BAKER HUGHES INCORPORATED
`Exhibit 1013
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`Page 1 of 93
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`2i'1 112016
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`|'|II|:Is2i'i'ppai r.uspto.gov.-‘pai ri'PA|RPrinISer\iIeI
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`11/104,467
`
`METHOD AND APPARATUS FOR WELLBORE FLUID
`TREATMENT
`
`45023-18
`
`02-11-
`20162212242254
`
`This application is officially maintained in electronic form. To View: Click the desired
`Document Description. To Download and Print: Check the desired document(s) and click
`PDF.
`
`Bibliographic Data
`Mail Room Date Doggrcreent
`04-26-2010
`PETDEC
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`2l'11f2015
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`WFEE
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`Specification
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`—sN—\l\)NtoNoaN—x—x<.oo—x-I>—x
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`Page 2 of 93
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`Page 2 of 93
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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;
`
`Inventors
`
`
`
`
`
`
`The application comprising:
`
`21_ pages of Disclosure;
`_4_ pages of Claims;
`_]_ pages of Abstract;
`fl_ sheet(s) of drawings.
`
`and enclosed with the application are:
`
`[ XX] A post card.
`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.
`’
`
`Respectfullyxsubmitted
`,—i
`
`;
`
`November 18, 2002
`
`Page 3 of 93
`
`BENNETT JONES
`4500 Bankers Hall East
`855 - 2nd Street SW
`Calgary, Alberta T2P 4K7
`Canada’
`
`Telephone: (403) 298-3661
`
`
`
`Page 3 of 93
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`

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`IIIIIIIIIIIIIIIIIIIIIIIIIIIllllll
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`
`
`'STl9699i
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`
`
`Attorney Docket No.
`
`450234 8
`
`PTOISBIOS (09-04)
`Approved for use through 07/31/2006. OMB 0651-0032
`U.S. Patent and Trademark Office. U.S. DEPARTMENT OF OOMMERCE
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`tion unless ’ dis a s a valid OMB control number.
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`
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`UTILITY
`
`
`PATENT APPLICATION
`
`First Inventor
`
`TRANSMITTAL
`
`FEHR
`Method and apparatus for wellbore
`
`
`
`(Only for new nonprovisional applications under 37 CFR 1.53(b))
`
`
`
` APPLICATION ELEMENTS
`ADDRESS TO.‘
`See MPEP chapter 600 oonoeming utility patent application contents.
`
`Commissioner for Patents
`P.O. Box 1450
`Alexandria VA 22313-1450
`
`
`
`
`
`Assignment Papers (cover sheet & document(s))
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`9.
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`10.
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`11. B English Translation Document (if applicable)
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`Copies of citations attached
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`Applicant claims small entity status.
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`26
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`Specification
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`Name of Assignee Packers Plus Energy Services Inc.
`Both the claims and abstract must start on a new page
`(For intomiation on the preferred arrangement see MPEP 608.01(5))
`Drawing(s) (35 U.S.C. 113)
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`name in the prior application, see 37 CFR
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`Applicant must attach form PTO/SBl35 or equivalent.
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`i. I:I CD-ROM or CD-R (2 copies); or
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`Prior application information:
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`Divisional
`
`I:I Continuation—in—part(CIP)
`Examiner Thompson Kenneth L.
`
`of prior application No.:1.0l299..0.04.................
`An Unit: 3679
`
`.
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`19. CORRESPONDENCE ADDRESS
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`_EW——
` lI—
`E(€z"v/"[!!i.ZtL/l'_
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`.
`Roseann B. Caldwell
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`This collection of information is required by 37 CFR 1.53(b). The information is required to obtain or retain a benefit by the public which is to file (and by the
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`Approved for use through 07/31/2006. OMB 0651-0032
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`erreeiive on 12/08/2004.
`Feespursuant to the ConsolidatedAppropriations Act. 2005 (H.R. 4818).
`FEE TRANSMITTAL
`For FY 2005
`. £
`.
`.
`-
`L‘ Applicant claims small entity status. See 37 CFR 1.27
`'
`. m
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`(960.00
`450234
`($)
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`Complete If Known
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`Utility
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`FILING FEES
`£ee_L§l
`300
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`(@
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`Fees Paid Q)
`is,0.”
`
`
`SEARCH FEES _
`EXAMINATION Fees
`Fifi).
`Eegm
`500
`200
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`
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`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`
`Design
`Plant
`Reissue
`Provisional
`
`200
`200
`300
`
`200
`
`100
`100
`150
`100
`
`100
`300
`500
`
`0
`
`so
`150
`250
`
`o
`
`130
`160
`600
`
`‘E5
`so
`300
`
`0
`
`_
`
`o
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`Eee Descgiptiog
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`2. excess CLAIM FEES 'Qm(im:méU.,,~a
`Each claim over 20 (including Reissues)
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`Each independent claim over 3 (including Reissues)
`Multiple dependent claims
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`Total Claims
`Extra Claims
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`x
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`-20 or HP=
`E
`HP = highest number of total claims paid for, if greater than 20.
`lndep. Claims
`Extra Claims
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`=
`x
`L - 3 or HP =
`0
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`Fee Paid (§l
`lSO-co
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`Fee Paid Q)
`Q
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`Fee
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`Fee may
`50 Q?! to
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`200
`180
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`Page 5 of 93
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`Page 5 of 93
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`

`
`Method and Appa
`
`ratus for Wellbore Fluid Treatment
`
`Field of the Invention
`on relates to a method and apparatus for wellbore fluid treatment and, in
`d and apparatus for selective communication to a wellbore for
`
`The inventi
`
`particular, to a metho
`
`fluid treatment.
`
`Background of the Invention
`
`well, an op
`
`erator may decide to leave productive intervals uncased (open hole) to
`ermit unrestricted wellbore inflow of petr
`sed with a liner, which is then perforated to
`
`oleum products.
`
`permit
`
`expose porosity and p
`Altemately, the hole may be ca
`inflow through the openings created by p
`
`erforatin g.
`
`When natural inflow fro
`
`individually tr
`
`fluid treatment can be
`
`sed with
`
`m the well is not economical, the well may require wellbore
`s accomplished by pumping stimulation fluids
`treatment termed stimulation. This i
`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
`eated so that concentrated and controlled
`Often, in this method a tubing string is u
`ch provide for segment isolation. The
`der, are used to isolate segments
`
`packers, wh
`
`of the well and the tubi
`
`olated segment.
`
`provided along the wellbore.
`inflatable element packers thereabout whi
`ich are inflated with pressure using a blad
`rig is used to convey treatment fluids to the is
`d with respect to pressure capabilities as well as
`the packers are run for a
`esired to isolate
`
`Such inflatable packers may be limite
`under high pressure conditions. Generally,
`must be moved after each treatment if it is d
`
`durability
`
`wellbore treatment, but
`
`consumin
`
`g. Furthermore, it may require stimulation pumping equipment to be at the
`of time or for multiple visits. This method
`
`can be very time
`
`well site for long periods
`
`consuming and costly.
`
`Page 6 of 93
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`Page 6 of 93
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`

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`‘--
`
`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
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`flow into the wellbore. The apparatus and methods of the present invention can be
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`used in various borehole conditions including open holes, cased holes, vertical holes,
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`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,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
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`surface. ’I;hereby avoiding the need for tripping in a string or wire line for
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`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
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`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 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.
`
`
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`In view of the foregoing there is provided a methodfor 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 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.
`
`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 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
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`
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`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
`
`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: 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 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 pennitting 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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`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 lb 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
`
`invention;
`
`Figure 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;
`
`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
`
`treatment ports;
`
`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;
`
`Figure 4b is a side elevation of a flow control sleeve positionable in the sub of Figure
`
`4a;
`
`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
`
`assembly being in a first stage of wellbore treatment;
`
`Figure 6b is a section through the wellbore of Figure 6a with the fluid treatment
`
`assembly in a second stage of wellbore treatment;
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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
`
`assembly in a second stage of wellbore treatment;
`
`Figure 9c is a section through the wellbore of Figure 9a with the fluid treatment
`
`.
`
`assembly in a third stage of wellbore treatment; and
`
`Figure 9d is a section through the wellbore of Figure 9a with the fluid treatment
`
`assembly in a fourth stage of wellbore treatment.
`
`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
`
`wellbore assembly includes a tubing string 14 having a lower end 1421 and an upper
`end extending to surface (not shown). Tubing string 14 includes a plurality of spaced
`apart ported intervals 16a to 16c 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 20c 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 16c and lower end l4a 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 st