between the exterior and interior of the lock body  200 . Flow tracks  230  are oriented parallel to the longitudinal axis of the lock body  200  and are located ninety degrees around the circular exterior of the lock body  200  from the latching finger recesses  220 . The extended length of flow track  230  significantly increases the open area for fluid communication, thereby allowing greater unobstructed flow of fluids between the interior and exterior of lock body  200 . This results in more consistent, unimpeded flow of downhole fluids through the lock body  200 . As an added benefit of this elongated area, debris that may be immersed in the fluid mixture flow will be less likely to become trapped along flow track  230 , thereby decreasing the chance for obstructions to develop along the track. In conjunction with a preferred embodiment of neck  235 , these features may further improve flow characteristics in the well control tool not available with other tools known in the industry. 
     In a preferred embodiment, lock body  200  may further comprise a neck  235  with improved flow characteristics over other similar tools in the industry through the extension of the flow tracks  230  into the neck  235 . Such improved flow characteristics are achieved through shortening the length of the lock body neck  235 , which reduces the relative distance of the lock body  200  that fluids must pass through during production. As a result of lessening the distance traversed through the lock body  200 , there is less back pressure on a downhole ESP, which mitigates fluid choke effects, and consequently allows for greater fluid flow through the lock body  200 . In the embodiment of the well control tool shown in  FIG. 6 , the neck  235  is approximately 1.5″ in length. 
     Remaining on  FIG. 6 , a side view of pin channels  222  with a top portion of inserted latching fingers  300  may be seen. In the relaxed state of the lock body  200 , the top end of latching fingers  300  will naturally protrude from the surface of lock body  200  due to the tension provided by latch springs  327  positioned in a spring recess  320 . 
     Next,  FIG. 7  provides a cross-sectional view of the lock body  200  of  FIG. 6 . In  FIG. 7 , the latch springs  327  are seen located within the spring recess  320  of latching finger  300 . The latch springs  327  have an end pressing against the spring recess  320 , and a second end pressing against the spring wall  324 . In this manner, the top end of latching fingers  300  will protrude from the surface of lock body  200  when the lock body is not engaged with any other parts or components. The bottom of the latching fingers  300  have a detent  315  which engages a detent wall  226  located on the lock body  200  and stops the bottom of the latching finger from further rotation into the lock body  200 . 
     Referring now to  FIGS. 8 ,  9  and  10 , top, side and bottom views of the latching finger  300  are shown. As can be collectively seen in  FIGS. 8-10 , the latching finger  300  includes a spring recess  320 , a pin channel  322  and a latching finger shoulder  310 . As described in  FIGS. 3-4 , a latching finger  300  is placed in each latching finger recess  220  and secured into the recess  220  by means of a latch pin  329  which passes through the pin channels  222  of the lock body  200  and the pin channel  322  of the latching finger  300 . Also, as previously described, a latch spring  327  may be placed between the spring wall  224  of the lock body  200  and the latching finger spring recess  320 . Under this engagement, the latch spring  327  exerts an outward bias on the end of the latching finger  300  opposite the spring. By means of this arrangement, the latching finger  300  is allowed to rotate about the latch pin  329 , which forces the latching finger shoulder  310  outwards from the lock body  200  while forcing the opposite end of latching finger  300  inwards from the exterior of the lock body  200 . The opposite end of latching finger  300  further comprises a latching finger detent which engages a detent wall  226  located within latching finger recess  220  of the lock body  200 . In this manner, the latching finger  300  may only rotate a certain amount from the outward bias of latch spring  327 , thus controlling the distance which the shoulder  310  protrudes from the side of the lock body  200 . 
     In a preferred embodiment of the present invention, latching finger  300  may further comprise a set of notches  325  on either side of the latching finger  300 , and adjacent the pin channel  322 . Notches  325  are shaped to reduce the opportunity for latching finger  300  to become jammed while rotating about the pin. Further, notches  325  may also assist in the shearability of the pin of latching finger  300  should lock body  200  and consequently tubular seal stem  400  become stuck downhole. 
     Turning now to  FIG. 11 , a cross-sectional view of a fully assembled tubular seal stem  400  is shown. Tubular seal stem  400  comprises the flow nipple  100  and the lock body  200  threadedly connected together via the respective male threaded connector  110  and female threaded connector  210 . As previously mentioned, sealing gaskets and/or o-rings may be placed in the grooves  120  of flow nipple  100  in order to facilitate a fluid tight seal when the tubular seal stem  400  is placed in a tubular sub-assembly  500 . The complete tubular seal stem  400  is then ready for use within the tubular sub-assembly  500  in order to control the flow of fluids through the tubular sub-assembly  500 . 
     Next,  FIG. 12  shows a side view of a tubular sub-assembly  500  of a preferred embodiment of the present invention within which the tubular seal stem  400  may be placed when the well control tool is in operation. Sub-assembly  500  has a generally tubular structure and has an internal cavity with a length and width sufficient for engaging and securing seal stem  400 . The ends of tubular sub-assembly  500  each have a threaded connector  505  for threaded connection to upstream and downhole portions of a drill string. Along the outer surfaces of the tubular sub-assembly  500  are two longitudinal grooves  520 , which are located on opposite sides of the tubular sub-assembly  500  and recessed from the side surface of the tubular sub-assembly  500  and provide an area for locating a cable  522  for the downhole ESP. Cable  522  may be any manner of cable used by a downhole section of the drill string and may comprise electric, hydraulic and other types of lines or cables. 
     By locating grooves  520  on opposite sides of sub-assembly  500 , a well operator may select the appropriate track for optimal routing of cable  522  depending on the location of the cable relative to the position of the groove  522 . Further, the benefit of locating cable  522  within groove  520  may help to ensure that cable  522  remains in position along the side of the sub-assembly  500 , and does not obstruct ports  510 , thereby allowing the well control tool to provide unimpeded flow of fluids downhole. Thus, the grooves  520  provide protection for cable  522  by safely locating the cable  522  away from any potential damage due to particles and debris in the fluid flow. 
     Next, at  FIG. 13 , a cross-sectional view of tubular sub-assembly  500  is shown with the sub-assembly  500  rotated 90 degrees about its longitudinal axis. In the view provided by  FIG. 15 , a port  510  can be seen located in the side wall of the sub-assembly  500 . Port  510  is positioned 90 degrees from the grooves  520  about the longitudinal axis of the sub-assembly  500  and provides fluid communication between the interior and exterior of the sub-assembly  500 . An identical port  510  (not shown) is located 180 degrees opposite of the port  510 . Thus, the two ports  510  are formed to provide substantially improved flow characteristics of well fluid by allowing for the passage of large pieces of debris typically dispersed within downhole fluids such as kill mud, water, oil or gas. 
     At  FIG. 14 , a top cross-sectional view of tubular sub-assembly  500  taken along dotted line A is shown. In this figure, the particular layout of the grooves  520  and ports  510  can be more readily seen. In particular, it can be seen that the ports  510  are oriented opposite one another, and the grooves  520  are oriented opposite one another, with each port  510  located approximately 90 degrees along the longitudinal axis of the sub-assembly  500  from an adjacent groove  520 . The particular design of sub-assembly  500  allows for maximum fluid flow through the use of two oppositely aligned ports  510  while also minimizing the opportunity for a cable  522  to obstruct the ports  510  by locating the cable  522  within the grooves  520  as far away from the ports  510  as possible. 
     In a preferred embodiment of the present invention, ports  510  may be substantially diamond in shape and enlarged to a size that maximizes fluid flow while simultaneously minimizing the opportunity for debris to obstruct the ports. Ports  510  may also be shaped and sized such that the structural integrity of lock flow sub-assembly  500  is not compromised by an overly enlarged port. During the fluid production process, many different types of debris may develop and comingle with fluids to be produced. This debris may include undesirable hydrocarbons such as paraffin, or other compounds such as iron sulfide. As the production fluid is pumped up through the tubular sub-assembly  500  by the ESP, the unwanted paraffin and iron sulfide may begin to build up along the flow track of the sub-assembly  500 . If the slots  510  on sub-assembly  500  are improperly shaped or sized, there is a chance that the debris will block the slot, thereby causing a halt in fluid production as well as potentially dangerous back pressure further downhole. Additionally, incorrect shaping and sizing of ports  510  may place significant strain on the structural integrity of tubular sub-assembly  500 , thereby leading to premature failure of the sub-assembly  500 . 
     However, due to the shape and size of this preferred embodiment for the ports  510 , substantially improved fluid flow characteristics may be achieved. As a result of these substantially improved flow characteristics, there is less back pressure on the ESP, and less downtime attributable to having to retrieve and service the tool as a result of blockage. The reduced back pressure also significantly reduces the opportunity for failures to develop in other equipment further downhole, as well as prolonging the useful service life of the well control tool and downhole ESP. 
     Referring to  FIG. 15 , therein is shown a cross-sectional view of the seal stem  400  located within the tubular sub-assembly  500 . Through the use of a setting tool, the tubular seal stem  400  may be set into the tubular cavity provided by the tubular-sub assembly  500  by way of the top hole of the tubular sub-assembly  500  in order to seal the flow of fluids through the ports  510  of the tubular sub-assembly  500 . Prior to setting the tubular seal stem  400  into the tubular sub-assembly  500 , commonly used seals in the field, such as gasket seals or o-rings, may be fitted onto the flow nipple  100  by engaging the gasket seals or o-rings into the circumferential grooves  120  located on the exterior of the flow nipple  100 . Upon insertion of the tubular seal stem  400  into the tubular sub-assembly  500 , a fluid tight seal may be formed as a result of the gasket seals or o-rings engaging both the exterior wall of the flow nipple  100  and the interior wall of the sub-assembly  500 . These seals ensure that no fluid may flow through the ports  510  of the tubular sub-assembly  500 . Once the tubular seal stem  400  has been set into the tubular sub-assembly  500 , the setting tool may be pulled in an upward motion to ensure that the tubular seal stem  400  is locked in place. 
     The interior of the tubular sub-assembly  500  has a circumferential recessed area near a top end of the sub-assembly  500  and adjacent the lock body  200 , forming lateral circumferential recessed shoulders  530  along the interior of the sub-assembly  500 . When the tubular seal stem  400  is placed within the tubular sub-assembly  500  using a downward motion, the latching finger shoulders  310  will be forcibly depressed back into the latching finger recesses  220  of the lock body  200 . However, once the shoulders  310  are slidingly engaged with the recessed shoulders  530 , the latching finger shoulders  310  spring back out and lock with the recessed shoulders  530 , thereby preventing upward movement and withdrawal of the seal stem  400 , thus locking the seal stem  400  in place. Additionally, the seal stem  400  is prevented from further downward movement in this position as a result of the engagement of the bottom end of the seal stem  400  with the interior wall of the sub-assembly  500 . 
     Accordingly, while seal stem  400  is engaged within tubular sub-assembly  500 , fluids may only flow through the top or bottom apertures of the sub-assembly  500 , as the ports  510  are effectively shut off from fluid flow. In this manner, the well control tool controls the flow of downhole fluids such that an operator at the surface may determine whether the flow of fluid through the ports  510  is desired in a given scenario. 
     Next, in  FIG. 16 , side and cross-sectional views of a releasing probe  700  are provided which is essentially a solid cylindrical shape and includes a shoulder  710 . Using a standard overshot tool (not shown), a threaded end  720  of the releasing probe  700  may be attached to the overshot tool in order to engage and release the tubular seal stem  400  from the tubular sub-assembly  500 , or more specifically, to disengage the latching fingers  300  located on the lock body  200  from the recessed shoulders  530  of the sub-assembly  500 . By inserting a downhole end  730  of the releasing probe  700  through the interior of the tubular seal stem  400 , the probe  700  will engage and actuate the latching fingers  300 , rotating them until the shoulder  710  passes the latching fingers shoulder  310 , at which point the springs cause the latching fingers  300  to rotate back into their unbiased position. In this orientation, the latching fingers shoulders  310  prevent the releasing probe  700  from being withdrawn from the tubular seal stem unless the seal stem is manipulated as described above to allow the tubular seal stem  400  to be disengaged from the tubular sub-assembly  500 . Once the latching fingers  300  have been disengaged, an upward motion on the releasing probe  700  releases the tubular seal stem  400  to be retrieved at the surface. If for some reason the latching fingers  300  become stuck such that the releasing probe  700  is unable to actuate the latching fingers  300 , the pins  222  may be designed to be shearable so that a mechanical jar will shear pins  222  and disengage latching fingers  300 , thereby releasing the tubular seal stem  400 . 
     Turning next to  FIG. 17 , a side view of another preferred embodiment of a lock body  800  is shown. Lock body  800  is a replacement of the lock body  200  and may be threadedly engaged to flow the nipple  100  in similar fashion to the lock body  200 . Lock body  800  has corollary parts and functionality with the lock body  200 . For instance, lock body  800  has through-holes  815 , latching finger recesses  820 , pin channels  822 , spring walls  824 , detent walls  826 , flange  837 , plunges  839 , and pinning mounts  841  which are substantially similar to the corresponding parts in lock body  200 . However, in lock body  800 , the neck  835  has been lengthened to approximately 2.0″ as compared to the approximately 1.5″ length of the neck  235  for lock body  200 . The advantage of the lengthened neck  835  as compared to the neck  235  is to provide a greater extension of the lock body  800  in order for easier latching and retrieval of the lock body  800 . In particular, for situations where there may be a buildup of downhole debris around the lock body  800 , such as buildup of iron sulfide or paraffin mixtures, the additional extension provided by the elongated neck  835  may allow for the top flange  837  of the lock body  800  to protrude sufficiently for retrieval of the tool. Additionally, the latching finger  300  shown in this embodiment removes the use of notches  325 . 
     At  FIG. 18 , a cross-sectional view of the lock body  800  of  FIG. 17  is shown. Here, another difference between the lock body  200  and lock body  800  can be seen in that the flow tracks  830  no longer extend into the neck  835  as with flow tracks  230  of lock body  200 . Rather, flow tracks  830  terminate at a lateral distance adjacent the spring wall  824 . Thus, flow tracks  830  are shorter and provide less flow area relative to flow tracks  230  of the lock body  200 . However, as a tradeoff for the lesser flow rate provided by lock body  800 , the neck  835  provides increased structural integrity and durability of the lock body  800  as compared to lock body  200 . Thus, for certain applications where the priority is placed in maximizing fluid flow, the lock body  200  may be used to provide the greatest amount of flow area. In instances where the downhole fluids may cause problems as a result of buildup of debris, such as iron sulfide or paraffin, the lock body  800  may alternatively be used to provide greater structural integrity of the lock body as well as ease of tool retrieval. 
     Next, at  FIGS. 19-20 , side and cross-sectional views of the lock body  800  are shown rotated approximately 90 degrees about its longitudinal axis from the view of lock body  800  shown in  FIGS. 17-18 . Here, it can be more clearly seen that flow tracks  830  have been shortened relative to the flow tracks  230  of lock body  830 . In particular, the top end of flow track  830  now terminates roughly adjacent the top of latching finger  300 , and no longer extends into the neck  835 . All other elements of lock body  800  remain essentially the same as with lock body  200 , including the spring wall  824  and detent wall  826 , for example. 
     In a preferred embodiment of the present invention, the flow nipple  100 , lock body  200  and tubular sub-assembly  500  may be fabricated from stainless steel or other suitably durable and wear-resistant materials. Other materials may also be used to fabricate the components of the well control tool so long as they have sufficient wear, corrosion and hardness to withstand the intense pressures and temperatures as is typical in a downhole environment. Further, the latching fingers  300  and latch pin  329  may also be fabricated from various suitable metals, with the latch pin  329  ideally manufactured to be shearable in the event the lock body  200  becomes stuck within the sub-assembly  500 . 
     It will be understood that while specific embodiments of the instant invention have been described, other variants are possible and are encompassed within this description, which will be readily apparent to those of ordinary skill in the art and will be readily understood to be encompassed by the instant invention. Those of ordinary skill in the art will understand the methods of fabricating the instant invention and will readily comprehend its manner of use and intended use.

Summary:
A downhole well control tool allows for the control of in-situ fluid flow from a production well. The flow control tool is engaged to an electrical submersible pump (“ESP”) and allows for the in-situ fluid to flow through the tool when the ESP is both active and inactive. The tool also allows for the flow of drilling mud and other drilling fluids when necessary. In addition, the well control tool may also be used to seal off the flow of fluids, and may be used in the retrieval of the ESP.