Patent Publication Number: US-9890610-B2

Title: Mechanical method for restoring downhole circulation

Description:
BACKGROUND 
     In the recovery of downhole hydrocarbons, it is useful to inject fluids or fluid slurries through the wellbore and into the hydrocarbon bearing formation to facilitate or otherwise treat the wellbore or the hydrocarbon bearing formation. Typically, accessing a hydrocarbon bearing formation begins with drilling a wellbore through at least one hydrocarbon bearing zone. After the well is drilled, the well is completed by inserting a casing into the wellbore, cementing the casing into place, and accessing the hydrocarbon bearing formation through the casing after which fluids may be injected into or removed from the formation. In some cases the casing is not cemented into the wellbore, in such situations annular packers may be used for zone isolation. 
     In addition to holding the casing in place the cement acts as an annular seal between the casing and the hydrocarbon formation as well as a seal longitudinally along the length of the casing between various hydrocarbon formations or hydrocarbon formation zones. Annular packers may also be used as longitudinal seal along the length of the casing between various, formations or hydrocarbon formation zones. Annular seals, whether by cement or by packers, along the length of the casing prevents fracturing fluid that is pumped down the wellbore from migrating out of the targeted zone. If such a targeted zone is not isolated, the fracturing fluid that is pumped down the wellbore, will flow into the annular area between the casing and the formation and travel along the exterior of the casing out of the targeted zone into areas that are not hydrocarbon bearing formations and perhaps even into other separate hydrocarbon bearing formations quickly overcoming the ability of the casing to transport the fluid into the formations and the ability of the pumps to supply the fluid at pressure sufficient to fracture the formation. Similarly, annular fluid flow between the wellbore and casing may result in reduced recovery of fluids, loss of treatment fluids, or infiltration of undesired materials into a targeted or untargeted zones. 
     Usually after a zone has been isolated, ports in the casing may be opened to allow for the injection of fluids or slurries into the well. The open ports may also facilitate the removal of fluids or slurries from the hydrocarbon bearing formation. It may be desirable that the ports may be selectively opened or closed. Typically the ports are installed in the well in a closed condition by use of sliding sleeves. Usually sliding sleeve valves comprise a sleeve having circumferential seals such as O-rings at the top and bottom edges thereof to seal against a wall of the casing. Thus, when the sleeve is positioned over a port, the sleeve substantially prevents fluid communication between the interior of the casing and the hydrocarbon bearing formation through the port. The port may be opened by moving the sliding sleeve so that the sliding sleeve is located above or below the port or at least aligning a port in the sliding sleeve with the port in the casing thereby allowing fluid flow into or out of the desired zone. In many instances the sliding sleeve is equipped with a seat in the interior of the sliding sleeve. 
     More specifically, a tubular assembly is put together on the rig floor prior to being lowered into the well bore. If the operator does not plan to cement the tubular assembly into the wellbore, annular zonal isolation packers will also be installed along the length of the tubular assembly. Typically a packer will be installed both above and below each port and spaced far enough apart to straddle a particular hydrocarbon bearing formation or a portion of a particular zone of a hydrocarbon bearing formation. In many instances a single packer may serve as the upper packer on one zone as well as the lower packer on an adjacent zone. The tubular assembly is then lowered into the wellbore so that a port is adjacent to the desired zone. 
     In order to open the sliding sleeve, the seat is sized such that when a ball, dart, or plug is pumped into the well the ball will land on the seat sealing the interior of the tubular at the seat against fluid flow past the seat. As fluid pressure is increased the ball then exerts force against the seat and thus the sliding sleeve thereby causing the sliding sleeve to open providing fluid access from the interior of the tubular to the exterior of the tubular. Usually the sliding sleeve having a seat with the smallest diameter is placed towards the bottom for toe of the well. Sliding sleeves having seats with increasingly larger diameters are placed in the wellbore such that the smallest diameter is at the bottom of the well while the largest diameter is towards the top of the well. By having sliding sleeves with seats with larger diameters towards the top of the well, the smaller diameter balls are able to pass through the upper sliding sleeves without actuating the sliding sleeves as they pass through them. Unfortunately there are limitations that are imposed upon the operator when completing the well using progressively larger sized seats and balls in conjunction with sliding valves such as an increasingly reduced diameter of the wellbore towards the toe of the well which in turn leads to either reduced production or milling out each of the progressively smaller valve seats. Additionally there is a limitation on the number of zones that may be accessed when using progressively larger size seats and balls. 
     A recurring problem in some fracturing operations has been premature screen-out. In many cases premature screen-out occurs when the proppant or sand bridges in the wellbore or casing or at a point where the flow velocity slows allowing the proppant to settle out of the transport fluid thereby preventing further fluid flow past the flow restriction. This can happen when the zone in a hydrocarbon formation stops taking a sufficient flow or volume of fluid to allow continued fracking of the zone. When a screen out occurs the fluid pressure needed to keep injecting proppant into a well exceeds the limitations of the tubulars, wellhead, or surface equipment thereby shutting down the frac operation. Additionally with fluid circulation in the wellbore lost it becomes practically impossible to pump an additional ball into the wellbore to open any valve above the flow restriction in order to continue the frac operation. 
     In one current method of dealing with the screen out the operator may draw or flow the well back along with the ball seated on the valve seat that corresponds to the screen out. By drawing the well and the last ball sent downhole the operator is able to attempt to remove the flow restriction in order to continue dropping balls and fracking the other zones above. If the screened out zone will not take any additional fluid, then when the operator attempts to pump fluid downhole the ball will reseal on the ball seat thus preventing further pump down. In such an event the current solution is to bring in coil tubing to intervene in the well in order to reestablish circulation. This can be a costly and time consuming process. 
     SUMMARY 
     In an embodiment of the current invention a gate, including but not limited to fingers, a flapper, a rod, or a cam is locked open prior to the sleeve being actuated. When the gate is locked open any portion of the gate that might prevent passage of a ball, dart, or plug is prevented from blocking the passage of a ball, dart or plug. In practice the gate is part of a sliding sleeve assembly and the portion of the gate that might prevent passage of a ball, dart, or plug is locked in the open condition by the sliding sleeve. 
     The gate is actuated or put in an active closed position after a ball lands on the seat of the sliding sleeve and opens the sliding sleeve. As the sliding sleeve moves towards the bottom of the well in response to fluid pressure against the ball, the gate, now above the ball, is released so that fingers of the gate extend into the interior of the tubular or sliding sleeve. In the event that the formation or the sliding sleeve should prematurely screen out, thereby preventing fluid circulation, the operator will as before reverse the pumps on the surface in an attempt to flow the well back. The ball will flow back through the gate to a position above the gate. Once the ball is allowed to flow back some small amount the fingers on the gate prevent the ball from moving back down and reaching the ball seat and thus resealing the tubular. The fingers also allow fluid to flow around the ball thereby allowing the operator to re-establish circulation to the bottom of the well or at least to a lower zone in order to continue fracking operations and dropping additional balls. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cutaway view of a typical sliding sleeve. 
         FIG. 2  depicts the sliding sleeve of  FIG. 1  in the open condition. 
         FIG. 3  depicts an embodiment of a sliding sleeve with the gate open. 
         FIG. 4  depicts an embodiment of a sliding sleeve of  FIG. 3  with the gate closed. 
         FIG. 5  depicts an embodiment of the sliding sleeve of  FIG. 4  with the gate closed and the sliding sleeve port screened out. 
         FIG. 6  depicts an embodiment of the sliding sleeve of  FIG. 5  as the operator draws the well back. 
         FIG. 7  depicts an embodiment of the sliding sleeve of  FIG. 6  with a ball prevented from moving downward by the closed gate while fluid flows around the ball. 
         FIG. 8  depicts an alternative embodiment of a gate mechanism where the actuating mechanism occupies only a portion of the inner circumference of a tubular. 
         FIG. 9  is a side view of the actuating mechanism prior to actuation. 
         FIG. 10  is a side view of actuating mechanism after actuation where the well has screened out and the actuating ball is flowed back some distance above the gate. 
     
    
    
     DETAILED DESCRIPTION 
     The description that follows includes exemplary apparatus, methods, techniques, or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details. 
       FIG. 1  is a cutaway view of a typical sliding sleeve  10  having a housing  12  a box end  14  and a pen end  16 . Typically the pen end  16  is towards the toe or bottom of the well while the box end  14  is towards the heel or upper end of the well. The housing  12  has at least one port  18 . The port  18  is closed by the inner sleeve  20  the inner sleeve  20  has a first seal  22  and a second seal  24  that prevent any fluid flow around either the upper or lower end of the inner sleeve  20 . 
     Typically sliding sleeve  10  is located in a wellbore  21  adjacent to a hydrocarbon bearing formation. The sliding sleeve  10  may be cemented in place or may have an annular packer both above and below the sliding sleeve  10  to direct the fluid flow into the hydrocarbon formation and to prevent the longitudinal movement of fluid either up or down the length of the casing. 
       FIG. 2  depicts the sliding sleeve of  FIG. 1  in the open condition. Where a ball  28  has formed a seat  30  with the upper end of inner sleeve  22 . Fluid pressure against the ball  28  from the surface has forced the inner sleeve  20  to move from its first or closed position to a second open position. With the inner sleeve  20  in the open position fluid flow as depicted by arrow  32  is able to flow from the interior of the sliding sleeve  10  to the exterior of sliding sleeve  10 . 
       FIG. 3  depicts an embodiment of the current invention where the sliding sleeve  50  has a housing  52 , a pen end  54  a box end  56  and at least one port  58 . The port  58  is provided with an inner sleeve  60  having a first seal  62  and a second seal  64 . Together the inner sleeve  60 , the first seal  62 , and the second seal  64  prevent fluid flow through port  58 . The inner sleeve  60  also has at least one shoulder  66 . The shoulder  66  provides a seating surface for ball, dart, or plug to seat on and feel the interior of the sliding sleeve  50  against longitudinal fluid flow past sliding sleeve  50 , through the interior of the tubular, and towards the bottom of the well. At the upper end of inner sleeve  60  is finger  70 . Finger  70  is allowed to pivot on hinge  72  and is biased to move radially inward towards the interior of sliding sleeve  50  by biasing device  74 . The biasing device  74  may be, but is not limited to, a spring, piston, elastomer, or other means to move the finger radially inwards. In some instances finger  70  may be biased or forced inward by a cam that forces the finger  70  to move inward in response to movement of inner sleeve  60 . In the embodiment shown in  FIG. 3  finger  70  is restrained in its inward position by lock  76  that engages finger  70  while inner sleeve  60  is in its first or closed position. In certain instances finger  70  may not be restrained in inward position but is not locked against downward movement until after the appropriate ball passes the finger  70  and actuates the one way gate. It is envisioned that in certain instances finger  70  may be made of a material that disappears within 30 days, or more preferably 15 days, of being placed downhole. Such erodible or dissolvable materials that disappear over time are for example polyglycolic acid, polylactic acid, or metals such as magnesium and aluminum. 
       FIG. 4  depicts the embodiment of  FIG. 3  in the open condition. Ball  80  has formed a seat on shoulder  66 . Fluid pressure against the ball  80  from the surface has forced the inner sleeve  60  to move from its first or closed position to a second open position. With the inner sleeve  60  in its open position finger  70  is moved downward so that the upper end  82  of finger  70  disengages from lock  76  allowing finger  72  rotate radially inward in the direction of arrow  84 . With the inner sleeve  60  in the open position fluid flow as depicted by arrow  86  is able to flow from the interior of sliding sleeve  50  to the exterior siding sleeve  50 . 
       FIG. 5  depicts the sliding sleeve  50  where the inner sleeve  60  has been shifted down towards the toe of the well by ball  80  and finger  70  has rotated radially inward. In  FIG. 5  however sand  82  has built up or bridged across the exterior of port  58 . The sand  82  now blocks fluid flow from the interior of the sliding sleeve  50  to the exterior of the sliding sleeve  50  so that fluid as depicted by arrows  84  is no longer able to flow through port  58 . 
       FIG. 6  depicts sliding sleeve  50  as the operator tries to draw back the well to reestablish circulation in the well. With the pumps reversed fluid flows from the lower portion of the well towards the surface as indicated by arrows  90 . As the fluid flows towards the surface ball  80  is dislodged from shoulder  66  and moves some distance towards the surface. The ball however must be moved at least a sufficient distance towards the surface to pass finger  70  of the gate. As the ball  80  passes the finger  70 , the force applied by the bias device  74  is overcome by the force the ball exerts against finger  70  causing finger  72  rotate radially outward in the direction of arrow  92  allowing the ball  80  to pass finger  70 . Once ball  80  passes finger  70  biased device  74  again causes finger  72  rotate radially inward. Depending upon the amount of fluid drawn back as well as other wellbore parameters such as fluid flow out of a previously treated zone balls that reside on seats below the screened out sliding sleeve  50  may also be moved upward off their seat and past each gate that may actuated with a finger moving radially inward. 
       FIG. 7  depicts sliding sleeve  50  after the operator has reestablished circulation in the well with the surface pumps pumping fluid down the well bore as indicated by arrow  101 . The sand  82  continues to block port  58  so that is fluid flows towards  58  the fluid flow is diverted back towards the interior of the sliding sleeve  50  as indicated by arrow  84 . However as ball  80  is pushed down the interior of sliding sleeve  50  it encounters finger  72  and is prevented from traveling further down the well bore and landing on shoulder  66 . With ball  80  held on finger  72  fluid flow is allowed to pass around ball  80  as indicated by arrow  102  and continue further down the well as indicated by arrow  104 . With fluid flow reestablished the operator may then drop the next ball into the well bore to actuate a tool or sliding sleeve above sliding sleeve  50 . 
       FIG. 8  depicts an alternative embodiment of a gate mechanism where the actuating mechanism  100  occupies only a portion of the inner circumference of tubular  102 . Actuating mechanism  100  is sized such that a ball (not shown) that will actuate the next sleeve below the gate will also actuate the gate. In some instances it may be necessary to add protrusions such as protrusion  104  and  106  to the interior of tubular  102 . The protrusions  104   106  allow the ball to interact with actuating mechanism  100  and when the gate mechanism is actuated allow fluid flow to pass by the ball when it is held at the gate 
       FIG. 9  is a side view of actuating mechanism  100  prior to actuation. Finger  110  is recessed into the side wall of tubular  102  in side pocket  114  and is biased radially outward by biasing device  112 . In this instance the biasing device  112  is a spring. The actuating mechanism  100  is held in place so that at least a portion of actuating mechanism  100  is adjacent to finger  110  and holds finger  110  in side pocket  114 . The actuating mechanism  100  in this instance is prevented from longitudinally moving by shear screw  116 . 
       FIG. 10  is a side view of actuating mechanism  100  after actuation and after the well has screened out the operator has been able to flow back the actuating ball  120  some distance above the gate  130 . In order to actuate the actuating mechanism  100  actuating ball  120  was forced toward actuating mechanism  100  by protrusion  104  and  106 . Longitudinal force was then exerted by actuating ball  120  upon actuating mechanism  100  and through actuating mechanism  100  upon shear screw  116  shearing shear screw  116  and allowing actuating mechanism  100  to move longitudinally downward. While shear screw  116  is described as a shear screw it may be a shear pin or any other mechanism known in the art that will retain actuating mechanism  100  in place until a predetermined force acts upon shear screw  116 . After actuation the actuating mechanism  100  moves longitudinally downward into recess  118  where the actuating mechanism  100  is allowed to move radially outward into recess  118  thereby allowing the ball  120  to pass. Also as actuating mechanism  100  moves longitudinally downward finger  110  is released and is free to move. Biasing device  112  forces the finger  110  to move radially inward towards the interior of tubular  102  after which finger  110  will allow the ball  120  to move upwards in the well but will no longer allow the ball  120  to downward past gate  130 . 
     While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. 
     Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.