WO2013016822A1 - Wellbore tool with indexing mechanism and method - Google Patents
Wellbore tool with indexing mechanism and method Download PDFInfo
- Publication number
- WO2013016822A1 WO2013016822A1 PCT/CA2012/050516 CA2012050516W WO2013016822A1 WO 2013016822 A1 WO2013016822 A1 WO 2013016822A1 CA 2012050516 W CA2012050516 W CA 2012050516W WO 2013016822 A1 WO2013016822 A1 WO 2013016822A1
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- WO
- WIPO (PCT)
- Prior art keywords
- sleeve
- dog
- tool
- notch
- teeth
- Prior art date
Links
- 230000007246 mechanism Effects 0.000 title claims abstract description 116
- 238000000034 method Methods 0.000 title claims abstract description 32
- 239000012530 fluid Substances 0.000 claims abstract description 57
- 238000009434 installation Methods 0.000 claims description 3
- 241000282472 Canis lupus familiaris Species 0.000 description 139
- 102000005650 Notch Receptors Human genes 0.000 description 75
- 108010070047 Notch Receptors Proteins 0.000 description 75
- 230000015572 biosynthetic process Effects 0.000 description 8
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- 210000004907 gland Anatomy 0.000 description 7
- 238000012856 packing Methods 0.000 description 7
- 239000007787 solid Substances 0.000 description 5
- 230000009471 action Effects 0.000 description 4
- 238000004873 anchoring Methods 0.000 description 3
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- 230000003993 interaction Effects 0.000 description 3
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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
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/06—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting packers
-
- 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
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/004—Indexing systems for guiding relative movement between telescoping parts of downhole tools
-
- 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
- E21B33/12—Packers; Plugs
-
- 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
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
- E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
-
- 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
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/06—Sleeve valves
Definitions
- the invention relates to a wellbore tool with an indexing mechanism and methods using the tool.
- Indexing mechanisms may be useful where a tool is intended to be actuated through a number of positions.
- indexing mechanisms are employed to actuate a tool through a number of inactive positions before it reaches an active position
- indexing mechanisms may be employed in wellbore tools for wellbore fluid treatment such as staged well treatment.
- staged well treatment a wellbore treatment string is deployed to create a plurality of isolated zones within a well and includes a plurality of openable ports that allow selected access to each such isolated zone.
- the treatment string is based on a tubing string and carries a plurality of packers that can be set in the hole to create isolated zones therebetween about the annulus of the tubing string. Between at least selected packers, there are openable ports through the tubing string.
- the ports are selectively openable and include a sleeve thereover with a scalable seat formed in the inner diameter of the sleeve.
- a sleeve thereover with a scalable seat formed in the inner diameter of the sleeve.
- the seat in each sleeve can be formed to accept a ball of a selected diameter but to allow balls of lower diameters to pass.
- such wellbore treatment systems may tend to be limited in the number of zones that may be accessed. For example, if the well diameter dictates that the largest sleeve in a well can at most accept a 33 ⁇ 4" ball, then the well treatment string will generally be limited to approximately eleven sleeves and, therefore, can treat in only eleven stages.
- a wellbore tool comprising: a tubular housing including an upper end, a lower end, and a wall defining an inner bore and an outer surface; a tool mechanism capable of being moved through a plurality of positions; an indexing mechanism for moving the tool mechanism through the plurality of positions, the indexing mechanism including an axis, a first ratchet sleeve including a first plurality of teeth extending substantially parallel to the axis and a notch between each adjacent pair of teeth of the first plurality of teeth, a dog sleeve including an end and a dog extending axially from the end, the dog configured for meshing with the first plurality of teeth of the ratchet sleeve, the dog sleeve and/or the ratchet sleeve being axially and rotationally moveable to permit the dog and the first plurality of teeth to move into and out of engagement and to permit the dog to move from notch to notch along the first
- a wellbore fluid treatment string for installation in a wellbore
- the wellbore fluid treatment string comprising: a sliding sleeve sub including: a tubular housing including an upper end, a lower end and a wall defining an inner bore and an outer surface; a fluid port through the wall of the tubular housing; and a sleeve installed in the inner bore, the sleeve being axially slidable in the inner bore at least from a first position covering the fluid port to a second position exposing the fluid port to the inner bore; a first ratchet sleeve including a first plurality of teeth extending substantially parallel to the axis and a notch between each adjacent pair of teeth of the first plurality of teeth and a final notch after the plurality of teeth; a dog sleeve including a dog extending axially from an end thereof for meshing with the first plurality of teeth, the dog sleeve and/or the
- a method for actuating a downhole tool to an active condition comprising: axially moving a component of an indexing mechanism to move a dog in the downhole tool into and out of meshing engagement with a crown ratchet sleeve, the dog being moved from a first notch to a next notch in the indexing mechanism until the dog reaches a final notch in the indexing mechanism, the tool being configured into an active condition when the dog reaches the final notch.
- Figures 1 to 5 are views of a wellbore tool with an indexing mechanism, wherein:
- Figure 1 is a sectional view through a wellbore tool in a run in position
- Figure 2 is a view of the tool of Figure 1 in a position just beginning movement through an indexing cycle
- Figures 3 A, 3B and 3C are views of the tool following from Figure 2 in a later portion of an indexing cycle;
- Figure 3A is a sectional view taken along the tool's long axis;
- Figure 3B is a side elevation of the tool with the housing cut away to show the indexing mechanism;
- Figure 3C is an enlarged sectional view taken along the tool's long axis;
- Figure 3 A shows a section along the tool between seat segments, which is a sectional view offset from the section shown in Figures 1 and 2, while the sectional orientation of Figure 3C is similar to that shown in Figures 1 and 2 (passing through seat segments);
- Figure 3C shows an actuator in the bore which has just passed through the seat, while the actuator is omitted in Figure 3A for clarity;
- Figures 4A, 4B and 4C are views of the tool following from Figures 3;
- the tool is shown in the active position;
- Figure 4A is a sectional view taken along the tool's long axis and between seat segments;
- Figure 4B is a side elevation of the tool with the housing cut away to show the indexing mechanism;
- Figure 4C is an enlarged sectional view taken along the tool's long axis;
- Figure 4C shows an actuator in the seat, while the actuator is omitted in Figure 4A for clarity;
- Figure 5 is a view following after Figures 4, in a final position
- Figure 6 is a sectional view through another wellbore tool with an indexing mechanism
- Figure 7 is a sectional view through wellbore having positioned therein a fluid treatment assembly and showing another method according to the present invention.
- Figures 8A to 8F are a series of schematic sectional views through a wellbore having positioned therein a fluid treatment assembly showing a method according to the present invention.
- a wellbore tool that is actuable through a plurality of positions may include a tubular housing including an upper end, a lower end, an inner bore and an outer surface; a tool mechanism capable of being moved through a plurality of positions; an indexing mechanism for moving the tool mechanism through the plurality of positions, the indexing mechanism including an axis, a first ratchet sleeve including a first plurality of teeth extending substantially parallel to the axis and a notch between each adjacent pair of teeth of the first plurality of teeth; a dog sleeve including a dog extending axially from an end thereof for meshing with the first plurality of teeth of the ratchet sleeve, the dog sleeve and/or the ratchet sleeve being axially and rotationally moveable to permit the dog and the first plurality of teeth to move into engagement and to permit the dog to move from notch to notch along the first ratchet sleeve; and a biasing member for urging
- the tool may be employed in a wellbore operation wherein the tool is positioned in a well with the housing in a selected position, a force may be applied to an indexing mechanism of the tool to drive a tool mechanism through a plurality of positions, the applied force driving a dog and a plurality of ratchet teeth axially out of engagement and causing a slight relative rotation between the dog and the plurality of ratchet teeth and biasing the dog and the plurality of teeth back into engagement to move the dog from a first position relative to the plurality of teeth to a second position which is slightly rotated from the first position.
- a wellbore tool often has a tubular housing, as a tubular form can pass readily through the wellbore as drilled. Also, tubular forms can be connected by threading into assembled tools or strings deployable into a well. The tool may be run into a well for temporary use or may be installed in a well for longer term use or reuse.
- the wellbore tool may be a packer, an anchor, a sliding sleeve tool, etc.
- the form of the wellbore tool is determined by its tool mechanism.
- a packer includes a tool mechanism including packing mechanism with at least a set and an unset position, the packing mechanism may include an annular packing element, a compression ring, etc.
- the tool mechanism of an anchor includes an anchoring mechanism including at least a set and an unset position, the anchoring mechanism may include a plurality of slips, a slip expander, etc.
- a tool mechanism of a sliding sleeve tool includes a port and a sliding sleeve moveable to open and close the port and the sliding sleeve tool has at least a closed port position and an open port position.
- another sliding sleeve tool has a tool mechanism including a port, a sliding sleeve moveable to open and close the port and a seat for the sliding sleeve to allow ball actuation of the sliding sleeve and in such an embodiment, the sliding sleeve valve may include at least an activated seat position ready to catch a ball (or other plug that is sized to seal in the seat) and an inactive seat position wherein either the seat has not yet formed or the seat is in place but the ball may pass through the seat.
- the form of the tool determines the method that is carried out by the tool.
- the method may include forming an annular seal, anchoring a tool, opening a port or forming a seat.
- the tools and methods of the present invention can be used in various borehole conditions including open holes, cased holes, vertical holes, horizontal holes, straight holes or deviated holes.
- an example of a wellbore sliding sleeve tool 10 is shown that is modified by the passage therethrough of an actuator 40 that configures a sleeve 12 of the tool to be drivable to an open position by a sleeve shifting device 14, while sleeve 12 was not previously configured for such operation, such that during the subsequent passage of a sleeve shifting device, sleeve 12 may be actuated by the sleeve shifting device.
- the reconfiguration of the sleeve to be driven by a sleeve shifting device in this embodiment includes the formation of a seat 16 in non-collapsible form after one or more actuations of the tool, as controlled by an indexing mechanism.
- the indexing mechanism may allow the tool to be advanced through a plurality of positions prior to placement in a position wherein the valve seat is actually configured in a non-collapsible way.
- an actuating mechanism which may include one or more actuators, such as a plurality of balls or other plugs, may cycle the components of the indexing mechanism to advance one position at a time through one or more inactive (also termed passive) positions before finally moving into an active position to form the final, non-collapsible valve seat.
- Figure 1 shows tool 10 in a run in position
- Figure 2 shows an actuator 40 just beginning to move the tool through one indexing cycle
- Figures 3 show the tool about half-way through an indexing cycle, as driven by actuator 40
- Figures 4 show tool 10 in an active position, with sleeve 12 reconfigured with seat 16 formed in a non- collapsible way, and sleeve 12 ready to be driven by a sleeve shifting device 14
- Figure 5 shows tool 10 with sleeve 12 shifted to an open position such that ports 22 are opened for fluid flow therethrough.
- the illustrated sliding sleeve tool includes a tubular housing 20 including an upper end 20a, a lower end 20b, an inner bore 20c and an outer surface 20d.
- the sliding sleeve tool may be formed as a sub with its tubular housing 20 having threaded ends such that it may be connected into a wellbore tubular string.
- the housing defines a long axis x extending through its ends 20a, 20b.
- the sliding sleeve tool includes one or more ports 22 through the wall of the tubular housing where the port, when opened, provides access between inner bore 20c and outer surface 20d.
- the open and closed condition of port 22 is determined by sleeve 12.
- the sleeve is axially moveable in the tubular housing between a position overlying and closing port 22 (Figure 1) and a position retracted from, and therefore opening, port 22 ( Figure 5).
- the sleeve includes seat 16 that is capable of being configured through a plurality of positions including a plurality of inactive positions and an active position.
- seat 16 In the inactive positions ( Figures 1 to 3) seat 16 is collapsible and allows any actuator, such as ball 40 or other plug form, that lands therein to pass.
- seat 16 In the active position, ( Figures 4 and 5) seat 16 is configured in a non-collapsible way and is capable of catching and retaining sleeve shifting device 14, such as a ball or other plug form.
- Sleeve shifting device 14 and actuators 40 may be balls, as shown, or other forms of plugs, that are launchable from surface and sized to have an OD greater than the uncollapsed ID of seat 16.
- the ball 40 may actually be identical to ball 14, but the seat collapses when it is in an inactive configuration to let ball 40 pass, while seat 16, when active, is configured to retain and create a seal with ball 14, which explains the differing operations.
- seat 16 cannot collapse and sleeve shifting device 14 that is sized to be larger than the uncollapsed ID of the seat will be caught in the seat and cannot pass through.
- Sleeve shifting device 14 therefore, lands in and creates a substantial seal with the seat.
- an axially directed force can be applied to sleeve 12 by fluid pressure through the piston effect created by device 14 in seat 16.
- the applied pressure can overcome any holding devices such as shear pins 17 and drives the sleeve to open (Figure 5).
- the indexing mechanism is operable to control the movement of the tool mechanism through the plurality of positions.
- the indexing mechanism is substantially coaxial with axis x.
- the indexing mechanism includes an end of sleeve 12 formed to act as a first ratchet sleeve 12a and includes a first plurality of teeth 28 extending substantially parallel to the axis and a notch 29 between each adjacent pair of teeth of the first plurality of teeth and a notch 29' after the last tooth of the first plurality of teeth.
- the first plurality of teeth 28 are positioned at the end of the sleeve and the teeth extend axially from the end of sleeve 12 with the notches 29 exposed.
- each tooth 28 where the tooth extends from sleeve 12
- the teeth and the notches alternate in a direction about the circumference of the sleeve such that the end of the sleeve 12 has a saw tooth effect.
- the first ratchet sleeve may be termed a crown-type ratchet sleeve.
- Each tooth of the plurality of teeth include a steeply sloped front flank 28a and a moderately sloped rear flank 28b, causing the notches 29 to each be generally V-shaped.
- the first ratchet sleeve may include any number of teeth to form any number of notches 29, 29'.
- the number of notches may be selected to be at least equal to the number of positions through which the indexing mechanism is intended to move in operation.
- notches 29, 29' may be formed about the entire circumference of the end of the sleeve and, as such, depending on the size of each notch and the diameter of the sleeve, there may be a great number of notches.
- the indexing mechanism is formed with a number of notches, for example fifteen, selected to be the maximum number of possible indexing positions the tool is to have, which allows the tool to be set up to have any number of indexing positions up to fifteen.
- All teeth/notches may be similarly formed or there may be differing forms depending on the intended operation of the indexing mechanism.
- the presently illustrated indexing mechanism is intended to impart a final axial shift in the tool, when the indexing mechanism reaches its final position, thus the notches may have differing depths, and in this embodiment, for example, the final notch 29' is positioned at the end of the plurality of teeth and has a depth that it penetrates axially into the end of the greater than the depth of other notches 29.
- the indexing mechanism further includes a dog sleeve 30 including a dog 32 extending axially from an end thereof.
- dog 32 is positioned at the end of dog sleeve 30 and extends fully beyond the end of ratchet sleeve 12a such that its side edges 32a, 32b are fully, axially exposed. At least a portion of the base of dog 32, where the dog extends from sleeve 30, is axially in line with side edges 32a, 32b of the tooth and with the sleeve, such that any force parallel to axis x against the flanks can pass axially through the dog, through its base and into sleeve 30.
- dog sleeve 30 is installed such that dog 32 extends toward teeth 28 of sleeve 12a.
- Dog 32 is sized and shaped to mesh with the first plurality of teeth of the ratchet sleeve 12a.
- dog 32 is sized and shaped to fit into the notches 29, 29' formed by the teeth.
- One, as shown, or both side edges 32a, 32b are sloped toward the outboard tip 32c of the dog such that the outboard end of the dog is wedge shaped.
- dog 32 has a length L extending beyond the end of the sleeve sufficient to protrude into and substantially bottom out in all notches, including final notch 29' that has the greater depth.
- Dog sleeve 30 and ratchet sleeve 12a are installed in a substantially coaxial manner within housing, are positioned axially offset from each other along axis x and are sized to be able to butt against each other at teeth 28 and dog 32.
- the inner/outer diameters at teeth 28 and at dog 32 are selected such that the sleeves cannot telescope into one another at the location of the teeth and, instead, when the sleeves 12a and 30 are axially moved toward each other, the dog and teeth 28 and dog 32 are positioned to butt against, and mesh with, each other.
- dog sleeve 30 at dog 32 has an outer diameter greater than the inner diameter of sleeve 12a at teeth 28.
- first ratchet sleeve 12a is rotationally and axially fixed within housing during indexing, while dog sleeve 30 is moveable both axially toward and away from sleeve 12a and rotationally about axis x, as shown by arrow R in Figure 3B.
- the indexing mechanism further includes a biasing member, such as spring 36, for biasing the parts of the indexing mechanism into one axial position.
- the biasing member may urge the dog and the first plurality of teeth into one of (i) meshing engagement or (ii) out of meshing engagement.
- the biasing member is, however, able to be overcome to allow movement of the dog and the first plurality of teeth axially into the other of (i) meshing engagement or (ii) out of meshing engagement.
- spring 36 urges the dog and the first plurality of teeth into meshing engagement, but spring 36 is able to be overcome by application of force against the spring force of spring 36, to allow movement of the dog and the first plurality of teeth axially away from each other and out of engagement.
- spring 36 is positioned between a shoulder 37 on the housing and a shoulder 38 on dog sleeve 30 and spring 36 acts between these shoulders 37, 38 to bias dog sleeve 30 toward first ratchet sleeve 12a to normally ensure the meshing of dog 32 into a notch 29, 29', but dog 32 can be removed from the notch in which it is positioned by applying a force to compress spring 36 and move sleeve 30 and dog 32 away from sleeve 12a.
- the force may be applied to spring 36 through dog sleeve 30.
- an actuating mechanism may be employed for generating an application of force to act against spring 36.
- the present tool is intended for use downhole and there are a few ways to apply a force against the spring when it is downhole.
- an axial force may be applied by a string conveyed tool, such as on a wireline, a tubing string, etc. Alternately, an axial force may be applied
- a piston that is in place or a piston that is established by landing a plug in a seat may be employed for hydraulic actuation.
- the form of the actuating mechanism may be selected depending on the way in which the force is to be applied.
- the actuating mechanism may include the tool and a gland into which the tool lands and engages.
- the axial force is applied hydraulically and the actuating mechanism includes an actuator, such as ball 40 as noted above, that lands on a ball seat in the tool, which in this embodiment, is the same seat 16 that will eventually move sleeve 12.
- the actuator may be free of any connection to surface such that it may be rapidly and simply conveyed to actuate the tool by being introduced at surface and conveyed by gravity or fluid flow to the seat. Once ball 40 lands on seat 16, an axial force is generated.
- the axial force may be from impact or through a hydraulic force.
- seat 16 may simply act as a ball stop that receives impact force from the ball before the ball passes, or seat 16 may act as a ball stop that holds the ball in a sealing position relative to an uphole portion of the structure on which the seat is carried or alternately seat 16 may itself be formed to create a substantial seal with the ball across the inner diameter of seat and a pressure differential can be created across the seal, wherein the pressure uphole of the ball/seat is greater than the pressure downhole of the ball/seat and a force is applied toward the lower pressure side.
- the force generated through the actuating mechanism, herein ball 40 and seat 16 drives dog 32 to move from notch to notch.
- the force, arrow A in Figure 2 generated by ball 40 landing in seat 16 moves dog 32 out of one notch 29 so the dog can move to another notch and, thereby, advance through the indexing mechanism.
- the force applied by ball 40 in seat 16 acts against spring 36, to remove dog 32 axially from the notch 29 in which it is held by spring 36.
- the indexing mechanism is selected to cause the dog sleeve to rotate, or be rotated along arrow R, to place dog 32 into alignment with a next notch 29 during or after the application of force and, once the applied force is discontinued, spring 36 drives dog 32 back toward first ratchet sleeve 12a and into the next notch. This operation is shown in Figures 2 and 3.
- the actuating mechanism may operate to only temporarily apply force such that the dog sleeve can be released to move into the next notch.
- the string may be slacked off or picked up to discontinue the application of force or the tool may be disengaged from the indexing mechanism.
- the fluid pressure for example, the pressure differential may be dissipated.
- the fluid pressure may be dissipated from surface or any piston effect may be removed.
- ball 40 is able to pass through seat 16 to remove the piston effect.
- the ball may be selected to be deformable to pass through the seat or, as shown, seat 16 may be selected to be deformable to allow the ball to pass, after an appropriate force has been applied.
- Seat 16 is only temporarily deformable and rapidly resets to be ready to catch and seal with another ball such that the dog 32 can be moved to a further notch.
- seat 16 includes a plurality of segments 16a that together form an annular seat structure. The seat segments normally protrude inwardly defining a normal seat ID to catch a suitably sized ball. However, seat segments 16a can be expanded outwardly to enlarge the seat to ID 1 so that ball can pass through.
- segments 16a can be moved axially along the tubular housing to align over openings 44 into which the seat segments can expand outwardly.
- the inner diameter of the seat is enlarged to ID' and the ball can pass and continue down, as shown by arrow B in Figure 3C.
- the indexing mechanism in this embodiment is selected to cause the dog sleeve to rotate or be rotated into alignment with a next notch 29 during or after the application of force.
- the rotation is caused in part by the form of teeth 28, the form of dog 32 and the interaction thereof.
- Teeth 28 and dog 32 mesh axially, for example dog 32 can mesh with teeth 28 by axial movement toward sleeve 12a, but dog 32 can be removed from meshing engagement with teeth 28 by axial movement away from sleeve 12a.
- teeth 28 and dog 32 include sloped surfaces defined by flanks 28b and side edge 32a, respectively, which when making contact, urge rotation of the dog sleeve relative to the first ratchet sleeve.
- the actuating mechanism includes an actuating sleeve 46 on which seat 16 is carried.
- Actuating sleeve 46 is positioned concentrically within first ratchet sleeve 12a and is axially moveable therein between a recessed position relative to teeth 28 and the notches ( Figures 1 and 2) and an extended position ( Figures 3) wherein an end 46a of sleeve 46 extends axially beyond teeth 28. At least in the extended position, end 46a of actuating sleeve 46 is positioned to bear against dog 32.
- first ratchet sleeve 12a and actuating sleeve 46 are both positioned and sized to contact dog 32.
- dog sleeve 30 at dog 32 has an outer diameter greater than the inner diameter of sleeve 12a at teeth 28 and dog sleeve 30 at dog 32 has an inner diameter less than the outer diameter of sleeve 46 at end 46a.
- actuating sleeve 46 can be driven by application of hydraulic force through seat 16 into the extended position and, in so doing, to move axially out and push dog 32 axially away from sleeve 12a and out of engagement with the notch 29 in which it was positioned.
- the bias in spring 36 ensures that dog 32 is biased against sleeve 12a or sleeve 46, depending on whichever sleeve is protruding axially out beyond the other.
- sleeve 46 no longer has a force pushing it down and the bias in spring 36 pushes dog 32 against sleeve 46 to push sleeve 46 back into a recessed position into sleeve 12a until dog 32 comes back to rest against teeth 28 of the first ratchet sleeve.
- Actuating sleeve 46 also includes a plurality of teeth on end 46a, for clarity referenced herein as the second plurality of teeth 48.
- Teeth 48 extend substantially parallel to the axis x.
- Each tooth of the plurality of teeth 48 includes a sloped front flank 48a and a sloped rear flank 48b that merge to form a point 48c.
- Flanks 48a, 48b extend in a direction along the circumference of the sleeve such that the end of the sleeve 46 has a saw tooth effect.
- the second plurality of teeth 48 extend from the sleeve with the flanks 48a, 48b axially exposed.
- the actuating sleeve may also be termed a crown-type ratchet sleeve.
- the number of teeth on actuating sleeve 46 is at least equal to the number of notches 29 on ratchet sleeve 12a.
- Teeth 48 are sized and positioned to correspond with the size and position of the teeth on sleeve 12a. In particular, teeth 48 are sized and positioned such that points 48c line up with notches 29 and, in particular, each point 48c lines up along a rear flank 28b of a tooth, between the tip 28c of a tooth and the bottom of the adjacent notch 29.
- the rotation of sleeve 30 is also caused in part by the interaction of teeth 48 against dog 32.
- Teeth 48 and dog 32 can mesh axially.
- teeth 48 and dog 32 include sloped surfaces 48b and 32a, respectively, which when making contact, urge rotation of the dog sleeve relative to the actuation sleeve and the first ratchet sleeve.
- the sloping surface of flank 48b drives against the dog's sloped side edge 32a (as is clearly shown in Figure 3B) and dog 32 tends to slide along the slope in flank 48b until the dog bottoms out in the space between flanks 48a, 48b.
- sleeve 30 is driven to rotate a small increment and when the force through seat 16 is discontinued, as when segments 16a expand out into openings 44, the bias in spring 36 pushes sleeve 30 against sleeve 46 until it is recessed back into sleeve 12a and dog 32 can come back to bear against the flanks of a tooth 28 of the first ratchet sleeve.
- dog 32 is then urged to slide along the slope of flank 28b until it bottoms out in notch 29. This completes the incremental rotation of dog sleeve 30 and has moved dog 32 from one notch to a next notch.
- sleeve 46 is fully pushed back to a recessed position within sleeve 12 at least to the depth of the notch in which the dog is positioned.
- actuator sleeve 46 also acts with indexing mechanism to configure the seat 16 into an active position ready for use in the opening of ports 22.
- Sleeve 12 for example, carries a lock ring 50 that is initially out of alignment with a gland 52 on sleeve 46.
- the sleeves 12 and 46 can slide axially relative to each other. The lock ring and the gland remain out of alignment as long as the dog rides in notches 29, but when dog 32 enters deeper notch 29', sleeve 46 is driven by dog 32 and the force of spring 36 axially further recessed back into sleeve 12, lock ring 50 aligns with gland 52 and snaps therein to lock the sleeves 12 and 46 together (Figure 4).
- Sleeve 46 can be protected from inadvertent axial movement by provision of a pressure shield 56.
- Pressure shield is sealed by seals 58a against sleeve 12 and by seals 58b against an inner diameter of sleeve 46 to shield the upper end thereof from problematic pressure regimes, as may be generated for example by pressure drops generated by fluid passing through sleeve 46.
- Shield 56 is secured to sleeve 12 and sleeve 46 is axially moveable relative to the shield without restriction until sleeve 46 is locked to sleeve 12.
- the downhole tool can include various components for appropriate operations.
- seals 60 may be positioned between sleeve 12 and housing 20 to prevent fluid leakage and bypass.
- Torque pins such as pins 62, 64 may be employed in slots to control against rotation of the parts. Pin 62 prevents relative rotation of sleeves 12a and 46 and pin 64 prevents rotation of sleeve 30 within housing 20 after ports 22 are opened.
- two dogs 32 can be seen in Figure 3B and the teeth above notch 29' are a separate ratchet rack than the teeth below notch 29'.
- the teethed regions forming independent ratchet racks may be substantially evenly spaced apart about the circumference of the sleeve 12.
- a lock ring 66 and gland 68 may be provided for locking sleeve 12 in a port open position, as shown in Figure 5.
- a mode of construction may be employed that best configures the parts and/or facilitates construction.
- many parts are formed of interconnected subcomponents.
- the tool illustrated in Figures 1 to 5 may be employed in a method to index a tool through a plurality of inactive positions before arriving at an active position.
- the indexing mechanism can be set to undergo any number of cycles, in other words any number of incremental rotations, up to the maximum number of notches 29 before arriving at deep notch 29'.
- the number of cycles may be selected based on the number of balls that are intended to pass through the tool prior to the tool being configured for its main function.
- the indexing mechanism allows tool to be indexed through a plurality of inactive seat positions before a final active, non-collapsible seat is formed. It is noted that from Figure 3B that the illustrated tool would have to be actuated at least four more times before reaching the deeper notch 29' where the final active, non-collapsible seat is formed.
- the final active, non-collapsible seat can be used to drive the sleeve and open ports in the tool to provide fluid access between the tool's inner bore and the tool's outer surface.
- the indexing mechanism is durable since the shear forces that are generated during every cycle of the tool are absorbed through the indexing mechanism also in a fully axial direction, parallel to long axis x, through the dog, through its base and into sleeve 30. All meshing portions of the indexing mechanism also operate in the axial direction, which reduces damage and failure. For example, the axial forces generated by spring are absorbed axially through sleeve 12a and the axial force to move the tool through the indexing positions, which is that force arising from ball 40 landing in seat 16, passes axially through sleeve 46 and into the dog, through its base and into sleeve 30.
- the tool could be configured to actually open the sleeve when moving to the final position of the indexing mechanism.
- FIG. 6 another embodiment of a tool 110 with an indexing mechanism according to the present invention is shown in Figure 6.
- seat 116 operates with deformable plugs. The plug can deform to pass through seat 116 and actuate it from notch to notch.
- first ratchet sleeve 126 carries ratchet form teeth on its opposing ends. Sleeve 126 has both (i) teeth 128 that mesh axially with dog 132 and (ii) teeth 148, that act like teeth 48 of sleeve 46 in the previous embodiment, to convert axial movement to rotational movement and drive a portion of the rotation in the indexing mechanism.
- Teeth 148 mesh with further ratchet teeth 149 rather than directly with dog 132.
- the biasing member 136 acts on sleeve 1 12 to move it axially, along axis x, while dog sleeve 130 remains axially fixed and biasing member 136 urges the teeth of first ratchet sleeve out of engagement with dog 132 but meshing can occur by overcoming the bias in member 136, as by landing a ball temporarily in a seat 116.
- sleeve 1 12 is driven rotationally by actions of the teeth 128, 148, while dog sleeve 130 remains torque locked.
- the tool can be indexed by axial movements of one component relative to another to ratchet the tool through a plurality of inactive positions to arrive at an active position.
- the axial movements alternately mesh and disengage a ratcheting sleeve and a dog to move the indexing mechanism through a plurality of positions wherein the tool is inactive, until dog 132 eventually is positioned in a final position, for example, in a deeper notch 129', which corresponds with an active position of the tool.
- the active position is a position when sleeve 1 12 is moved axially far enough, by dog 132 penetrating into deeper notch 129', to open ports 122 through the wall of the tool's housing 120.
- the tool of Figure 6 could be modified, if desired, to have a collapsible seat and work with non-deformable balls, to have two seats one for actuating through the indexing mechanism and one for being configured to move the sleeve to finally open ports 122, to have the concentric indexing arrangement of Figures 1 to 5, etc.
- the sliding sleeve tools 10, 110 described above may be employed in methods which provide for selective communication to a wellbore for fluid treatment thereof.
- the sliding sleeve tools and the methods provide for staged injection of treatment fluids wherein ports 22, 122 are opened to permit fluid to be injected into selected intervals of the wellbore, while other intervals are closed.
- the method may include running in of a fluid treatment string, the fluid treatment string having ports substantially closed against the passage of fluid
- the indexing mechanism may be used to allow the tool to cycle through a number of inactive positions before arriving at an active position, wherein seat 16 is formed non-collapsible (as in Figures 4) or ports 122 are opened, as in the embodiment of Figure 6.
- the indexing mechanism such as that shown in Figures 1 to 5 or that shown in Figure 6, provides a reliable yet simple solution where the tool must pass through a larger number (more than two or three) inactive positions before arriving at the active state.
- the cycling of the tool through inactive positions does not unseat sleeve 12 from its seals 60, which may be beneficial.
- one or more of the tools with an indexing mechanism may be positioned in a tubing string. Because of their usefulness to increase the possible numbers of sleeves in any tubing string, the sliding sleeve tools may often be installed above one or more sleeves having a set valve seat.
- a wellbore tubing string apparatus may include a tubing string 614 having a long axis and an inner bore 618, a first sleeve 632 in the tubing string inner bore, the first sleeve being moveable along the inner bore from a first position to a second position; a second sleeve 633 in the tubing string inner bore, the second sleeve offset from the first sleeve along the long axis of the tubing string, the second sleeve being moveable along the inner bore from a third position to a fourth position; and a third sleeve 634 offset from the second sleeve and moveable along the tubular string from a fifth position to a sixth position.
- the first sleeve may have an indexing mechanism such as according to one of the embodiments described above, but illustrated according to the embodiment of Figures 1 to 5, having an actuating mechanisms 638 therein, which can be actuated to form a non-collapsible valve seat (shown not yet formed).
- the second and third sleeves may be reconfigurable or, as shown, standard sleeves, with a set valve seat 626a, 626b therein.
- the sleeve furthest downhole, sleeve 634 includes valve seat 626b with a diameter Dl and the sleeve thereabove has valve seat 626a with a diameter D2. Diameter Dl is smaller than D2 and therefore sleeve 634 requires the smaller ball 623 to seal
- Actuating mechanism 638 of sleeve 632 includes a collapsible seat with an inner diameter D2.
- Second sleeve 633 can likewise be actuated to move along tubing string 612 by ball 636 which is sized to pass through all of the sleeves thereabove to land and seal in seat 626a, so that pressure can be built up thereabove.
- ball 636 can pass through the sleeves thereabove, it may actuate those sleeves, for example sleeve 632, to generate valve seats thereon.
- actuating mechanism 638 on sleeve 632 includes the collapsible seat with a diameter D2 and is formed to be axially moved by ball 636 passing thereby cycle the indexing mechanism and create the non-collapsible seat.
- ball 636 does pass through sleeve 632 and the ball can continue to seat 626a.
- the formation of the valve seat on the first seat should be timed or selected to avoid interference with access to the valve seats therebelow.
- the inner diameter of any valve seat formed on the first sleeve should be sized to allow passage thereby of actuators (i.e. plugging balls or other plugs) for the valves therebelow.
- the timing of the actuation of the first sleeve to form a valve seat is delayed until access to all larger diameter valve seats therebelow is no longer necessary, for example all such larger diameter valve seats have been actuated or plugged.
- the wellbore tubing string apparatus may be useful for wellbore fluid treatment and may include ports 617 over or past which sleeves 632, 633, 634 act.
- sleeves 632, 633, 634 are positioned to control the condition of ports 617, note that, as shown, in the closed port position, the sleeves can be positioned over their ports to close the ports against fluid flow therethrough.
- the ports for one or both sleeves may have mounted thereon a cap extending into the tubing string inner bore and in the position permitting fluid flow, their sleeve has engaged against and opened the cap.
- the cap can be opened, for example, by action of the sleeve shearing the cap from its position over the port.
- Each sleeve may control the condition of one or more ports, grouped together or spaced axially apart along a path of travel for that sleeve along the tubing string.
- the ports may have mounted thereover a sliding sleeve and in the position permitting fluid flow, the first sleeve has engaged and moved the sliding sleeve away from the first port.
- the tubing string apparatus may also include outer annular packers 620 to permit the creation of isolated wellbore segments between adjacent packers.
- the packers can be of any desired type to seal between the wellbore and the tubing string.
- at least one of the first, second and third packer is a solid body packer including multiple packing elements. In such a packer, it is desirable that the multiple packing elements are spaced apart.
- a wellbore tubing string apparatus such as that shown in Figure 7 including tools with indexing mechanisms, for example according to one of the various embodiments described herein, may be run into a wellbore and installed as desired. Thereafter the sleeves may be shifted to allow fluid treatment or production through the string.
- the actuator such as a plugging ball may be conveyed to seal against the seat of a sleeve and fluid pressure may be increased to act against the plugging ball and its seat to move the sleeve.
- any indexable sleeves are actuated to form their valve seats.
- an actuator for such purpose may take various forms.
- the actuator is a device launched to also plug a lower sleeve or the actuator may act apart from the plugging ball for lower sleeves.
- a plugging ball for a lower sleeve may actuate the formation of a valve seat on the first sleeve as it passes thereby and after which may land and seal against the valve seat of sleeve with a set valve seat.
- a device from below a configurable sleeve can actuate the sleeve as it passes upwardly through the well.
- a plugging ball when it is reversed by reverse flow of fluids, can move past the first sleeve and actuate the first sleeve to form a valve seat thereon.
- the method can be useful for fluid treatment in a well, wherein the sleeves operate to open or close fluid ports through the tubular.
- the fluid treatment may be a process for borehole stimulation using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, C0 2 , nitrogen and any of these fluids containing proppants, such as for example, sand or bauxite.
- the method can be conducted in an open hole or in a cased hole. In a cased hole, the casing may have to be perforated prior to running the tubing string into the wellbore, in order to provide access to the formation.
- the packers may be of the type known as solid body packers including a solid, extrudable packing element and, in some embodiments, solid body packers include a plurality of extrudable packing elements.
- the methods may therefore, include setting packers about the tubular string and introducing fluids through the tubular string.
- Figures 8A to 8F show a method and system to allow several sliding sleeve valves to be run in a well, and to be selectively activated.
- the system and method employs a tool as described herein that will shift through several "inactive" shifting cycles ( Figures 1 to 3). Once each valve passes through all its passive cycles, it can move to an "active” state ( Figures 4). Once it shifts to the active state, the valve can be shifted from closed to open position ( Figure 5), and thereby allow fluid placement through the open parts from the tubing to the annulus.
- Figure 8A shows a tubing string 714 in a wellbore 712.
- a plurality of packers 720 a-f can be expanded about the tubing string to segment the wellbore into a plurality of zones where the wellbore wall is the exposed formation along the length between packers.
- the string may be considered to have a plurality of intervals 1-5, each interval identified as between each adjacent pair of packers.
- Each interval includes at least one port and a sliding sleeve valve thereover (within the string), which together are designated 716 a-e.
- Sliding sleeve valve 716a includes a ball stop, herein called a seat, that permits a ball- actuated axial force to be applied to move the sleeve away from the ports it covers.
- Sliding sleeve valves 716b to 716e each include therein collapsible seats which are formable to non-collapsible seats when actuated to do so by use of an indexing mechanism for ratcheted movement of the seat between inactive positions where the seat is collapsible and an active position where the seats is activated and formed in a non- collapsible manner.
- the seats of sleeves 716a to 716e may be similar to seat 16 as shown in Figures 1 to 5, that is configurable to a ball retaining diameter upon being ratcheted into an active position, Initially, as shown in Figure 8A, all ports are in the closed position, wherein they are closed by their respective sliding sleeve valves.
- a ball 736 may be pumped onto a seat in the sleeve 716a to open its port in Interval 1.
- a wellbore fluid treatment may be effected through the ports opened by sleeve 716a.
- the ball passes through the sleeves 716c-e in Intervals 5, 4, and 3, they make a passive shift from one inactive notch position to a next inactive notch position.
- the ball passes through Interval 2, it moves the indexing mechanism into a final notch and a non-collapsible ball stop is formed on sleeve 716b on that interval such that it can be shifted to the open position when desired.
- a ball 736a is pumped onto the activated seat in sleeve 716b to open the port in Interval 2.
- they make a passive shift.
- the ball passes through Interval 3, it moves sleeve 716c from an inactive position to an active position so that it can be shifted to the open position when desired.
- ball 736a lands in sleeve 716b in Interval 2
- a ball 736b is pumped onto the activated seat in sleeve 716c to open the port in Interval 3.
- ball 736b lands in sleeve 716c, it opens that sleeve by landing on the ball stop formed in Figure 8C and a wellbore fluid treatment may be effected through the ports opened by sleeve 716c.
- ball 736b passes through the sleeve 716e in Interval 5
- that sleeve makes a passive shift moving from one inactive notch position to a next inactive notch position.
- the ball passes through Interval 4, it moves sleeve 716d from inactive to active, for example, into a final notch, so that sleeve 716d can be shifted to the open position when desired.
- a ball 736c is pumped onto the activated seat of sleeve 716d to open the port in Interval 4 and a fluid treatment may be effect therethrough.
- ball 736c passes through Interval 5, it moves sleeve 716e from inactive to active so that it can be shifted to the open position when desired.
- sleeve 716b of Interval 2 would be installed with the dog in the first notch away from the deeper notch, such that after one actuation thereof (i.e. after one ball passes therethrough), the dog would land in the deeper notch and the seat would be activated in a non-collapsible form.
- the sleeve 716c of Interval 3 would be installed with its dog in the second notch away from the deeper notch, such that after two actuations thereof (i.e. after two balls pass therethrough), the dog would land in the deeper notch and the seat would be activated in a non-collapsible form.
- the other sleeves, 716d and 716e would have their dogs in the third and fourth inactive notches, respectively.
- the formation accessed therethrough can be stimulated as by fracturing. It is noted, therefore, that the formation can be treated in a focused, staged manner. It is also noted that balls 736 - 736d may all be the same size, but still this portion of the formation can be treated in a focused, staged manner, through one port at a time. Note that while only five ports are shown in this segment of the string, more than five ports can be run in a string. The intervals need not be directly adjacent, as shown, but can be spaced and there can be more than one port/sleeve per interval (i.e. at least two ports in one interval that open after the same number of actuations or which open in sequence). Further similar series of ports could be employed above and/or below this series, which use other sized balls. Of course, any sleeves below that use a different sized ball will use a smaller ball that can pass through the illustrated sleeves without actuating them.
- This system and tool of Figures 8 provides a substantially unrestricted internal diameter along the string and allows a single sized ball or other plug to function numerous valves.
- the sleeves may sense the passing of a ball by various mechanisms, for example those as shown including deformable seats, deformable balls that squeeze through a fixed seat, or other mechanisms such a collets, c-rings, etc.
- the system can use combinations of solid ball seats and sleeves with indexing mechanisms.
- the system allows for installations of fluid placement liners of very long length forming large numbers of separately accessible wellbore zones.
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Quick-Acting Or Multi-Walled Pipe Joints (AREA)
- Drilling And Boring (AREA)
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- Earth Drilling (AREA)
Abstract
Description
Claims
Priority Applications (5)
Application Number | Priority Date | Filing Date | Title |
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BR112014002189A BR112014002189A2 (en) | 2011-07-29 | 2012-07-27 | well tool with indexing mechanism and method |
CA2844342A CA2844342C (en) | 2011-07-29 | 2012-07-27 | Wellbore tool with indexing mechanism and method |
US14/112,883 US9574414B2 (en) | 2011-07-29 | 2012-07-27 | Wellbore tool with indexing mechanism and method |
AU2012289710A AU2012289710A1 (en) | 2011-07-29 | 2012-07-27 | Wellbore tool with indexing mechanism and method |
EP12819715.9A EP2737163A4 (en) | 2011-07-29 | 2012-07-27 | Wellbore tool with indexing mechanism and method |
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US201161513448P | 2011-07-29 | 2011-07-29 | |
US61/513,448 | 2011-07-29 |
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WO2013016822A1 true WO2013016822A1 (en) | 2013-02-07 |
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PCT/CA2012/050516 WO2013016822A1 (en) | 2011-07-29 | 2012-07-27 | Wellbore tool with indexing mechanism and method |
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US (1) | US9574414B2 (en) |
EP (1) | EP2737163A4 (en) |
AU (1) | AU2012289710A1 (en) |
BR (1) | BR112014002189A2 (en) |
CA (1) | CA2844342C (en) |
WO (1) | WO2013016822A1 (en) |
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- 2012-07-27 WO PCT/CA2012/050516 patent/WO2013016822A1/en active Application Filing
- 2012-07-27 AU AU2012289710A patent/AU2012289710A1/en not_active Abandoned
- 2012-07-27 US US14/112,883 patent/US9574414B2/en not_active Expired - Fee Related
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US10422202B2 (en) | 2013-06-28 | 2019-09-24 | Innovex Downhole Solutions, Inc. | Linearly indexing wellbore valve |
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CN103982167A (en) * | 2014-05-23 | 2014-08-13 | 湖南唯科拓石油科技服务有限公司 | Staged fracturing apparatus with full-bore ball throwing sliding sleeve |
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Also Published As
Publication number | Publication date |
---|---|
CA2844342A1 (en) | 2013-02-07 |
BR112014002189A2 (en) | 2017-03-01 |
CA2844342C (en) | 2019-09-03 |
AU2012289710A1 (en) | 2014-02-20 |
EP2737163A1 (en) | 2014-06-04 |
US9574414B2 (en) | 2017-02-21 |
EP2737163A4 (en) | 2016-12-14 |
US20140138101A1 (en) | 2014-05-22 |
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