I IIIII
`
`1111111111111111111111111111111111111111111111111111111111111
`US007134505B2
`
`c12) United States Patent
`Fehr et al.
`
`(10) Patent No.:
`(45) Date of Patent:
`
`US 7,134,505 B2
`Nov. 14, 2006
`
`(54) METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`(75)
`
`Inventors: Jim Fehr, Edmonton (CA); Daniel Jon
`Themig, Cochrane (CA)
`
`(73) Assignee: Packers Plus Energy Services Inc.,
`Calgary (CA)
`
`( *) Notice:
`
`Subject to any disclaimer, the term of this
`patent is extended or adjusted under 35
`U.S.C. 154(b) by 0 days.
`
`(21) Appl. No.: 111104,467
`
`(22) Filed:
`
`Apr. 13, 2005
`
`(65)
`
`Prior Publication Data
`
`US 2005/0178552 Al
`
`Aug. 18, 2005
`
`Related U.S. Application Data
`
`(62) Division of application No. 10/299,004, filed on Nov.
`19, 2002, now Pat. No. 6,907,936.
`
`(60) Provisional application No. 60/404,783, filed on Aug.
`21, 2002, provisional application No. 60/331,491,
`filed on Nov. 19, 2001.
`
`(51)
`
`Int. Cl.
`E21B 43114
`(2006.01)
`E21B 331124
`(2006.01)
`E21B 34114
`(2006.01)
`(52) U.S. Cl. ...................... 166/387; 166/191; 166/194;
`166/306; 166/318
`(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,
`166/306, 313; 175/237,317
`See application file for complete search history.
`
`(56)
`
`References Cited
`
`U.S. PATENT DOCUMENTS
`
`2,737,244 A
`
`3/1956 Baker et al.
`
`9/1962 Baker et al.
`3,054,415 A
`7/1978 Hutchison et a!.
`4,099,563 A
`6/1985 Pringle
`4,520,870 A
`111990 Stokley et a!.
`4,893,678 A
`1111990 Murray
`4,967,841 A
`12/1995 Kennedy et a!.
`5,472,048 A
`3/1996 Lee
`5,499,687 A
`6/1996 Jordan, Jr. et al.
`5,526,880 A
`7/1996 Jordan, Jr. et al.
`5,533,573 A
`10/1999 Allamon et al.
`5,960,881 A
`4/2000 Zeltmann et al.
`6,047,773 A
`6,253,861 B1
`7/2001 Carmichael et a!.
`6,488,082 B1 * 12/2002 Echols et al .................. 166/51
`
`OTHER PUBLICATIONS
`
`http:/ /www.packersplus.com/rockseal%202.htm description of open
`hole packer, available prior to Nov. 19, 2001.
`Design and Installation of a Cost-Effective Completion System for
`Horizontal Chalk Wells Where Multiple Zones Require Acid Stimu(cid:173)
`lation, D. W. Thompson, SPE Drilling & Completion, Sep. 1998, pp.
`151-156.
`* cited by examiner
`Primary Examiner-Kenneth Thompson
`(74) Attorney, Agent, or Firm-Bennett Jones LLP
`
`(57)
`
`ABSTRACT
`
`A tubing string assembly is disclosed for fluid treatment of
`a well bore. The tubing string can be used for staged well bore
`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 rnn in in a pressure tight condition and later
`is needed to be in an open-port condition.
`
`44 Claims, 9 Drawing Sheets
`
`lsurtace
`
`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 1 of 9
`
`US 7,134,505 B2
`
`c=>- Surface
`of Well
`
`10
`
`FIG. 1 a
`
`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 2 of 9
`
`US 7,134,505 B2
`
`t
`
`to surface
`
`10
`
`24d
`
`16d
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`02
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`16e
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`24e
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`FIG. 1 b
`
`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 3 of 9
`
`US 7,134,505 B2
`
`0
`
`0
`
`20~
`
`21a
`
`FIG. 2
`
`

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`42a
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`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 5 of 9
`
`US 7,134,505 B2
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`76"
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`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 6 of 9
`
`US 7,134,505 B2
`
`t Surface
`
`10
`
`FIG. 5
`
`114
`
`

`
`U.S. Patent
`
`Nov. 14,2006
`
`Sheet 7 of 9
`
`US 7,134,505 B2
`
`216b
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`
`212
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`220a
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`216b
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`222b
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`226
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`250
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`
`

`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 8 of 9
`
`US 7,134,505 B2
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`.0
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`
`U.S. Patent
`
`Nov. 14, 2006
`
`Sheet 9 of 9
`
`US 7,134,505 B2
`
`316b
`420a 16a
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`

`
`US 7,134,505 B2
`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`CROSS REFERENCE TO RELATED
`APPLICATIONS
`
`This is a divisional application of U.S. application Ser.
`No. 10/299,004, filed Nov. 19, 2002, which is now U.S. Pat.
`No. 6,907,936 U.S. application Ser. No. 10/299,004 and the
`present application claim priority from U.S. provisional 10
`application 60/331,491, filed Nov. 19, 2001 and U.S. pro(cid:173)
`visional application 60/404,783, filed Aug. 21, 2002.
`
`2
`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 perfo(cid:173)
`rations, the fluid must be pumped at high rates to achieve a
`consistent distribution of treatment fluids along the well(cid:173)
`bore.
`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
`15 passage therethrough 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
`
`FIELD OF THE INVENTION
`
`The invention relates to a method and apparatus for
`wellbore fluid treatment and, in particular, to a method and
`apparatus 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 25
`porosity and permit unrestricted wellbore inflow of petro(cid:173)
`leum products. Alternately, the hole may be cased with a
`liner, which is then perforated to permit inflow through the
`openings created by perforating.
`When natural inflow from the well is not economical, the 30
`well may require wellbore treatment termed stimulation.
`This is accomplished by pumping stimulation fluids such as
`fracturing fluids, acid, cleaning chemicals and/or proppant
`laden fluids to improve wellbore inflow.
`In one previous method, the well is isolated in segments 35
`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
`segment isolation. The packers, which are inflated with 40
`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 pressure conditions. Generally, the packers are 45
`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. Furthermore, it may require stimulation pump(cid:173)
`ing equipment to be at the well site for long periods of time 50
`or for multiple visits. This method can be very time con(cid:173)
`suming and costly.
`Other procedures for stimulation treatments use foam
`diverters, gelled diverters and/or limited entry procedures
`through tubulars to distribute fluids. Each of these may or 55
`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 60
`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 perforations 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-
`
`20
`
`A method and apparatus has been invented which pro(cid:173)
`vides 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 well(cid:173)
`bore, while other intervals are closed. In another aspect, the
`method and apparatus provide for the running in of a fluid
`treatment string, the fluid treatment string having ports
`substantially closed against the passage of fluid there(cid:173)
`through, but which are openable when desired to permit fluid
`flow into the well bore. The apparatus and methods of the
`present invention can be used in various borehole conditions
`including open holes, cased holes, vertical holes, horizontal
`holes, straight holes or deviated holes.
`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 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 first
`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 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 in 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 permitting 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 bore.
`In one embodiment, the second sleeve has formed thereon
`a seat and the means for moving the second sleeve includes
`65 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
`
`

`
`US 7,134,505 B2
`
`3
`second 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 posi(cid:173)
`tioned 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 embodi(cid:173)
`ment, 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(cid:173)
`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 of the first, second and third packer is a solid body
`packer including multiple packing elements. In such a 50
`packer, it is desirable that the multiple packing elements are
`spaced apart.
`In view of the foregoing there is provided a method for
`fluid treatment of a borehole, the method comprising: pro(cid:173)
`viding an apparatus for wellbore treatment according to one
`of the various embodiments of the invention; rnnning the
`tubing string into a wellbore in a desired position for treating
`the wellbore; setting the packers; conveying the means for
`moving the second sleeve to move the second sleeve and
`increasing 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, C02 , nitrogen and any of these fluids containing prop(cid:173)
`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
`
`4
`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.
`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 extrudable packing elements.
`In one embodiment, there is provided an apparatus for
`fluid treatment of a borehole, the apparatus comprising a
`10 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
`15 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 relative to the port, the sleeve being
`moveable relative to the port between a closed port position
`20 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
`25 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,
`30 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
`35 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 of the tubing string and the sleeve can act upon all of
`40 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
`45 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: pro-
`55 viding 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
`60 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 relative to the port, the sleeve being
`65 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
`
`

`
`US 7,134,505 B2
`
`5
`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 moving the
`sleeve to move the sleeve and increasing fluid pressure to
`permit the flow of well bore treatment fluid out through the
`port.
`
`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. 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 well bore
`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
`positionable in the sub of FIG. 4a;
`FIG. 5 is a section through another wellbore having
`positioned therein a fluid treatment assembly according to
`the present invention;
`FIG. 6a is a section through another wellbore having
`positioned therein another fluid treatment assembly accord(cid:173)
`ing 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 well bore
`treatment;
`FIG. 6c is a section through the well bore 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
`positioned therein another fluid treatment assembly accord(cid:173)
`ing 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 well bore
`treatment;
`FIG. 9c is a section through the well bore of FIG. 9a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`
`6
`FIG. 9d is a section through the well bore of FIG. 9a with
`the fluid treatment assembly in a fourth stage of well bore
`treatment.
`
`DETAILED DESCRIPTION OF THE PRESENT
`INVENTION
`
`Referring to FIGS. 1a and 1b, a wellbore fluid treatment
`assembly is shown, which can be used to effect fluid
`10 treatment of a formation 10 through a wellbore 12. The
`wellbore assembly includes a tubing string 14 having a
`lower end 14a 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
`15 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
`interval16a and the surface and further packers 20b to 20e
`are mounted between each pair of adjacent ported intervals.
`20 In the illustrated embodiment, a packer 20fis also mounted
`below the lower most ported interval16e and lower end 14a
`of the tubing string. 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
`25 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
`30 intervals to achieve a desired interval length or number of
`ported intervals per segment. In addition, packer 20/ 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.
`35 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)
`operations. In another embodiment, a plurality of packers
`are positioned in side by side relation on the tubing string,
`40 rather than using one packer between each ported interval.
`Sliding sleeves 22c to 22e 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
`45 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
`50 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
`55 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 of the wellbore. Preferably,
`the sleeves for each isolated interval between adjacent
`packers are opened individually to permit fluid flow to one
`60 wellbore segment at a time, in a staged, concentrated treat(cid:173)
`ment process.
`the sliding sleeves are each moveable
`Preferably,
`remotely from their closed port position to their position
`permitting through-port fluid flow, for example, without
`65 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
`
`

`
`US 7,134,505 B2
`
`7
`conveyed by gravity or 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 of the
`ported interval16e are opened, fluid can flow therethrough
`to the annulus 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
`smallest 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 ported interval16d
`by launching a ball 24d which is sized to pass through all of
`the seats closer to surface, including seat 26c, but which will 35
`land in and seal against seat 26d.
`Lower end 14a of the tubing string can be open, closed or
`fitted in various ways, depending on the operational char(cid:173)
`acteristics of the tubing string which are desired. In the
`illustrated embodiment, includes a pump out plug assembly 40
`28. Pump out plug assembly acts to close off end 14a 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 45
`most sleeve 22e by generation of a pressure differential. As
`will be appreciated, an opening adjacent end 14a 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 50
`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 14a can be left
`open or can be closed for example by installation of a 55
`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 60
`ports from the tubing string inner bore to the well bore 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 attach(cid:173)
`ments can be used.
`
`8
`treatment apparatus, as
`the wellbore fluid
`In use,
`described with respect to FIGS. 1a and 1b, can be used in the
`fluid treatment of a wellbore. For selectively treating for(cid:173)
`mation 10 through wellbore 12, the above-described assem(cid:173)
`bly is run into the borehole and the packers are set to seal the
`annulus at each location creating a plurality of isolated
`annulus zones. Fluids can then pumped down the tubing
`string and into a selected zone of the annulus, such as by
`increasing the pressure to pump out plug assembly 28.
`10 Alternately, a plurality of open ports or an open end can be
`provided or lower most sleeve can be hydraulically open(cid:173)
`able. Once that selected zone is treated, as desired, ball 24e
`or another sealing plug is launched from surface and con(cid:173)
`veyed by gravity or fluid pressure to seal against seat 26e of
`15 the lower most sliding sleeve 22e, this seals off the tubing
`string below sleeve 22e and opens ported interval 16e to
`allow the next annulus zone, the zone between packer 20e
`and 20fto be treated with fluid. The treating fluids will be
`diverted through the ports of interval 16e exposed by
`20 moving the sliding sleeve and be directed to a specific area
`of the formation. Ball 24e is sized to pass though all of the
`seats, including 26c, 26d closer to surface without sealing
`thereagainst. When the fluid treatment through ports 16e is
`complete, a ball 24d is launched, which is sized to pass
`25 through all of the seats, including seat 26c closer to surface,
`and to seat in and move sleeve 22d. This opens 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
`30 zones are treated. The balls can be launched without stop(cid:173)
`ping the flow of treating fluids. After treatment, fluids can be
`shut in or flowed back immediately. Once fluid pressure is
`reduced from surface, any balls seated in sleeve seats can be
`unseated by pressure from below to