`Exhibit 1019
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`Page 1 of 12
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`Method and Assembly for Wellbore Fluid Treatment
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`It
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`is well known that wellbore fluid treatment
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`is useful for operations such as fracturing,
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`stimulating and acidizing well boreholes.
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`Summary
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`The invention relates to a wellbore fluid treatment assembly and method for fluid treatment of a
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`formation through a wellbore. The wellbore assembly includes a tubing string with a plurality of
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`spaced apart sliding sleeves disposed therein. Between each pair of adjacent sliding sleeves and
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`between the upper-most packer and the surface is a packer. The packers are disposed about the
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`tubing string and selected to seal the annulus between the tubing string and the wellbore wall,
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`when the assembly is disposed in a well.
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`The sliding sleeves are disposed to control the opening of ports through the tubing string and are
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`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.
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`The sliding sleeves are openable remotely without having to run in a line or string for
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`manipulation.
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`In one embodiment, the sliding sleeves are ball or plug actuated, wherein the
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`surface of the sleeve which is open to the inner bore of the tubing string defines a seat onto
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`which a ball or plug, when launched from surface, can seat on and seal thereagainst. When the
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`ball seals against the sleeve seat, this creates a pressure differential upon further applied pressure
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`which causes the sliding sleeve on which the ball has landed to slide to an open position,
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`allowing access therethrough to the annulus between the tubing string and the wellbore.
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`Each of the plurality of sliding sleeves has a different diameter seat and therefore each accept
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`different sized balls.
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`In particular, the lower-most sliding sleeve has the smallest diameter seat
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`and accepts the smallest sized ball and each sleeve that is progressively closer to surface has a
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`larger seat. This provides that the lowest sleeve can be actuated to open first by launching the
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`smallest ball first, which can pass though all of the seats of the sleeves closer to surface.
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`Page 2 of 12
`Page 2 of 12
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`The packers can be of any type but are preferably solid body, rather than inflatable packers.
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`Solid body packers including multiple packing elements on a single packer are particularly
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`useful for open hole (uncased wellbore) operations.
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`The method includes selectively treating a formation through a wellbore by running the above~
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`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.
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`Detailed Description of the Invention
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`An uncased (open hole) completed wellbore can be more effectively treated using a system such
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`as that shown in Figure 1 including a plurality of packers such as, for example, that shown in
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`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
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`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 rnulti-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
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`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
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`Page 3 of 12
`Page 3 of 22
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`providing high pressure sealing in the open hole, as the elements of each packer will load into
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`each other to provide additional pack-off. Once the packers are set, fluids are then pumped down
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`the tubing string between specific sets of packers. The packers will divert the fluids to a specific
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`segment of the wellbore. A ball or plug is then pumped to shut off the lower segment of the well
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`and to open a siding sleeve to allow fluid to be forced into the next interval, where packers will
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`again divert fluids into specific segment of the well. The process is continued until all desired
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`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.
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`Similarly, multiple intervals in a cased wellbore Figure 4 can be treated with fluid using this
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`assembly and method. The intervals are first perforated. Then cased hole packers and a tubing
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`string combined with a series of ball or plug activated sliding sleeves are assembled. The
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`packers are run into the well and set using pressure or mechanical forces and placed between the
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`perforated intervals. Once the packers are set, stimulation fluids are then pumped down the
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`tubing string between specific sets of packers. The packers will divert the fluids to a specific
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`segment of the wellbore. A ball or plug is then pumped to shut off the lower segment of the well
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`and to open a siding sleeve to allow fluid to be forced into the next interval, where packers will
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`again divert fluids into specific segment of the well. The process is continued until all desired
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`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. The assembly can be pulled to surface or left
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`downhole and produced therethrough.
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`In one embodiment, a sub is used with a retrievable sliding sleeve, as shown in Figure 5, such
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`that when stimulation and flow back are completed, the sleeves can be removed from the ball
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`activated sliding sleeves. This leaves the ports of the sub open or, alternately, a flow control
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`device, such as that shown in Figure 6, can be installed in the sub. The flow control tool can be
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`installed by wireline or (coil) tubing and can be installed in any way such as by dogs or collet
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`fingers that engage in a groove formed in the sub. The flow control tool acts to control inflow
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`from the segments in the well.
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`The method described provides for setting up isolation points using packers, for example of the
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`open hole solid body type. The solid packing tools can withstand higher pressures than
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`Page 4 of 12
`Page 4 of3l2
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`inflatables due to the solid element design which can hold higher pressures that those required to
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`set the packers. The packers are all run into the well and set at the same time. Once they are
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`positioned, tubing forces or hydraulic pressure is applied to set the packers and to establish an
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`annular seat to the open hole. These solid element packers contain multiple packing elements.
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`They are spaced (greater than 1 ft, and generally 3ft or greater) to cover a great deal of formation
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`surface. This provides improved isolation in porous or fractured rock. Once the annular seal is
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`established, the packers will act to force stimulation fluids to stay within the selected interval.
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`The stimulation pumping equipment can be set up on location, and the fluids injected into the
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`first interval. A ball or plug is inserted into the pumping line following the first stage.
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`It is
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`pumped down to the ball or plug activated sliding sleeve, and it forces the sleeve open, then acts
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`as a plug to the lower segment of the well. The fluids are now pumped between the next set of
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`packers and forces into the formation at that point.
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`This method may greatly improve the ability to treat a specific segment of the wellbore, or all of
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`,;
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`the wellbore.
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` the wellbore. Furthermore, it allows for distributing stimulation fluids to all or most segments of
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`If the packers are left in the well, then they can be relied on to provide isolation for Well
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`production control. For example, if a segment or interval in the well begins to produce unwanted
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`water, an isolation sleeve can be installed to shut off that producing segment of the well.
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` In a cased well, a similar system is used to isolate perforated segments in the well. While this is
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`commonly accomplished using a packer and bridge plug, it again, can be time consuming and
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`costly. The above-described system allows all stimulation pumping operations to be done during
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`a single pumping operation. The well fluids can then be flowed either after shut in or
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`immediately to clean up the stimulation fluids, and return the well to production. The ability to
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`pump stimulation fluids into multiple intervals with little or no interruption can provide cost
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`savings and improve efficiency of completion operations.
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`Once the flow—back operations are complete, the ball activated sliding sleeves can be accessed
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`via tubing or wireline to install flow control devices such as isolation sleeves, plugs, and chokes.
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`Page 5 of 12
`Page 5 of 42
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`‘f
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`—*“*“
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`C—_—>
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`Surface
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`<———- Ball or plug activated sliding sleeve
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`, 4-"‘ Solid body open hole packers or packers
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`3
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`V 4...... Ball or plug activated sliifing sleeve
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` Ebunbl
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`4--——~ Solid may open hole packers or packers
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`4--—— Ball or plug activated sliding sleeve
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`4-—-— Solid may open hole packers or packers
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`4...... Ball or plug activated sliding sleeve
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`<——- Solid body open hole packers or packers
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`‘___.
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`‘j..-
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`Ball or plug activated sliding sleeve
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`4—— Solid body open hole packers or packers
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`057*“°""4 Solid pump-out plug assembly set @ 4500 PSI
`6-1/8" open hole
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`Page 6 of 12
`Page 6 of 12
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`Page 7 of 12
`Page 7 of 12
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`Page 8 of 12
`Page 8 of 12
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`Page 9 of 12
`Page 9 of 12
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`Page 10 of 12
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`Page 11 of 12
`Page 11 of 12
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`United States Patent & Trademark Office
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`Office of Initial Patent Examination -- Scanning Division
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`Page 12 of 12
`Page 12 of 12