BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1001
`Page 1 of 19
`
`

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`U.S. Patent
`
`Jun. 21,2005
`
`Sheet 1 0f 9
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`US 6,907,936 B2
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`Page 2 of 19
`Page 2 of 19
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`

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`U.S. Patent
`
`Jun. 21,2005
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`Sheet 2 0f 9
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`US 6,907,936 B2
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`Page 3 of 19
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`

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`U.S. Patent
`
`Jun. 21,2005
`
`Sheet 3 of 9
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`US 6,907,936 B2
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`Page 4 of 19
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`

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`U.S. Patent
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`Jun. 21,2005
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`Sheet 4 0f 9
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`US 6,907,936 B2
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`U.S. Patent
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`Jun. 21,2005
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`Sheet 5 of 9
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`US 6,907,936 B2
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`U.S. Patent
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`Jun. 21,2005
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`U.S. Patent
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`Jun. 21,2005
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`Sheet 7 of 9
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`US 6,907,936 B2
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`U.S. Patent
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`Jun. 21,2005
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`Sheet 8 0f 9
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`US 6,907,936 B2
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`Page 9 of 19
`Page 9 of 19
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`

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`U.S. Patent
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`Jun. 21,2005
`
`Sheet 9 of 9
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`US 6,907,936 B2
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`420a 17 420b
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`Page 10 of 19
`Page 10 of 19
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`

`
`US 6,907,936 B2
`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`This application claims priority from U.S. provisional
`application 60/331,491, filed Nov. 19, 2001 and U.S. pro-
`visional application 60/404,783, filed Aug. 21, 2002.
`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
`porosity and permit unrestricted wellbore inflow of petro-
`leum products. Alternately, the hole may be cased with a
`liner, which is then perforated to permit inflow through the
`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 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.
`
`10
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`15
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`20
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`25
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`30
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`40
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`45
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`50
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`55
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`2
`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
`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 pro-
`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
`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 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
`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. 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
`
`Page 11 of 19
`Page 11 of 19
`
`

`
`US 6,907,936 B2
`
`3
`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-
`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
`embodiment, the apparatus further comprises a third port
`having mounted thereon a cap extending into the tubing
`string inner bore and in the position permitting fluid flow, the
`first sleeve also engages against the cap of the third port to
`open it.
`In another embodiment, the first port has mounted there-
`over a sliding sleeve and in the position permitting fluid
`flow, the first sleeve has engaged and moved the sliding
`sleeve away from the first port. The sliding sleeve can
`include, for example, a groove and the first sleeve includes
`a locking dog biased outwardly therefrom and selected to
`lock into the groove on the sleeve. In another embodiment,
`there is a third port with a sliding sleeve mounted thereover
`and the first sleeve is selected to engage and move the third
`port sliding sleeve after it has moved the sliding sleeve of the
`first port.
`The packers can be of any desired type to seal between the
`wellbore and the tubing string. In one embodiment, at least
`one 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: pro-
`viding 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
`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.
`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.
`
`4
`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 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
`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 bc a second port spaced along the long
`axis of the tubing string from the first port and the sleeve can
`be moveable to a position permitting flow through the port
`and the second port.
`As noted hereinbefore, the sleeve can be positioned in
`various ways when in the closed port position. For example,
`in the closed port position, the sleeve can be positioned over
`the port to close the port against fluid flow therethrough.
`Alternately, when in the closed port position, the sleeve can
`be offset from the port, and the port can be closed by other
`means such as by a cap or another sliding sleeve which is
`acted upon, as by breaking open or shearing the cap, by
`engaging against the sleeve, etc., by the sleeve to open the
`port.
`There can be more than one port spaced along the long
`axis of the tubing string and the sleeve can act upon all of
`the ports to open them.
`The sleeve can be actuated in any way to move into the
`position permitted fluid flow through the port. Preferably,
`however, the sleeve is actuated remotely, without the need to
`trip a work string such as a tubing string or a wire line. In
`one embodiment, the sleeve has formed thereon a seat and
`the means for moving the sleeve includes a sealing device
`selected to seal against the seat, such that fluid pressure can
`be applied to move the sleeve and the sealing device can seal
`against fluid passage past the sleeve.
`The first packer and the second packer can be formed as
`a solid body packer including multiple packing elements, for
`example, in spaced apart relation.
`In view of the forgoing there is provided a method for
`fluid treatment of a borehole, the method comprising: pro-
`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
`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
`moveable relative to the port between a closed port position
`and a position permitting fluid flow through the port from the
`tubing string inner bore and a sleeve shifting means for
`moving the sleeve from the closed port position to the
`position permitting fluid flow; running the tubing string into
`a wellbore in a desired position for treating the wellbore;
`setting the packers; conveying the means for moving the
`sleeve to move the sleeve and increasing fluid pressure to
`permit the flow of wellbore treatment fluid out through the
`port.
`
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`Page 12 of 19
`Page 12 of 19
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`

`
`US 6,907,936 B2
`
`5
`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 wellbore
`of FIG. 1a with the fluid treatment assembly also shown in
`section;
`FIG. 2 is a sectional view along the long axis of a packer
`useful in the present invention;
`FIG. 3a is a sectional view along the long axis of a tubing
`string sub useful in the present invention containing a sleeve
`in a closed port position;
`FIG. 3b is a sectional view along the long axis of a tubing
`string sub useful in the present invention containing a sleeve
`in a position allowing fluid flow through fluid treatment
`ports;
`FIG. 4a is a quarter sectional view along the long axis of
`a tubing string sub useful in the present invention containing
`a sleeve and fluid treatment ports;
`FIG. 4b is a side elevation of a flow control sleeve
`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-
`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 wellbore
`treatment;
`FIG. 6c is a section through the wellbore of FIG. 6a with
`the fluid treatment assembly in a third stage of wellbore
`treatment;
`FIG. 7 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`FIG. 8 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`FIG. 9a is a section through another wellbore having
`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. 9b is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`FIG. 9c is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`FIG. 9a’ is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a fourth stage of wellbore
`treatment.
`
`DETAILED DESCRIPTION OF THE PRESENT
`INVENTION
`
`Referring to FIGS. la and lb, a wellbore fluid treatment
`assembly is shown, which can be used to effect fluid
`
`10
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`25
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`6
`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 166 each including a plurality of ports
`17 opened through the tubing string wall to permit access
`between the tubing string inner bore 18 and the wellbore.
`A packer 20a is mounted between the upper-most ported
`interval 16a and the surface and further packers 20b to 206
`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 166 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
`disposed in the wellbore. The packers divide the wellbore
`into isolatcd scgmcnts whcrcin 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 226 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 22a’) 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 226).
`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 treat-
`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
`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 246 (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 246
`engages against sleeve 226, and, when pressure is applied
`through the tubing string inner bore 18 from surface, ball
`246 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
`
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`US 6,907,936 B2
`
`7
`defines a seat 266 onto which an associated ball 246, 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 interval 166 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 226 has the
`smallest diameter D1 seat and accepts the smallest sized ball
`246 and each sleeve that is progressively closer to surface
`has a larger seat. For example, as shown in figure 1b,
`the
`sleeve 226 includes a seat 266 having a diameter D3, sleeve
`22d includes a seat 26d having a diameter D2, which is less
`than D3 and sleeve 226 includes a seat 266 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 246, which can pass though all of the seats of
`the sleeves closer to surface but which will land in and seal
`
`against seat 266 of sleeve 226. Likewise, penultimate sleeve
`22d can be actuated to move away from 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 14a 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, includes a pump out plug assembly
`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
`most sleeve 226 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
`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
`welded or threaded plug.
`While the illustrated tubing string includes five ported
`intervals, it is to be understood that any number of ported
`intervals could be used. In a fluid treatment assembly desired
`to be used for staged fluid treatment, at least two openable
`ports from the tubing string inner bore to the wellbore must
`be provided such as at least two ported intervals or an
`openable end and one ported interval.
`It
`is also to be
`understood that any number of ports can be used in each
`interval.
`
`Centralizer 29 and other standard tubing string attach-
`ments can be used.
`
`the wellbore fluid treatment apparatus, as
`In use,
`described with respect to FIGS. 1a and 1b, can be used in the
`fluid treatment of a wellbore. For selectively treating for-
`mation 10 through wellbore 12, the above-described assem-
`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
`
`10
`
`15
`
`20
`
`25
`
`30
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`8
`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 be hydraulically open-
`able. Once that selected zone is treated, as desired, ball 246
`or another sealing plug is launched from surface and con-
`veyed by gravity or fluid pressure to seal against seat 266 of
`the lower most sliding sleeve 226, this seals off the tubing
`string below sleeve 226 and opens ported interval 166 to
`allow the next annulus zone, the zone between packer 206
`and 20f to be treated with fluid. The treating fluids will be
`diverted through the ports of interval 166 exposed by
`moving the sliding sleeve and be directed to a specific area
`of the formation. Ball 246 is sized to pass though all of the
`seats, including 26c, 26d closer to surface without sealing
`thereagainst. When the fluid treatment through ports 166 is
`complete, a ball 24a’ is launched, which is sized to pass
`through all of the seats, including seat 266 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 206. This process of launching
`progressively larger balls or plugs is repeated until all of the
`zones are treated. The balls can be launched without stop-
`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 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. 2, 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-off.
`Packing element 21a is mounted between fixed stop ring
`34a and compressing ring 34b and packing element 21b is
`mounted between fixed stop ring 34c and compressing ring
`34a’. The hydraulically actuated setting mechanism includes
`a port 35 through inner mandrel 32 which provides fluid
`access to a hydraulic chamber defined by first piston 36a and
`second piston 36b. First piston 36a acts against compressing
`ring 34b to drive compression and, therefore, expansion of
`packing element 21a, while second piston 36b acts against
`compressing ring 34a’ to drive compression and, therefore,
`expansion of packing element 21b. First piston 36a includes
`a skirt 37, which encloses the hydraulic chamber between
`the pistons and is telescopically disposed to ride over piston
`36b. 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.
`
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`US 6,907,936 B2
`
`9
`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 but is locked
`against retraction to lock the packing elements in extruded
`position.
`Ring 34a includes shears 38 which mount the ring to
`mandrel 32. Thus, for release of the packing elements from
`sealing po