BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1001
`BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC. v. PACKERS
`PLUS ENERGY SERVICES, INC.
`IPR2016-00597
`
`Page 1 of 19
`
`

`
`US007543634B2
`
`(12) Ulllted States Patent
`Fehr et al.
`
`(10) Patent No.:
`(45) Date of Patent:
`
`US 7,543,634 B2
`*Jun. 9, 2009
`
`(54) METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`(58) Field of Classification Search ............... .. 166/387,
`166/386, 373, 374, 142, 146, 147, 184, 185,
`166/194, 318, 269, 126, 127, 131, 191, 305.1,
`
`(75)
`
`Inventors: Jim Fehr, Edmonton (CA); Daniel Jon
`Themig, Cochrane (CA)
`
`165/306, 313; 1.75/237, 317
`.
`.
`See application file for complete search history.
`
`(73) Assignee: Packers Plus Energy Services Inc.,
`Calgary (CA)
`.
`.
`.
`.
`Sublect 10 any dlsclalmers the term Ofthls
`patent is extended or adjusted under 35
`U.S.C. 154(b) by 0days.
`
`.
`NOUCB3
`
`( * )
`
`This patent is subject to a terminal dis-
`Claimer
`
`.
`
`.
`(21) Appl' No" 11/550363
`(22)
`Filed:
`Oct. 19’ 2006
`
`(56)
`
`References Cited
`U.S. PATENT DOCUMENTS
`1,956,694 A *
`5/1934 P
`' h ..................... .. 277/342
`2,227,539 A *
`1/1941 Diriijn ...................... .. 166/70
`2,737,244 A
`3/1955 Baker et 31.
`3,054,415 A
`9/1962 Baker etal.
`4,099,563 A
`7/1978 Hutchinson et al.
`4,516,379 A
`5/1935 Berry Gt 31-
`4,520,870 A
`6/1985 Pringle
`4,569,396 A
`2/1986 Brisco ................... .. 166/305.1
`4,794,989 A
`1/1989 Mills ........................ .. 166/387
`4,893,678 A
`1/1990 Stokley et al,
`4,949,788 A
`8/1990 .Szarka et al.
`(Continued)
`
`(65)
`
`Prior Publication Data
`
`OTHER PUBLICATIONS
`
`Us 2007/0151734 A1
`
`Jul‘ 5 3 2007
`
`Related U.S. Application Data
`
`(60) Continuation of application No. 11/104,467, filed on
`Apr. 13, 2005, now Pat. No. 7,134,505, which is a
`division of application No. 10/299,004, filed on Nov.
`19, 2002, now Pat. No. 6,907,936.
`
`(60) Provisional application No. 60/331,491, filed on Nov.
`19, 2001, provisional application No. 60/404,783,
`filed on Aug. 21, 2002.
`
`(51)
`
`Int, Cl,
`(2006.01)
`E213 43/14
`(2006.01)
`E213 33/124
`(200601)
`E213 34/14
`(52) U.S. Cl.
`..................... .. 166/191; 166/313; 166/373;
`166/147; 166/318
`
`http://wwwpackersplus.com/rockseal%202.htm description ofopen
`hole packer, available prior to Nov. 19, 2001.
`.
`(Continued)
`
`.
`.
`Primary Emml"er—KenI}eth Thompson
`(74) A3107’719% A897”; 07’ F17’m*Be1mett -101195 LLP
`
`(57)
`
`ABSTRACT
`.
`.
`.
`.
`.
`A tubing string assembly is disclosed for fluid treatment of a
`wellbore. The tubing string can be used for staged wellbore
`fluid treatment where a selected segment of the wellbore is
`treated, while other segments are sealed off. The tubing string
`can also be used where a ported tubing string is required to be
`run in in a pressure tight condition and later is needed to be in
`an ope11—port condition.
`
`25 Claims, 9 Drawing Sheets
`
`
` ,"7/////5>'\\‘
`\\\.\\\\'
`
`
`
`\\\\‘~‘
`117
`
`
`
`L\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\\VI‘%)\\§\\\%\\\§\\xX\\\\
`
`
`
`1/1’/II///IVIIIIIIIII-Vrlln
`rv7'r//I/////////;L/(/__[/{/(/{{{_/{//
`
`7'
`
`Page 1 of 19
`Page 1 of 19
`
`

`
`US 7,543,634 B2
`Page 2
`
`U.S. PATENT DOCUMENTS
`
`4,967,841
`5,472,048
`5,499,687
`5,526,880
`5,533,573
`5,894,888
`5,960,881
`6,047,773
`6,253,861
`6,446,727
`6,460,619
`6,763,885
`6,907,936
`
`B2*
`
`11/1990
`12/1995
`3/1996
`6/1996
`7/1996
`4/1999
`10/1999
`4/2000
`7/2001
`9/2002
`10/2002
`7/2004
`6/2005
`
`Murray
`Kennedy et al.
`Lee
`Jordan, Jr. et al.
`Jordan, Jr. et al.
`Wiemers et al.
`Allamon et al.
`Zeltmann et al.
`Carmichael et al.
`Zemlak et al.
`Braithwaite et al.
`Cavender
`Fehr et al.
`
`........... .. .... .. 166/387
`
`4/2006 Themig
`7,021,384 B2
`8/2006 Weng et al.
`7,096,954 B2
`9/2006 Jones
`7,108,060 B2
`9/2006 Themig et al.
`7,108,067 B2
`7,134,505 B2 * 11/2006 Fehr et al.
`..... ..
`7,267,172 B2
`9/2007 Hofman
`
`OTHER PUBLICATIONS
`
`.......... .. 166/387
`
`Design and Installation of a Cost-Effective Completion System for
`Horizontal Chalk Wells Where Multiple Zones Require Acid Stimu-
`lation, D. W. Thompson, SPE Drilling & Completion, Sep. 1998, pp.
`151-156.
`
`* cited by examiner
`
`Page 2 of 19
`Page 2 of 19
`
`

`
`U.S. Patent
`
`Jun. 9, 2009
`
`Sheet 1 of9
`
`Us 7,543,634 B2
`
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`
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`
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`
`28
`
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`
`Page 3 of 19
`Page 3 of 19
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`

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`U.S. Patent
`
`Jun. 9, 2009
`
`Sheet 2 of9
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`Us 7,543,634 B2
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`Page 4 of 19
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`

`
`U.S. Patent
`
`Jun. 9, 2009
`
`Sheet 3 of9
`
`US 7,543,634 B2
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`Page 5 of 19
`Page 5 of 19
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`

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`U.S. Patent
`
`Jun. 9, 2009
`
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`Us 7,543,634 B2
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`Page 6 of 19
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`U.S. Patent
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`Jun. 9, 2009
`
`Sheet 5 of 9
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`US 7,543,634 B2
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`
`U.S. Patent
`
`Jun. 9, 2009
`
`Sheet 7 of9
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`US 7,543,634 B2
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`

`
`U.S. Patent
`
`Jun. 9, 2009
`
`Sheet 9 of9
`
`US 7,543,634 B2
`
`
`
`3: 17
`1
`317 414 4200 22c 420d 317412 317
`FIG. 9a
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`
`Page 11 of 19
`Page 11 of 19
`
`

`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`CROSS REFERENCE TO RELATED
`APPLICATIONS
`
`This is a continuation application of U.S. application Ser.
`No. 11/104,467, filedApr. 13, 2005, now U.S. Pat. No. 7,134,
`505, issued Nov. 14, 2006, which is a divisional of U.S.
`application Ser. No. 10/299,004, filed Nov. 19, 2002, now
`U.S. Pat. No. 6,907,936, issued Jun. 21, 2005. The parent
`applications and the present application claim priority from
`U.S. provisional application 60/331,491, filed Nov. 19, 2001
`and U.S. provisional application 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 communication to a wellbore for fluid
`treatment.
`
`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 foam
`diverters, gelled diverters and/or limited entry procedures
`through tubulars to distribute fluids. Each ofthese may or may
`not be effective in distributing fluids to the desired segments
`in the wellbore.
`
`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
`tubing string is used having a plurality of spaced apart perfo-
`rations through its wall. The perforations can be distributed
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`US 7,543,634 B2
`
`2
`
`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. Where
`there are significant numbers of perforations, the fluid must
`be pumped at high rates to achieve a consistent distribution of
`treatment fluids along the wellbore.
`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.
`
`SUMMARY OF THE INVENTION
`
`A method and apparatus has been invented which provides
`for selective communication to a wellbore for fluid treatment.
`
`In one aspect of the invention the method and apparatus
`provide for staged injection of treatment fluids wherein fluid
`is injected into selected intervals of the wellbore, while other
`intervals are closed. In another aspect, the method and appa-
`ratus provide for the running in of a fluid treatment string, the
`fluid treatment string having ports sub stantially closed
`against the pas sage of fluid therethrough, but which are open-
`able 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, cased
`holes, vertical holes, horizontal holes, straight holes or devi-
`ated 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 first port opened through the wall
`of the tubing string, a second port opened through the wall of
`the tubing string, the second port offset from the first port
`along the long axis ofthe tubing string, a first packer operable
`to seal about the tubing string and mounted on the tubing
`string to act in a position offset from the first port along the
`long axis ofthe tubing string, a second packer operable to seal
`about the tubing string and mounted on the tubing string to act
`in a position between the first port and the second port along
`the long axis of the tubing string; a third packer operable to
`seal about the tubing string and mounted on the tubing string
`to act iii a position offset from the second port along the long
`axis of the tubing string and on a side of the second port
`opposite the second packer; a first sleeve positioned relative
`to the first port, the first sleeve being moveable relative to the
`first port between a closed port position and a position per-
`mitting fluid flow through the first port from the tubing string
`inner bore and a second sleeve being moveable relative to the
`second port between a closed port position and a position
`permitting fluid flow through the second port from the tubing
`string inner bore; and a sleeve shifting means for moving the
`second sleeve from the closed port position to the position
`permitting fluid flow, the means for moving the second sleeve
`selected to create a seal in the tubing string against fluid flow
`past the second sleeve through the tubing string inner borc.
`In one embodiment, the second sleeve l1as formed thereon
`a seat and the means for moving the second sleeve includes a
`sealing device selected to seal against the seat, such that fluid
`pressure can be applied to move the second sleeve and the
`sealing device can seal against fluid passage past the second
`
`Page 12 of 19
`Page 12 of 19
`
`

`
`US 7,543,634 B2
`
`3
`sleeve. The sealing device can be, for example, a plug or a
`ball, which can be deployed without connection to surface.
`Thereby avoiding the need for tripping in a string or wire line
`for manipulation.
`The means for moving the second sleeve can be selected to
`move the second sleeve without also moving the first sleeve.
`In one such embodiment, the first sleeve has formed thereon
`a first seat and the means for moving the first sleeve includes
`a first sealing device selected to seal against the first seat, such
`that once the first sealing device is seated against the first seat
`fluid pressure can be applied to move the first sleeve and the
`first sealing device can seal against fluid passage past the first
`sleeve and the second sleeve has formed thereon a second seat
`
`and the means for moving the second sleeve includes a second
`sealing device selected to seal against the second seat, such
`that when the second sealing device is seated against the
`second seat pressure can be applied to move the second sleeve
`and the second sealing device can seal against fluid passage
`past the second sleeve, the first seat having a larger diameter
`than the second seat, such that the second sealing device can
`move past the first seat without sealing thereagainst to reach
`and seal against the second seat.
`In the closed port position, the first sleeve can be positioned
`over the first port to close the first port against fluid flow
`therethrough. In another embodiment,
`the first port has
`mounted thereon a cap extending into the tubing string inner
`bore and in the position permitting fluid flow, the first sleeve
`has engaged against and opened the cap. The cap can be
`opened, for example, by action of the first sleeve shearing the
`cap from its position over the port. In another embodiment,
`the apparatus further comprises a third port having mounted
`thereon a cap extending into the tubing string inner bore and
`in the position permitting fluid flow, the first sleeve also
`engages against the cap of the third port to open it.
`In another embodiment, the first port has mounted there-
`over 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 sliding sleeve can include, for
`example, a groove and the first sleeve includes a locking dog
`biased outwardly therefrom and selected to lock into the
`groove on the sleeve. In another embodiment, there is a third
`port with a sliding sleeve mounted thereover and the first
`sleeve is selected to engage and move the third port sliding
`sleeve after it has moved the sliding sleeve of the first port.
`The packers can be of any desired type to seal between the
`wellbore and the tubing string. In one embodiment, at least
`one ofthe 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.
`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 in a desired position for treating the
`wellbore; setting the packers; conveying the means for mov-
`ing the second sleeve to move the second sleeve and increas-
`ing fluid pressure to wellbore treatment fluid out through the
`second port.
`In one method according to the present invention, the fluid
`treatment is 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.
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`4
`
`In an open hole, preferably, the packers include solid body
`packers including a solid, extrudable packing element and, in
`some embodiments, solid body packers include a plurality of
`cxtrudablc packing clcmcnts.
`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 port opened through the wall ofthe
`tubing string, a first packer operable to seal about the tubing
`string and mounted on the tubing string to act in a position
`offset from the port along the long axis of the tubing string, a
`second packer operable to seal about the tubing string and
`mounted on the tubing string to act in a position offset from
`the port along the long axis of the tubing string and on a side
`of the port opposite the first packer; a sleeve positioned rela-
`tive to the port, the sleeve being moveable relative to the port
`between a closed port position and a position permitting fluid
`flow through the port from the tubing string inner bore and a
`sleeve shifting means for moving the sleeve from the closed
`port position to the position permitting fluid flow. In this
`embodiment of the invention, there can be a second port
`spaced along the long axis of the tubing string from the first
`port and the sleeve can be moveable to a position permitting
`flow through the port and the second port.
`As noted hereinbefore, the sleeve can be positioned in
`various ways when in the closed port position. For example,
`in the closed port position, the sleeve can be positioned over
`the port to close the port against fluid flow therethrough.
`Alternately, when in the closed port position, the sleeve can be
`offset from the port, and the port can be closed by other means
`such as by a cap or another sliding sleeve which is acted upon,
`as by breaking open or shearing the cap, by engaging against
`the sleeve, etc., by the sleeve to open the port.
`There can be more than one port spaced along the long axis
`ofthe tubing string and the sleeve can act upon all of the ports
`to open them.
`The sleeve can be actuated in any way to move into the
`position permitted fluid flow through the port. Preferably,
`however, the sleeve is actuated remotely, without the need to
`trip a work string such as a tubing string or a wire line. In one
`embodiment, the sleeve has formed thereon a seat and the
`means for moving the sleeve includes a sealing device
`selected to seal against the seat, such that fluid pressure can be
`applied to move the sleeve and the sealing device can seal
`against fluid passage past the sleeve.
`The first packer and the second packer can be formed as a
`solid body packer including multiple packing elements, for
`example, in spaced apart relation.
`In view of the forgoing there is provided a method for fluid
`treatment of a borehole, the method comprising: providing an
`apparatus for wellbore treatment including a tubing string
`having a long axis, a port opened through the wall of the
`tubing string, a first packer operable to seal about the tubing
`string and mounted on the tubing string to act in a position
`offset from the port along the long axis of the tubing string, a
`second packer operable to seal about the tubing string and
`mounted on the tubing string to act in a position offset from
`the port along the long axis of the tubing string and on a side
`of the port opposite the first packer; a sleeve positioned rela-
`tive to the port, the sleeve being moveable relative to the port
`between a closed port position and a position permitting fluid
`flow through the port from the tubing string inner bore and a
`sleeve shifting means for moving the sleeve from the closed
`port position to the position permitting fluid flow; running the
`tubing string into a wellbore in a desired position for treating
`the wellbore; setting the packers; conveying the means for
`
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`US 7,543,634 B2
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`moving the sleeve to move the sleeve and increasing fluid
`pressure to permit the flow of wellbore treatment fluid out
`through the port.
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`6
`FIG. 9d is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a fourth stage of wellbore
`treatment.
`
`BRIEF DESCRIPTION OF THE DRAWINGS
`
`DETAILED DESCRIPTION OF THE PRESENT
`INVENTION
`
`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. 1a is a sectional view through a wellbore having
`positioned therein a fluid treatment assembly according to the
`present invention;
`FIG. 1b is an enlarged view of a portion of the wellbore of
`FIG. 1a with the fluid treatment assembly also shown in
`section;
`FIG. 2 is a sectional view along the long axis of a packer
`useful in the present invention;
`FIG. 3a is a sectional view along the long axis of a tubing
`string sub useful in the present invention containing a sleeve
`in a closed port position;
`FIG. 3b is a sectional view along the long axis of a tubing
`string sub useful in the present invention containing a sleeve
`in a position allowing fluid flow through fluid treatment ports;
`FIG. 4a is a quarter sectional view along the long axis of a
`tubing string sub useful in the present invention containing a
`sleeve and fluid treatment ports;
`FIG. 4b is a side elevation of a flow control sleeve posi-
`tionable in the sub of FIG. 4a;
`
`FIG. 5 is a section through another wellbore having posi-
`tioned therein a fluid treatment assembly according to the
`present invention;
`FIG. 6a 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. 6b is a section through the wellbore of FIG. 6a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`
`FIG. 6c is a section through the wellbore of FIG. 6a with
`the fluid treatment assembly in a third stage of wellbore
`treatment;
`
`FIG. 7 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. 8 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. 9a 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. 9b is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`
`FIG. 9c is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`
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`Referring to FIGS. 1a and 1b, a wellbore fluid treatment
`assembly is shown, which can be used to effect fluid treatment
`ofa formation 10 through a wellbore 12. The wellbore assem-
`bly 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 16a 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.
`
`A packer 20a is mounted between the upper-most ported
`interval 16a and the surface and furtherpackers 20b 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 14a
`ofthe tubing string. The packers are disposed about the tubing
`string and selected to seal the armulus 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 segment of the
`well, but is prevented from passing through the annulus into
`adjacent segments. As will be appreciated the packers can be
`spaced in any way relative to the ported intervals to achieve a
`desired interval length or number of ported intervals per seg-
`ment. In addition, packer 20f need not be present in some
`applications.
`The packers are 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 particularly useful
`especially for example in open hole (unlined wellbore) opera-
`tions. In another embodiment, a plurality of packers are posi-
`tioned in side by side relation on the tubing string, rather than
`using one packer between each ported interval.
`Sliding sleeves 22c to 222 are disposed in the tubing string
`to control the opening of the ports. In this embodiment, a
`sliding sleeve is mounted over each ported interval to close
`them against fluid flow therethrough, but can be moved away
`from their positions covering the ports to open the ports and
`allow fluid flow therethrough.
`In particular,
`the sliding
`sleeves are disposed to control the opening of the ported
`intervals through the tubing string and are each moveable
`from a closed port position covering its associated ported
`interval (as shown by sleeves 22c and 22d) to a position away
`from the ports wherein fluid flow of, for example, stimulation
`fluid is permitted 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. The sleeves
`are moved to their open position when the tubing string is
`ready for use in fluid treatment ofthe wellbore. Preferably, the
`sleeves for each isolated interval between adjacent packers
`are opened individually to permit fluid flow to one wellbore
`segment at a time, in a staged, concentrated treatment pro-
`cess.
`
`Preferably, the sliding sleeves are each moveable remotely
`from their closed port position to their position permitting
`through-port fluid flow, for example, without having to run in
`a line or string for manipulation thereof. In one embodiment,
`the sliding sleeves are each actuated by a device, such as a ball
`24e (as shown) or plug, which can be conveyed by gravity or
`
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`US 7,543,634 B2
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`7
`fluid flow through the tubing string. The device engages
`against the sleeve, in this case ball 24e engages against sleeve
`22e, and, when pressure is applied through the tubing string
`inner bore 18 from surface, ball 24e seats against and creates
`a pressure differential 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 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
`to an port-open position. When the ports ofthe 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 different sized balls.
`In particular, the lower-most sliding sleeve 22e has the small-
`est diameter D1 seat and accepts the smallest sized ball 24e
`and each sleeve that is progressively closer to surface has a
`larger seat. For example, as shown in FIG. 1b, the sleeve 22c
`includes a seat 26c 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 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 away from potted 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, includes a pump out plug assembly 28.
`Pump out plug assembly acts to close off end 1411 during run
`in ofthe tubing string, to maintain the inner bore ofthe tubing
`string relatively clear. However, by application of fluid pres-
`sure, 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 appreci-
`ated, 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. Alternately, the lower
`most sleeve can be hydraulically actuated, including a fluid
`actuated piston secured by shear pins, so that the sleeve can be
`opened 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 five 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 standard tubing string attachments
`can be used.
`In use, the wellbore fluid treatment apparatus, as described
`with respect to FIGS. la and 1b, can be used in the fluid
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`treatment of a wellbore. For selectively treating formation 10
`through wellbore 12, the above-described assembly is run
`into the borehole and the packers are set to seal the armulus