BAKER HUGHES INCORPORATED AND
`BAKER HUGHES OILFIELD OPERATIONS, INC.
`Exhibit 1014
`BAKER HUGHES INCORPORATED AND
`BAKER HUGHES OILFIELD OPERATIONS, INC.
`v. PACKERS PLUS ENERGY SERVICES, INC.
`IPR2016-00596
`Page 1 of 10
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`Packers Plus Energy Services Inc. 2020 738 6"‘ Avenue S.W. Calgary, Alberta T2P 317
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`Phone (403) 263-7587 Fax (403) 263-7599
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`Page 2 of 10
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`Packers Plus Energy Services Inc. 2020 736 6"‘ Avenue S.W. Calgary. Alberta T2P 317
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`Phone (403) 263-7587 Fax (403) 263-7599
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`Page 4 of 10
`Page 4 of 10
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`Re:
`
`Patent application — Method to place wellbore stimulation fluids in oil and/or gas wells
`
`Applicants: Packers Plus Energy Services Inc. — Canada Corporation — 2020 736 6"‘ Ave SW, Calgary, Alberta T2P 3T7
`
`Inventor—Themi g, Daniel Jon 52 Glenhill Dr. Cochrane, Alberta T4C 1G9
`
`The invention relates to a method for placing wellbore stimulation fluids in oil and/or gas wells and, in particular, systems and
`methods for stimulating, acidizing, or fracturing an open hole horizontal, vertical, or multi-lateral (branched) well.
`
`Background of the invention:
`
`When drilling an oil or gas well, an operator may decide to leave productive intervals uncased (open hole) to expose porosity and
`improve wellbore inflow. When natural well inflow is not economical. the well may require stimulation. This may be
`_ accomplished by pumping acid, cleaning chemicals or proppant laden fluid into the well to improve well productivity. A
`perforated liner (with pre-sized holes throughout or at chosen segments) in the liner may be run, as shown in Figure 1. This
`method is termed sprinkling. 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, to distribute stimulation fluids to desired segments of
`the well. Generally, the fluid must be pumped at high rates to achieve this “limited entry” result.
`
`Other procedures for open hole stimulation are foam diverters, gelled diverters, and coil tubing conveyed acid, and limited entry
`through tubing to distribute fluids. Each of these may or may not be effective in distributing fluids to the desired segments in the
`I wellbore.
`
`Recently, the present applicant has begun conducting stimulations using a staged method and assembly, as shown. This method is
`descried in applicant's corresponding US provisional application 60/331,491, filed November 19, 2001, incorporated herein by
`reference.
`
`Summary of the invention:
`
`The methods described herein may improve the results due to better control over fluid placement, as well as combining the
`effectiveness for focused fluid placement in combination with distributed fluid placement. It may also allow for differences in
`formation treating pressures in the wellbore that may be induces or naturally accruing. Furthermore, the methods and procedures
`described above may include the benefits of improved well control and safety, better control of wellbore fluid placement, enhance
`fracture length extension, higher stimulation pressures, and effective stimulation of multiple leg wells in open hole.
`
`Selective segment "Multi-stage Sprinkler" system (Figure 21
`
`An uncased (open hole) wellbore can be more effectively stimulated using a system which includes a section of tubing with
`specially designed, selectively opened ports that sprays or “jets” a specific segment of the wellbore in order to focus the treatment
`on that segment of the well. A series of limited entry (size restricted) ports create a "sprinkler" effect on chosen segments to
`distribute the stimulation fluids across that selected segment (or segments). A tubing or casing string is made up with a series of
`size restricted ports subs in which the ports are each covered with a protective pressure holding internal cap, the ports being
`divided into a series of segments and a movable sleeve is provided for each segment. The sleeve includes seats or profiles that can
`act as a cutters to cut off the protective caps when the sleeve is driven along the tubing string segment.
`
`Once the system is run into the well, stimulation fluids are pumped into the end section of the well to begin the stimulation
`treatment. identified as stage 1 in the drawing. Initially, fluids will be forced to the lower section of the well. The lower segment
`
`Page 7 of 10
`Page 7 of 10
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`of the tubing can include a plurality of normally open size restricted ports, which do not require opening for stimulation fluids to
`be jetted therethrough. Alternately, the ports can be installed in closed configuration, but opened once the tubing is in place.
`When desired to stimulate another section of the well, a ball or plug is pumped by fluid pressure, arrow P, down the well and will
`seat in a selected cutter sleeve sized to accept the ball or plug. The force of the moving fluid behind the ball will push the cutter
`sleeve against any force, such as a shear pin, holding the sleeve in position and down the tubing string, arrow S. As it moves
`down, it will remove the pressure holding caps from the ports in its segment of the tubing string. Once the cutter sleeve reaches a
`desired depth, it will be stopped by a no-go shoulder. Since fluid pressure will hold the ball in the sleeve, this effectively shuts off
`the lower segment of the well (previously treated stage 1).
`
`Treating fluids will then be forced into the newly opened ports using limited entry or a tubing to wellbore pressure drop to insure
`distribution. If desired, the segment of the well may be isolated from other parts of the wellbore using open hole packers.
`
`After the desired volume of stimulation fluids are pumped, a slightly larger second ball or plug is injected into the tubing and
`pumped down the well, and will seat in a cutter sleeve which is selected to retain the larger ball or plug, such as the stage 3 sleeve
`as shown. The force of the moving fluid will push the cutter sleeve down the tubing string and as it moves down, it will remove
`the pressure holding cap from a segment of the well. Once the cutter reaches a desired depth, it will be stopped by a no—go
`shoulder, effectively shutting off the lower segment of the well (previously treated stages 1 and 2). This process can be repeated 21
`number of times until most or all of the wellbore is threaded using a sprinkler approach over each individual section.
`
`Casing or tubing circulating system.
`
`Tubing may be run into a well, and used to circulate out existing wellbore fluids (drilling mud for example) and replaced with a
`different fluid. To accomplish this, the tubing must have pressure integrity. A tubing or easing string is made up with a series size
`restricted ports subs in which the ports are covered with a protective pressure holding internal cap and a single or series of
`movable sleeves with seats or profiles that can act as a cutters to cut off the protective caps. Once the system is run into the well,
`fluids can be circulated down the tubing or casing to displace existing wellbore fluids out of the well. Initially, fluids will be
`forced to the end 0 f the tubing string. When desired, a ball or plug is pumped down the well, and will seat in the (or one of the)
`cutter sleeves. The force of the moving fluid will push the cutter sleeve down the tubing string and as it moves down, it will
`remove the pressure holding cap from a segment of the well. Fluids may then exit any or all of the exposed ports, Once the cutter
`reaches a desired depth, it will be stopped by a no-go shoulder, effectively shutting off the end of the tubing string and/or the
`lower segment of the well (previously treated).
`
`Combined “Multi-stav,e Frac and Sprinkler System" stimulation system (Figure 31
`
`The multiple segment sprinkler system described above can also be combined with a series of ball activated sliding sleeves and
`open hole packers to allow some segments of the well to be stimulated using a sprinkler approach and other segments of the well
`‘to be simulated using a focused fracturing approach.
`
`In this embodiment, a tubing or casing string is made up with some segments formed of subs having a series of size restricted
`ports therethrough and in which the ports are each covered with protective pressure holding internal caps and each segment
`including a movable sleeve with seats or profiles that can act as a cutter to cut off the protective caps to open the ports. Other
`segments have open hole packers thereabout and a ball or plug activated sliding sleeve, such as is described in applicant's
`aforementioned provisional application, to create a “focused” stimulation effect. Once the system is run into the well, the tubing
`may be pressured to set some or all of the open hole packers. When the packers are set, stimulation fluids are pumped into the end
`section of the tubing to begin the stimulation treatment, identified as stage 1. Initially, fluids will be forced to the lower section of
`the well.
`
`Sections of the well that use a “sprinkler approach” will be treated as follows. When desired, a ball or plug is pumped down the
`well, and will seat in one of the cutter sleeves. The force of the moving fluid will push the cutter sleeve down the tubing string
`and as it moves down, it will remove the pressure holding caps from the segment of the well through which it passes. Once the
`cutter reaches a desired depth, it will be stopped by a no—go shoulder and the ball will remain in the sleeve effectively shutting off
`the lower segment of the well (previously treated). Stimulation fluids are then pumped as required.
`
`Segments "of the well that use a “focused stimulation approach” will be treated as follows. Following the stimulation treatment on
`this segment of the well, another ball or plug (generally slightly larger) and will seat in and shift open a pressure shifted sliding
`sleeve, and block off the lower segment(s) of the well. Stimulation fluids are directed out the sliding sleeve and are contained by
`the open hole packers to allow for treating only that section of the well.
`
`The stimulation process can be continued using “sprinkler" and/or “focused" placement of fluids, depending on the segment which
`is opened along the tubing string.
`Shiftin Sleeve/Port Sleeve Fi ure4
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`S:\C4\472\45023\8\D00l -1-app.doc
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`Page 8 of 10
`Page 8 of 10
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`In another embodiment, instead of the shearable caps, sliding port sleeves can be used to control fluid passage through ports. In
`particular, a series of limited entry moveable sliding port sleeves are installed over a plurality of ports in a casing string. A ball or
`plug is introduced to the string and pumped into the well. The ball engages a shifting sleeve and fluid pressure behind the
`ball/sleeve will move it down in the well. When the shifting sleeve passes through the limited entry port sleeve, a set of shifting
`dogs or keys engage in a shoulder or profile on the port sleeve. As they engage, the port sleeve is shifted to the open position not
`covering the port and the limited entry port is exposed. The shifting dogs to release, as by increasing pressure behind the
`ball/sleeve and the shifting sleeve moves downward to the next limited entry port sleeve.
`
`The process continues until all sleeves are shifted to the open position. The shifting sleeve will stop when it reaches a shoulder
`and will stop fluid from entering the toe end of the well. All or most additional fluid will be diverted through the newly exposed
`ports.
`
`‘ Lateral wellbore isolation system gFioure 5)
`
`A wellbore with lateral or sidetraek — multiple legs can be effectively stimulated with a junction isolation system using packers,
`such as solid body open hole packers, combined with tubing. A solid body packer is defined as a tool to create a seal between
`tubing and easing or the borehole wall using a packing element which is mechanically extruded, using either mechanically or
`hydraulically applied force. A well may be drilled with multiple legs or laterals that may be vertical, horizontal, or shaped
`otherwise. When junctions to the legs are created, isolating one leg from the remainder of the wellbore can be especially
`important to provide the ability to stimulate legs individually. This is especially true in open hole junctions. In one embodiment,
`a junction isolation system can be installed that utilizes tubing combined with packers such as solid body open hole packers that
`are placed in a selected lateral at some distance past the wellbore junction. Once the packers are set, they are used to isolate that
`leg form the remainder of the wellbore. A valve is used in association with the packer that substantially maintains the seal at the
`packer, but is openable to pennit communication to the lateral below the packer by engagement with a tubing string. Stimulation
`fluids can be pumped down the tubing string and forced into the selected lateral by connecting at the valve of the selected lateral.
`Following the stimulation, the packers may be left in the well for future isolation or may be removed.
`
`The solid body packers provide high pressure sealing in the open holes and may be equipped with multiple packing elements that
`will load into each other to provide additional pack-off. The tubing string may be connected to a packer in the casing to provide
`additional stability to the system. Also, an open hole slip system may be required to stabilize the packers during pressure pumping
`- operations.
`
`A system to isolate open hole laterals and junctions for stimulation may be used with any wellbore stimulation arrangement such
`as for example with a “sprinkler", focused packer and sleeve system, or a multiple stage “sprinkler” system, or any combination
`thereof. It may also be used during production of the well.
`
`Claims — multi—stage sprinkler system:
`1.
`
`Wellbore fluids can be distributed to segments of the well bore using “limited entry” by creating a pressure drop through
`pumping flow restrictions.
`
`High pumping rates and pressures may be required to achieve limited entry over a long interval.
`
`A series for stages to create a sprinkler effect over smaller intervals may reduce the requirements for high pumping rates.
`
`Smaller segments that are treated may allow and increase pumping rate per foot of formation being treated may be more
`effective in establishing fracturing length of fluid distribution.
`
`A higher density of fluid exit points may create more effective stimulation results
`
`Ports with internal protective covers can be installed in a tubing string and then into a well.
`
`The protected ports can provide pressure holding capability to allow stimulation fluids to be routed to other segments of
`the well.
`
`A movable sleeve can be installed into the tubing string that will remove the protective cap from the ports to effectively
`open the port.
`
`A ball or plug can be pumped into a well that will seat in the movable cutter sleeve.
`
`Pressure from moving fluids push the moveable cutter sleeve down the wellbore and effectively remove multiple
`protective caps to open these ports.
`‘
`
`The moveable sleeve will seat in a no-go to seal off the lower portion of the well.
`
`10.
`
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`Page 9 of 10
`Page 9 of 10
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`12. More effective stimulation may be accomplished by increasing the density of the port placement.
`
`13. Pumping costs may be reduced using this method due to lower pumping rate requirements.
`
`14. This system will allow the wellbore fluids to be circulated out of the well and replaced with an alternative fluid.
`
`Casing or tubing circulating system.
`
`1.
`
`’It may be desirable to displace existing wellbore fluids from a well before installing a sprinkler system
`
`If sprinkler ports are exposed, it may not be possible to circulate to the end of the well
`
`A system of protected ports can provide pressure integrity for the liner
`
`.w.4>.~=!¥> The method may remove the need for perforating after it is installed, thereby creating cost savings.
`
`Once the wellbore fluids have been circulated, the movable cutter can expose ports for stimulation
`
`Combined “Sprinkler and Focused” stimulation system
`
`1. A series of “sprinkler” combined with “focused” fracturing or stimulation may provide enhanced stimulation results.
`
`Stages in a well may be treated selectively with segment “sprinkler” systems
`
`Stages in the same well may be treated using packers and pressure shifted sliding sleeves.
`
`‘-":“."’!\’ A sprinkler system can provide stimulation fluid distribution
`
`This method may be much faster that conventional methods (movable straddle isolating packers or bridge plugs)
`
`6. A focused fracturing system may provide long fracturing length.
`
`Lateral juncture isolation for open hole sidetracl-:s
`
`1. Wells with multiple legs can be more effectively stimulated if done so individually.
`
`2 3 4 5 6
`
`A system has been developed to isolate a wellbore juncture using solid body Packers
`
`High pressure stimulation operations can be performed using this method and system
`
`Open hole junctures can be isolated in stimulated individually.
`
`The system can be used for several legs in a single well
`
`. The system can be used to isolate the lateral after stimulation is completed.
`
`7
`
`Stimulations and wellbore fluids can flow back through the isolation system
`
`8 Open hole sidetrack wells are less expensive than cased hole sidetrack.
`
`9
`
`Isolation of laterals may be required to provide effective stimulation
`
`10. Solid body, multi-element packer as described can provide high pressure sealing
`
`11. This method can result in cost savings as well as higher well productivity.
`
`S:\C4\472\.15023\8\DO0 l -1-app doc
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`Page 10 of 10
`Page 10 of 10