New Page 1
`
`Page 1 of 2
`
`5.1 RockSealTM II Open Hole Packer Series
`
`5.1.1 Description
`
`The Rockseal II packer is a first for the oil and gas industry. The
`packer is a double element, solid body packer with Rock-$0//0’ sealing
`and holding power. It combines the sealing strength of a mechanical
`element along with the setting force of a dual-piston setting cylinder
`and mechanical body-lock system. The Rockseal
`II packer has a
`specially designed multi-piece elastomer with the largest possible
`cross section to provide excellent expansion ratios to set in oversized
`holes. The packing element also contains a special backup system
`that provides a solid pack-off, even with borehole ovality.
`
`The Rockseal II packer provides minimum running diameters for any
`given size, and is short in length, yet,
`long enough to provide a
`formation packer span of nearly 4 feet
`(1.2 meters) to provide
`maximum protection from ,flow, through the formation, and around
`the packer. The packer body has a reduced mid-section to promote
`running through any unconformity or undulations created during
`drilling. The elastomers are protected when running by oversized
`packing element back-up rings.
`
`Finally, the packer is designed with an anti-preset feature standard on A
`the Rockseal II. This feature allows the tool to be pushed through
`tight spots in the well without pre-setting or shearing the packer.
`When it is time to pull, the Rockseal II packer is released with straight
`pull. Releasing forces can be reduced by pressuring the tubing string
`during the releasing operation.
`
`5.1.2 Features
`
`Dual multi-piece packing element
`Maximum expansion ratios
`Anti—pre-set feature designed into each tool
`Minimum running O.D.
`Available in sour service trim versions
`
`Adjustable setting and releasing forces
`
`5.1.3 Applications
`
`Water shut-off
`
`WEATHERFORD
`
`INTERNATIONAL,
`LLC, et al.
`
`EXHIBIT 1022
`
`INC.
`
`WEATHERFORD
`
`INTERNATIONAL,
`LLC, et al.
`V.
`
`PACKERS PLUS
`
`ENERGY SERVICES,
`
`http://www.packersp1us.com/rockseal%202.htm
`
`07/04/2005
`
`

`
`, New Page 1
`
`Page 2 of 2
`
`Gas shut-off
`
`Production control
`
`Formation fracture isolation
`
`Build section isolation
`
`Production testing
`Vertical or horizontal open hole completions
`Isolation of a horizontal build section
`
`For More Information, Please Email us at info@packerspIus.com
`
`Packers Plus Energy Services Inc. © 2004
`
`http://www.packersplus.corn/rockseal%202.htm
`
`O7/04/2005
`
`

`
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`rowrrornewnmmonwanmavaws-vw mm» _
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`Provisional
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`200
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`200
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`100
`100
`150
`100
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`100
`300
`500
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`0
`
`50
`150
`250
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`o
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`130
`160
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`V65
`80
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`Fee Paid Q)
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`

`
`BENNETT JONES LLP
`
`The Commissionerof Patents and Trademarks
`Washington, D.C. 20231,
`U.S.A.
`
`BOX: PATENT APPLICATION
`
`Sir:
`
`Transmitted herewith for filing is the patent application of:
`
`Attorney Docket
`No.
`
`45023-.7
`
`
`Jim; Edmonton, CANADA and THEMIG, Daniel
`FEHR,
`
`
`Cochrane, CANADA.
`
`METHOD AND APPARATUS FOR WELLBORE FLUID TREATMENT
`US Provisional Application 60/331,491 filed November 19, 2001
`US Provisional A lication 60/404,783 filed Au ust 21, 2002
`
`Jon;
`
`J+—®
`
`
`
`
`
`The application comprising:
`
`_21_ pages of Disclosure;
`j_ pages of Claims;
`_]_ pages of Abstract;
`fl_ sheet(s) of drawings.
`
`and enclosed with the application are:
`
`[ XX ] A postcard.
`This patent application is being submitted under‘ 37 CFR 1.53(f) and 35 U.S.C. 111, without a
`Declaration and without the filing fee.
`’
`
`Respefctfullyksubmitted
`,— l
`
`-,
`
`November 18, 2002
`
`BENNETT JONES
`4500 Bankers Hall East
`855 - 2nd Street SW
`Calgary, Alberta T2P 4K7
`Canada’
`
`Telephone: (403) 298-3661
`
`

`
`Method and Apparatus for Wellborc Fluid Treatment
`
`Field of the Invention
`on relates to a method and apparatus for wellbore fluid treatment and, in
`paiticular, to a metho
`on to a wellbore for
`d and apparatus for selective communicati
`
`The inventi
`
`fluid treatment.
`
`well, an ope
`
`Background of the Invention
`An oil or gas well relies on inflow of petroleum products. When drilling an oil or gas
`rvals uncased (open hole) to
`rator may decide to leave productive inte
`ermit unrestricted wellbore inflow of petr
`expose porosity and p
`Altemately, the hole may be ca
`sed with a liner, which is then perforated to
`inflow through the openings created by perforating.
`
`oleum products.
`
`permit
`
`m the well is not economical, the well may require wellbore
`When natural inflow fro
`treatment termed stimulation. This is accomplished by pumping stimulation fluids
`
`improve wellbore inflow.
`In one previous method, the well is isolated in segments and each segment is
`individually tr
`uid treatment can be
`eated so that concentrated and controlled fl
`e. Often, in this method a tubing string is u
`provided along the wellbor
`ch provide for segment isolation. The
`inflatable element packers thereabout whi
`der, are used to isolate segments
`packers, whi
`ch are inflated with pressure using a blad
`ng is used to convey treatment fluids to the is
`(1 with respect to pressure capabilities as well as
`the packers are run for a
`
`of the well and the tubi
`
`olated segment.
`
`Such inflatable packers may be limite
`under high pressure conditions. Generally,
`must be moved after each treatment if it is
`t. This process can be expensive and time
`other segments of the well for treatmen
`Furthermore, 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
`
`durability
`
`wellbore treatment, but
`
`consumin g.
`
`consuming and costly.
`
`desired to isolate
`
`

`
`Other proceduresfor stimulation treatments use foam diverters, gelled diverters
`and/or limited entry procedures through tubulars to distribute fluids. Each of these
`
`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
`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. 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 timeifor 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
`
`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 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, 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 along 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,Aa 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 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 sleeve. The sealing device can
`
`be, for example, a plug or a ball, which can be deployed without connection to
`
`surface. ’I;hereby 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 tliereagainst 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 pennitting 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 thereover 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 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: 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 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, CO2, nitrogen and any of these fluids containing proppants, such as
`for example, sand or bauxite. The method can be conducted in an" open hole or in a
`cased hole. In a eased 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 cxtrudable packing elements.
`
`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 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 stiing 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 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. Altemately,
`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
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`upon, as by breaking open or shearing the cap, by engaging against the sleeve, ete., by
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`the sleeve to open the port.
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`There can be more than one port spaced along the long axis of the tubing string and
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`the sleeve can act upon all of the ports to open them.
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`The sleeve can be actuated in any way to move into the position permitted fluid flow
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`through the port. Preferably, however, the sleeve is actuated remotely, without the
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`need to trip a work string such as a tubing string or a wire line. In one embodiment,
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`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
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`multiple packing elements, for example, in spaced apart relation.
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`In view of the forgoing there is provided a method for fluid treatment of a borehole,
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`the method comprising: providing an apparatus for wellbore treatment including a
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`tubing string having a long axis, a port opened through the wall of the tubing string, a
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`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 H
`second packer operable to seal about the tubing string and mounted on the tubing
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`string to act in a position offset from the port along the long axis of the tubing string
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`and on a side of the port opposite the first packer; a sleeve positioned relative to the
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`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
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`a sleeve shifting means for moving the sleeve from the closed port position to the
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`position permitting fluid flow; running the tubing string into a wellbore in a desired
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`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
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`of wellbore treatment fluid out through the port.
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`

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`Brief Description of the Drawings F
`
`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:
`
`Figure la is a sectional view through a wellbore having positioned therein a fluid
`treatment assembly according to the present invention;
`
`Figure 1b is an enlarged view of a portion of the wellbore of Figure la with the fluid
`treatment assembly also shown in section;
`
`Figure 2 is a sectional view along the long axis of a packer useful in the present
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`invention;
`
`Figure 3a is a sectional view along the long axis of a tubing stnng sub useful in the
`present invention containing a sleeve in a closed port position;
`
`Figure 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
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`treatment ports;
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`Figure 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;
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`Figure 4b is a side elevation of a flow control sleeve positionable in the sub of Figure
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`4a;
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`Figure 5 is a section through another wellbore having positioned therein a fluid
`treatment assembly according to the present invention;
`
`Figure 6a is a section through another wellbore having positioned therein another
`fluid treatment assembly according to the present invention, the fluid treatment
`\
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`assembly being in a first stage of wellbore treatment;
`
`Figure 6b is a section through the wellbore of Figure 6a with the fluid treatment
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`assembly in a second stage of wellbore treatment;
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`

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`Figure 6c is a section through the wellbore of Figure 6a with the fluid treatment
`assembly in a third stage of wellbore treatment;
`
`Figure 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;
`
`Figure 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;
`
`Figure 9a is a section through another 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;
`
`Figure 9b is a section through the wellbore of Figure 9a with the fluid treatment
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`assembly in a second stage of wellbore treatment;
`
`Figure 9c is a section through the wellbore of Figure 9a with the fluid treatment
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`.
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`assembly in a third stage of wellbore treatment; and
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`Figure 9d is a section through the wellbore of Figure 9a with the fluid treatment
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`assembly in a fourth stage of wellbore treatment.
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`Detailed Description of the Present Invention
`
`Refening to Figures la and 1b, a wellbore fluid treatment assembly is shown, which
`can be usedto effect fluid treatment of a formation 10 through a wellbore 12. The
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`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 l6e 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
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`wellbore.
`
`A packer 20a is mounted between the upper-most ported interval 16a and the surface
`and further packers 20b to 20e are mounted between each pair of adjacent ported
`intervals. In the illustrated embodiment, a packer 20f is also mounted below the
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`lower most ported interval 16c and lower end 14a of the tubing string. The packers
`are disposed about the tubing string and selected to seal the annulus between the
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`

`
`tubing string andthe 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 segment. 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) operations. In another embodiment, a
`plurality of packers are positioned in side by side relation on the tubing string, rather
`than using one packer between each ported interval.
`
`Sliding sleeves 22c to 22c 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 22c).
`
`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 of the 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
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`process. \
`
`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
`
`

`
`10
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`sliding sleeves are each actuated by a device, such as a ball 24e (as shown) or plug,
`which can be conveyed by gravity or fluid flow through the tubing string. The device
`engages against the sleeve, in this case ball 24e engages against sleeve 22c, 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