BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1003
`Page 1 of 11
`
`

`
`Us 8,215,411 B2
`Page 2
`
`OTHER PUBLICATIONS
`
`Halliburton brochure; Service Tools, “Delta Stim Lite Sleeve:
`Designed for Selective Multi-Zone Fracturing or Acidizing Through
`the Completion,” H06033, Jul. 2009.
`DSI Brochure; “PBL-Multiple Activation Autolock Bypass Sys-
`tems,” obtained from http://www.dsi-pbl.com, undated.
`DSI, “Autolock Bypass System,” obtained from http://www.dsi-pbl.
`com/, generated on Oct. 28, 2009.
`DSI, “Autolock Bypass System—application,” obtained from http://
`wwW.dsi-pb1.com/, generated on Oct. 28, 2009.
`DSI Brochure, “PBL Multiple Activation Autolock Bypass System,”
`obtained from http://www.dsi-pbl.com/, undated.
`Weatherford Brochure, “WXO and WXA Standard Sliding Sleeves,”
`4603.02, copyrighted 2007-2008.
`First Office Action in copending U.S. Appl. No. 13/087,635, mailed
`Sep. 27, 2011.
`
`Reply to First OfliceAction in copending U.S. Appl. No. 13/087,635,
`filed Dec. 27,2011.
`Final Office Action in copcnding U.S. Appl. No. 13/087,635, mailcd
`Mar. 12, 2012.
`Reply to Final Office Action in copending U.S. Appl. No.
`13/087,635, filed Apr. 7, 2012.
`Notice of Protest in counterpart Canadian Appl. No. 2,716,834,
`mailed Mar. 20, 2012.
`First Requisition in counterpart Canadian Appl. No. 2,716,834,
`mailed Mar. 28, 2012.
`First Office Action in counterpart Canadian Appl. No. 2,716,834,
`mailed Mar. 28, 2012.
`Notice ofAllowance in copendingU.S. Appl. No. 13/087,635, mailed
`Apr. 19,2012.
`
`* cited by examiner
`
`Page 2 of 11
`Page 2 of 11
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`

`
`U.S. Patent
`
`Jul. 10, 2012
`
`Sheet 1 014
`
`US 8,215,411 B2
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`Page 3 of 11
`Page 3 of 11
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`

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`U.S. Patent
`
`Jul. 10, 2012
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`Sheet 2 014
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`US 8,215,411 B2
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`Page 4 of 11
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`U.S. Patent
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`Jul. 10, 2012
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`Sheet 3 014
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`US 8,215,411 B2
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`U.S. Patent
`
`Jul. 10, 2012
`
`Sheet 4 014
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`US 8,215,411 B2
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`Page 6 of 11
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`

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`US 8,215,411 B2
`
`1
`CLUSTER OPENING SLEEVES FOR
`WELLBORE TREATMENT AND METHOD OF
`USE
`
`BACKGROUND
`
`In a staged frac operation, multiple zones of a formation
`need to be isolated sequentially for treatment. To achieve this,
`operators install a frac assembly down the wellbore. Typi-
`cally, the assembly has a top liner packer, open hole packers
`isolating the wellbore into zones, various sliding sleeves, and
`a wellbore isolation Valve. When the zones do not need to be
`
`closed after opening, operators may use single shot sliding
`sleeves for the frac treatment. These types of sleeves are
`usually ball-actuated and lock open once actuated. Another
`type of sleeve is also ball-actuated, but can be shifted closed
`after opening.
`Initially, operators run the frac assembly in the wellbore
`witl1 all of the sliding sleeves closed and with the wellbore
`isolation valve open. Operators then deploy a setting ball to
`close the wellbore isolation valve. This seals off the tubing
`string so the packers can be hydraulically set. At this point,
`operators rig up fracturing surface equipment and pump fluid
`down the wellbore to open a pressure actuated sleeve so a first
`zone can be treated.
`
`As the operation continues, operates drop successively
`larger balls down the tubing string and pump fluid to treat the
`separate zones in stages. When a dropped ball meets its
`matching seat in a sliding sleeve, the pumped fluid forced
`against the seated ball shifts the sleeve open. In turn, the
`seated ball diverts the pumped fluid into the adjacent zone and
`prevents the fluid from passing to lower zones. By dropping
`successively increasing sized balls to actuate corresponding
`sleeves, operators can accurately treat each zone up the well-
`bore.
`
`Because the zones are treated in stages, the lowermost
`sliding sleeve has a ball seat for the smallest sized ball size,
`and successively higher sleeves have larger seats for larger
`balls. In this way, a specific sized dropped ball will pass
`though the seats of upper sleeves and only locate and seal at a
`dcsircd scat in thc tubing string. Dcspitc thc cffcctivcncss of
`such an assembly, practical limitations restrict the number of
`balls that can be run in a single tubing string. Moreover,
`depending on the formation and the zones to be treated,
`operators may need a more versatile assembly that can suit
`their immediate needs.
`The subject matter of the present disclosure is directed to
`overcoming, or at least reducing the effects of, one or more of
`the problems set forth above.
`
`SUMMARY
`
`A cluster of sliding sleeve deploys on a tubing sting in a
`wellbore. Each sliding sleeve has an inner sleeve or insert
`movable from a closed condition to an opened condition.
`When the insert is in the closed condition, the insert prevents
`communication between a bore and a port in the sleeve’s
`housing. To open the sliding sleeve, a plug (ball, dart, or the
`like) is dropped into the sliding sleeve. When reaching the
`sleeve, the ball engages a corresponding seat in the insert to
`actuate the sleeve from the closed condition to the opened
`condition. Keys or dogs of the insert’s seat extend into the
`bore and engage the dropped ball, allowing the insert to be
`moved open with applied fluid pressure. After opening, fluid
`can communicates between the bore and the port.
`When the insert reaches the closed condition, the keys
`retract from the bore and allows the ball to pass through the
`
`2
`
`seat to another sliding sleeve deployed in the wellbore. This
`other sliding sleeve can be a cluster sleeve that opens with the
`same ball and allows the ball to pass therethrough after open-
`ing. Evcntually, howcvcr, thc ball can reach an isolation
`sleeve deployed on the tubing string that opens when the ball
`engages its seat but does not allow the ball to pass there-
`through. Operators can deploy various arrangements of clus-
`ter and isolation sleeves for different sized balls to treat
`desired isolated zones of a formation.
`The foregoing summary is not intended to summarize each
`potential embodiment or every aspect of the present disclo-
`sure.
`
`BRIEF DESCRIPTION OF THE DRAWINGS
`
`10
`
`15
`
`FIG. 1 diagrammatically illustrates a tubing string having
`multiple sleeves according to the present disclosure.
`FIG. 2A illustrates an axial cross-section of a cluster slid-
`
`20
`
`ing sleeve according to the present disclosure in a closed
`condition.
`FIG. 2B illustrates a lateral cross-section of the cluster
`
`sliding sleeve in FIG. 2A.
`FIG. 3A illustrates another axial cross-section of the clus-
`
`25
`
`ter sliding sleeve in an open condition.
`FIG. 3B illustrates a lateral cross-section of the cluster
`
`sliding sleeve in FIG. 3A.
`FIG. 4 illustrates an axial cross-section of an isolation
`
`sliding sleeve according to the present disclosure in an
`opened condition.
`FIGS. 5A-5C schematically illustrate an arrangement of
`cluster sliding sleeves and isolation sliding sleeves in various
`stages of operation.
`FIG. 6 schematically illustrates another arrangement of
`cluster sliding sleeves and isolation sliding sleeves in various
`stages of operation.
`
`DETAILED DESCRIPTION
`
`A tubing string 12 shown in FIG. 1 deploys in a wellbore
`10. The string 12 has an isolation sliding sleeve 50 and cluster
`sliding sleeves 100A-B disposed along its length. A pair of
`packers 40A-B isolate portion of the wellbore 10 into an
`isolated zone. In general, the wellbore 10 can be an opened or
`cased hole, and the packers 40A-B can be any suitable type of
`packer intended to isolate portions of the wellbore into iso-
`lated zones. The sliding sleeves 50 and 100A-B deploy on the
`tubing string 12 between the packers 40A-B and can be used
`to divert treatment fluid to the isolated zone of the surround-
`
`ing formation.
`The tubing string 12 can be part of a frac assembly, for
`example, having a top liner packer (not shown), a wellbore
`isolation valve (not shown), and other packers and sleeves
`(not shown) in addition to those shown. The wellbore 10 can
`have casing perforations 14 at various points. As convention-
`ally done, operators deploy a setting ball to close the wellbore
`isolation valve, rig up fracturing surface equipment, pump
`fluid down the wellbore, and open a pressure actuated sleeve
`so a first zone can be treated. Then, in a later stage of the
`operation, operators actuate the sliding sleeves 50 and
`100A-B between the packers 40A-B to treat the isolated zone
`depicted in FIG. 1.
`Briefly, the isolation sleeve 50 has a seat (not shown).
`When operators drop a specifically sized plug (e.g., ball, dart,
`or the like) down the tubing string 12, the plug engages the
`isolation sleeve’s seat. (For purposes of the present disclo-
`sure, the plug is described as a ball, although the plug can be
`any other acceptable device.) As fluid is pumped by a pump
`
`30
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`Page 7 of 11
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`

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`US 8,215,411 B2
`
`3
`system 35 down the tubing string 12, the seated ball opens the
`isolation sleeve 50 so the pumped fluid can be diverted out
`ports to the surrounding wellbore 10 between packers 40A-B.
`In contrast to the isolation sleeve 50, the cluster sleeves
`100A-B have corresponding seats (not shown) according to
`the present disclosure. When the specifically sized ball is
`dropped down the tubing string 12 to engage the isolation
`sleeve 50, the dropped ball passes through the cluster sleeves
`100A-B, but opens these sleeves 100A-B without perma-
`nently seating therein. In this way, one sized ball can be
`dropped down the tubing string 12 to open a cluster of sliding
`sleeves 50 and 100A-B to treat an isolated zone at particular
`poi11ts (such as adjacent certain perforations 14).
`With a general understanding ofhow the sliding sleeves 50
`and 100 are used, attention now turns to details of a cluster
`sleeve 100 shown in FIGS. 2A-2B and FIGS. 3A-3B a11d an
`isolation sleeve 50 shown in FIG. 4.
`
`Turning first to FIGS. 2A through 3B, the cluster sleeve
`100 has a housing 110 defining a bore 102 therethrough and
`having ends 104/106 for coupling to a tubing string. Inside the
`housing 110, an inner sleeve or insert 120 can move from a
`closed condition (FIG. 2A) to an open condition (FIG. 3A)
`when an appropriately sized ball 130 (or other form ofplug)
`is passed through the sliding sleeve 100.
`In the closed condition (FIG. 2A), the insert 120 covers
`external ports 112 in the housing 110, and peripheral seals
`126 on the insert 120 keep fluid in the bore 102 from passing
`through these ports 112. In the open condition (FIG. 3A), the
`insert 120 is moved away from the external ports 112 so that
`fluid in the bore 102 can pass out through the ports 112 to the
`surrounding annulus and treat the adjacent formation.
`To move the insert 120, the ball 130 dropped down the
`tubing string from the surface engages a seat 140 inside the
`insert 120. The seat 140 includes a plurality of keys or dogs
`142 disposed in slots 122 defined in the insert 120. When the
`sleeve 120 is in the closed condition (FIG. 2A), the keys 142
`extend out into the internal bore 102 of the cluster sleeve 100.
`As best shown in the cross-section of FIG. 2B, the inside wall
`ofthe housing 110 pushes these keys 142 into the bore 102 so
`that the keys 142 define a restricted opening with a diameter
`(d) smaller than the intended diameter (D) ofthe dropped ball.
`As shown, four such keys 142 can be used, although the seat
`140 can have any suitable number ofkeys 142.As also shown,
`the proximate ends 144 ofthe keys 142 can have shoulders to
`catch inside the sleeve’s slots 122 to prevent the keys 142
`from passing out ofthe slots 122.
`When the dropped ball 130 reaches the seat 140 in the
`closed condition, fluid pressure pumped down through the
`sleeve’s bore 102 forces against the obstructing ball 130.
`Eventually, the force releases the insert 120 from a catch 128
`that initially holds it in its closed condition. As shown, the
`catch 128 can be a shear ring, although a collet arrangement
`or other device known in the art could be used to hold the
`insert 120 temporarily in its closed condition.
`Continued fluid pressure then moves the freed insert 120
`toward the open condition (FIG. 3A). Upon reaching the
`lower extremity, a lock 124 disposed around the insert 120
`locks the insert 120 in place. For example, the lock 124 can be
`a snap ring that reaches a circumferential slot 116 in the
`housing 110 and expands outward to lock the insert 120 in
`place. Although the lock 124 is shown as a snap ring 124 is
`shown, the insert 120 can use a shear ring or other device
`known in the art to lock the insert 120 in place.
`When the insert 120 reaches its opened condition, the keys
`124 eventually reach another circumferential slot 114 in the
`housing 110. As best shown in FIG. 3B, the keys 124 retract
`slightly in the insert 120 when they reach the slot 114. This
`
`4
`
`allows the ball 130 to move or be pushed past the keys 124 so
`the ball 130 can travel out ofthe cluster sleeve 100 and further
`
`downhole (to another cluster sleeve or an isolation sleeve).
`When the insert 120 is moved from the closed to the opened
`condition, the seals 126 on the insert 120 are moved past the
`external ports 112. A reverse arrangement could also be used
`in which the seals 126 are disposed on the inside of the
`housing 110 and engage the outside of the insert 120. As
`shown, the ports 112 preferably have insets 113 with small
`orifices that produce a pressure differential that helps when
`moving the insert 120. Once the insert 120 is moved, however,
`these insets 113, which can be made of aluminum or the like,
`are forced out of the port 112 when fluid pressure is applied
`during a frac operation or the like. Therefore, the ports 112
`eventually become exposed to the bore 102 so fluid passing
`through the bore 102 can communicate through the exposed
`ports 112 to the surrounding annulus outside the cluster
`sleeve 100.
`
`10
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`15
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`20
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`As noted previously, the dropped ball 130 can pass through
`the sleeve 100 to open it so the ball 130 can pass further
`downhole to another cluster sleeve or to an isolation sleeve. In
`
`25
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`30
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`35
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`40
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`45
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`50
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`55
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`60
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`65
`
`FIG. 4, an isolation sleeve 50 is shown in an opened condition.
`The isolation sleeve 50 defines a bore 52 therethrough, and an
`insert 54 can be moved from a closed condition to an open
`condition (as shown). The dropped ball 130 with its specific
`diameter is intended to land on an appropriately sized ball seat
`56 within the insert 54. Once seated, the ball 130 typically
`seals in the seat 56 and does not allow fluid pressure to pass
`further downhole from the sleeve 50. The fluid pres sure com-
`municated down the isolation sleeve 50 therefore forces
`
`against the seated ball 130 and moves the insert 54 open. As
`shown, openings in the insert 54 in the open condition com-
`municate with external ports 56 in the isolation sleeve 50 to
`allow fluid in the sleeve’s bore 52 to pass out to the surround-
`ing annulus. Seals 57, such as chevron seals, on the inside of
`the bore 52 can be used to seal the external ports 56 and the
`insert 54. One suitable example for the isolation sleeve 50 is
`the Single-Shot ZoneSelect Sleeve available from Weather-
`ford.
`
`As mentioned previously, several cluster sleeves 100 can
`be used together on a tubing string and can be used in con-
`junction with isolation sleeves 50. FIGS. 5A-5C show an
`exemplary arrangement in which three zones A-C can be
`separately treated by fluid pumped down a tubing string 12
`using multiple cluster sleeves 100, isolation sleeves 50, and
`different sized balls 130. Although not shown, packers or
`other devices can be used to isolate the zones A-C from one
`
`another. Moreover, packers can be used to independently
`isolate each of the various sleeves in the same zone from one
`
`another, depending on the implementation.
`As shown in FIG. 5A, a first zone A (the lowermost) has an
`isolation sleeve 50A and two cluster sleeves 100A-1 and
`
`100A-2 in this example. These are designed for use with a first
`ball 130A having a specific size. Because this first zone A is
`below sleeves in the other zones B-C, the first ball 130A has
`the smallest diameter so it can pass through the upper sleeves
`of these zones B-C without opening them. As depicted, the
`dropped ball 130A has passed through the isolation sleeves
`50B/50C and cluster sleeves 100B/100C in the upper zones
`B-C. At the lowermost zone A, however, the dropped ball
`130A has opened first and second cluster sleeves 100A-1/
`100A-2 according to the process described above and has
`traveled to the isolation sleeve 50A. Fluid pumped down the
`tubing string can be diverted out the ports 106 in these sleeves
`100A-1/100A-2 to the surrounding annulus for this zone A.
`In a subsequent stage shown in FIG. 5B, the first ball 130A
`has seated in the isolation sleeve 50A, opening its ports 56 to
`
`Page 8 of 11
`Page 8 of 11
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`

`
`US 8,215,411 B2
`
`5
`the surrounding annulus and sealing fluid communication
`past the seated ball 130A to any lower portion of the tubing
`string 12. As depicted, a second ball 130B having a larger
`diameter than the first has been dropped. This ball 130B is
`intended to pass through the sleeves 50C/100C of the upper-
`most zone C, but is intended to open the sleeves 50B/100B in
`the intermediate zone B.
`
`the dropped second ball 130B has passed
`As shown,
`through the upper zone C without opening the sleeves .Yet, the
`second ball 130B has opened first and second cluster sleeves
`100B-1/100B-2 in the intermediate zone B as it travels to the
`
`isolation sleeve 50B. Finally, as shown in FIG. 5C, the second
`ball 130B has seated in the isolation sleeve 50B, and a third
`ball 130C of an even greater diameter has been dropped to
`open the sleeves 50C/100C in the upper most zone C.
`The arrangement of sleeves 50/100 depicted in FIGS.
`5A-5C is illustrative. Depending on the particular implemen-
`tation and the treatment desired, any number of cluster
`sleeves 100 can be arranged in any number of zones. In
`addition, any number of isolation sleeves 50 can be disposed
`between cluster sleeves 100 or may not be used in some
`instances. In any event, by using the cluster sleeves 100,
`operators can open several sleeves 100 with one-sized ball to
`initiate a frac treatment in one cluster along an isolated well-
`bore zone.
`
`The arrangement in FIGS. 5A-5C relied on consecutive
`activation of the sliding sleeves 50/100 by dropping ever
`increasing sized balls 130 to actuate ever higher sleeves
`50/100. However, depending on the implementation, an
`upper sleeve can be opened by and pass a smaller sized ball
`while later passing a larger sized ball for opening a lower
`sleeve. This can enable operators to treat multiple isolated
`zones at the same time, with a different number of sleeves
`open at a given time, and with a non-consecutive arrangement
`of sleeves open and closed.
`For example, FIG. 6 schematically illustrates an arrange-
`ment of sliding sleeves 50/100 with a non-consecutive form
`of activation. The cluster sleeves 100(C1-C3) and two isola-
`tion sleeves 50(IA & IB) are shown deployed on a tubing
`string 12. Dropping of two balls 130(A & B) with different
`sizes are illustrated in two stages for this example. In the first
`stage, operators drop the smaller ball 130(A). As it travels,
`ball 130(A) opens cluster sleeve 100(C3), passes through
`cluster sleeve 100(C2) without engaging its seat for opening
`it, passes through isolation sleeve 50(IB) without engaging its
`seat for opening it, engages the seat in cluster sleeve 100(C1)
`and opens it, and finally engages the isolation sleeve 50(IA) to
`open and seal it. Fluid treatment down the tubing string after
`this first stage will treat portion of the wellbore adjacent the
`third cluster sleeve 100(C3), the first cluster sleeve 100(C1),
`and the lower isolation sleeve 50(IA).
`In the second stage, operators drop the larger ball 130(B).
`As it travels, ball 130(B) passes through open cluster sleeve
`100(C3). This is possible if the tolerances between the
`dropped balls 130(A & B) and the seat in the cluster sleeve
`100(C3) are suitably configured. In particular, the seat in
`sleeve 100(C3) can engage the smaller ball 130(A) when the
`C3 ’s insert has the closed condition. This allows C3 ’s insert to
`
`open and let the smaller ball 130(A) pass therethrough. Then,
`C3 ’s seat can pass the larger ball 130(B) when C3 ’s insert has
`the opened condition because the seat’s key are retracted.
`After passing through the third cluster sleeve 100(C3)
`while it is open, the larger ball 130(B) then opens and passes
`through cluster sleeve 100(C2), and opens and seals in isola-
`tion sleeve 50(IB). Further downhole, the first cluster sleeve
`l00(C1) and lower isolation sleeve 50(IA) remain open by
`they are sealed off by the larger ball 130(B) seated in the
`
`10
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`15
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`20
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`25
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`6
`upper isolation sleeve 50(IB). Fluid treatment at this point can
`treat the portions ofthe formation adjacent sleeves 50(IB) and
`100(C2 & C3).
`As this example briefly shows, operators can arrange vari-
`ous cluster sleeves and isolation sleeves and choose various
`
`sized balls to actuate the sliding sleeves in non-consecutive
`forms of activation. The various arrangements that can be
`achieved will depend on the sizes of balls selected, the toler-
`ance of seats intended to open with smaller balls yet pass one
`or more larger balls, the size of the tubing strings, and other
`like considerations.
`
`For purposes of illustration, a deployment of cluster
`sleeves 100 can use any number of differently sized plugs,
`balls, darts or the like. For example, the diameters ofballs 130
`can range from 1-inch to 3%-inch with various step differ-
`ences in diameters between individual balls 130. In general,
`the keys 142 when extended can be configured to have %-inch
`interference fit to engage a corresponding ball 130. However,
`the tolerance in diameters for the keys 142 and balls 130
`depends on the number of balls 130 to be used, the overall
`diameter of the tubing string 12, and the differences in diam-
`eter between the balls 130.
`The foregoing description of preferred and other embodi-
`ments is not intended to limit or restrict the scope or applica-
`bility of the inventive concepts conceived of by the Appli-
`cants. In exchange for disclosing the inventive concepts
`contained herein,
`the Applicants desire all patent rights
`afforded by the appended claims. Therefore, it is intended that
`the appended claims include all modifications and alterations
`to the full extent that they come within the scope of the
`following claims or the equivalents thereof.
`What is claimed is:
`
`1. A downhole sliding sleeve, comprising:
`a housing defining a bore and defining a port communicat-
`ing the bore outside the housing;
`an insert disposed in the bore and being movable from a
`closed condition to an opened condition, the insert in the
`closed condition preventing fluid communication
`between the bore and the port, the insert in the opened
`condition permitting fluid communication between the
`bore and the port;
`a seat movably disposed in the insert, the seat when the
`insert is in the closed condition extending at least par-
`tially into the bore and engaging a plug disposed in the
`bore to move the insert from the closed condition to the
`
`opened condition, the seat when the insert is in the
`opened condition retracting from the bore and releasing
`the plug; and
`an inset member being temporarily disposed in the port, the
`inset member at least temporarily maintaining fluid
`pressure in the bore and allowing the maintained fluid
`pressure to act against the plug and open at least one
`additional downhole sliding sleeve.
`2. The sliding sleeve of claim 1, wherein the insert defines
`slots, and wherein the seat comprises a plurality of keys
`movable between extended and retracted positions in the
`slots.
`
`3. The sliding sleeve of claim 1, wherein the plug com-
`prises a ball.
`4. The sliding sleeve of claim 1, wherein the insert com-
`prises seals disposed thereon and sealing offthe port when the
`insert is in the closed condition.
`
`5. The sliding sleeve of claim 1, wherein the bore com-
`prises seals disposed on either side of the port and sealing
`against the insert when in the closed condition.
`6. The sliding sleeve of claim 1, further comprising a catch
`temporarily holding the insert in the closed condition.
`
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`US 8,215,411 B2
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`7
`7. The sliding sleeve of claim 6, wherein the catch com-
`prises a shear ring engaging an end of the insert in the closed
`condition.
`
`8. The sliding sleeve of claim 1, further comprising a lock
`locking the insert in the opened condition.
`9. The sliding sleeve ofclaim 8, wherein the lock comprises
`a snap ring disposed about the insert and expandable into a
`slot in the bore when the insert is in the opened condition.
`10. The sliding sleeve ofclaim 1, wherein the inset member
`defines an orifice communicating the bore outside the hous-
`ing through the inset member, the orifice producing a pres sure
`differential across the insert in the closed condition and facili-
`
`tating movement oftlie insert from the closed condition to the
`opened condition.
`11. The sliding sleeve ofclaim 1, wherein the inset member
`dislodges from the port when subjected to fluid pressure for a
`frac operation in the bore.
`12. A downhole well fluid system, comprising:
`first cluster sleeves disposed on a tubing string deployable
`in a wellbore,
`each of the first cluster sleeves being actuatable by a first
`plug deployable down the tubing string,
`each of the first cluster sleeves being actuatable from a
`closed condition to an opened condition, the closed con-
`dition preventing fluid communication between a port in
`the first cluster sleeve and the wellbore, the opened
`condition permitting fluid communication between the
`port in the first cluster sleeve and the wellbore,
`each of the first cluster sleeves in the opened condition
`allowing the first plug to pass therethrough, and
`each of the first cluster sleeves having an inset member
`being temporarily disposed in the port, the inset member
`for a given one of the first cluster sleeves at least tem-
`porarily maintaining fluid pressure in the bore and
`allowing the maintained fluid pressure to act against the
`first plug at least until the first cluster sleeves are opened.
`13. The system of claim 12, wherein the first plug com-
`prises a ball.
`14. The system ofclaim 12, wherein each ofthe first cluster
`sleeves comprises:
`a housing defining a bore and defining the port communi-
`cating the bore outside the housing;
`an insert disposed in the bore and being movable from the
`closed condition to the opened condition, the insert in
`the closed condition preventing fluid communication
`between the bore and the port, the insert in the opened
`condition permitting fluid communication between the
`bore and the port; and
`a seat movably disposed in the insert, the seat when the
`insert is in the closed condition extending at least par-
`tially into the bore and engaging a plug disposed in the
`bore to move the insert from the closed condition to the
`
`opened condition, the seat when the insert is in the
`opened condition retracting from the bore and releasing
`the plug.
`15. The system of claim 12, further comprising an isolation
`sleeve disposed on the tubing string and being actuatable
`from a closed condition to an opened condition, the closed
`condition preventing fluid communication between the isola-
`tion sleeve and the wellbore, the opened condition permitting
`fluid communication between the isolation sleeve and the
`
`wellbore, the isolation sleeve having a seat engaging the first
`plug and preventing fluid communication therepast.
`16. The system of claim 12, further comprising:
`second cluster sleeves disposed on the tubing string,
`each of the second cluster sleeves being actuatable by a
`second plug deployed down the tubing string,
`
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`each of the second cluster sleeves being actuatable from a
`closed condition to an opened condition, the closed con-
`dition preventing fluid communication between the sec-
`ond cluster sleeve and the wellbore, the opened condi-
`tion permitting fluid communication between the
`second cluster sleeve and the wellbore,
`each of the second cluster sleeves in the opened condition
`allowing the second plug to pass therethrough.
`17. The system of claim 16, wherein each of the second
`cluster sleeves pass the first plug therethrough without being
`actuated.
`
`18. The system of claim 16, further comprising an isolation
`sleeve disposed on the tubing string and being actuatable
`from a closed condition to an opened condition, the closed
`condition preventing fluid communication between the isola-
`tion sleeve and the wellbore, the opened condition permitting
`fluid communication between the isolation sleeve and the
`
`wellbore, the isolation sleeve having a seat engaging the
`second plug and preventing fluid communication therepast.
`19. The system of claim 16, wherein each of the second
`cluster sleeves comprises an inset member being temporarily
`disposed in a port of the second cluster sleeves, the inset
`member for a given one of the second cluster sleeves at least
`temporarily maintaining fluid pressure in the bore and allow-
`ing the maintained fluid pressure to act against the second
`plug and open at least until the second cluster sleeves are
`opened.
`20. The system of claim 12, wherein the inset member for
`each of the first cluster sleeves defines an orifice communi-
`
`cating the bore outside the first cluster sleeve through the inset
`member, the orifice producing a pressure differential across
`an insert in the closed condition in the first cluster sleeve and
`
`facilitating movement of the insert from the closed condition
`to the opened condition in the first cluster sleeve.
`21. The system of claim 12, wherein the inset member for
`each of the first cluster sleeves dislodges from the port in the
`first cluster sleeve when subjected to fluid pressure for a frac
`operation in a bore of the first cluster sleeve.
`22. A wellbore fluid treatment method, comprising:
`deploying first and second sliding sleeves on a tubing string
`in a wellbore, each of the sliding sleeves having a closed
`condition preventing fluid communication between
`ports in the sliding sleeves and the wellbore;
`dropping a first plug down the tubing string;
`changing the first sliding sleeve to an open condition allow-
`ing fluid communication between the port in the first
`sl 'ding sleeve and the wellbore by engaging the first plug
`on a first seat disposed in the first sliding sleeve;
`pass'ng the first plug through the first sliding sleeve in the
`opened condition to the second sliding sleeve: and
`at least temporarily maintaining fluid pressure in the first
`sl'ding sleeve in the opened condition to open at least
`one additional sliding sleeve with the first plug engaging
`an additional seat disposed in the at least one additional
`sl'ding sleeve by restricting fluid flow through the port
`w'th an inset member disposed in the port of the first
`sl'ding sleeve.
`23. The method of claim 22, wherein the at least one
`additional sliding sleeve comprises the second sliding sleeve
`having a second seat as the additional seat, and wherein the
`methoc further comprises changing the second sleeve to an
`open condition allowing fluid communication between the
`second sliding sleeve and the wellbore by engaging the first
`plug on the second seat disposed in the second sliding sleeve.
`24. The method ofclaim 23, further comprising passing the
`first plug through the second sliding sleeve in the opened
`condition.
`
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`US 8,215,411 B2
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`9
`25. The method ofclaim 23, further comprising sealing the
`first plug on the second seat of the second sliding sleeve and
`preventing fluid communication therethrough.
`26. Thc mcthod of claim 22, further comprising:
`deploying a third sliding sleeve on the tubing string in the
`wellbore, the third sliding sleeve havin