BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1001
`BAKER HUGHES INCORPORATED
`AND BAKER HUGHES OILFIELD
`OPERATIONS, INC. v. PACKERS
`PLUS ENERGY SERVICES, INC.
`IPR2016-00598
`
`Page 1 of 20
`
`

`
`Us 7,861,774 B2
`Page 2
`
`U.S. PATENT DOCUMENTS
`
`2007/0151734 A1
`
`7/2007 Fehr et al.
`
`................. .. 166/318
`
`OTHER PUBLICATIONS
`
`Halliburton “Halliburton Guiberson® G-77 Hydraulic-Set Retriev-
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`Baker Oil Tools, “Retrievable Packer Systems,” product brochure, 1
`page.
`Drawings, Packer Installation Plan, PACK 05543, 5 pages, 1997.
`Guiberson°AVA & Dresser, Retrievable Packer Systems, “Tandem
`Packer,” 1 page.
`Halliburton, “Hydraulic-Set GuibersonTM Wizard Packer®,” 1 page.
`D.W. Thomson, “Design and Installation of a Cost-Effective
`Completion System for Horizontal Chalk Wells Where Multiple
`Zones Require Acid Stimulation,” SPE Drilling & Completion, Sep.
`1998, pp. 151-156, 1998.
`Packers Plus Energy Services, Inc. “5.1 RockSealTM II Open Hole
`Packer Series,” 2 pages, 2004.
`Halliburton Guiberson G-77 Hydraulic-Set Retrievable Packer pre-
`sentation, 6 pages.
`Owen Oil Tools Mechanical Gun Release; 2-3/8" & 2-7/8" product
`description, 1 page.
`Sapex Oil Tools Ltd. Downhole Completions catalog, 24 pages.
`Halliburton, catalog, pp. 51-54, 1957.
`Baker Hughes, catalog, pp. 66-73, 1991.
`Trahan, Kevin, Aflidavit, May 19, 2008.
`Trahan, Kevin, Aflidavit Exhibit C, May 19, 2008.
`Trahan, Kevin, Aflidavit Exhibit E, May 19, 2008.
`Trahan, Kevin, Aflidavit Exhibit G, May 19, 2008.
`Baker Oil Tools, catalog, p. 29, Model “C” Packing Element Circu-
`lating Washer, Product No. 470-42, Mar. 1997.
`Guiberson-AVA Dresser, catalog, front page and pp. 1 & 20, 1994.
`Baker Oil Tools, catalog, p. 38, Twin Seal Submersible Pumppacker.
`Halliburton, Plaintiff’ s Fourth Amended Petition in Cause No.
`CV-44964, 238th Judicial District of Texas, Aug. 13, 2007.
`Packers Plus, Second Amended Original Answer in Cause No.
`CV-44964, 23 8th Judicial District District of Texas, Feb. 13, 2007.
`Packers Plus, Original Answer in Cause No. CV-44964, 23 8th Judi-
`cial District of Texas, Feb. 13, 2007.
`Guiberson AVA, Packer Installation Plan, Aug. 26, 1997.
`Guiberson AVA, Packer Installation Plan, Sep. 9, 1997.
`Guiberson AVA, Packer Installation Plan, Nov. 11, 1997.
`Guiberson AVA, Wizard II Hydraulic Set Retrievable Packer Tech
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`Dresser Oil Tools, catalog, Multilateral Completion Tools Section.
`Dresser Oil Tools, catalog, Technical Section, title page and page 18,
`Nov. 1997.
`Berryman, William, First Supplemental Expert Report in Cause No.
`CV-44964, 23 8th Judicial District of Texas.
`Brown Oil Tools, catalog page, entitled “Brown Hydraulic Set Pack-
`ers.”
`Brown Oil Tools, catalog page, entitled “Brown HS-16-1 Hydraulic
`Set Retrievable Packers.”
`Brown Oil Tools General Catalog 1962-63, Hydraulic Set Packers
`and Hydraulic Set Retrievable Packers, pp. 870-871.
`First Supplemental Expert Report of Kevin Trahan, Case No.
`CV-44,964, 238th Judicial District, Midland County, Texas, Aug. 21,
`2008, 28 pages, 2008.
`Order of Dismissal, Case No. CV-44,964, 238th Judicial District,
`Midland County, Texas, Oct. 14, 2008, 1 page.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit 6,
`Deposition of Daniel Jon Themig, Calgary, Alberta, Canada, dated
`Jan. 17, 2006, parts 1 and 2 total for a total of82 pages with redactions
`from p. 336, Line 10 through all ofp. 337.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit 7,
`Deposition of Daniel Jon Themig, Calgary, Alberta, Canada, dated
`Jan. 8, 2007, 75 pages with redactions from p. 716, Line 23 through
`p. 726, Line 22.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit 8,
`Deposition of Daniel Jon Themig, Calgary, Alberta, Canada, dated
`Jan. 9, 2007,46 pages with redactions on p. 850, Lines 13-19.
`
`Page 2 of 20
`Page 2 of 20
`
`Loomis ................. .. 73/40.5 R
`Townsend ................. .. 405/269
`Loomis .................... .. 166/187
`Baker et al.
`.............. .. 166/122
`Brown et al.
`. . . .. 29/705
`Loomis . . . . . .
`Loomis ................. .. 73/40.5 R
`Loomis .................... .. 277/337
`Loomis
`73/40.5 R
`Loomis
`73/40.5 R
`Loomis
`73/40.5 R
`Loomis
`29/407.01
`Loomis ............... .. 166/250.08
`Loomis .................... .. 277/337
`Loomis
`166/147
`Hefley et al.
`.............. .. 166/120
`Hutchison et al.
`Weitz ....................... .. 166/312
`Ross et al.
`................ .. 166/312
`Berry et al.
`Cochron ................... .. 166/312
`Pringle
`..
`Ross et al.
`Zunkel et al.
`Brisco
`Evans ............. ..
`Barrington et al.
`Evans ............. ..
`Dech ..... ..
`Mohaupt
`.
`Gentry ........ ..
`Greenlee et al.
`Mills
`Stokley et al.
`Szarka et al.
`Murray
`Greenlee .................. .. 166/ 120
`Clark et al.
`.
`. 166/122
`Wood et al.
`.
`. 166/387
`Morgan ....... ..
`. 166/181
`Kennedy et al.
`............ .. 166/50
`Kennedy et al.
`Lee
`Jordan, Jr. et al.
`Jordan, Jr. et al.
`Pringle ..................... .. 166/ 120
`Kilgore et al.
`.
`. 166/119
`Arizmendi et al
`. 166/206
`
`Skinner et al.
`............ .. 166/187
`Wiemers et al.
`Allamon et al.
`Arizmendi
`................ .. 166/ 187
`Zeltmann et al.
`Kilgore et al.
`............ .. 166/120
`Henley et al.
`............. .. 166/373
`Carmichael et al.
`Zemlak et al.
`Braithwaite et al.
`Chatterji et al.
`........... .. 166/276
`Cavender
`Fehr et al.
`Themig
`Weng et al.
`Jones
`Themig et al.
`Fehr et al.
`................. .. 166/387
`Kilgore et al.
`............ .. 166/134
`Kilgore et al.
`............ .. 166/134
`Hotman
`Depiak et al.
`
`
`
`................. .. 166/387
`
`............. .. 166/185
`
`
`
`. 166/321
`............. .. 166/120
`
`
`
`166/128
`166/135
`166/134
`166/380
`. 166/305.1
`166/313
`.......... .. 166/387
`
`
`
`>>>>>>>>>>>D>>D>>>>>>>>>>D>>>D>D>>>D>D>D>D>D>D>D>D>>D>3>>D>>D>D>D>D>D>D>>D>D>D>D>
`
`2,841,007
`2,860,489
`3,038,542
`3,054,415
`3,122,205
`3,153,845
`3,154,940
`3,158,378
`3,165,918
`3,165,919
`3,165,920
`3,193,917
`3,194,310
`3,195,645
`3,199,598
`3,311,169
`4,099,563
`4,279,306
`4,498,536
`4,516,879
`4,519,456
`4,520,870
`4,552,218
`4,567,944
`4,569,396
`4,590,995
`4,646,829
`4,657,084
`4,714,117
`4,716,967
`4,754,812
`4,791,992
`4,794,989
`4,893,678
`4,949,788
`4,967,841
`5,103,901
`5,152,340
`5,186,258
`5,197,547
`5,454,430
`5,472,048
`5,499,687
`5,526,880
`5,533,573
`5,542,473
`5,701,954
`5,775,429
`5,791,414
`5,894,888
`5,960,881
`6,041,858
`6,047,773
`6,112,811
`6,131,663
`6,253,861
`6,446,727
`6,460,619
`6,543,545
`6,763,885
`6,907,936
`7,021,384
`7,096,954
`7,108,060
`7,108,067
`7,134,505
`7,198,110
`7,231,987
`7,267,172
`2002/0162660
`
`7/1958
`11/1958
`6/1962
`9/1962
`2/1964
`10/1964
`11/1964
`11/1964
`1/1965
`1/1965
`1/1965
`7/1965
`7/1965
`7/1965
`8/1965
`3/1967
`7/1978
`7/1981
`2/1985
`5/1985
`5/1985
`6/1985
`11/1985
`2/1986
`2/1986
`5/1986
`3/1987
`4/1987
`12/1987
`1/1988
`7/1988
`12/1988
`1/1989
`1/1990
`8/1990
`11/1990
`4/1992
`10/1992
`2/1993
`3/1993
`10/1995
`12/1995
`3/1996
`6/1996
`7/1996
`8/1996
`12/1997
`7/1998
`8/1998
`4/1999
`10/1999
`3/2000
`4/2000
`9/2000
`10/2000
`7/2001
`9/2002
`10/2002
`4/2003
`7/2004
`6/2005
`4/2006
`8/2006
`9/2006
`9/2006
`11/2006
`4/2007
`6/2007
`9/2007
`11/2002
`
`

`
`Us 7,861,774 B2
`Page 3
`
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit 9,
`Cross-exarnination of Daniel Jon Themig, In the Court of Queen’s
`Bench of Alberta, Canada, dated Mar. 14, 2005, 67 pages.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit
`10, Deposition of William Sloane Muscroft, Edmonton, Alberta,
`Canada, dated Mar. 31, 2007, parts 1 and 2 for a total of 111 pages.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit
`1 1, Email from William Sloane Muscroft to Peter Krabben dated Jan.
`27, 2000, 1 page.
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit
`12, Email from William Sloane Muscroft to Daniel Jon Themig dated
`Feb. 1, 2000, 1 page.
`
`238th District Court, Midland, Texas, Case No. CV44964, Exhibit
`13, Email from Daniel Jon Themig to William Sloane Muscroft dated
`Jun. 19, 2000, 2 pages.
`Design and Installation of a Cost-Effective Completion System for
`Horizontal Chalk Wells Where Multiple Zones Require Acid Stimu-
`lation, D. W. Thompson, SPE Drilling & Completion, Sep. 1998, pp.
`1 5 1 - 1 56.
`
`http://wwW.packersplus.com/rockseal%202.htrn description of open
`hole packer, available prior to Nov. 19, 2001.
`
`* cited by examiner
`
`Page 3 of 20
`Page 3 of 20
`
`

`
`U.S. Patent
`
`Jan. 4, 2011
`
`Sheet 1 of9
`
`Us 7,861,774 B2
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`Page 4 of 20
`Page 4 of 20
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`

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`U.S. Patent
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`Jan. 4, 2011
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`Sheet 2 of9
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`Page 5 of 20
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`

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`U.S. Patent
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`Jan. 4, 2011
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`Sheet 3 of9
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`Page 6 of 20
`Page 6 of 20
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`Jan. 4, 2011
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`U.S. Patent
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`Jan. 4, 2011
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`Page 12 of 20
`Page 12 of 20
`
`

`
`1
`METHOD AND APPARATUS FOR
`WELLBORE FLUID TREATMENT
`
`CROSS REFERENCE TO RELATED
`APPLICATIONS
`
`This is a continuation application of U.S. application Ser.
`No. 11/550,863 filed Oct. 19, 2006, now U.S. Pat. No. 7,543,
`634, issued Jun. 9, 2009, which is a continuation of U.S.
`application Ser. No. 11/104,467, filed Apr. 13, 2005, now
`U.S. Pat. No. 7,134,505, issued Nov. 14, 2006, which is a
`divisional of U.S. application Ser. No. 10/299,004, filed Nov.
`19, 2002, now U.S. Pat. No. 6,907,936, issued Jun. 21, 2005.
`The parent applications and the present application claim
`priority from U.S. provisional application 60/331,491, filed
`Nov. 19, 2001 and U.S. provisional application 60/404,783,
`filed Aug. 21, 2002.
`
`FIELD OF THE INVENTION
`
`The invention relates to a method and apparatus for well-
`bore fluid treatment and, in particular, to a method and appa-
`ratus for selective communication to a wellbore for fluid
`treatment.
`
`BACKGROUND OF THE INVENTION
`
`An oil or gas well relies on inflow of petroleum products.
`When drilling an oil or gas well, an operator may decide to
`leave productive intervals uncased (open hole) to expose
`porosity and permit unrestricted wellbore inflow of petro-
`leum products. Alternately, the hole may be cased with a liner,
`which is then perforated to permit inflow through the open-
`ings created by perforating.
`When natural inflow from the well is not economical, the
`well may require wellbom treatment termed stimulation. This
`is accomplished by pumping stimulation fluids such as frac-
`turing fluids, acid, cleaning chemicals and/or proppant laden
`fluids to improve wellbore inflow.
`In one previous method, the well is isolated in segments
`and each segment is individually treated so that concentrated
`and controlled fluid treatment can be provided along the
`wellbore. Often, in this method a tubing string is used with
`inflatable element packers thereabout which provide for seg-
`ment isolation. The packers, which are inflated with pressure
`using a bladder, are used to isolate segments of the well and
`the tubing is used to convey treatment fluids to the isolated
`segment.
`Such inflatable packers may be limited with respect to
`pressure capabilities as well as durability under high 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. Further-
`more, it may require stimulation pumping equipment to be at
`the well site for long periods of time or for multiple visits.
`This method can be very time consuming and costly.
`Other procedures for stimulation treatments use foam
`diverters, gelled diverters and/or limited entry procedures
`through tubulars to distribute fluids. Each ofthese may or may
`not be effective in distributing fluids to the desired segments
`in the wellbore.
`
`The tubing string, which conveys the treatment fluid, can
`include ports or openings for the fluid to pass therethrough
`into the borehole. Where more concentrated fluid treatment is
`desired in one position along the wellbore, a small number of
`larger ports are used. In another method, where it is desired to
`
`10
`
`15
`
`20
`
`25
`
`30
`
`35
`
`40
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`45
`
`50
`
`55
`
`60
`
`65
`
`US 7,861,774 B2
`
`2
`
`distribute treatment fluids over a greater area, a perforated
`tubing string is used having a plurality of spaced apart perfo-
`rations through its wall. The perforations can be distributed
`along the length of the tube or only at selected segments. The
`open area of each perforation can be pre-selected to control
`the volume of fluid passing from the tube during use. When
`fluids are pumped into the liner, a pressure drop is created
`across the sized ports. The pressure drop causes approximate
`equal volumes of fluid to exit each port in order to distribute
`stimulation fluids to desired segments of the well. Where
`there are significant numbers of perforations, the fluid must
`be pumped at high rates to achieve a consistent distribution of
`treatment fluids along the wellbore.
`In many previous systems, it is necessary to run the tubing
`string into the bore hole with the ports or perforations already
`opened. This is especially true where a distributed application
`of treatment fluid is desired such that a plurality of ports or
`perforations must be open at the same time for passage there-
`through of fluid. This need to run in a tube already including
`open perforations can hinder the running operation and limit
`usefulness of the tubing string.
`
`SUMMARY OF THE INVENTION
`
`A method and apparatus has been invented which provides
`for selective communication to a wellbore for fluid treatment.
`
`In one aspect of the invention the method and apparatus
`provide for staged injection of treatment fluids wherein fluid
`is injected ir1to selected intervals of the wellbore, while other
`intervals are closed. In another aspect, the method and appa-
`ratus provide for the running in of a fluid treatment string, the
`fluid treatment string having ports substantially closed
`against the pas sage of fluid therethrough, but which are open-
`able when desired to permit fluid flow into the wellbore. The
`apparatus and methods ofthe present invention can be used in
`various borehole conditions including open holes, cased
`holes, vertical holes, horizontal holes, straight holes or devi-
`ated holes.
`
`In one embodiment, there is provided an apparatus for fluid
`treatment of a borehole, the apparatus comprising a tubing
`string having a long axis, a first port opened through the wall
`of the tubing string, a second port opened through the wall of
`the tubing string, the second port offset from the first port
`along the long axis ofthe tubing string, a first packer operable
`to seal about the tubing string and mounted on the tubing
`string to act in a position offset from the first port along the
`long axis ofthe tubing string, a second packer operable to seal
`about the tubing string and mounted on the tubing string to act
`in a position between the first port and the second port along
`the long axis of the tubing string; a third packer operable to
`seal about the tubing string and mounted on the tubing string
`to act i11 a position offset from the second port along the long
`axis of the tubing string and on a side of the second port
`opposite the second packer; a first sleeve positioned relative
`to the first port, the first sleeve being moveable relative to the
`first port between a closed port position and a position per-
`mitting fluid flow through the first port from the tubing string
`inner bore and a second sleeve being moveable relative to the
`second port between a closed port position and a position
`permitting fluid flow through the second port from the tubing
`string inner bore; and a sleeve shifting means for moving the
`second sleeve from the closed port position to the position
`permitting fluid flow, the means for moving the second sleeve
`selected to create a seal in the tubing string against fluid flow
`past the second sleeve through the tubing string inner bore.
`In one embodiment, the second sleeve l1as formed thereon
`a seat and the means for moving the second sleeve includes a
`
`Page 13 of 20
`Page 13 of 20
`
`

`
`US 7,861,774 B2
`
`3
`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 seat, such
`that once the first sealing device is seated against the first seat
`fluid pressure can be applied to move the first sleeve and the
`first sealing device can seal against fluid passage past the first
`sleeve and the second sleeve has formed thereon a second seat
`
`and the means for moving the second sleeve includes a second
`sealing device selected to seal against the second seat, such
`that when the second sealing device is seated against the
`second seat pressure can be applied to move the second sleeve
`and the second sealing device can seal against fluid passage
`past the second sleeve, the first seat having a larger diameter
`than the second seat, such that the second sealing device can
`move past the first seat without sealing thereagainst to reach
`and seal against the second seat.
`In the closed port position, the first sleeve can be positioned
`over the first port to close the first port against fluid flow
`therethrough. In another embodiment,
`the first port has
`mounted thereon a cap extending into the tubing string inner
`bore and in the position permitting fluid flow, the first sleeve
`has engaged against and opened the cap. The cap can be
`opened, for example, by action of the first sleeve shearing the
`cap from its position over the port. In another embodiment,
`the apparatus further comprises a third port having mounted
`thereon a cap extending into the tubing string inner bore and
`in the position permitting fluid flow, the first sleeve also
`engages against the cap of the third port to open it.
`In another embodiment, the first port has mounted there-
`over a sliding sleeve and in the position permitting fluid flow,
`the first sleeve has engaged and moved the sliding sleeve
`away from the first port. The sliding sleeve can include, for
`example, a groove and the first sleeve includes a locking dog
`biased outwardly therefrom and selected to lock into the
`groove on the sleeve. In another embodiment, there is a third
`port with a sliding sleeve mounted thereover and the first
`sleeve is selected to engage and move the third port sliding
`sleeve after it has moved the sliding sleeve of the first port.
`The packers can be of any desired type to seal between the
`wellbore and the tubing string. In one embodiment, at least
`one ofthe first, second and third packer is a solid body packer
`including multiple packing elements. In such a packer, it is
`desirable that the multiple packing elements are spaced apart.
`In view ofthe foregoing there is provided a method for fluid
`treatment of a borehole, the method comprising: providing an
`apparatus for wellbore treatment according to one of the
`various embodiments of the invention; running the tubing
`string into a wellbore in a desired position for treating the
`wellbore; setting the packers; conveying the means for mov-
`ing the second sleeve to move the second sleeve and increas-
`ing fluid pressure to wellbore treatment fluid out through the
`second port.
`In one method according to the present invention, the fluid
`treatment is borehole stimulation using stimulation fluids
`such as one or more of acid, gelled acid, gelled water, gelled
`oil, CO2, nitrogen and any of these fluids containing prop-
`pants, such as for example, sand or bauxite. The method can
`be conducted in an open hole or in a cased hole. In a cased
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`hole, the casing may have to be perforated prior to running the
`tubing string into the wellbore, in order to provide access to
`the formation.
`
`In an open hole, preferably, the packers include solid body
`packers including a solid, extrudable packing element and, in
`some embodiments, solid body packers include a plurality of
`extrudable packing elements.
`In one embodiment, there is provided an apparatus for fluid
`treatment of a borehole, the apparatus comprising a tubing
`string having a long axis, a port opened through the wall ofthe
`tubing string, a first packer operable to seal about the tubing
`string and mounted on the tubing string to act in a position
`offset from the port along the long axis of the tubing string, a
`second packer operable to seal about the tubing string and
`mounted on the tubing string to act in a position offset from
`the port along the long axis of the tubing string and on a side
`of the port opposite the first packer; a sleeve positioned rela-
`tive to the port, the sleeve being moveable relative to the port
`between a closed port position and a position permitting fluid
`flow through the port from the tubing string inner bore and a
`sleeve shifting means for moving the sleeve from the closed
`port position to the position permitting fluid flow. In this
`embodiment of the invention, there can be a second port
`spaced along the long axis of the tubing string from the first
`port and the sleeve can be moveable to a position permitting
`flow through the port and the second port.
`As noted hereinbefore, the sleeve can be positioned in
`various ways when in the closed port position. For example,
`in the closed port position, the sleeve can be positioned over
`the port to close the port against fluid flow therethrough.
`Alternately, when in the closed port position, the sleeve can be
`offset from the port, and the port can be closed by other means
`such as by a cap or another sliding sleeve which is acted upon,
`as by breaking open or shearing the cap, by engaging against
`the sleeve, etc., by the sleeve to open the port.
`There can be more than one port spaced along the long axis
`ofthe tubing string and the sleeve can act upon all of the ports
`to open them.
`The sleeve can be actuated in any way to move into the
`position permitted fluid flow through the port. Preferably,
`however, the sleeve is actuated remotely, without the need to
`trip a work string such as a tubing string or a wire line. In one
`embodiment, the sleeve has formed thereon a seat and the
`means for moving the sleeve includes a sealing device
`selected to seal against the seat, such that fluid pressure can be
`applied to move the sleeve and the sealing device can seal
`against fluid passage past the sleeve.
`The first packer and the second packer can be formed as a
`solid body packer including multiple packing elements, for
`example, in spaced apart relation.
`In view of the forgoing there is provided a method for fluid
`treatment of a borehole, the method comprising: providing an
`apparatus for wellbore treatment including a tubing string
`having a long axis, a port opened through the wall of the
`tubing string, a first packer operable to seal about the tubing
`string and mounted on the tubing string to act in a position
`offset from the port along the long axis of the tubing string, a
`second packer operable to seal about the tubing string and
`mounted on the tubing string to act in a position offset from
`the port along the long axis of the tubing string and on a side
`of the port opposite the first packer; a sleeve positioned rela-
`tive to the port, the sleeve being moveable relative to the port
`between a closed port position and a position permitting fluid
`flow through the port from the tubing string inner bore and a
`sleeve shifting means for moving the sleeve from the closed
`port position to the position permitting fluid flow; running the
`tubing string into a wellbore in a desired position for treating
`
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`US 7,861,774 B2
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`5
`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.
`
`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 posi-
`tionable in the sub of FIG. 411;
`FIG. 5 is a section through another wellbore having posi-
`tioned therein a fluid treatment assembly according to the
`present invention;
`FIG. 6a is a section through another wellbore having posi-
`tioned therein another fluid treatment assembly according to
`the present invention, the fluid treatment assembly being in a
`first stage of wellbore treatment;
`FIG. 6b is a section through the wellbore of FIG. 6a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`FIG. 6c is a section through the wellbore of FIG. 6a with
`the fluid treatment assembly in a third stage of wellbore
`treatment;
`FIG. 7 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`FIG. 8 is a sectional view along the long axis of a tubing
`string according to the present invention containing a sleeve
`and axially spaced fluid treatment ports;
`FIG. 9a is a section through another wellbore having posi-
`tioned therein another fluid treatment assembly according to
`the present invention, the fluid treatment assembly being in a
`first stage of wellbore treatment;
`FIG. 9b is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a second stage of wellbore
`treatment;
`
`FIG. 9c is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a third stage of wellbore
`treatment; and
`FIG. 9d is a section through the wellbore of FIG. 9a with
`the fluid treatment assembly in a fourth stage of wellbore
`treatment.
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`DETAILED DESCRIPTION OF THE PRESENT
`INVENTION
`
`Referring to FIGS. la and 1b, a wellbore fluid treatment
`assembly is shown, which can be used to effect fluid treatment
`ofa formation 10 through a wellbore 12. The wellbore assem-
`bly includes a tubing string 14 having a lower end 1411 and an
`upper end extending to surface (not shown). Tubing string 14
`includes a plurality of spaced apart ported intervals 16a to 16e
`each including a plurality of ports 17 opened through the
`tubing string wall to permit access between the tubing string
`inner bore 18 and the wellbore.
`
`A packer 20a is mounted between the upper-most ported
`interval 16a and the surface and furtherpackers 20b to 20e are
`mounted between each pair of adjacent ported intervals. In
`the illustrated embodiment, a packer 20f is also mounted
`below the lower most ported interval 16e and lower end 14a
`ofthe tubing string. The packers are disposed about the tubing
`string and selected to seal the armulus between the tubing
`string and the wellbore wall, when the assembly is disposed in
`the wellbore. The packers divide the wellbore into isolated
`segments wherein fluid can be applied to one segment of the
`well, but is prevented from passing through the annulus into
`adjacent segments. As will be appreciated the packers can be
`spaced in any way relative to the ported intervals to achieve a
`desired interval length or number of ported intervals per seg-
`ment. In addition, packer 20f need not be present in some
`applications.
`The packers are of the solid body-type with at least one
`extrudable packing element, for example, formed of rubber.
`Solid body packers including multiple, spaced apart packing
`elements 21a, 21b on a single packer are particularly useful
`especially for example in open hole (unlined wellbore) opera-
`tions. In another embodiment, a plurality of packers are posi-
`tioned in side by side relation on the tubing string, rather than
`using one packer between each ported interval.
`Sliding sleeves 22c to 22e are disposed in the tubing string
`to control the opening of the ports. In this embodiment, a
`sliding sleeve is mounted over each ported interval to close
`them against fluid flow therethrough, but can be moved away
`from their positions covering the ports to open the ports and
`allow fluid flow therethrough.
`In particular,
`the sliding
`sleeves are disposed to control the opening of the ported
`intervals through the tubing string and are each moveable
`from a closed port position covering its associated ported
`interval (as shown by sleeves 22c and 22d) to a position away
`from the ports wherein fluid flow of, for example, stimulation
`fluid is permitted through the ports of the ported interval (as
`shown by sleeve 22e).
`The assembly is run in and positioned downhole with the
`sliding sleeves each in their closed port position. The sleeves
`are moved to their open position when the tubing string is
`ready for use in fluid treatment ofthe wellbore. Preferably, the
`sleeves for each isolated interval between adjacent packers
`are opened individually to permit fluid flow to one wellbore
`segment at a time, in a staged, concentrated treatment pro-
`cess.
`
`Preferably, the sliding sleeves are each moveable remotely
`from their closed port position to their position permitting
`through-port fluid flow, for example, without having to run in
`a line or string for manipulation thereof. In one embodiment,
`the sliding sleeves are each actuated by a device, such as a ball
`24e (as shown) or plug, which can be conveyed by gravity or
`fluid flow through the tubing string. The device engages
`against the sleeve, in this case ball 24e engages against sleeve
`22e, and, when pressure is applied through the tubing string
`inner bore 18 from surface, ball 24e seats against and creates
`
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`US 7,861,774 B2
`
`7
`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