BENNETT JONES LLP
`
`The Commissioner of Patents and Trademarks
`Washington, D.C. 20231,
`U.S.A.
`
`BOX: PATENT APPLICATION
`PROVISIONAL APPLICATION FILING
`UNDER 37 CFR 1.53(b)(2)
`COVER SHEET
`
`I ~~~rney Docket I
`
`45023-3
`
`Sir:
`
`~11rransmitted herewith for filing is the provisional patent application of:
`f.:j
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`METHOD AND ASSEMBLY FOR WELLBORE FLUID TREATMENT
`~t: Title
`1;:-
`j;~he application comprising:
`:.,';, 1 page of application cover sheet
`~~-f::4 pages of Specification; and
`~'1 ["' sheet(s) of drawings.
`~&,
`~;Bnd enclosed with the application are:
`~~
`~~'[X] A post card.
`The Commissioner is hereby authorized to charge the required filing fees amounting to EIGHTY
`DOLLARS ($80.00) and any additional fees which may be required, or credit any overpayment to
`Deposit Account No. 02-2057. Two copies of this form are enclosed for use in connection with any
`Deposit Account activity.
`
`Respectfully submitted
`
`November 15, 2001
`
`BENNETT JONES LLP
`Suite 4500. 855 2nd Street S.W.
`Calgary, Alberta,
`CANADA
`T2P 4K7
`
`Telephone: (403) 298-3661
`
`Encl.
`
`

`
`Method and Assembly for Well bore Fluid Treatment
`
`It is well known that wellbore fluid treatment IS useful for operations such as fracturing,
`
`stimulating and acidizing well boreholes.
`
`Summary
`
`The invention relates to a wellbore fluid treatment assembly and method for fluid treatment of a
`formation through a wellbore. The wellbore assembly includes a tubing string with a plurality of
`
`spaced apart sliding sleeves disposed therein. Between each pair of adjacent sliding sleeves and
`between the upper-most packer and the surface is a packer. The packers are disposed about the
`tubing string and selected to seal the annulus between the tubing string and the wellbore wall,
`
`when the assembly is disposed in a well.
`
`The sliding sleeves are disposed to control the opening of ports through the tubing string and are
`moveable from a sealing position covering the ports to an open position not preventing fluid flow
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`of, for example, stimulation fluid through the ports. The assembly is positioned downhole with
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`the sliding sleeves in the sealing position.
`
`The sliding sleeves are openable remotely without having to run in a line or string for
`In one embodiment, the sliding sleeves are ball or plug actuated, wherein the
`manipulation.
`surface of the sleeve which is open to the inner bore of the tubing string defines a seat onto
`which a ball or plug, when launched from surface, can seat on and seal thereagainst. When the
`
`ball seals against the sleeve seat, this creates a pressure differential upon further applied pressure
`which causes the sliding sleeve on which the ball has landed to slide to an open position,
`allowing access therethrough to the annulus between the tubing string and the wellbore.
`
`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 has the smallest diameter seat
`and accepts the smallest sized ball and each sleeve that is progressively closer to surface has a
`larger seat. This provides that the lowest sleeve can be actuated to open first by launching the
`smallest ball first, which can pass though all of the seats of the sleeves closer to surface.
`
`

`
`The packers can be of any type but are preferably solid body, rather than inflatable packers.
`
`Solid body packers including multiple packing elements on a single packer are particularly
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`useful for open hole (uncased wellbore) operations.
`
`The method includes selectively treating a formation through a wellbore by running the above(cid:173)
`
`described assembly into a borehole and setting the packers to seal the annulus at each location
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`creating a plurality of isolated annulus zones. Fluids are then pumped down the tubing string
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`and into a selected zone of the annulus. This may require opening a sliding sleeve or the tubing
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`string can include a plurality of ports or open end, which does not have a sliding sleeve seal.
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`Once that selected zone is treated, as desired, a sealing plug or ball is launched to seal against the
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`lower most sliding sleeve, this seals off the tubing string below the sleeve and opens the ports to
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`allow the next annulus zone to be treated with fluid. The treating fluids will be diverted through
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`the ports exposed by the sliding sleeve and be directed to a specific area of the formation. This
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`process of launching a progressively larger ball or plug is repeated until all of the zones are
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`treated. The balls can be launched without stopping the flow of treating fluids.
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`The wellbore can be horizontal or vertical, cased or open hole.
`
`Detailed Description of the Invention
`
`An uncased (open hole) completed wellbore can be more effectively treated using a system such
`
`as that shown in Figure 1 including a plurality of packers such as, for example, that shown in
`
`t-,&:
`
`Figures 2a and 2b and a tubing string combined with a series of ball or plug activated sliding
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`sleeves, as shown in Figure 3.
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`The packers are run into the well and set using pressure or mechanical forces. While any packers
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`can be used that substantially seal the wellbore against flow around the packer, a particularly
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`preferred packer is a multiple element solid body open hole packer such as that shown in Figure
`
`2. The packer includes a mechanical element, a dual piston setting cylinder and a mechanical
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`body lock system. The sealing element is a multi-piece elastomer with the largest possible cross
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`section to provide excellent expansion ratios to set in oversized holes. The packing element also
`
`contains a special back up system that provides a solid pack off even with borehole ovality. The
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`multiple packing elements, separated by 0.3m or greater on the solid body packers aid in
`
`2
`
`

`
`~~}
`
`providing high pressure sealing in the open hole, as the elements of each packer will load into
`each other to provide additional pack-off. Once the packers are set, fluids are then pumped down
`the tubing string between specific sets of packers. The packers will divert the fluids to a specific
`
`segment of the wellbore. A ball or plug is then pumped to shut off the lower segment of the well
`and to open a siding sleeve to allow fluid to be forced into the next interval, where packers will
`
`again divert fluids into specific segment of the well. The process is continued until all desired
`
`segments of the wellbore are stimulated or treated. When completed, the treating fluids can be
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`either shut in or flowed back immediately.
`
`Similarly, multiple intervals in a cased wellbore Figure 4 can be treated with fluid using this
`
`assembly and method. The intervals are first perforated. Then cased hole packers and a tubing
`string combined with a series of ball or plug activated sliding sleeves are assembled. The
`packers are run into the well and set using pressure or mechanical forces and placed between the
`
`perforated intervals. Once the packers are set, stimulation fluids are then pumped down the
`tubing string between specific sets of packers. The packers will divert the fluids to a specific
`segment of the wellbore. A ball or plug is then pumped to shut off the lower segment of the well
`and to open a siding sleeve to allow fluid to be forced into the next interval, where packers will
`again divert fluids into specific segment of the well. The process is continued until all desired
`segments of the wellbore are stimulated or treated. When completed, the treating fluids can be
`
`either shut in or flowed back immediately. The assembly can be pulled to surface or left
`downhole and produced therethrough.
`
`In one embodiment, a sub is used with a retrievable sliding sleeve, as shown in Figure 5, such
`that when stimulation and flow back are completed, the sleeves can be removed from the ball
`
`activated sliding sleeves. This leaves the ports of the sub open or, alternately, a flow control
`device, such as that shown in Figure 6, can be installed in the sub. The flow control tool can be
`
`installed by wireline or (coil) tubing and can be installed in any way such as by dogs or collet
`fingers that engage in a groove formed in the sub. The flow control tool acts to control inflow
`from the segments in the well.
`
`The method described provides for setting up isolation points using packers, for example of the
`open hole solid body type. The solid packing tools can withstand higher pressures than
`
`3
`
`

`
`inflatables due to the solid element design which can hold higher pressures that those required to
`set the packers. The packers are all run into the well and set at the same time. Once they are
`positioned, tubing forces or hydraulic pressure is applied to set the packers and to establish an
`annular seat to the open hole. These solid element packers contain multiple packing elements.
`They are spaced (greater than 1 ft, and generally 3ft or greater) to cover a great deal of formation
`surface. This provides improved isolation in porous or fractured rock. Once the annular seal is
`established, the packers will act to force stimulation fluids to stay within the selected interval.
`The stimulation pumping equipment can be set up on location, and the fluids injected into the
`first interval. A ball or plug is inserted into the pumping line following the first stage. It is
`pumped down to the ball or plug activated sliding sleeve, and it forces the sleeve open, then acts
`as a plug to the lower segment of the well. The fluids are now pumped between the next set of
`packers and forces into the formation at that point.
`
`This method may greatly improve the ability to treat a specific segment of the wellbore, or all of
`the wellbore. Furthermore, it allows for distributing stimulation fluids to all or most segments of
`the wellbore.
`
`If the packers are left in the well, then they can be relied on to provide isolation for well
`production control. For example, if a segment or interval in the well begins to produce unwanted
`water, an isolation sleeve can be installed to shut offthat producing segment of the well.
`
`::.
`~
`f'"
`
`In a cased well, a similar system is used to isolate perforated segments in the well. While this is
`commonly accomplished using a packer and bridge plug, it again, can be time consuming and
`costly. The above-described system allows all stimulation pumping operations to be done during
`a single pumping operation. The well fluids can then be flowed either after shut in or
`immediately to clean up the stimulation fluids, and return the well to production. The ability to
`pump stimulation fluids into multiple intervals with little or no interruption can provide cost
`savings and improve efficiency of completion operations.
`
`Once the flow-back operations are complete, the ball activated sliding sleeves can be accessed
`via tubing or wireline to install flow control devices such as isolation sleeves, plugs, and chokes.
`
`4
`
`

`
`t Optional packer set in casing
`
`Surface
`of Well
`
`Ball or plug activated sliding sleeve
`
`4
`
`Solid body open hole packers or packers
`
`~
`
`Ball or plug activated sliding sleeve
`
`•
`
`Solid body open hole packers or packers
`
`Ball or plug activated sliding sleeve
`
`Solid body open hole packers or packers
`
`•
`
`Cit
`
`Ban or plug activated sliding sleeve
`
`Solid body open hole packers or packers
`
`Ball or plug activated sliding sleeve
`
`4
`
`Solid body open hole packers or packers
`
`or-He~ Solid pump-out plug assembly set@ 4500 PSI
`6-1/8" open hole
`
`

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`United States Patent & Trademark Office
`Office of Initial Patent Examination -- Scanning Division
`
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