BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1001
`
`Page 1 of 15
`
`

`
`US 8,657,009 B2
`Page2
`
`8/2004 Echols et al.
`6,782,948 B2
`6/2005 Fehretal.
`6,907,936 B2
`10/2005 Haughom et al.
`6,951,331 B2
`6/2006 Surjaatmadja
`7,066,265 B2
`9/2006 T11e1111g 61111,
`7,108,067 132*
`12/2006 TuI11eret 31,.
`7,152,678 B2
`7/2007 Sur]aatm2_1dJaeta1.
`7,243,723 B2
`5/2008 RY11eWS1<1 ~~~~~~~~~~~~~~~~~~~ ~~ 166/313
`7,377,321 132*
`7,431,091 132* 10/2008 T11e1111g 61111,
`166/317
`7,748,460 132*
`7/2010 Them1geta1.
`166/317
`8,291,980 132* 10/2012 Fay ~~~~~~~~~ ~~
`166/317
`8,397,820 132*
`3/2013 Fe111e1111~
`166/3321
`2004/0000405 A1*
`1/2004 141111111011 61111,
`~~~~~~~~~~~~ ~~ 155/373
`2005/0061508 A1
`3/2005 SurJaatmz_1dJa
`:1:
`§f1eWS1<1:e“11~ ~~~~~~~~~~ ~~
`“WY.
`~~~~~~ ~~
`2009/0084553 A1*
`4/2009 Ryt1ewsk1eta1.
`166/305.1
`2010/0132959 A1*
`6/2010 Tinker ..... ..
`. 166/386
`2011/0180274 A1*
`7/2011 Wangetal.
`....... ..
`166/386
`2012/0085548 A1*
`4/2012 Fleckenstein etal.
`II. 166/373
`,,
`2013/0043042 A1
`2/2013 F1°reSe“*1' """""""" " 166/373
`* cited by examiner
`
`
`
`~~~~~~~~~~~~~~ ~~ 166/317
`
`Page 2 of 15
`Page 2 of 15
`
`(56)
`
`References Cited
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`U,S, PATENT DOCUMENTS
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`............ .. 166/291
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`3/1997 Hennig et 31,
`5,609,178 A
`9/1998 J0rda_n,Jr,
`5,810,082 A
`4/1999 Wiemersetal.
`5,894,888 A
`5,960,881 A * 10/1999 Allamon etal.
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`12/1999 Whiteleyetal,
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`4/2000 Zeltman etal.
`6,053,250 A *
`4/2000 Echols ........................ .. 166/317
`6,065,541 A
`5/2000 Allen
`6,109,354 A
`8/2000 R1-nggenberg 6,61,
`6,189,619 B1
`2/2001 Wyatteta1.
`6,220,357 B1
`4/2001 Carmichael etal.
`6,388,577 B1
`5/2662 Cmtensen
`6,390,200 B1
`5/2002 Allamon
`6,446,727 B1
`9/2002 Zemlak et al.
`6,651,743 B2
`11/2003 Szarka
`6,695,057 B2
`2/2004 Ingrametal.
`6,695,066 B2*
`2/2004 Allamon et al.
`
`............ .. 166/386
`
`

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`U.S. Patent
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`U.S. Patent
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`Feb. 25, 2014
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`Sheet 2 of6
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`Page 4 of 15
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`Page 8 of 15
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`

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`US 8,657,009 B2
`
`2
`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`CROSS REFERENCE TO RELATED
`APPLICATIONS
`
`This application is a continuation application of 12/830,
`412 filed Jul. 5, 2010. U.S. Ser. No. 12/830,412 is a continu-
`ation-in-part application of 12/208,463, filed Sep. 11, 2008,
`now U.S. Pat. No. 7,748,460 issued Jul. 6, 2010, which is a
`continuation of U.S. application Ser. No. 11/403,957 filed
`Apr. 14, 2006, now U.S. Pat. No. 7,431,091, issued Oct. 7,
`2008, which is a divisional application of U.S. application
`Ser. No. 10/604,807 filed Aug. 19, 2003, now U.S. Pat. No.
`7,108,067, issued Sep. 19, 2006. This application also claims
`priority through the above-noted applications to U.S. provi-
`sional application Ser. No. 60/404,783 filed Aug. 21, 2002.
`
`FIELD OF THE INVENTION
`
`The invention relates to a method and apparatus for well-
`bore fluid treatment and, in particular, to a method and appa-
`ratus for selective flow control to a wellbore for fluid treat-
`ment.
`
`BACKGROUND OF THE INVENTION
`
`An oil or gas well relies on inflow of petroleum products.
`When drilling an oil or gas well, an operator may decide to
`leave productive intervals uncased (open hole) to expose
`porosity and permit unrestricted wellbore inflow of petro-
`leum products. Alternately, the hole may be cased with a liner,
`which is then perforated to permit inflow through the open-
`ings created by perforating.
`When natural inflow from the well is not economical, the
`well may require wellbore treatment termed stimulation. This
`is accomplished by pumping stimulation fluids such as frac-
`turing fluids, acid, cleaning chemicals and/or proppant laden
`fluids to improve wellbore inflow.
`In one previous method, the well is isolated in segments
`and each segment is individually treated so that concentrated
`and controlled fluid treatment can be provided along the
`wellbore. Often, in this method a tubing string is used with
`inflatable element packers thereabout which provide for seg-
`ment isolation. The packers, which are inflated with pressure
`using a bladder, are used to isolate segments of the well and
`the tubing is used to convey treatment fluids to the isolated
`segment. Such inflatable packers may be limited with respect
`to pressure capabilities as well as durability under high pres-
`sure conditions. Generally, the packers are run for a wellbore
`treatment, but must be moved after each treatment if it is
`desired to isolate other segments of the well for treatment.
`This process can be expensive and time consuming. Further-
`more, it may require stimulation pumping equipment to be at
`the well site for long periods of time or for multiple visits.
`This method can be very time consuming and costly.
`Other procedures for stimulation treatments use tubing
`strings without packers such that tubing is used to convey
`treatment fluids to the wellbore, the fluid being circulated up
`hole through the annulus between the tubing and the wellbore
`wall or casing.
`The tubing string, which conveys the treatment fluid, can
`include ports or openings for the fluid to pass therethrough
`into the borehole. Where more concentrated fluid treatment is
`
`desired in one position along the wellbore, a small number of
`larger ports are used. In another method, where it is desired to
`distribute treatment fluids over a greater area, a perforated
`
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`tubing string is used having a plurality of spaced apart perfo-
`rations through its wall. The perforations can be distributed
`along the length of the tube or only at selected segments. The
`open area of each perforation can be pre-selected to control
`the volume of fluid passing from the tube during use. When
`fluids are pumped into the liner, a pressure drop is created
`across the sized ports. The pressure drop causes approximate
`equal volumes of fluid to exit each port in order to distribute
`stimulation fluids to desired segments of the well.
`In many previous systems, it is necessary to run the tubing
`string into the bore hole with the ports or perforations already
`opened. This is especially true where a distributed application
`of treatment fluid is desired such that a plurality of ports or
`perforations must be open at the same time for passage there-
`through of fluid. This need to run in a tube already including
`open perforations can hinder the running operation and limit
`usefulness of the tubing string.
`Some sleeve systems have been proposed for flow control
`through tubing ports. However, the ports are generally closely
`positioned such that they can all be covered by the sleeve.
`
`10
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`15
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`20
`
`SUMMARY OF THE INVENTION
`
`25
`
`A method and apparatus has been invented which provides
`for selective communication to a wellbore for fluid treatment.
`
`In one aspect, the method and apparatus provide for the run-
`ning in of a fluid treatment string, the fluid treatment string
`having ports substantially closed against the passage of fluid
`therethrough, but which are openable when desired to permit
`fluid flow into the wellbore. The apparatus and methods ofthe
`present invention can be used in various borehole conditions
`including open holes, lined or cased holes, vertical, inclined
`or horizontal holes, and straight or deviated holes.
`In one embodiment, there is provided an apparatus for fluid
`treatment of a borehole, the apparatus comprising a tubing
`string having a long axis, a plurality of closures accessible
`from the inner diameter of the tubing string, each closure
`closing a port opened through the wall ofthe tubing string and
`preventing fluid flow through its port, but being openable to
`permit fluid flow through its port and each closure openable
`independently from each other closure and a port opening
`sleeve positioned in the tubing string and driveable through
`the tubing string to actuate the plurality ofclosures to open the
`ports.
`The sleeve can be driven in any way to move through the
`tubing string to actuate the plurality of closures. In one
`embodiment, the sleeve is driveable remotely, without the
`need to trip a work string such as a tubing string, coiled tubing
`or a wire line.
`In one embodiment, the sleeve has formed thereon a seat
`and the apparatus includes a sealing device selected to seal
`against the seat, such that fluid pressure can be applied to
`drive the sleeve and the sealing device can seal against fluid
`passage past the sleeve. The sealing device can be, for
`example, a plug or a ball, which can be deployed without
`connection to surface. This embodiment avoids the need for
`
`tripping in a work string for manipulation.
`In one embodiment,
`the closures each include a cap
`mounted over its port and extending into the tubing string
`inner bore, the cap being openable by the sleeve engaging
`against. The cap, when opened, permits fluid flow through the
`port. The cap can be opened, for example, by action of the
`sleeve breaking open the cap or shearing the cap from its
`position over the port.
`In another embodiment, the closures each include a port-
`closure sleeve mounted over at least one port and openable by
`the sleeve engaging and moving the port-closure sleeve away
`
`Page 9 of 15
`Page 9 of 15
`
`

`
`US 8,657,009 B2
`
`3
`from its associated at least one port. The port-closure sleeve
`can include, for example, a profile on its surface open to the
`tubing string and the port-opening sleeve includes a locking
`dog biased outwardly therefrom and selected to engage the
`profile on the port-closure sleeve such that the port-closure
`sleeve is moved by the port opening sleeve. The profile is
`formed such that the locking dog can disengage therefrom,
`permitting the sleeve to move along the tubing string to a next
`port-closure sleeve.
`In one embodiment, the apparatus can include a packer
`about the tubing string. The packers can be ofany desired type
`to seal between the wellbore and the tubing string. For
`example, the packer can be a solid body packer including
`multiple packing elements.
`In View ofthe foregoing there is provided a method for fluid
`treatment of a borehole, the method comprising: providing an
`apparatus for wellbore treatment according to one of the
`various embodiments of the invention; running the tubing
`string into a wellbore to a position for treating the wellbore;
`moving the sleeve to open the closures of the ports and
`increasing fluid pressure to force wellbore treatment fluid out
`through the ports.
`In one method according to the present invention, the fluid
`treatment is a borehole stimulation using stimulation fluids
`such as one or more of acid, gelled acid, gelled water, gelled
`oil, CO2, nitrogen and any of these fluids containing prop-
`pants, 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 method can include setting a packer about the tubing
`string to isolate the fluid treatment to a selected section of the
`wellbore.
`
`BRIEF DESCRIPTION OF THE DRAWINGS
`
`A further, detailed, description of the invention, briefly
`described above, will follow by reference to the following
`drawings of specific embodiments of the invention. These
`drawings depict only typical embodiments of the invention
`and are therefore not to be considered limiting of its scope. In
`the drawings:
`FIG. 1 is a sectional view through a wellbore having posi-
`tioned therein a fluid treatment assembly according to the
`present invention;
`FIG. 2 is a sectional view through a wellbore having posi-
`tioned therein a fluid treatment assembly according to the
`present invention;
`FIG. 3 is a sectional view along the long axis of a packer
`useful in the present invention;
`FIG. 4a is a section through another wellbore having posi-
`tioned therein another fluid treatment assembly according to
`the present invention, the fluid treatment assembly being in a
`first stage of wellbore treatment;
`FIG. 4b is a section through the wellbore of FIG. 4a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`FIG. 4c is a section through the wellbore of FIG. 4a with
`the fluid treatment assembly in a third stage of wellbore
`treatment;
`FIG. 5 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`FIG. 6 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`
`10
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`FIG. 7a is a section through a wellbore having positioned
`therein another fluid treatment assembly according to the
`present invention, the fluid treatment assembly being in a first
`stage of wellbore treatment;
`FIG. 7b is a section through the wellbore of FIG. 7a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`FIG. 7c is a section through the wellbore of FIG. 7a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`FIG. 7d is a section through the wellbore of FIG. 7a with
`the fluid treatment assembly in a fourth stage of wellbore
`treatment.
`
`DETAILED DESCRIPTION OF THE PRESENT
`INVENTION
`
`Referring to FIG. 1, a wellbore fluid treatment assembly is
`shown, which can be used to effect fluid treatment of a for-
`mation 10 through a wellbore 12. The wellbore assembly
`includes a tubing string 14 having a lower end 1411 and an
`upper end extending to surface (not shown). Tubing string 14
`includes a plurality of spaced apart ports 17 opened through
`the tubing string wall to permit access between the tubing
`string inner bore 18 and the wellbore. Each port 17 includes
`thereover a closure that can be closed to substantially prevent,
`and selectively opened to permit, fluid flow through the ports.
`A port-opening sleeve 22 is disposed in the tubing string to
`control the opening of the port closures. In this embodiment,
`sleeve 22 is mounted such that it can move, arrow A, from a
`port closed position, wherein the sleeve is shown in phantom,
`axially through the tubing string inner bore past the ports to a
`open port position, shown in solid lines, to open the associ-
`ated closures of the ports allowing fluid flow therethrough.
`The sliding sleeve is disposed to control the opening of the
`ports through the tubing string and is moveable from a closed
`port position to a position wherein the ports have been opened
`by passing of the sleeve and fluid flow of, for example, stimu-
`lation fluid is permitted down through the tubing string,
`arrows F, through the ports ofthe ported interval. If fluid flow
`is continued, the fluid can return to surface through the annu-
`lus.
`
`The tubing string is deployed into the borehole in the
`closed port position and can be positioned down hole with the
`ports at a desired location to effect fluid treatment of the
`borehole.
`
`Referring to FIG. 2, a wellbore fluid treatment assembly is
`shown, which can be used to effect fluid treatment of a for-
`mation 10 through a wellbore 12. The wellbore assembly
`includes a tubing string 14 having a lower end 1411 and an
`upper end extending to surface (not shown). Tubing string 14
`includes a plurality of spaced apart ported intervals 16c to 16e
`each including a plurality of ports 17 opened through the
`tubing string wall to permit access between the tubing string
`inner bore 18 and the wellbore. The ports are normally closed
`by pressure holding caps 23.
`Packers 20d to 20e are mounted between each pair of
`adjacent ported intervals. In the illustrated embodiment, a
`packer 20f is also mounted below the lower most ported
`interval 16e and lower end 1411 of the tubing string. Although
`not shown herein, a packer can be positioned above the upper
`most ported interval. The packers are disposed about the
`tubing string and selected to seal the annulus between the
`tubing string and the wellbore wall, when the assembly is
`disposed in the wellbore. The packers divide the wellbore into
`isolated segments wherein fluid can be applied to one seg-
`ment of the well, but is prevented from passing through the
`
`Page 10 of 15
`Page 10 of 15
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`

`
`US 8,657,009 B2
`
`5
`annulus into adjacent segments. As will be appreciated the
`packers can be spaced in any way relative to the ported inter-
`vals to achieve a desired interval length or number of ported
`intervals per segment. In addition, packer 20f need not be
`present in some applications.
`The packers can be, as shown, of the solid body-type with
`at least one extrudable packing element, for example, formed
`of rubber. Solid body packers including multiple, spaced
`apart packing elements 21a, 21b on a single packer are par-
`ticularly useful especially for example in open hole (unlined
`wellbore) operations. In another embodiment, a plurality of
`packers are positioned in side by side relation on the tubing
`string, rather than using only one packer between each ported
`interval.
`
`Sliding sleeves 22c to 22e are disposed in the tubing string
`to control the opening ofthe ports by opening the caps. In this
`embodiment, a sliding sleeve is mounted for each ported
`interval and can be moved axially through the tubing string
`inner bore to open the caps of its interval. In particular, the
`sliding sleeves are disposed to control the opening of their
`ported intervals through the tubing string and are each move-
`able from a closed port position away from the ports of the
`ported interval (as shown by sleeves 22c and 22d) to a position
`wherein it has moved past the ports to break open the caps and
`wherein fluid flow of, for example, stimulation fluid is per-
`mitted through the ports of the ported interval (as shown by
`sleeve 22e).
`The assembly is run in and positioned downhole with the
`sliding sleeves each in their closed port position. When the
`tubing string is ready for use in fluid treatment of the well-
`bore, the sleeves are moved to their port open positions. The
`sleeves for each isolated interval between adjacent packers
`can be opened individually to permit fluid flow to one well-
`bore segment at a time, in a staged treatment process.
`Preferably, the sliding sleeves are each moveable remotely,
`for example without having to run in a line or string for
`manipulation thereof, from their closed port position to their
`position permitting through-port fluid flow. In one embodi-
`ment, the sliding sleeves are actuated by devices, such as balls
`24d, 24e (as shown) or plugs, which can be conveyed by
`gravity or fluid flow through the tubing string. The device
`engages against the sleeve and causes it to move 4 through the
`tubing string. In this case, ball 24e is sized so that it cannot
`pass through sleeve 22e and is engaged in it when pressure is
`applied through the tubing string inner bore 18 from surface,
`ball 24e seats against and plugs fluid flow past the sleeve.
`Thus, when fluid pressure is applied after the ball has seated
`in the sleeve, a pressure differential is created above and
`below the sleeve which drives the sleeve toward the lower
`
`pressure side.
`In the illustrated embodiment, the inner surface of each
`sleeve, which is the side open to the inner bore of the tubing
`string, defines a seat 26e onto which an associated ball 24e,
`when launched from surface, can land and seal thereagainst.
`When the ball seals against the sleeve seat and pressure is
`applied or increased from surface, a pressure differential is set
`up which causes the sliding sleeve on which the ball has
`landed to slide through the tubing string to an port-open
`position until it is stopped by, for example, a no go. When the
`ports of the ported interval 16e are opened, fluid can flow
`therethrough to the armulus between the tubing string and the
`wellbore and thereafter into contact with formation 10.
`
`Each of the plurality of sliding sleeves has a different
`diameter seat and, therefore, each accept a different sized
`ball. In particular, the lower-most sliding sleeve 22e has the
`smallest diameter D1 seat and accepts the smallest sized ball
`24e and each sleeve that is progressively closer to surface has
`
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`6
`a larger seat. For example, as shown in FIG. 1b, the sleeve 22c
`includes a seat 260 having a diameter D3, sleeve 22d includes
`a seat 26d having a diameter D2, which is less than D3 and
`sleeve 22e includes a seat 26e having a diameter D1, which is
`less than D2. This provides that the lowest sleeve can be
`actuated to open it ports first by first launching the smallest
`ball 24e, which can pass though all of the seats of the sleeves
`closer to surface but which will land in and seal against seat
`26e of sleeve 22e. Likewise, penultimate sleeve 22d can be
`actuated to move through ported interval 16d by launching a
`ball 24d which is sized to pass through all of the seats closer
`to surface, including seat 26c, but which will land in and seal
`against seat 26d.
`Lower end 1411 of the tubing string can be open, closed or
`fitted in various ways, depending on the operational charac-
`teristics of the tubing string which are desired. In the illus-
`trated embodiment, the tubing string includes a pump out
`plug assembly 28. Pump out plug assembly 28 acts to close
`off end 1411 during run in of the tubing string, to maintain the
`inner bore of the tubing string relatively clear. However, by
`application of fluid pressure, for example at a pressure of
`about 3000 psi, the plug can be blown out to permit actuation
`of the lower most sleeve 22e by generation of a pressure
`differential. As will be appreciated, an opening adjacent end
`1411 is only needed where pressure, as opposed to gravity, is
`needed to convey the first ball to land in the lower-most
`sleeve. Altemately, the lower most sleeve can be hydrauli-
`cally actuated, including a fluid actuated piston secured by
`shear pins, so that the sleeve can be driven along the tubing
`string remotely without the need to land a ball or plug therein.
`In other embodiments, not shown, end 1411 can be left open
`or can be closed, for example, by installation of a welded or
`threaded plug.
`While the illustrated tubing string includes three ported
`intervals, it is to be understood that any number of ported
`intervals could be used. In a fluid treatment assembly desired
`to be used for staged fluid treatment, at least two openable
`ports from the tubing string inner bore to the wellbore must be
`provided such as at least two ported intervals or an openable
`end and one ported interval. It is also to be understood that any
`number of ports can be used in each interval.
`Centralizer 29 and other tubing string attachments can be
`used, as desired.
`The wellbore fluid treatment apparatus, as described with
`respect to FIG. 2, can be used in the fluid treatment of a
`wellbore. For selectively treating formation 10 through well-
`bore 12, the above-described assembly is run into the bore-
`hole and the packers are set to seal the armulus at each location
`creating a plurality of isolated annulus zones. Fluids can then
`pumped down the tubing string and into a selected zone ofthe
`annulus, such as by increasing the pressure to pump out plug
`assembly 28. Altemately, a plurality of open ports or an open
`end can be provided or lower most sleeve can include a piston
`face for hydraulic actuation thereof. Once that selected zone
`is treated, as desired, ball 24e or another sealing plug is
`launched from surface and conveyed by gravity or fluid pres-
`sure to seal against seat 26e of the lower most sliding sleeve
`22e, this seals off the tubing string below sleeve 22e and
`drives the sleeve to open the ports of ported interval 16e to
`allow the next annulus zone, the zone between packer 20e and
`20], to be treated with fluid. The treating fluids will be
`diverted through the ports of interval 16e whose caps have
`been removed by moving the sliding sleeve. The fluid can
`then be directed to a specific area ofthe formation. Ball 24e is
`sized to pass though all of the seats closer to surface, includ-
`ing seats 26c, 26d, without sealing thereagainst. When the
`fluid treatment through ports 16e is complete, a ball 24d is
`
`Page 11 of 15
`Page 11 of 15
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`US 8,657,009 B2
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`7
`launched, which is sized to pass through all of the seats,
`including seat 26c closer to surface, and to seat in and move
`sleeve 22d. This opens the ports of ported interval 16d and
`permits fluid treatment of the annulus between packers 20d
`and 20e. This process of launching progressively larger balls
`or plugs is repeated until all of the zones are treated. The balls
`can be launched without stopping the flow of treating fluids.
`After treatment, fluids can be shut in or flowed back imme-
`diately. Once fluid pressure is reduced from surface, any balls
`seated in sleeve seats can be unseated by pressure from below
`to permit fluid flow upwardly therethrough.
`The apparatus is particularly useful for stimulation of a
`formation, using stimulation fluids, such as for example, acid,
`gelled acid, gelled water, gelled oil, CO2, nitrogen and/or
`proppant laden fluids.
`Referring to FIG. 3, a packer 20 is shown which is useful in
`the present invention. The packer can be set using pressure or
`mechanical forces. Packer 20 includes extrudable packing
`elements 21a, 21b, a hydraulically actuated setting mecha-
`nism and a mechanical body lock system 31 including a
`locking ratchet arrangement. These parts are mounted on an
`inner mandrel 32. Multiple packing elements 21a, 21b are
`formed of elastomer, such as for example, rubber and include
`an enlarged cross section to provide excellent expansion
`ratios to set in oversized holes. The multiple packing elements
`21a, 21b can be separated by at least 0.3M and preferably
`0.8M or more. This arrangement of packing elements aid in
`providing high pressure sealing in an open borehole, as the
`elements load into each other to provide additional pack-off.
`Packing element 21a is mounted between fixed stop ring
`34a and compressing ring 34b and packing element 21b is
`mounted between fixed stop ring 34c and compressing ring
`34d. The hydraulically actuated setting mechanism includes a
`port 35 through inner mandrel 32, which provides fluid access
`to a hydraulic chamber defined by first piston 36a and second
`piston 36b. First piston 36a acts against compressing ring 34b
`to drive compression and, therefore, expansion of packing
`element 21a, while second piston 36b acts against compress-
`ing ring 34d to drive compression and, therefore, expansion
`of packing element 21b. First piston 3611 includes a skirt 37,
`which encloses the hydraulic chamber between the pistons
`and is telescopically disposed to ride overpiston 36b. Seals 38
`seal against the leakage of fluid between the parts. Mechani-
`cal body lock system 31, including for example a ratchet
`system, acts between skirt 37 and piston 36b permitting
`movement therebetween driving pistons 36a, 36b away from
`each other but locking against reverse movement of the pis-
`tons toward each other, thereby locking the packing elements
`into a compressed, expanded configuration.
`Thus, the packer is set by pressuring up the tubing string
`such that fluid enters the hydraulic chamber and acts against
`pistons 36a, 36b to drive them apart, thereby compressing the
`packing elements and extruding them outwardly. This move-
`ment is permitted by body lock system 31. However, body
`lock system 31 locks the packers against retraction to lock the
`packing elements in their extruded conditions.
`Ring 3411 includes shears 38 which mount the ring to man-
`drel 32. Thus, for release of the packing elements from seal-
`ing position the tubing string into which mandrel 32 is con-
`nected, can be pulled up to release shears 38 and, thereby,
`release the compressing force on the packing elements.
`FIGS. 4a to 4c shows an assembly and method for fluid
`treatment, termed sprinkling, wherein fluid supplied to an
`isolated interval is introduced in a distributed, low pressure
`fashion along an extended length of that interval. The assem-
`bly includes a tubing string 212 and ported intervals 216a,
`216b, 216c each including a plurality of ports 217 spaced
`
`5
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`8
`along the long axis of the tubing string. Packers 220a, 220b
`are provided between each interval to form an isolated seg-
`ment in the wellbore 212.
`
`While the ports of interval 216c are open during run in of
`the tubing string, the ports of intervals 216b and 216a, are
`closed during run in and sleeves 222a and 222b are mounted
`within the tubing string and actuatable to selectively open the
`ports of intervals 216a and 216b, respectively. In particular, in
`FIG. 4a, the position of sleeve 222b is shown when the ports
`of interval 216b are closed. The ports in any of the intervals
`can be size restricted to create a selected pressure drop there-
`through, permitting distribution of fluid along the entire
`ported interval.
`Once the tubing string is run into the well, stage 1 is
`initiated wherein stimulation fluids are pumped into the end
`section of the well to ported interval 216c to begin the stimu-
`lation treatment (FIG. 4a). Fluids will be forced to the lower
`section of the well below packer 220b. In this illustrated
`embodiment, the ports ofinterval 216c are normally open size
`restricted ports, which do not require opening for stimulation
`fluids to be jetted therethrough. However, it is to be under-
`stood that the ports can be installed in closed configuration,
`but opened once the tubing is in place.
`When desired to stimulate another section ofthe well (FIG.
`4b), a ball or plug (not shown) is pumped by fluid pressure,
`arrow P, down the well and will seat in a selected sleeve 222b
`sized to accept the ball or plug. The pressure of the fluid
`behind the ball will push the cutter sleeve against any force or
`member, such as a shear pin, holding the sleeve in position
`and down the tubing string, arrow S. As it moves down, it will
`open the ports of interval 216b as it passes by them. Sleeve
`222b eventually stops against a stop means. Since fluid pres-
`sure will hold the ball in the sleeve, this effectively shuts off
`the lower segment of the well including previously treated
`interval 216c. Treating fluids will then be forced through the
`newly opened ports. Using limited entry or a flow regulator, a
`tubing to annulus pressure drop insures distribution. The fluid
`will be isolated to treat the formation between packers 220a
`and 220b.
`
`After the desired volume of stimulation fluids are pumped,
`a slightly larger second ball or plug is injected into the tubing
`and pumped down the well, and will seat in sleeve 222a which
`is selected to retain the larger ball or plug. The force of the
`moving fluid will push sleeve 222a down the tubing string and
`as it moves down, it will open the ports in interval 216a. Once
`the sleeve reaches a desired depth as shown in FIG. 4c, it will
`be stopped, effectively shutting off the lower segment of the
`well including previously treated intervals 216b and 216c.
`This process can be repeated a number of times until most or
`all of the wellbore is treated in stages, using a sprinkler
`approach over each individual section.
`The above noted method can also be used for wellbore
`
`circulation to circulate existing wellbore fluids (drilling mud
`for example) out of a wellbore and to replace that fluid with
`another fluid. In such a method, a staged approach need not be
`used, but the sleeve