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`BENNETT JONES LLP
`
`The Commissioner of Patents and Trademarks
`Washington, D.C. 20231,
`U.S.A.
`
`BOX: PATENT APPLICATION
`
`Sir:
`
`Transmitted herewith for filing is the patent application of:
`
`
`
`PTO
`
`.3.
`
` J]D50U
`1n/299004
`
`Attorney Docket
`No.
`
`45023-7
`
`Inventors
`
`Title
`
`
`
`
`
`Jon;
`
`
`
`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
`
`
`The application comprising:
`
`A pages of Disclosure;
`__4_ pages of Claims;
`L pages of Abstract;
`_9_ sheet(s) of drawings.
`
`and enclosed with the application are:
`
`[XX] A postcard.
`
`This patent application is being submitted under 37 CFR 1.53(f) and 35 U.S.C. 111, without a
`» Declaration and without the filing fee.
`
`Respe_gtfully\submitted
`/,.~"/
`“\
`
`November 18, 2002
`
`BENNETT JONES
`4500 Bankers Hall East
`%";?g;,2gyf“A.S,§;‘i,e; $3, W
`Canada’
`
`Telephone: (403) 298-3661
`Encl.
`
`WEATHERFORD INTERNATIONAL, LLC, et al.
`
`EXHIBIT 1023
`
`PACKERS PLUS ENERGY SERVICES, INC.
`
`WEATHERFORD INTERNATIONAL, LLC, et al.
`V.
`
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`Method and Apparatus for Wellbore Fluid Treatment
`
`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 petroleum products.
`
`Altemately, the hole may be cased with a liner, which is then perforated to permit
`
`inflow through the openings created by perforating.
`
`When natural inflow from the well is not economical, the well may require wellbore
`
`treatment termed stimulation. This is accomplished by pumping stimulation fluids
`
`such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to
`
`improve wellbore inflow.
`
`In one previous method, the well is isolated in segments and each segment is
`
`individually treated so that concentrated and controlled fluid treatment can be
`
`provided along the wellbore. Often, in this method a tubing string is used with
`
`inflatable element packers thereabout which provide for segment isolation. The
`
`packers, which are inflated with pressure using a bladder, are used to isolate segments
`
`of the well and the tubing is used to convey treatment fluids to the isolated segment.
`
`Such inflatable packers may be limited with respect to pressure capabilities as well as
`
`durability under high pressure conditions. Generally, the packers are run for a
`
`wellbore treatment, but must be moved after each treatment if it is desired to isolate
`
`other segments of the well for treatment. This process can be expensive and time
`
`consuming. Furthermore, it may require stimulation 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.
`
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`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.
`
`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 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
`
`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 slccvc 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
`
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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 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 thereover a sliding sleeve and in
`
`the position permitting fluidiflow, 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 method for fluid treatment of a borehole,
`
`the method comprising: providing an apparatus for wellbore treatment according to
`
`one of the various embodiments of the invention; running the tubing string into a
`
`wellbore in a desired position for treating the wellbore; setting the packers; conveying
`
`the means for moving the second sleeve to move the second sleeve and increasing
`
`fluid pressure to wellbore treatment fluid out through the second port.
`
`In one method according to the present invention, the fluid treatment is borehole
`
`stimulation using stimulation fluids such as one or more of acid, gelled acid, gelled
`
`water, gelled oil, CO2, nitrogen and any of these fluids containing proppants, such as
`
`for example, sand or bauxite. The method can be conducted in an open hole or in a
`
`cased hole. In a 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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`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 fonned 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 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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`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:
`
`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 1a 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
`
`Referring to Figures la and 1b, a wellbore fluid treatment assembly is shown, which
`
`can be used to effect fluid treatment of a formation 10 through a wellbore 12. The
`
`wellbore assembly includes a tubing string 14 having a lower end 14a 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 further packers 20b to 20e are mounted between each pair of adjacent ported
`
`intervals. In the illustrated embodiment, a packer 20f is also mounted below the
`
`lower most ported interval 16c and lower end 14a of the tubing string. The packers
`
`are disposed about the tubing string and selected to seal the annulus between the
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`tubing string 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 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 220 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 22c).
`
`The assembly is run in and positioned downhole with the sliding sleeves each in their
`
`closed port position. The sleeves are moved to their open position when the tubing
`
`string is ready for use in fluid treatment of the wellbore. Preferably, the sleeves for
`
`each isolated interval between adjacent packers are opened individually to permit
`
`fluid flow to one wellbore segment at a time, in a staged, concentrated treatment
`
`process.
`
`Preferably, the sliding sleeves are each moveable remotely from their closed port
`
`position to their position permitting through—port fluid flow, for example, without
`
`having to run in a line or string for manipulation thereof. In one embodiment, the
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`sliding sleeves are each actuated by a device, such as a ball 24e (as shown) or plug,
`
`which can be conveyed by gravity or fluid flow through the tubing string. The device
`engages against the sleeve, in this case ball 24e engages against sleeve 22c, and, when
`pressure is applied through the tubing string inner bore 18 from surface, ball 24e seats
`
`against and creates a pressure differential above and below the sleeve which drives
`
`the sleeve toward the lower pressure side.
`
`In the illustrated embodiment, the inner surface of each sleeve which is open to the
`
`inner bore of the tubing string defines a seat 26e onto which an associated ball 24e,
`
`when launched from surface, can land and seal thereagainst. ’When the ball seals
`
`against the sleeve seat and pressure is applied or increased from surface, a pressure
`
`differential is set up which causes the sliding sleeve on which the ball has landed to
`
`slide to an port—open position. When the poits of the ported interval l6e 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 22e has the
`
`smallest diameter D1 seat and accepts the smallest sized ball 24e and each sleeve that
`
`is progressively closer to surface has a larger seat. For example, as shown in figure
`
`1b, the sleeve 22c includes a seat 260 having a diameter D3, sleeve 22d includes a
`
`seat 26d having a diameter D2, which is less than D3 and sleeve 22e includes a seat
`
`26e having a diameter D1, which is less than D2. This provides that the lowest sleeve
`
`can be actuated to open first by first launching the smallest ball 24e, which can pass
`
`though all of the seats of the sleeves closer to surface but which will land in and seal
`against seat 26e of sleeve 22e. Likewise, penultimate 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 characteristics 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
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`pressure, for example at a pressure of about 3000 psi, the plug can be blown out to
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`permit actuation of the lower most sleeve 22e by generation of a pressure differential.
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`As will be appreciated, an opening adjacent end 14a is only needed where pressure, as
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`opposed to gravity, is needed to convey the first ball to land in the lower—most sleeve.
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`Altemately, the lower most sleeve can be hydraulically actuated, including a fluid
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`actuated piston secured by shear pins, so that the sleeve can be opened remotely
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`without the need to land a ball or plug therein.
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`In other embodiments, not shown, end l4a can be left open or can be closed for
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`example by installation of a welded or threaded plug.
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`While the illustrated tubing string includes five ported intervals, it is to be understood
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`that any number of ported intervals could be used. In a fluid treatment assembly
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`desired to be used for staged fluid treatment, at least two openable ports from the
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`tubing string inner bore to the wellbore must be provided such as at least two ported
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`intervals or an openable end and one ported interval. It is also to be understood that
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`any number of ports can be used in each interval.
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`Centralizer 29 and other standard tubing string attachments can be used.
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`In use, the wellbore fluid treatment apparatus, as described with respect to Figures la
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`and 1b, can be used in the fluid treatment of a wellbore. For selectively treating
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`formation 10 through wellbore 12, the above—described assembly is run into the
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`borehole and the packers are set to seal the annulus at each location creating a
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`plurality of isolated annulus zones. Fluids can then pumped down the tubing string
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`and into a selected zone of the annulus, such as by increasing the pressure to pump
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`out plug assembly 28." Altemately, a plurality of open ports or an open end can be
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`provided or lower most sleeve can be hydraulically openable. Once that selected zone
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`is treated, as desired, ball 24e or another sealing plug is launched from surface and
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`conveyed by gravity or fluid pressure to seal against seat 26e of the lower most
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`sliding sleeve 22e, this seals off the tubing string below sleeve 22c and opens ported
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`interval l6e to allow the next annulus zone, the zone between packer 20e and 20f to
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`be treated with fluid. The treating fluids will be diverted through the ports of interval
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`l6e exposed by moving the sliding sleeve and be directed to a specific area of the
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`formation. Ball 24e is sized to pass though all of the seats, including 26c, 26d closer
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`to surface without sealing thereagainst. When the fluid treatment through ports 16c is
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`complete, a ball 24d is launched, which is sized to pass through all of the seats,
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`including seat 26c closer to surface, and to seat in and move sleeve 22d. This opens
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`ported interval 16d and permits fluid treatment of the annulus between packers 20d
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`and 20e. This process of launching progressively larger balls or plugs is repeated
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`until all of the zones are treated. The balls can be launched without stopping the flow
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`of treating fluids. After treatment, fluids can be shut in or flowed back immediately.
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`Once fluid pressure is reduced from surface, any balls seated in sleeve seats can be
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`unseated by pressure from below to permit fluid flow upwardly therethrough.
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`The apparatus is particularly useful for stimulation of a formation, using stimulation
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`fluids, such as for example, acid, gelled acid, gelled water, gelled oil, CO2, nitrogen
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`and/or proppant laden fluids.
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`Referring to Figure 2, a packer 20 is shown which is useful in the present invention.
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`The packer can be set using pressure or mechanical forces. Packer 20 includes
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`extmdable packing elements 21a, 21b, a hydraulically actuated setting mechanism and
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`a mechanical body lock system 31 including a locking ratchet arrangement. These
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`parts are mounted on an inner mandrel 32. Multiple packing elements 21a, 21b are
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`formed of elastomer, such as for example, rubber and include an enlarged cross
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`section to provide excellent expansion ratios to set in oversized holes. The multiple
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`packing elements 21a, 21b can be separated by at least 0.3M and preferably 0.8M or
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`more. This arrangement of packing elements aid in providing high pressure sealing in
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`an open borehole, as the elements load into each other to provide additional pack—off.
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`Packing element 21a is mounted between fixed stop ring 34a and compressing ring
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`34b and packing element 21b is mounted between fixed stop ring 34c and
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`compressing ring 34d. The hydraulically actuated setting mechanism includes a port
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`35 through inner mandrel 32 which provides fluid access to a hydraulic chamber
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`defined by first piston 36a and second piston36b. First piston 36a acts against
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`compressing ring 34b to drive compression and, therefore, expansion of packing
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`element 21a, while second piston 36b acts against compressing ring 34d to drive
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`compression and, therefore, expansion of packing element 21b. First piston 36a
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`includes a skirt 37, which encloses the hydraulic chamber between the pistons and is
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`telescopically disposed to ride over piston 36b. Seals 38 seal against the leakage of
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`fluid between the parts. Mechanical body lock system 31, including for example a
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`ratchet system, acts between skirt 37 and piston 36b permitting movement
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`therebetween driving pistons 36a, 36b away from each other but locking against
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`reverse movement of the pistons toward each other, thereby locking the packing
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`elements into a compressed, expanded configuration.
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`Thus, the packer is set by pressuring up the tubing string such that fluid enters the
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`hydraulic chamber and acts against pistons 36a, 36b to drive them apart, thereby
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`compressing the packing elements and extruding them outwardly. This movement is
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`permitted by body lock system 31 but is locked against retraction to lock the packing
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`elements in extruded position.
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`Ring 34a includes shears 38 which mount the ring to mandrel 32. Thus, for release of
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`the packing elements from sealing position the tubing string into which mandrel 32 is
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`connected, can be pulled up to release shears 38 and thereby release the compressing
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`force on the packing elements.
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`Refening to Figures 3a and 3b, a tubing string sub 40 is shown having a sleeve 22,
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`positionable over a plurality of ports 17 to close them against fluid flow thercthrough
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`and moveable to a position, as shown in Figure 3b, wherein the ports are open and
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`fluid can flow thercthrough.
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`The sub 40 includes threaded ends 42a, 42b for connection into a tubing string. Sub
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`includes a wall 44 having formed on its inner surface a cylindrical groove 46 for
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`retaining sleeve 22. Shoulder