WO2014107805A1 - Outil à étages pour cimentation de trou de forage - Google Patents
Outil à étages pour cimentation de trou de forage Download PDFInfo
- Publication number
- WO2014107805A1 WO2014107805A1 PCT/CA2014/050007 CA2014050007W WO2014107805A1 WO 2014107805 A1 WO2014107805 A1 WO 2014107805A1 CA 2014050007 W CA2014050007 W CA 2014050007W WO 2014107805 A1 WO2014107805 A1 WO 2014107805A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- stage tool
- valve
- port
- inner bore
- plug
- Prior art date
Links
- 239000004568 cement Substances 0.000 claims abstract description 67
- 239000012530 fluid Substances 0.000 claims abstract description 42
- 238000007789 sealing Methods 0.000 claims abstract description 3
- 238000000034 method Methods 0.000 claims description 17
- 238000005086 pumping Methods 0.000 claims description 4
- 230000011664 signaling Effects 0.000 claims 1
- 238000011282 treatment Methods 0.000 description 10
- 230000015572 biosynthetic process Effects 0.000 description 9
- 238000004891 communication Methods 0.000 description 9
- 239000004033 plastic Substances 0.000 description 8
- 229920003023 plastic Polymers 0.000 description 8
- 239000000463 material Substances 0.000 description 4
- 238000002955 isolation Methods 0.000 description 3
- 230000005012 migration Effects 0.000 description 3
- 238000013508 migration Methods 0.000 description 3
- 239000002253 acid Substances 0.000 description 2
- 230000004913 activation Effects 0.000 description 2
- 230000002706 hydrostatic effect Effects 0.000 description 2
- 238000009434 installation Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 230000004044 response Effects 0.000 description 2
- 239000004734 Polyphenylene sulfide Substances 0.000 description 1
- 230000003213 activating effect Effects 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000007664 blowing Methods 0.000 description 1
- -1 centralizers Substances 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 230000001351 cycling effect Effects 0.000 description 1
- 230000005611 electricity Effects 0.000 description 1
- 239000003673 groundwater Substances 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 229910001120 nichrome Inorganic materials 0.000 description 1
- 229920000069 polyphenylene sulfide Polymers 0.000 description 1
- 239000002002 slurry Substances 0.000 description 1
- 239000002689 soil Substances 0.000 description 1
- 125000006850 spacer group Chemical group 0.000 description 1
- 239000003381 stabilizer Substances 0.000 description 1
- 230000000638 stimulation Effects 0.000 description 1
- 238000003466 welding Methods 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B34/063—Valve or closure with destructible element, e.g. frangible disc
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B34/102—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position
- E21B34/103—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position with a shear pin
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
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 a tubular wall defining an inner tubular surface and 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 method for cementing a tubing string in a wellbore comprising: positioning the tubing string with a stage tool in the wellbore, an annulus being defined between the stage tool and the wellbore wall; expelling a plug from over a cementing port of the stage tool by pressuring up an inner bore of the stage tool; pumping cement into the annulus; and closing the cementing port to hold the cement in the annulus to provide time for the cement to set.
- a stage tool comprising: a main body including a tubular wall with an outer surface and an inner bore extending from a top end to a bottom end; a cementing port through the tubular wall providing fluidic access between the inner bore and the outer surface; a valve for controlling flow through the cementing port between the outer surface and the inner bore; and a plug sealing a circulation path between the valve and the outer surface, the plug being expellable by pressure applied from the inner bore.
- Figure 1 is a schematic sectional view through a wellbore with a tubing string installed therein;
- Figures 2A to 2F 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 activated and 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, Figure 2D is an axial sectional view of the stage tool of Figure 2A in a position closed by a check valve after dissipation of circulation pressure, Figure 2E is an axial sectional view of the stage tool of Figure 2A in a closed and locked position preventing cement circulation and Figure 2F is an axial sectional view of the stage tool of Figure 2A in a closed position, with a back up sleeve 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 of a 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 for cement circulation through the annulus, Figure 3 C is an axial sectional view of the stage tool in a first stage of being closed, Figure 3D is an axial sectional view of the stage tool in a second stage of being closed, and Figure 3 E is an axial sectional view of the stage tool of Figure 3 A in a closed position preventing cement circulation.
- Figures 4A to 4D are view of a kobe useful in the stage tool of Figure 3 A, wherein Figure 4A is a side elevation of the original kobe, Figure 4B is an axial section, Figure 4C is an isometric view of the original kobe and Figure 4D is an isometric view of the kobe after use.
- an extended wellbore 101 may be drilled below the surface casing point 100a to reach a formation of interest 103.
- 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 100a with an active, lower portion of the liner extending out beyond casing point 100a at the bottom of the cased section of the well.
- a tool, a process and an installation are described that permit a liner 104 to be supported in an extended wellbore 101 by stage cementing below any casing point 100a, 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 104 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 110, which separates the string into an upper portion 104b, above (uphole of) the stage tool, and a lower portion, below (downhole of) the stage tool.
- stage tool 1 10 can be positioned at various locations along the liner.
- stage tool 1 10 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 108a, 108b, etc. of the liner.
- cement C may be introduced into the annulus 150 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 101a.
- 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 108a, multistage fracturing components such as sleeve valves, hydraulic ports 108b (i.e. fracing ports) and packers 108c', 108c for zone isolation, a blow out plug 108d, 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 104 including below stage tool 1 10, for example, for circulation or for pressure actuation of active components.
- the string may later be opened to achieve conductivity to the formation.
- 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.
- An example of such a pressure cycle valve is shown in applicants corresponding application WO 1009/132462, published November 5, 1009.
- packers 108c, 108c' 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 1 10 is positioned downhole of uppermost packer 108c' 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 1 10 includes one or more ports 122 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 104b from annulus 150.
- cement may be pumped by fluid circulation as provided through ports 122.
- cement is pumped from above down through the annulus 150 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 122.
- 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 122 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.
- holding the cement in the annulus includes allowing a valve to close and to thereby seal the cement in the annulus.
- 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.
- closing the valve to seal the cement in the annulus includes pressuring up on the inner diameter of the string.
- 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 lock that positively locks the valve in the closed position.
- the valve may include a backup closure that can be closed to seal the cement in the annulus.
- stage tool 210 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 port, a one way check valve for the port, used, when activated, to open the port to fluid flow therethrough in response to reverse circulation and a releasable lock that holds the one-way check valve in an inoperable position until the valve is activated.
- the stage tool further may include a final lock for locking the check valve in a closed position and/or a backup 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 through the wall of the tubing body and a one way check valve for the port, such as one including a spring loaded valve body in the form of a sleeve or a rod (for example, a poppet), used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter).
- the stage tool may further include a releasable lock in the form of an expellable plug, The releasable lock initially releasably locks the check valve in the inactive position.
- the expellable plug is hydraulically actuatable to activate, and in this embodiment release, the check valve for operation.
- the stage tool may further include a final closing sleeve operable to provide a back up closure for the port.
- Stage tool 210 may include a tubular body including a wall 21 1 with an outer surface 212, an inner bore 214 defined by an inner surface 216 of the wall, a first end 218 and a second end 220.
- a port 222 extends through the wall and is openable (Figure 2C) and closable ( Figures 2A, 2B, 2D to 2F) to open and close, respectively, the stage tool to circulation through the port.
- Stage tool 210 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 214 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 218, 220 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 valve body 224 is positioned to act as a closure for port 222 and is moveable relative to the port to manipulate it between the open and the closed positions.
- Valve body 224 may carry or ride over seals 223 that provide a pressure seal between valve body 224 and wall 21 1 to seal against migration of fluid through port 222 past the valve body.
- Valve body 224 acts as a one way check valve. Valve body 224, when activated, is biased to a closed position, but may be moved by fluid pressure to open. Thus, port 222 can be opened and closed without the need to run in a manipulation string or line to open or close it. Valve body 224 is spring-loaded with a biasing spring 226 such that it is normally in a position closing port 222, but can be moved to open the port when the annular pressure PI is greater than the tubing pressure P2 with a differential sufficient to overcome the bias in spring 226.
- valve body 224 may be opened by reverse flow from the annulus to the tubing string such that fluid can pass through port 222 inwardly from annulus 250 to inner bore 214, with valve body 224 acting as a one way check valve and resisting flow outwardly through the ports of the stage tool.
- Valve body 224 may be secured adjacent the port to be positionable, when active, to sense the pressure differential PI vs P2 with annular pressure on one side of seals and tubing pressure on the other side of seals.
- check valve body 224 is also positionable such that this pressure differential is not sensed.
- valve body 224 is installed in an external chamber 225 (sometimes also called a pocket) defined between wall 212 and wall 225a.
- the chamber has an active space in the circulation path between port 222 and an open end 225b wherein seals 223 on the valve body can reside.
- Wall 225a also forms a closed end of the chamber which is positioned adjacent port 222 but diametrically opposite open end 225b, The closed end doesn't have an opening to the exterior of the tool and defines an inactive area for the valve body.
- the valve body When the seals of the valve body are in this inactive area, the valve body is inactive as seals 223 are not exposed to a pressure differential.
- valve body 224 In the inactive position, valve body 224 can be held from moving in the pocket and may be held with seals 223 in the inactive area.
- the valve body When activated, the valve body can slide in the chamber as driven by spring 226 and, when seals 223 are in the active area, the valve body may be driven by pressure.
- the valve body is secured against removal from chamber 225 by stops 227 that reduce the space across the chamber to a dimension through which valve body 223 cannot pass.
- chamber 225 is shown here as a cylindrical side pocket, it is to be understood that it could be annularly formed extending fully or partly around wall 21 1 and in which case the valve body may be a sleeve.
- the check valve may include a lock to positively lock valve body 224 in a port closed position with seals in active position.
- the lock may include a lock ring 229a formed to catch on a ridge (sometimes called an upset) 229b. While here valve body 224 carries lock ring 229a, it may be installed on either the valve body or the chamber, While lock ring 229a is normally biased outwardly to catch on and limit movement past ridge 229b, lock ring 229a is collapsible if sufficient force is applied to move past the ridge.
- the surface of ridge 229b may be ramped, gradually increasing in height, such that it is easier to ride thereover (i.e.
- the locking side 229b' or the surface may have an abrupt height change to create a stop wall over which lock ring 229b cannot readily pass.
- the locking side 229b" of the ridge is abruptly angled to prevent lock ring 229a from returning over the ridge once it has passed into the locked position.
- valve body 224 may be driven from the activated position into the locked position by pressuring up on the inner bore, Pressuring on the inner bore renders P2 greater than PI .
- This differential is communicated to the valve body through port 222 and port 228 and is sensed across seals 223. This drives the valve body up until it is stopped by stops 227.
- Valve body 224 is initially inactive, for example, during run in of the tool such that it is not affected by pressure differentials. However, the valving operation of valve body 224 may be activated when its operation is required.
- valve body 224 may be releasably locked in an inactive position, but may be unlocked to act as a check valve when such operation is required.
- the releasable lock for maintaining the inactive state of valve body 224 is provided by plug 230.
- the plug normally holds valve body 224 in an inactive position, but movement of the plug can release valve body 224 for check valve operation.
- Plug 230 for example, is secured by a shear pin 231 in a position holding valve 224 in an inactive position, where it cannot move and the seals are in the inactive area. However, plug 230 can be moved to free valve body 224 for movement. Plug 230 can be moved by overcoming the holding force of pin 231. In this embodiment, plug 230 is expellable from chamber 225 to activate valve body 224.
- Plug 230 is positioned in chamber 225 and seals the circulation path from port 222 to open end 225b and thus, when in place, isolates external pressure from the check valve. Plug 230 itself, however, can feel pressure differentials thereacross between annular pressure and tubing pressure and can act as a piston and be expelled through the open end when P2 is sufficiently greater than PI to overcome pin 231.
- Plug 230 also serves to close port 222 when valve body 224 is inactive.
- Plug 230 may include seals 226 to ensure that pressure differentials are sensed across the plug and to prevent fluid leakage between outer surface 212 and bore 214.
- the plug can be sized to catch against stop 227 to resist further movement of the plug, if PI becomes greater than P2.
- plug 230 may be moveable by various means, hydraulic means permits the activation of valve body 224 entirely remotely, simply by pressuring up on the inner bore 214.
- valve body 224 is responsive to fluid pressure differentials between P I and P2 and only allows one way flow inwardly when P1>P2.
- the stage tool may include a final closing sleeve 246 to act as a back-up seal for port 222.
- Final closing sleeve 246 may be normally offset from port 222 but is moveable to cover the port, Sleeve 246 may be moveable in various ways, as by a remote system, such as hydraulics, electronics, motors, etc. or by engagement by a shifting tool.
- Final closing sleeve 246 may include seals 258 to seal the interface between sleeve 246 and wall 216 to prevent leaks therebetween.
- a lock such as a body lock ring or ratchet may be employed between sleeve 246 and wall 21 1 to lock sleeve 246 against movement towards reopening.
- Stage tool 210 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 openable position ( Figures 2B to 2D) and a third, cementing port-closed position ( Figure 2E). The stage tool 210 may also be manipulated to a contingency closed position ( Figure 2F),
- 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 an active condition shown in Figures 2C and 2D for stage cementing an annulus about the stage tool.
- Stage tool 210 allows cement to be introduced through the annulus and allows reverse circulation, arrows C, of annular fluids from the annulus into the tubing string though inner bore 214 and then back up toward surface.
- the stage tool acts to permit only flow inwardly to inner bore 214, when pressure PI is sufficient to overcome the force of spring 226. When the pressure PI is insufficient, spring 226 forces the valve into a closed position, to close off communication between the annulus and the inner bore of the tool and, thus, holding the cement in the annulus.
- the tool may be manipulated to a condition shown in Figure 2E to positively lock stage tool in a closed position.
- back up sleeve 246 may be moved to also close port 222 ( Figure 2F).
- 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 plug 230, which also holds a check valve in an inactive state.
- plug 230 Once in position, port 222 is rendered openable by hydraulic actuation, here by blowing out plug 230, to provide fluid communication between the annulus about the tool and inner bore 214.
- the stage tool can be located just above an uppermost packer on a treatment string, such that the annulus 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 222 into inner bore 214.
- port 222 When sufficient cement is introduced to fill the annulus along a selected length, port 222 is closed to stop circulation from the annulus into bore 214. 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 214.
- tool 210 may be installed in a tubular string with its inner bore 214 in communication with the inner diameter of the tubing string.
- the tool will be run into the wellbore with ports 222 closed.
- Figure 2A shows the position of the components of stage tool 210 during run in.
- valve body 224 can be activated to operate as a check valve by removing its releasable 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 valve body may occur at the same time. 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 valve body 224 to the active position by removing plug 230 ( Figure 2B).
- inner bore 214 can be pressured up relative to the annulus about stage tool 210 to overcome the holding force of pin 231 and to blow plug 230 out of the chamber, as shown by arrow E. Removal of plug 230 renders port 222 openable and activates check valve body 224. Plug 230 is expelled outwardly by pump pressure, such that it is out of the way of cementing flows. Plug 230 may be released entirely from the stage tool into the annulus.
- the plug 230 when in place in the stage tool, seals off a cement circulation path from annulus to port 322, but when removed, the cement circulation path is opened through open end 225b, the active area of chamber and port 322 to inner bore 314.
- cement can be pumped down the annulus 250 which creates a pressure P1>P2 sufficient to overcome the check valve and, in particular, to move valve body 224 against the bias of spring 226 to permit circulation, arrows C, through port 222 and into bore 214 toward surface.
- Valve body 224 resists flow in an opposite direction relative to arrows C through port 222 due to the bias in spring 226. In this active position, closing movement of the valve body is stopped when lock ring 229a hits ridge 229b. Spring 226 cannot apply sufficient force to move lock ring 229a over the ridge.
- valve body 224 shuts. This prevents further flow through port 224, unless pressure is increased again in annulus 250.
- the bias in spring 226 can be sufficient to resist the opening of valve body 224 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 222 into inner bore 214.
- 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 may be stopped before the cement begins to pass through port 222,
- valve body 224 can be locked in a closed position.
- the tubing string can be pressured up to cause P2 to exceed PI .
- the seals being positioned in the active area between port 222 and open end 225b of the pocket, feel the pressure differential P2>P1 and drive the valve body toward open end 225b.
- the pressure differential may be sufficient to move lock ring 229a over ridge 229b. Stop 227 prevents the valve body from being expelled from chamber, Due to the abrupt angle on surface 229" and the outward bias of lock ring 229a, it cannot be pushed back over ridge 229b and is, thus, locked in a closed position relative to port 222 ( Figure 2E).
- final closing sleeve 246 can be moved over port 222 to prevent further flow through the port in either direction and to act as a back-up for sleeve 224, This may include engaging final closing sleeve 246 to move it to a cementing port-closed position ( Figure 2F), After the cement is installed and set, wellbore operations may proceed.
- the tubing string inner bore is open and by selection of the inner diameter of sleeve 246 may be fully open to the drift diameter.
- wellbore operations may include wellbore fluid treatments such as stimulation including fracturing. In such an embodiment, 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 214 of tool 210, 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 214 of the stage tool.
- tools, free or connected to strings must be passed through the string inner bore including bore 214 of the stage tool.
- stage tool 310 is shown in Figures 3 A to 3E. That stage tool 310 also contains a pump out plug 320 to control activation of the stage tool's cementing port 322. However, in this embodiment, once plug 320 is pumped out, the cementing port is entirely open to flows in either direction, While there is no check valve illustrated in this embodiment, one could be employed if desired. Stage tool 310 however, does have a closure that can be set to close the port when desired, As with the stage tool of Figure 2A, this stage tool 310 also can be closed by hydraulics without launching a plug into the string.
- the stage tool 310 has a cementing port closure operable through electronics.
- the side pocket cementer may be installed in a stage tool anywhere along the string.
- the tool allows run in with the cementing port closed, cementing of the annulus of a well by opening the cementing port 322 and closing the port with a pressure signal.
- the port has a valve that controls the open and closed condition of the port,
- the port is in the liner wall 31 1 and opens into a side pocket 325 on the wall,
- a side pocket can be arrnularly formed and accommodate a sleeve type valve, or a side pocket can be formed as a non-annular, roughly cylindrical form and accommodate a poppet type valve.
- the side pocket 325 forms therewithal a channel extending between port 322 and the exterior of the stage tool at an open end 325a of the side pocket.
- the port's valve is normally closed, for example during installation of the liner ( Figure 3A).
- the valve is then openable and then is recloseable.
- the valve includes a plug 320 held in the channel by a shear pin 331.
- the plug is in communication on one side with the tubing pressure and on the other with the annular pressure and can therefore be affected by a pressure differential set up between the tubing string and the annulus.
- An end 320a of the plug 320 holds a valve body in the form of a piston 324 in place in the channel.
- Piston 324 is in communication on one side with tubing pressure and. on the other communicates with a chamber 352 at atmospheric pressure, which is normally always lower than both tubing and annular pressures.
- piston 324 is also activated, since it is no longer held in place by end 320a.
- Piston 324 is sized and intended as a closure for port 322. However, even though it is activated it cannot move to close the port until it is signaled to do so. In particular, the applied pressure that removed piston 320 and the subsequent flow of cement creates a hydrostatic pressure greater than that in the atmospheric chamber and that pressure differential holds piston 324 in place, In fact, piston 324 may be pushed against a spring 326. The spring may collapse to bias the piston against the pressure that is higher than atmospheric, but the pressure differential (hydrostatic pressure vs atmospheric pressure) holds the piston from advancing into channel 325 toward port 322.
- a pressure signal is transmitted down the tubing and is communicated to controller 354, here through a port 355 ( Figure 3C).
- This signal could be a maximum pressure (greater than the pressure to shear pin 331) or a plurality of pressure pulses.
- a sensor in controller 354 senses this pressure signal and opens chamber 352 to tubing pressure such that the pressures are equalized across piston ( Figure 3D).
- the spring now has the power to push the piston over the port 322 closing the communication between the tubing and the annulus.
- the force in spring 326 may then act on piston 324 and bias it into a plugging position in channel 325 over the port ( Figure 3B). This closes the port against further flow.
- Controller can take various forms.
- controller 354 includes a circuit board and a battery and a releasable plug in the form of a meltable kobe 356.
- the sensor senses the signal, it communicates with the circuit board and the circuit board in turn activates the batteries that heat a wire 358 configured to melt the kobe material and open the kobe end 356' to expose a channel 356" to conduct fluid pressure P2 to chamber 352.
- the meltable material is plastic and the wire is wrapped around the plastic kobe 356.
- the described valve works with either forward or reverse flows, provided there is an initial forward flow to remove piston 320.
- a meltable kobe 456 is shown in Figures 4A to 4D.
- the kobe includes an inner bore 460 defined by side walls. There is an opening to the bore at a base end 462. The bore is closed by a closed end 464.
- the kobe is installed by its base end 462 in a mount such that a fluid can enter bore 460. The kobe remains closed as long as side walls and end 464 remain intact. However, the kobe can be opened to permit fluid flow through bore 460 by creating an opening in the side walls or end 464.
- a wire 458 is wrapped around side walls in an area through which bore 460 extends.
- wire 458 operates as a thermal knife relative to the material of the kobe's side walls.
- the wire may be of nichrome or other electrical resistance wire.
- the wire may be applied externally, as shown, in multiple wraps or a U-shaped wrap or the wire may be embedded.
- electricity is supplied to the wire which heats it to a temperature suitable to soften and degrade the plastic to break open the closed end 464.
- the internal pressure within bore 460 assists the opening of closed end 464, as the pressure may move the melted plastic away.
- the plastic of the closed end yields and a leak path is formed to release the internal pressure from bore 460 to the chamber.
Abstract
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA2897229A CA2897229A1 (fr) | 2013-01-08 | 2014-01-08 | Outil a etages pour cimentation de trou de forage |
US14/759,394 US20150337624A1 (en) | 2013-01-08 | 2014-01-08 | Stage tool for wellbore cementing |
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201361750098P | 2013-01-08 | 2013-01-08 | |
US201361750092P | 2013-01-08 | 2013-01-08 | |
US61/750,098 | 2013-01-08 | ||
US61/750,092 | 2013-01-08 |
Publications (1)
Publication Number | Publication Date |
---|---|
WO2014107805A1 true WO2014107805A1 (fr) | 2014-07-17 |
Family
ID=51166458
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/CA2014/050007 WO2014107805A1 (fr) | 2013-01-08 | 2014-01-08 | Outil à étages pour cimentation de trou de forage |
Country Status (3)
Country | Link |
---|---|
US (1) | US20150337624A1 (fr) |
CA (1) | CA2897229A1 (fr) |
WO (1) | WO2014107805A1 (fr) |
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2017066877A1 (fr) * | 2015-10-20 | 2017-04-27 | Modern Wellbore Solutions Ltd. | Appareil et procédés de cimentation de puits de forage |
WO2022132183A1 (fr) * | 2020-12-17 | 2022-06-23 | Halliburton Energy Services, Inc. | Cimentier à manchon unique et à plusieurs étapes |
Families Citing this family (13)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9856715B2 (en) * | 2012-03-22 | 2018-01-02 | Daniel Jon Themig | Stage tool for wellbore cementing |
WO2015130258A1 (fr) * | 2014-02-25 | 2015-09-03 | Halliburton Energy Services, Inc. | Bouchon cassant pour commander l'écoulement au travers d'une complétion |
WO2016054748A1 (fr) * | 2014-10-10 | 2016-04-14 | Packers Plus Energy Services Inc. | Outil étagé |
GB201600468D0 (en) * | 2016-01-11 | 2016-02-24 | Paradigm Flow Services Ltd | Fluid discharge apparatus and method of use |
US10214996B2 (en) * | 2016-06-24 | 2019-02-26 | Baker Hughes, A Ge Company, Llc | Method and apparatus to utilize a metal to metal seal |
US20180073328A1 (en) * | 2016-09-13 | 2018-03-15 | Baker Hughes Incorporated | Mechanically lockable and unlockable hydraulically activated valve, borehole system and method |
US10954740B2 (en) | 2016-10-26 | 2021-03-23 | Weatherford Netherlands, B.V. | Top plug with transitionable seal |
US10648272B2 (en) * | 2016-10-26 | 2020-05-12 | Weatherford Technology Holdings, Llc | Casing floatation system with latch-in-plugs |
US20180328139A1 (en) * | 2017-05-12 | 2018-11-15 | Weatherford Technology Holdings, Llc | Temporary Barrier for Inflow Control Device |
WO2020152622A1 (fr) * | 2019-01-24 | 2020-07-30 | The Wellboss Company, Inc. | Outil de manchon de fond de trou |
GB2596005B (en) * | 2019-04-26 | 2022-12-07 | Halliburton Energy Services Inc | Float equipment assemblies and methods to isolate downhole strings |
US11578557B2 (en) * | 2020-08-19 | 2023-02-14 | Saudi Arabian Oil Company | Reverse stage cementing sub |
US20240084682A1 (en) * | 2022-09-09 | 2024-03-14 | Baker Hughes Oilfield Operations Llc | Fracture system and method |
Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3358770A (en) * | 1965-04-16 | 1967-12-19 | Zanal Corp Of Alberta Ltd | Cementing valve for oil well casing |
US4949788A (en) * | 1989-11-08 | 1990-08-21 | Halliburton Company | Well completions using casing valves |
GB2408764B (en) * | 2002-10-02 | 2007-01-31 | Baker Hughes Inc | Cement through side pocket mandrel |
WO2012177358A1 (fr) * | 2011-06-21 | 2012-12-27 | Fike Corporation | Outil de cimentation |
WO2013138896A1 (fr) * | 2012-03-22 | 2013-09-26 | Packers Plus Energy Services Inc. | Outil étagé pour cimentation de puits de forage |
-
2014
- 2014-01-08 CA CA2897229A patent/CA2897229A1/fr not_active Abandoned
- 2014-01-08 WO PCT/CA2014/050007 patent/WO2014107805A1/fr active Application Filing
- 2014-01-08 US US14/759,394 patent/US20150337624A1/en not_active Abandoned
Patent Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3358770A (en) * | 1965-04-16 | 1967-12-19 | Zanal Corp Of Alberta Ltd | Cementing valve for oil well casing |
US4949788A (en) * | 1989-11-08 | 1990-08-21 | Halliburton Company | Well completions using casing valves |
GB2408764B (en) * | 2002-10-02 | 2007-01-31 | Baker Hughes Inc | Cement through side pocket mandrel |
WO2012177358A1 (fr) * | 2011-06-21 | 2012-12-27 | Fike Corporation | Outil de cimentation |
WO2013138896A1 (fr) * | 2012-03-22 | 2013-09-26 | Packers Plus Energy Services Inc. | Outil étagé pour cimentation de puits de forage |
Cited By (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2017066877A1 (fr) * | 2015-10-20 | 2017-04-27 | Modern Wellbore Solutions Ltd. | Appareil et procédés de cimentation de puits de forage |
WO2022132183A1 (fr) * | 2020-12-17 | 2022-06-23 | Halliburton Energy Services, Inc. | Cimentier à manchon unique et à plusieurs étapes |
US11739611B2 (en) | 2020-12-17 | 2023-08-29 | Halliburton Energy Services, Inc. | Single sleeve, multi-stage cementer |
Also Published As
Publication number | Publication date |
---|---|
CA2897229A1 (fr) | 2014-07-17 |
US20150337624A1 (en) | 2015-11-26 |
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