Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B33/00—Sealing or packing boreholes or wells
  • E21B33/10—Sealing or packing boreholes or wells in the borehole
  • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
  • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B33/00—Sealing or packing boreholes or wells
  • E21B33/10—Sealing or packing boreholes or wells in the borehole
  • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B33/00—Sealing or packing boreholes or wells
  • E21B33/10—Sealing or packing boreholes or wells in the borehole
  • E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
  • E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
  • E21B33/146—Stage cementing, i.e. discharging cement from casing at different levels
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B34/00—Valve arrangements for boreholes or wells
  • E21B34/06—Valve arrangements for boreholes or wells in wells
  • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole

Definitions

• the invention relates to a tool for wellbore operations and, in particular, a tool for wellbore cementing.
• cementing may be used to control migration of fluids outside a liner installed in the wellbore.
• cement may be installed in the annulus between the liner and the formation wall to deter migration of the fluids axially along the annulus.
• a stage tool may be used for this purpose.
• a stage tool is a tubular that can be installed along the length of the liner and includes an inner bore defined by an inner tubular surface, an outer tubular surface and a port between the inner tubular surface and the outer tubular surface through which fluid can be passed to cement the annulus along a length of the liner.
• a wellbore assembly including: a tubular string having an upper end, a lower end, a tubular wall, an inner bore within the tubular wall and an outer surface; a packer encircling the outer surface and spaced from the upper end; a fluid port through the tubular wall providing fluidic access between the inner bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve permitting only one way flow through the fluid port in a direction from the outer surface to the inner bore.
• a method for cementing a tubing string in a wellbore comprising: running into a wellbore toward bottom hole with a tubing string to a position in the wellbore, an annulus being defined between the tubing string and the wellbore wall; opening a circulation path from the annulus into the tubing string; introducing cement to the annulus to flow down to at least the heel; and closing the circulation path to hold the cement in the annulus to provide time for the cement to set.
• a stage tool for wellbore annular cementing comprising: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve including a closure for the fluid port and a check valve for permitting one way flow through the fluid port in a direction from the outer surface to the inner bore, the check valve being normally inactive and only acting on fluid flows through the fluid port when activated.
• Figures 1A and IB are a schematic sectional views through a wellbore with a tubing string installed therein;
• Figures 2A to 2D are views of a stage tool according to one aspect of the present invention in sequential stages of operation, wherein Figure 2A is an axial sectional view of a stage tool in a run in position, Figure 2B is an axial sectional view of the stage tool of Figure 2A in a position ready to be opened for cement circulation through the annulus, Figure 2C is an axial sectional view of the stage tool of Figure 2A in an open position for circulation therethrough to permit cementing through the annulus and Figure 2D is an axial sectional view of the stage tool of Figure 2A in a closed position, closing against cement circulation;
• Figures 3A to 3E are views of a stage tool according to one aspect of the present invention in sequential stages of operation, wherein Figure 3A is an axial sectional view through a wall of the stage tool in a run in position, Figure 3B is an axial sectional view of the stage tool of Figure 3 A in a position activated and ready to be opened for cement circulation through the annulus, Figure 3C is an axial sectional view of the stage tool of Figure 3A in an open position for circulation therethrough to permit cementing through the annulus, Figure 3D is an axial sectional view of the stage tool of Figure 3A in a position closed by a check valve after dissipation of circulation pressure, and Figure 3E is an axial sectional view of the stage tool of Figure 3 A in a final closed position, closing against cement circulation.
• a surface hole is drilled and surface casing 200 is installed and cemented in place to protect surface soil and ground water from wellbore operations and to prevent cave in.
• an extended wellbore 201 may be drilled below the surface casing point 200a to reach a formation of interest 203.
• further casing is installed below the surface casing.
• the liner can extend from a point above the lower most casing point, in this case casing point 200a with an active, lower portion of the liner extending out beyond casing point 200a at the bottom of the cased section of the well.
• a tool, a process and an installation are described that permit a liner 204 to be supported in an extended wellbore 201 by stage cementing below any casing point 200a, as shown, which may be of the surface casing or a lower section of casing.
• the liner therefore, can be run in, set and cemented in a well including in an open hole, uncased section of the well.
• the liner 204 has an upper end, a lower end, a tubular wall defining an inner diameter and an outer surface and, installed along its length, a stage tool 210, which separates the string into an upper portion 204b, above (uphole of) the stage tool, and a lower portion, below (downhole of) the stage tool.
• stage tool 210 can be positioned at various locations along the liner.
• stage tool 210 is positioned near the end of the liner in the toe of the well, with the upper portion of the string above the stage tool containing active components.
• stage tool 210 is positioned near the heel of the well, for example, just downhole of the heel.
• the lower portion of the liner below the stage tool may contain active components 208a, 208b, etc. of the liner.
• cement C may be introduced into the annulus 250 to fill a portion of the annulus along a length of the liner to cement, and therefore seal off, that portion of the annulus between the liner and the open hole wall 201 a.
• the cement may be introduced to fill a selected portion of the annulus, for example, to create a column extending back from at least above the stage tool to the lowest cased section of the well.
• the cement is introduced until it fills the annulus down to a point above the active components.
• Active components on the liner may take various forms such as, for example, selected from one or more of packers, slips, stabilizers, centralizers, fluid treatment intervals (such as may include fluid treatment ports, nozzles, port closures, etc.), fluid production intervals (such as may include fluid inflow ports, screens, inflow control devices, etc.), etc.
• active components may include slips 208a, multistage fracturing components such as sleeve valves, hydraulic ports 208b (i.e. fracing ports) and packers 208c', 208c for zone isolation, a blow out plug 208d, etc.
• multistage fracturing components such as sleeve valves, hydraulic ports 208b (i.e. fracing ports) and packers 208c', 208c for zone isolation, a blow out plug 208d, etc.
• the liner may be run in and positioned in the well by any of various procedures.
• a fluid may fill, be introduced to or circulated through the string. It may be useful to have pressure communication through the fluid through the string 204 including below stage tool 210, for example, for circulation or for pressure actuation of active components.
• the liner is configured to hold pressure during the setting of the packers, but can be opened for fluid conductivity thereafter for fluid treatments to the formation.
• the liner may be run in with a valve that selectively holds pressure in the liner or a blow out plug, which before being expelled, holds pressure in the liner.
• the liner may include a port opened by pressure cycling, such that once downhole, the liner can be pressured up and pressure released to open the liner.
• packers 208c, 208c' are carried on the liner.
• the packers may be open hole packers or take other forms.
• the packers are set to create annular seals between the liner and the wellbore wall for zone isolation.
• the packers intended for zone isolation during wellbore treatments are set in a substantially horizontal section of the well, downhole of the heel.
• stage tool 210 is positioned downhole of uppermost packer 208c', as shown in Figure 1A, the annulus can be cemented to a point below the uppermost packer for example, down to the location of the stage tool, as desired.
• Stage tool 210 includes one or more ports 222 and a valve to control flow through the ports from the annulus to the inner bore.
• the valve may be operated to open the ports to permit fluid flows with the cement to flow therethrough to achieve circulation to the string inner bore 204b from annulus 250.
• cement may be pumped by fluid circulation as provided through ports 222.
• cement is pumped from above down through the annulus 250 toward the stage tool, in what is called a reverse cementing operation.
• a reverse cementing operation since the circulation flow is down through the annulus and up through the liner, this is the reverse of a standard flow direction for circulation and the cement can be placed in the annulus without requiring it to be pumped through or even into the string.
• a spacer is pumped first, followed by a cement slurry.
• the stage tool includes a closure that closes the ports.
• the stage tool and its components such as the valve may take various forms.
• the stage tool may include a mechanical closure installed therein, such as a sleeve and/or a check valve that can be manipulated remotely or directly to seal off ports 222.
• a wellbore may be stage cemented by use of a stage tool with flow in a reverse direction.
• a method for cementing a tubing string in a wellbore having a heel transitioning from a substantially vertical section to a substantially horizontal section may include: introducing cement to the annulus to flow down to a selected depth, which may be at least the heel and/or possibly just above the uppermost packer on the string and/or all the way to the stage tool; allowing the cement to flow through the annulus by opening a stage tool to create a circulation path from the annulus into the tubing string; and holding the cement in the annulus to provide time for the cement to set.
• the amount of cement can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into the inner bore.
• the circulation path can be closed before the cement passes from the annulus into the tubing string.
• the method may include running into a wellbore with a string that includes at least one fracing port below the uppermost packer and after cementing, a fracturing fluid treatment is conducted through the string and out through the at least one fracing port to treat the formation accessed by the at least one fracing port.
• the method may include activating and/or opening ports 222 of the stage tool by pressuring up on the string.
• Pressuring up may include substantially the entire string or just a portion of the string (i.e. a portion above a seat). Pressuring up may be solely to activate or open the valve or may be used for other purposes in the string such as the setting of one or more packers.
• Pressuring up may drive a piston by creating a pressure differential across a piston. Pressuring up may include launching a ball to land in a seat to create a pressure-drivable piston in the string. Pressuring up may include landing a ball in a seat to move a component of the valve.
• holding the cement in the annulus includes actuating a valve to close and to thereby seal the cement in the annulus.
• closing the valve to seal the cement in the annulus includes pressuring up on the inner diameter of the string.
• closing the valve to seal the cement in the annulus includes dissipating a pressure differential where annular pressure had been higher than tubing pressure, which may include pressuring up on the inner diameter of the string or reducing annular pressure.
• the valve operates relative to a port through the tubing string wall.
• the valve may control fluid flow from the annulus through the port and upwardly through the inner diameter toward surface. Alternately or in addition, the valve may control fluid flow downwardly through the inner diameter and through the port toward the annulus.
• the valve may include a closure that can be closed to seal the cement in the annulus.
• stage tool 310 for use to stage cement a wellbore liner is shown.
• the stage tool may be installed in a tubular string.
• Stage tool 310 may include a tubular body including a wall 31 1 with an outer surface 312, an inner bore 314 defined by an inner surface 316 of the wall, a first end 318 and a second end 320.
• a port 322 extends through the wall and is openable (Figure 2C) and closable ( Figures 2A, 2B and 2D) to open and close, respectively, the stage tool to circulation from the outer surface to the inner bore.
• Stage tool 310 may be intended for use in wellbore applications for actuation to permit cementing of a section of the annulus behind a borehole liner through ports in the liner wall along a length of the liner.
• the tubular body may be formed of materials useful in wellbore applications such as of pipe, liner, casing, etc. and may be incorporated as a portion of a tubing string or in another wellbore string.
• Bore 314 may be in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface, such as for wellbore treatment therethrough.
• the tubular body may be formed in various ways to be incorporated in a tubular string.
• the tubular segment may be formed integral or connected by permanent means, such as welding, with another portion of the tubular string,
• the ends 318, 320 of the tubular body may be formed for engagement in sequence with adjacent tubulars in a string.
• the ends may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.
• a sleeve 324 is positioned to act as a closure for port 322 and is moveable relative to the port to manipulate it between the open and the closed positions.
• Sleeve 324 may carry (as shown) or ride over seals 323 that provide a pressure seal between sleeve 324 and inner surface 316 of the wall.
• Sleeve 324 may be moved by fluid pressure to open and close, which avoids the need to run in a manipulation string or line.
• Stage tool 310 further includes one or more check valves to control fluid flow through bore 314 between ends 318, 320.
• the first check valve 326 is configured to allow fluid flow down through bore 314 from end 318 to end 320, but stops reverse flow therethrough.
• This check valve allows circulation down through the string but acts as a float in the string to prevent backflow from the wellbore into the liner to facilitate liner installation and tubing control.
• the other check valve 328 is configured to act in an opposite fashion to valve 326.
• valve 328 In particular, fluid can pass through valve 328 upwardly, for example through the bore from end 320 to end 318, but valve 328 resists reverse flow (downwardly) through the stage tool.
• This check valve permits the formation of a piston face and allows pressure actuation of components of the stage tool, remotely without running in any tools.
• valve 326 holds pressure from below and valve 328 holds pressure from above.
• the illustrated check valves are poppet style, normally closed, spring-biased valves each including a poppet biased by a spring against a seat.
• Valve 328 cannot act on fluid flows until it is activated to do so.
• a bypass is provided around valve 328 so that fluid can be pumped down the string and through bore 314 from end 318 to end 320, for example to permit circulation during run in.
• valve 328 is installed in an inner diameter 329 of an inner tube 330 and an annular space 332 is opened between inner wall surface 316 and the inner tube, which forms a bypass around the valve.
• the bypass is open through annular space 332
• fluid can flow therethrough and avoid valve 328. If the bypass is closed, fluid flows are controlled by valve 328 and, for example, are prevented from flowing down through the tool.
• a mechanism can be provided to actuate the bypass from an open to a closed position when it is desired to expose the tubing string to the effect of valve 328.
• actuation can be made remotely from surface operations.
• the mechanism for closing the bypass is operated by landing a ball 336 ( Figure 2B) thereon and pressuring up behind the ball to cause the mechanism to shift from an open bypass to a closed bypass.
• the mechanism for closing the bypass includes a plurality of shiftable members that in one arrangement provide open access through the path through bypass and can be shifted by force applied by landing ball to close the bypass.
• This may include installing inner tube 330 to be axially movable within the housing and with openings 338 to annular space 332 at the upper end of inner tube and openings 340 from annular space at the bottom end of the inner tube, which openings can be closed by axially moving the inner tube by landing ball 336 to generate a piston face through which fluid pressure can act to apply force.
• a shiftable member 334 is positioned in an axially moveable fashion in housing above inner tube 330 and includes a ball seat 342 on its upper surface, a nipple 344 at its lower surface and a fluid channel 346 that extends from the ball seat 342 to open at the end of the nipple. While fluid channel is normally open to fluid flow from ball seat and out through nipple 344, it can be closed by landing ball 336 in the seat. This creates a piston face across the shiftable member and the ball seated therein and allows fluid pressure to act to move the shiftable member. When the bypass is open, shiftable member 334 is spaced above tube 330 and forms a gap between the nipple and the tube that creates opening 338.
• shiftable member 334 can be shifted to insert nipple 344 into the inner diameter 329 of the inner tube, which closes access from channel 346 to the annular space 332 and instead opens channel 346 directly into the inner diameter of the inner tube.
• Seals 348 may be provided between the tube and the nipple to resist leakage between channel 346/inner diameter 329 and annular space 332.
• a stop 350 may be provided to limit the axial movement of the shiftable member.
• a lock, such as a ratcheted surface 351a, 351b may be provided such that shiftable member 334 cannot move back up once it has shifted down.
• sleeve 324 may be moveable by various means, in one embodiment as illustrated, the closing mechanism for the bypass can be linked to the movement of sleeve 324.
• the closing of the bypass simultaneously moves sleeve 324 to open ports 322 to communication to inner bore 314.
• inner tube 330 may be connected at its bottom end to sleeve 324 and movement of tube 330 is communicated to the sleeve to likewise cause movement thereof.
• the inner tube may be configured, for example, such that when shiftable member 334 lands against and causes tube 330 to move down, this movement, in addition to closing the bypass through space 332, drives the tube 330 against sleeve 324 and causes the sleeve to move to open port 322.
• valve 328 and ports 322 may be closed by movement of tube 330 to close openings 340 while sleeve 324 remains stationary. Movement of tube 330 may be by application of fluid pressure through bore 314 from surface back against valve 328, which closes valve 328 and generates a piston effect across the valve to move tube 330.
• sleeve 324 can be stopped against a stop 352 such that tube 330 moves relative to the sleeve to overlap or further overlap with the sleeve such that any openings 340 therebetween are closed.
• the tube and the sleeve may be secured together by a frictional member such as close fitting surface or shear pins such that while the tube and the sleeve initially move together, they can be separated for independent movement.
• a stop 356 may be provided to limit the degree of overlap that can be achieved between tube 330 and sleeve 324.
• Seals 354 may be provided to seal against leakage between the parts.
• Stage tool 310 may be manipulated between a plurality of positions. As shown by the drawings, the stage tool may be manipulated between a first, run in position (Figure 2A), a second, cementing port-open position (Figure 2C) and a third, cement port-closed position (Figure 2D).
• the stage tool may be run into and set in the hole in a condition as shown in Figure 2A and may be manipulated as shown in Figure 2B to a condition shown in Figure 2C for stage cementing.
• Stage tool 310 allows cement to be introduced through the annulus and allows reverse circulation of annular fluids from the annulus into the tubing string though inner bore 314 and then back up toward surface. After the introduction of cement to an annulus 250 formed between the tool and the wellbore wall down to a selected level, the tool may be manipulated to a condition shown in Figure 2D to close off communication between the annulus and the inner bore of the tool.
• the stage tool installed in a tubing string, is run into the wellbore with the port closed by a removable closure, in this embodiment sleeve 324. Once in position, port 322 is opened, as by hydraulic actuation of the removable closure, to provide fluid communication between the annulus about the tool and inner bore 314.
• the stage tool can be located at various positions along the tubing string, for example, most often near the distal end, below any packers or frac ports (such as shown in Figure 1A) or sometimes just above an uppermost packer on a treatment string (such as shown in Figure IB) or anywhere in between, such that annulus 250 can be cemented between the upper end of the string and the location of stage tool for example, in one embodiment, from the upper end of the string down to a point just above the uppermost packer. Cement is then introduced to annulus and can be pumped down the annulus as permitted by circulation through port 322 and into inner bore 314. When sufficient cement is introduced to fill the annulus along a selected length, the ports are closed to stop circulation from the annulus into bore 314. This, then, holds the cement in the annulus and time is allowed for the cement to set. The amount of cement introduced can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into inner bore 314.
• the stage tool may be installed in a tubing string.
• tool 310 is installed in a tubular string with its inner bore 314 in communication with the inner diameter of the tubing string.
• the tool will be run into the wellbore with ports 322 closed. Once in position, the process to set the tubing string in the hole is initiated.
• Figure 2A shows the position of the components of stage tool 310 during run in and immediately after the string is in position in the well. Bypass through space 332 is open such that valve 328 has no effect on the flow of fluids through the stage tool.
• fluid can be circulated, arrows R, down through the string into bore 314, through channel 346, opening 338, space 332 and openings 340 to valve 326.
• valve 326 is normally closed, circulation pressures are sufficient to open valve 326 and fluid can pass through the stage tool to lower parts of the string. This fluid communication can be used to clean and condition the well, facilitate advancement of the string and/or set tools such as packers 208c. Valve 326 also permits the string to be floated into the well.
• sleeve 324 can be moved to open ports 322.
• ball 336 can be launched ( Figure 2B) to land on seat 342. This converts shiftable member 334 to a piston form and pressure P can be applied to force the shiftable member down.
• shiftable member 334 As shiftable member 334 is moved, sleeve 324, which is attached, also moves to expose ports 322 to inner bore 314 ( Figure 2C). The movement of shiftable member 334 is stopped when it contacts stop 350. Also at this point locking surfaces 351a, 351b lock up to resist reverse movement of shiftable member. Movement of shiftable member 334 also closes the bypass through space 332 such that all fluid flow between ports 322 and upper end 318 must pass through valve 328. The bypass is closed when the pressure pushes shiftable member 334 to close opening 338. In particular, nipple 344 is pushed into the upper end of inner tube 330 and against the seals 348.
• cement can be pumped down the annulus 250, arrows C.
• the fluid that is in the annulus 250 in front of the cement displaces while the cement is being pumped down the annulus ( Figure 2C).
• Ball 336 is moved with the circulating fluid and is removed from seat 342.
• Valve 328 opens to allow circulation from the space between the valves and valve remains closed, as the pressure is equalized about it. Once the correct amount of cement is pumped down the annulus, pressure may be applied to the tubing above shiftable member 334, which closes check valve 328 and converts inner tube 330 and valve 328 therein to a piston.
• Check valve 328 being closed, permits the development of a force by fluid pressure that pushes the inner tube 330 down closing openings 340 ( Figure 2D).
• inner tube 330 remains connected to, but axially moveable between, shiftable member 334 and sleeve 324.
• valve 328 is closed and inner tube 330 acts as a piston, the inner tube may be driven axially down and, while remaining sealed with shiftable member 334, may be telescopically driven into sleeve 324, until openings 340 and seals 354 overlap, and become sealed against, the sleeve.
• the fluid including cement in the annulus
• the cement will then set to cement the annulus.
• the process is controlled to prevent cement from actually entering the tubing string.
• There will be non- cementious liquid moving ahead of the cement for example, simply the amount of residual liquid in the well.
• an introduced plug of liquid may be pumped ahead of the cement.
• the leading plug may, for example, include mud, water, etc.
• the volumes pumped may be selected such that, the cement is introduced down to a selected point in the well and it is likely that any fluid entering the string may be devoid of settable cement.
• the process to set the tubing string in the well may further include setting of packers, slips, etc. Since the placement of cement in the annulus requires annular flow to the stage tool, the timing of the setting of the packers may depend on the location of the stage tool: whether the stage tool is positioned uphole or downhole from the packers. If the stage tool is positioned uphole of the packers, the packers may be set before or after placement of the cement. If no annular flow can be achieved past the packers and the stage tool is positioned downhole of the packers, the packers may be set after placement of the cement.
• wellbore operations may include wellbore fluid treatments such as stimulation including fracturing.
• fluid treatment ports may be opened through which treatment fluids will be communicated, sometimes under pressure to the formation.
• a fracing operation may be carried out on a formation accessed through the wellbore below the stage tool.
• fracturing fluids under pressure may be introduced through the tubing string, and injecting the fluids under pressure out from the tubing string through ports.
• string manipulations may be conducted including pressuring up the string inner bore.
• tools, free or connected to strings must be passed through the string inner bore.
• the string may be milled out to ensure full bore access through the string.
• the stage tool is positioned downhole of liner components used in these wellbore processes, such milling may not be required.
• stage tool 410 for use to stage cement a wellbore liner is shown.
• the stage tool may be installed in a tubular string.
• This stage tool includes a one way check valve over a port, used to open the port to fluid flow therethrough in response to reverse circulation, a releasable lock that holds the one-way check valve in an inoperable position until activated, and a closing sleeve that closes the port to fluid flow after use of the check valve.
• the stage tool may include a tubing body installable in a string, a port, a one way check valve over the port such as a spring loaded sleeve, used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter), a hydraulic actuating sleeve to initially releasably lock the check valve in the closed position but hydraulically actuable to release the check valve for operation, and a hydraulic closing sleeve operable to close the port by pressure actuation thereof.
• a tubing body installable in a string
• a port such as a spring loaded sleeve, used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter)
• a hydraulic actuating sleeve to initially releasably lock the check valve in the closed position but hydraulically actuable to release the check valve for operation
• a hydraulic closing sleeve operable to close the port by pressure actuation thereof.
• Stage tool 410 may include a tubular body including a wall 41 1 with an outer surface 412, an inner bore 414 defined by an inner surface 416 of the wall, a first end 418 and a second end 420.
• a port 422 extends through the wall and is openable (Figure 3C) and closable ( Figures 3A, 3B, 3D and 3E) to open and close, respectively, the stage tool to circulation from the outer surface to the inner bore.
• Stage tool 410 may be intended for use in wellbore applications for actuation to permit cementing of a portion of the annulus behind a borehole liner along a length of the liner, generally spaced from the liner's distal end.
• the tubular body may be formed of materials useful in wellbore applications such as of pipe, liner, casing, etc. and may be incorporated as a portion of a tubing string or in another wellbore string.
• Bore 414 may be in communication with the inner bore of a tubing string such that pressures may be controlled therein and fluids may be communicated from surface, such as for wellbore treatment therethrough.
• the tubular body may be formed in various ways to be incorporated in a tubular string.
• the tubular segment may be formed integral or connected by permanent means, such as welding, with another portion of the tubular string.
• the ends 418, 420 of the tubular body may be formed for engagement in sequence with adjacent tubulars in a string.
• the ends may be formed as threaded pins or boxes to allow threaded engagement with adjacent tubulars.
• a sleeve 424 is positioned to act as a closure for port 422 and is moveable relative to the port to manipulate it between the open and the closed positions.
• Sleeve 424 may carry or ride over seals 423 that provide a pressure seal between sleeve 424 and the wall to seal against migration of fluid through port 422 past the sleeve.
• Sleeve 424 acts as a one way check valve and may be moved by fluid pressure to open and close, which avoids the need to run in a manipulation string or line to open or close it.
• Sleeve 424 includes a biasing spring 428 such that it is normally in a position closing port 422, but can be opened by when the annular pressure PI is greater than the tubing pressure P2.
• sleeve 424 may be opened by reverse flow from the annulus to the tubing string such that fluid can pass through port 422 inwardly from annulus 250 to inner bore 414, with sleeve 424 acting as a one way check valve and resisting flow outwardly through the ports of the stage tool.
• Sleeve 424 is normally inactive, for example, during run in of the tool such that it is not effected by pressure differentials. However, the valving operation of sleeve 424 may be activated when its operation is required. For example, sleeve 424 may be releasably locked in an inactive position, but may be unlocked to act as a check valve when such operation is required.
• a lock sleeve 430 is provided for sleeve 424. The lock sleeve normally holds sleeve 424 in a position closing port 422, but movement of the lock sleeve can release sleeve 424 for check valve operation.
• Lock sleeve 430 for example, can hold, as by overlying, a lock protrusion 431 (i.e. pin, ball or ring) in a lock notch 432 of sleeve 424, but can be moved to release the protrusion from the notch and thereby allow movement of the sleeve 424.
• Lock sleeve 430 for example, may include a recess 436 normally offset from protrusion 431 but moveable with sleeve 430 into alignment with the protrusion. Lock sleeve 430 may be responsive to pressure conditions in inner bore 414 of the stage tool.
• lock sleeve 430 may include a piston face 430a acting between tubing pressure P2 and annulus pressure PI through port 433 and chamber 434 and can be moved when P2 is greater than PI sufficient to overcome the holding force of a shear pin 435.
• Lock sleeve 430 may include seals 438 to ensure that pressure differentials are sensed across face 430a and to prevent fluid leakage between outer surface 412 and bore 414.
• a locking structure such as a snap ring 440 may be provided to resist further movement of the lock sleeve, such as when PI becomes greater than P2. While lock sleeve 430 may be moveable by various means, hydraulic means permits the activation of sleeve 424 entirely remotely, simply by pressuring up on the inner bore 414.
• sleeve 424 is responsive to fluid pressure differentials between PI and P2 and only allows one way flow inwardly when P1>P2.
• the stage tool may include a final closing sleeve 446 to act as a back-up seal for port 422.
• Final closing sleeve 446 may be normally offset from port 422 but is moveable to cover the port.
• Final closing sleeve 446 may be responsive to pressure conditions in inner bore 414 of the stage tool.
• sleeve 446 may include a piston face 446a acting between tubing pressure P2 and annulus pressure PI through port 448 and chamber 450 and can be moved when P2 is greater than PI sufficient to overcome the holding force of a shear pin 452.
• Shear pin 452 has a holding force greater than shear pin 435 to ensure that pin 435 fails first to unlock sleeve 424.
• Final closing sleeve 446 may include seals 458 to ensure that pressure differentials are sensed across face 446a and act to seal the interface between sleeve 446 and wall 416 to prevent leaks therebetween.
• a lock 447 such as a body lock ring or ratchet, may be employed between sleeve 446 and wall 416 to lock it against movement towards reopening.
• Stage tool 410 may be manipulated between a plurality of positions. As shown by the drawings, the stage tool may be manipulated between a first, run in position (Figure 3A), a second, cementing port-openable position ( Figures 3B to 3D) and a third, cementing port-closed position ( Figure 3D).
• the stage tool may be run into and set in the hole in a condition as shown in Figure 3A and may be manipulated as shown in Figure 3B to an active condition shown in Figures 3C and 3D for stage cementing.
• Stage tool 410 allows cement to be introduced through the annulus and allows reverse circulation of annular fluids from the annulus into the tubing string though inner bore 414 and then back up toward surface. After the introduction of cement to an annulus 250 formed between the tool and the wellbore wall down to a selected level, the tool may be manipulated to a condition shown in Figure 3E to close off communication between the annulus and the inner bore of the tool.
• the stage tool may be installed in a tubing string and run into the wellbore with the port closed by a removable closure, in this embodiment sleeve 424.
• port 422 is rendered openable, as by hydraulic actuation of the removable closure, to provide fluid communication between the annulus about the tool and inner bore 414.
• the stage tool can be located just above an uppermost packer on a treatment string, such that annulus 250 can be cemented between the upper end of the string and a point just above the uppermost packer. Cement is then introduced to annulus and can be pumped down the annulus as permitted by circulation through port 422 and into inner bore 414.
• the ports are closed to stop circulation from the annulus into bore 414. This, then, holds the cement in the annulus and time is allowed for the cement to set.
• the amount of cement introduced can be selected to substantially fill the selected portion of the annulus without injecting much or any cement into inner bore 414.
• Tool 410 may be installed in a tubular string with its inner bore 414 in communication with the inner diameter of the tubing string.
• the tool will be run into the wellbore with ports 422 closed.
• Figure 3 A shows the position of the components of stage tool 410 during run in.
• sleeve 424 can be activated to operate as a check valve by removing its lock. This may be accomplished by pressuring up the tubing string.
• the process to set the tubing string in the hole, as by setting of packers, slips, etc, is also by pressuring up and, as such, the operations to set the string in the well and to activate the sleeve may occur together.
• This may include dropping a ball that lands in a toe-end of the string to pressure up substantially the entire string.
• This may set one or more packers on the string in addition to triggering sleeve 424 by moving lock sleeve 430 ( Figure 3B).
• cement can be pumped down the annulus which creates a pressure P1>P2 sufficient to overcome the check valve and, in particular, to move sleeve 424 against the bias of spring 438 to permit circulation, arrows C, through port 422 and into bore 414 toward surface.
• Sleeve 424 resists reverse flow through port 422 due to the effect on face and the bias in spring 438. Once the annulus pressure PI is reduced, Figure 3D, such as when the cement job is completed, the sleeve 424 shuts. This prevents further flow through port 424, unless pressure is increased again in annulus 250.
• the bias in spring 438 is sufficient to resist the opening of sleeve 424 by the weight of the cement, absent pump pressure.
• the amount of cement introduced can be selected to substantially fill a selected portion of the annulus at least uphole of the stage tool without injecting much or any cement through port 422 into inner bore 414.
• the method may include pumping leading fluids ahead of the cement, the fluids being pumped down the annulus to clean the annulus and/or open the check valve to flow through the port from the annulus to the inner diameter ahead of the cement.
• the fluids may include, for example, mud.
• the circulation through port allowing the cementing of the annulus can be accomplished by the leading fluids and circulation is stopped before the cement begins to pass through the ports.
• final closing sleeve 446 can be moved over port 422 to prevent further flow through the port in either direction and to act as a back-up for sleeve 424. This may include pressuring up the string to hydraulically actuate the final closing sleeve 446 to move to a cementing port-closed position ( Figure 3E).
• wellbore operations may proceed.
• the tubing string inner bore is open and by selection of the inner diameters of the sleeves 430 and 446 may be fully open to the drift diameter.
• wellbore operations may include wellbore fluid treatments such as stimulation including fracturing.
• string manipulations may be necessary below the stage tool.
• fluid treatment ports may be opened below the stage tool through which treatment fluids will be communicated, sometimes under pressure to the formation.
• a fracing operation may be carried out on a formation accessed through the wellbore below the stage tool.
• Fracturing fluids under pressure may be introduced through the tubing string, passing through inner bore 414 of tool 410, and injecting the fluids under pressure out from the tubing string through fracing ports downhole of the stage tool.
• string manipulation may include pressuring up the string inner bore including bore 414 of the stage tool.
• tools, free or connected to strings must be passed through the string inner bore including bore 414 of the stage tool.

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• 2012
  • 2012-05-22 US US14/118,634 patent/US20140076560A1/en not_active Abandoned
  • 2012-05-22 CA CA2836629A patent/CA2836629A1/en not_active Abandoned
  • 2012-05-22 WO PCT/CA2012/000487 patent/WO2012162792A1/en active Application Filing
  • 2012-05-22 EP EP12792178.1A patent/EP2737167A4/de not_active Withdrawn

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