BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1002
`
`Page 1 of 13
`
`

`
`US007l08067B2
`
`(12) United States Patent
`Themig et al.
`
`(10) Patent No.:
`
`(45) Date of Patent:
`
`US 7,108,067 B2
`*Sep. 19, 2006
`
`(54) METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`(56)
`
`References Cited
`U.S. PATENT DOCUMENTS
`
`(75)
`
`Inventors: Daniel Jon Themig, Calgary (CA); Jim
`Fehr, Edmonton (CA)
`(73) Assignee: Packers Plus Energy Services Inc.,
`Calgary (CA)
`Subject to any disclaimer, the term of this
`patent is extended or adjusted under 35
`U.S.C. 154(b) by 219 days.
`
`( * ) Notice:
`
`This patent is subject to a terminal dis-
`claimer.
`
`(21) Appl. No.: 10/604,807
`
`(22)
`
`Filed:
`
`Aug. 19, 2003
`
`(65)
`
`Prior Publication Data
`
`US 2004/0118564 A1
`
`Jun. 24, 2004
`
`6/1977 Sanford .................... .. 166/264
`4,031,957 A *
`7/1978 Hutchison et al.
`.
`166/191
`4,099,563 A *
`
`2/1985 Vann ........................ .. 166/297
`4,499,951 A *
`3/1986 Faulkner
`4,577,702 A
`5/1995 Ehlinger et al.
`5,411,095 A
`7/1996 Surjaatrnadja et al.
`5,533,571 A
`12/1999 Whiteley et al.
`6,006,838 A
`5/2000 Allen
`6,065,541 A
`2/2001 Wyatt et al.
`6,189,619 B1
`166/376
`5/2002 Allamon et al.
`6,390,200 B1*
`6,651,743 B1* 11/2003 Szarka ..................... .. 166/285
`
`
`
`OTHER PUBLICATIONS
`
`these or similar
`Information on RockSea1 Open Hole Packers,
`packers believed to be publicly avallable in the US prior to Aug. 19,
`2002.
`
`Related U.S. Application Data
`
`* cited by examiner
`
`(60) Provisional application No. 60/404,783, filed on Aug.
`21, 2002.
`
`(51)
`
`Int. Cl.
`(2006.01)
`E21B 34/14
`(52) U.S.Cl.
`.................... .. 166/317; 166/154;166/164;
`166/169; 166/186; 166/194; 166/250.17;
`166/332.4; 166/334.4
`(58) Field of Classification Search .............. .. 166/154,
`166/164, 169, 250.17, 263, 279, 291, 296,
`166/305.1, 306, 310, 312, 317, 332.4, 334.4,
`166/373, 383, 386
`See application file for complete search history.
`
`Primary Examiner—Zakiya W. Bates
`(74) Attorney, Agent, or Firm—Bennett Jones LLP
`
`(57)
`
`ABSTRACT
`
`A tubing string assembly for fluid treatment of a wellbore
`includes substantially pressure holding closures spaced
`along the tubing string, which each close at least one port
`through the tubing string wall. The closures are openable by
`a sleeve drivable through the tubing string inner bore.
`
`12 Claims, 6 Drawing Sheets
`
`Page 1 of 13
`Page 1 of 13
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`

`
`U.S. Patent
`
`Sep. 19,2006
`
`Sheet 1 of 6
`
`US 7,108,067 B2
`
`Tto surface
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`Page 2 of 13
`Page 2 of 13
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`
`

`
`U.S. Patent
`
`Sep. 19,2006
`
`Sheet 2 of 6
`
`US 7,108,067 B2
`
`24d
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`
`24e
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`Page 3 of 13
`Page 3 of 13
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`

`
`U.S. Patent
`
`Sep. 19,2006
`
`Sheet 3 of 6
`
`US 7,108,067 B2
`
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`FIG. 3
`
`Page 4 of 13
`Page 4 of 13
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`

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`U.S. Patent
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`Sep. 19,2006
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`Sheet 4 of 6
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`US 7,108,067 B2
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`
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`220a
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`Page 5 of 13
`Page 5 of 13
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` 5
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`

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`U.S. Patent
`
`Sep. 19,2006
`
`Sheet 5 of 6
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`US 7,108,067 B2
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`Page 6 of 13
`Page 6 of 13
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`

`
`U.S. Patent
`
`Sep. 19,2006
`
`Sheet 6 of 6
`
`US 7,108,067 B2
`
`420a
`
`420b
`
`414
`
`4200
`
`420d
`
`FIG. 7d
`
`Page 7 of 13
`Page 7 of 13
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`

`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`BACKGROUND OF INVENTION
`
`The invention relates to a method and apparatus for
`wellbore fluid treatment and, in particular, to a method and
`apparatus for selective flow control to a wellbore for fluid
`treatment.
`
`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. Altemately, 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
`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
`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
`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
`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-
`ing equipment to be at the well site for long periods of time
`or for multiple visits. This method can be very time con-
`suming 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 well-
`bore 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 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-
`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 therethrough of fluid. This need to run in a tube
`
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`US 7,108,067 B2
`
`2
`
`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.
`
`SUMMARY OF INVENTION
`
`A method and apparatus has been invented which pro-
`vides for selective communication to a wellbore for fluid
`
`treatment. In one 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 therethrough, but which are openable when
`desired to permit fluid flow into the wellbore. The apparatus
`and methods of the 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 of the 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 of
`closures 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 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 of any desired
`
`Page 8 of 13
`Page 8 of 13
`
`

`
`US 7,108,067 B2
`
`3
`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 of the foregoing there is provided a method for
`fluid treatment of a borehole, the method comprising: pro-
`viding 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 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
`positioned therein a fluid treatment assembly according to
`the present invention;
`FIG. 2 is a sectional view through a wellbore having
`positioned 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
`positioned therein another fluid treatment assembly accord-
`ing 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;
`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; and
`FIG. 7c is a section through the wellbore of FIG. 7a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`
`5
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`15
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`25
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`30
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`35
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`40
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`45
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`60
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`65
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`4
`
`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
`
`Referring to FIG. 1, a wellbore fluid treatment assembly
`is shown, which can be used to effect fluid treatment of a
`formation 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 substan-
`
`tially 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 embodi-
`ment, 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 associated 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 move-
`able from a closed port position to a position wherein the
`ports have been opened by passing of the sleeve and fluid
`flow ofi for example, stimulation fluid is permitted down
`through the tubing string, arrows F, through the ports of the
`ported interval. If fluid flow is continued, the fluid can return
`to surface through the annulus.
`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 eifect 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
`formation 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 segment of the well, but is prevented from
`passing through the armulus 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 segment. In addition, packer
`20f need not be present in some applications.
`The packers can be, as shown, of the solid body-type with
`least one extrudable packing element,
`for example,
`at
`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
`
`Page 9 of 13
`Page 9 of 13
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`

`
`US 7,108,067 B2
`
`5
`(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 of the 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
`moveable 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 permitted through the ports of the ported interval (as
`shown by sleeve 22:2).
`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
`wellbore, 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 wellbore segment at a time,
`in a staged treatment
`process.
`are each moveable
`sliding sleeves
`the
`Preferably,
`remotely, for example without having to run in a li11e or
`string for manipulation thereof, from their closed port posi-
`tion to their position permitting through-port fluid flow. In
`one embodiment, 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
`move4 through the tubing string. In this case, ball 24e is
`sized so that
`it cannot pass through sleeve 22e a11d 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 diflerent
`diameter seat and, therefore, each accept a different sized
`ball. In particular, the lower-most sliding sleeve 22e has the
`smallest diameter D] 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 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
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`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 char-
`acteristics of the tubing string which are desired. In the
`illustrated embodiment, the tubing string includes a pump
`out plug assembly 28. Pump out plug assembly 28 acts to
`close olf 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
`hydraulically 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
`wellbore 12, the above-described assembly 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 armulus, such as by increasing the pressure to
`pump out plug assembly 28. Alternately, 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 pressure to seal against seat 26e of the
`lower most sliding sleeve 22e, this seals olf the tubing string
`below sleeve 22e and drives the sleeve to open the ports of
`ported interval 16e to allow the next armulus 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 of the
`formation. Ball 24e is sized to pass though all of the seats
`closer to surface, including seats 26c, 26d, without sealing
`thereagainst. When the fluid treatment through ports 16e is
`complete, a ball 24d is 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
`
`Page 10 of 13
`Page 10 of 13
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`

`
`US 7,108,067 B2
`
`7
`witl1out stopping 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 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 extrud-
`able packing elements 21a, 21b, a hydraulically actuated
`setting mechanism 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-olf.
`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 211;, while second piston 36b acts against
`compressing ring 34d to drive compression and, therefore,
`expansion of packing element 2119. First piston 36a includes
`a skirt 37, which encloses the hydraulic chamber between
`the pistons and is telescopically disposed to ride over piston
`36!). Seals 38 seal against the leakage of fluid between the
`parts. Mechanical 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 pistons toward each other, thereby locking
`the packing elements into a compressed, expanded configu-
`ration.
`
`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
`movement 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 34a includes shears 38 which mount the ring to
`mandrel 32. Thus, for release of the packing elements from
`sealing position the tubing string into which mandrel 32 is
`connected, can be pulled up to release shears 38 and,
`thereby, release the compressing force on the packing ele-
`ments.
`
`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
`assembly includes a tubing string 212 and ported intervals
`216a, 216b, 216c each including a plurality of ports 217
`spaced along the long axis of the tubing string. Packers
`220a, 220b are provided between each interval to form an
`isolated segment in the wellbore 212.
`
`8
`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 par-
`ticular, 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 therethrough, 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
`stimulation treatment (FIG. 4a). Fluids will be forced to the
`lower section of the well below packer 220b. In this illus-
`trated embodiment, the ports of interval 216c are normally
`open size restricted ports, which do not require opening for
`stimulation fluids to be jetted therethrough. However, it is to
`be understood that the ports can be installed in closed
`configuration, but opened once the tubing is in place.
`When desired to stimulate another section of the 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 pressure will hold the ball in the sleeve, this
`elfectively shuts ofl 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, elfectively shutting olf
`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
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`in stages, using a sprinkler approach over each individual
`section.
`The above noted method can also be used for wellbore
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