US20170051574A1 - Multi-stage well isolation and fracturing - Google Patents

Multi-stage well isolation and fracturing Download PDF

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Publication number
US20170051574A1
US20170051574A1 US14/646,667 US201314646667A US2017051574A1 US 20170051574 A1 US20170051574 A1 US 20170051574A1 US 201314646667 A US201314646667 A US 201314646667A US 2017051574 A1 US2017051574 A1 US 2017051574A1
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US
United States
Prior art keywords
hole packer
cased hole
tool
liner
string
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Abandoned
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US14/646,667
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English (en)
Inventor
John Hughes
Ryan D. Rasmussen
James W. Schmidt
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Resource Completion Systems Inc
RESOURCE COMPLETION SYSTEMS Inc
Wellboss Co Inc
Original Assignee
Resource Completion Systems Inc
RESOURCE COMPLETION SYSTEMS Inc
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Application filed by Resource Completion Systems Inc, RESOURCE COMPLETION SYSTEMS Inc filed Critical Resource Completion Systems Inc
Priority to US14/646,667 priority Critical patent/US20170051574A1/en
Assigned to RESOURCE WELL COMPLETION TECHNOLOGIES INC. reassignment RESOURCE WELL COMPLETION TECHNOLOGIES INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: RASMUSSEN, RYAN D., MR, HUGHES, JOHN, MR., SCHMIDT, JAMES W, MR
Assigned to RESOURCE COMPLETION SYSTEMS, INC. reassignment RESOURCE COMPLETION SYSTEMS, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: RESOURCE WELL COMPLETION TECHNOLOGIES INC.
Publication of US20170051574A1 publication Critical patent/US20170051574A1/en
Assigned to THE WELLBOSS COMPANY, LLC reassignment THE WELLBOSS COMPANY, LLC ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: THE WELLBOSS COMPANY, INC.
Assigned to THE WELLBOSS COMPANY, INC. reassignment THE WELLBOSS COMPANY, INC. MUTUAL RESCISSION OF ASSIGNMENT Assignors: THE WELLBOSS COMPANY, LLC
Abandoned legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • E21B34/102—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position
    • E21B34/103—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for locking the closing element in open or closed position with a shear pin
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/128—Packers; Plugs with a member expanded radially by axial pressure
    • E21B33/1285—Packers; Plugs with a member expanded radially by axial pressure by fluid pressure
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/004—Indexing systems for guiding relative movement between telescoping parts of downhole tools
    • E21B23/006—"J-slot" systems, i.e. lug and slot indexing mechanisms
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/01—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
    • E21B33/1216—Anti-extrusion means, e.g. means to prevent cold flow of rubber packing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/122—Multiple string packers
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B2034/007—
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/06—Sleeve valves

Definitions

  • the present invention relates to devices for multi-stage, horizontal well isolation and fracturing.
  • Fracturing of formations via horizontal wellbores traditionally involves pumping a stimulant fluid through either a cased or open hole section of the wellbore and into the formation to fracture the formation and produce hydrocarbons therefrom.
  • Tubular strings for the fracing of multiple stages of a formation typically include one or more fracing tools separated by one or more packers.
  • frac systems are deployed in cased wellbores, in which case perforations are provided in the cemented in system to allow stimulation fluids to travel through the fracing tool and the perforated cemented casing to stimulate the formation beyond.
  • fracing is conducted in uncased, open holes.
  • multiple frac valve tools are used in a sequential order to frac sections of the formation, typically starting at a toe end of the wellbore and moving progressively towards a heel end of the wellbore.
  • An activation tool for use in a well isolation and stimulation string, said activation tool comprising a stationary seat for receiving a ball deployed down the string, a stationary inner body, a stationary outer body and a moving sleeve positioned between the stationary inner and stationary outer bodies and movable from an open position to a closed position by force of the ball against the seat.
  • a first stage frac valve tool is also provided for use in a well stimulation string, said first stage frac valve tool comprising a stationary outer body and an internal piston movable between an closed and an open position.
  • a singular tool comprising a float shoe, an activation tool comprising a stationary seat for receiving a ball deployed down the string, a stationary inner body, a stationary outer body and a moving sleeve positioned between the stationary inner, stationary outer bodies and movable from an open position to a closed position by force of the ball against the seat and integrally built with the float shoe and a first stage frac valve comprising a stationary outer body and an internal piston movable between an closed and an open position and integrally built with the activation tool.
  • a cased hole packer is further provided comprising an integral setting tool.
  • FIG. 1 is a schematic diagram of a horizontal well fitted with the tools of the present invention
  • FIG. 2 is a cross-sectional view of one example of the activation tool of the present invention, in various stages of use;
  • FIG. 3 is a cross sectional view of one example of the first stage frac valve tool of the present invention, in various stages of use;
  • FIG. 4 is a cross sectional view of one example of the cased hole packer of the present invention.
  • FIG. 5 is a cross sectional view of the cased hole packer of the present invention, showing a first means of deployment;
  • FIG. 6 is a cross sectional view of the cased hole packer of the present invention, showing a collet type latch seal assembly
  • FIG. 7 is a cross-sectional view of a cased hole packer that may be deployed on the casing string
  • FIG. 8 is a cross-sectional view of one example of a cased hole anchor of the present invention.
  • FIG. 9 is a schematic diagram of dual horizontal liners drilled in one well.
  • a series of tools is provided that improve on existing horizontal isolating and fracing tools, by providing increased safety during installation, reduced rig time and greater dependability of deploying the tools to the end of the horizontal section of the wellbore.
  • the present tools eliminate the need for handling pup joints, thereby reducing the rigidity of the liner. These features permit the more flexible, reduced outside diameter tool string to be deployed into the wellbore with greater ease.
  • the present invention consists of a series of tools strategically located along a liner and deployed into the open hole section of the wellbore.
  • the tools provide a means of isolating various stages of the horizontal wellbore. After isolating various stages, stimulation fluid can be pumped from surface and through valve tools that are opened sequentially to thereby multi-stage frac the formation.
  • the present system of tools comprises a cased hole packer 500 that anchors the liner and forms a seal between the casing string and the open hole.
  • a float shoe or guide 50 is run at the toe of the liner.
  • An activation tool 100 is placed a pre-determined distance from the guide shoe 50 .
  • a first stage frac valve tool 200 is then an series comprising an open hole packer 300 alternated with one or more subsequent stage frac valve tools 400 .
  • FIG. 1 merely represents one example of a tubular fracing string of tools and that additions, omissions and alterations to the illustrated string and its components can be made without departing from the scope of the present invention.
  • the float shoe 50 is preferably provided with an open end having a flap covering.
  • the open end allows the liner pressure to be at least somewhat equalized with the formation pressure while the flap prevents ingress of formation fluids into the liner.
  • the activation tool 100 as seen in FIG. 2 comprises an opening 102 .
  • the one piece construction of the outer body 120 of the activation tool allows torque to be applied from the upper liner section, through the tool and into the liner to make up the liner string.
  • the activation tool 100 can be lifted by hand and hand threaded onto the liner, which is typically gripped at the rig floor, and then a section of upper liner, typically gripped in an elevator or similar device, can be lowered onto the tool.
  • the opening 102 is open during deployment such that fluid can be circulated through the opening 102 when the liner is being run into the well, as seen in FIG. 2 a .
  • a ball 104 is circulated down to the activation tool 100 , as seen in FIG. 2 b , and prevents circulation through opening 102 and re-directs fluid into a chamber 106 formed between an activation tool inner body 118 and a sleeve 110 .
  • the sleeve 110 comprises a first and a second diameter, D 1 and D 2 respectively. While D 1 is exposed to wellbore fluids and experiences wellbore pressures, D 2 is exposed to fluid pressure from within the liner.
  • the product of the difference in these pressures and the difference in these diameters defines the force needed to displace sleeve 110 and move the activation tool 200 from an open ( FIGS. 2 a , 2 b ) to a closed position ( FIG. 2 c ).
  • Pressure from the liner fluid serves to shears screws 108 that have been holding the sleeve 110 in the open position.
  • the sleeve 110 then shifts and the opening 102 closes, blocking flow through the opening 102 .
  • pressure increases to thereby trigger activation and setting of the open hole packers 300 and the cased hole packer 500 .
  • a number of seals 116 between the sleeve 110 and the activation tool inner body 118 guide this movement from open to closed.
  • a collet 112 located on the sleeve 110 catches against an end of the activation tool inner body 118 when the sleeve 110 is in the closed position and prevents the sleeve 110 from shifting back to its original, open position.
  • the activation tool 100 further advantageously serves as a redundant safety device to the float shoe 50 , ensuring that wellbore fluids do not enter the liner prior to fracing.
  • the opening 102 in the activation tool has been designed with minimum moving parts.
  • the ball 104 and its corresponding seat 114 are entirely comprised of non-moving components, thereby eliminating the risk of creating a hydraulic lock, or locking of parts due to the presence of an incompressible fluid that has nowhere to be displaced to, below the opening 102 .
  • the internal sleeve 110 shifts to close the opening 102 and is locked by means of the collet 112 , so that in the event that the ball 104 undesirably rolls off of the valve seat 114 , the opening 102 remains in the closed position.
  • the next tool in the present invention is the first stage frac valve tool 200 , depicted in FIGS. 3 a and 3 b .
  • This is the frac valve through which the first stage of the stimulation is pumped to the toe of the wellbore.
  • the present first stage frac valve tool 200 can be lifted by hand and hand threaded onto the liner, which is typically gripped at the rig floor, and then a section of upper liner, typically gripped in an elevator or similar device, can be lowered onto the tool.
  • the first stage frac valve tool 200 Since the closing of the activation tool 100 prevents circulation of fluid, the first stage frac valve tool 200 relies solely on applied pressure to open.
  • the opening pressure of the first stage frac valve tool 200 must be greater than the pack off pressure required to set the open hole packer 300 and cased hole packer 500 .
  • Increasing liner fluid pressure acts on surface D 1 to apply pressure on piston 204 .
  • the opening pressure of the first stage frac valve tool 200 is preferably controlled by the number of shear screws 202 installed into the piston 204 , although other known means of controlling opening pressure would also be understood by a person of skill in the art and encompassed by the present invention.
  • the shear screws 202 shear allowing the piston 204 to be shifted to the open position, as seen in FIG. 3 b.
  • a snap ring 208 preferably locks the piston 204 in the open position, although other known biasing means may also be used and would be well known to a person skilled in the art.
  • the moving parts of the first stage frac valve tool 200 are all internal, meaning they do not have to overcome friction against the wellbore to shift from closed to open, allowing better control over the system.
  • a further advantage of the present first stage frac valve tool 200 is its ability to transmit torque. During installation torque can be transmitted through the first stage frac valve tool 200 from a joint above into the liner below in order to make up the threads.
  • the internal body connection of the first stage frac valve tool 200 has been designed to handle torque greater than the make-up torque of the liner connections.
  • the ability to transmit torque combined with its short size, eliminate the need for handling joints that would need to be torqued on both ends of the first stage frac valve tool 200 .
  • the geometry of the fracture ports 210 provides easy identification for the first stage frac valve tool 200 , thereby reducing the potential for incorrect placement in the liner string.
  • the unique geometry of the fracture ports 210 differentiates the appearance of the first stage frac valve tool 200 from other similar looking valves installed on the liner.
  • Ports 210 may also preferably be sized to reduce or prevent ingress of wellbore debris into the liner.
  • a singular tool comprising a float shoe 50 /activation tool 100 /first stage frac valve tool 200 can be used to replace individual float shoe 50 , activation tool 100 and first stage frac valve tool 200 with liner joints connecting them.
  • the singular combination tool requires less threaded connections, thereby reducing potential leak paths and decreases rig time since only one threaded connection needs to be torqued on the rig floor.
  • the singular combination tool also ensures that the fracture ports 210 of the first stage frac tool 200 are as close to the toe of the well as possible.
  • the first stage frac valve tool 200 When the first stage frac valve tool 200 opens, the formation is immediately exposed to high pressure liner fluid.
  • the first stage frac valve tool 200 may be configured such that a high fluid pressure is required to unlock the piston 204 , then a second surge of low pressure serves to open the fracture ports 210 .
  • This embodiment of the first stage frac valve tool 100 can be used to protect sensitive formations from excessive pressures.
  • the next tools installed onto the liner are a series of one or more open hole packers 300 and a frac valve tools 400 .
  • the open hole packers 300 are preferably single element open hole packers 300 .
  • the next element of the present invention is the cased hole packer 500 , which is run at the top of the liner, and is illustrated in FIG. 4 .
  • the cased hole packer 500 is a hydraulically set, preferably permanent packer with a tie back receptacle 502 and is used to anchor the liner into the casing string and provide a seal between the top of the liner and the casing string.
  • the present cased hole packer 500 advantageously incorporates an integral setting tool in the form of slips 504 to activate the cased hole packer 500 .
  • the slips 504 do not extend beyond the OD of the cased hole packer 500 and require no additional space.
  • the present cased hole packer 500 and other present tools can be run on a frac string, without the need to run a drill string and then change out to a frac string, saving time during operation. It would be well understood by a person of skill in the art that the present cased hole packer 500 can also be deployed on drill string and any number of means can be used to accommodate this smaller diameter pipe.
  • the opposing slips 504 serve to anchor the cased hole packer 500 to the casing string in both tension and compression due to wickers formed on an outer surface thereof that act to engage the casing string inside diameter when the cased hole packer 500 is set.
  • a setting piston 534 on the cased hole packer mandrel 530 comprises a first and a second diameter, D 1 and D 2 respectively. While D 1 is exposed to wellbore fluids and experiences wellbore pressures, D 2 is exposed to fluid pressure from within the liner. The product of the difference in these pressures and the difference in these diameters defines the force needed to displace setting piston 534 and move the cased hole packer 500 from an unset to a set position. A pair of seals 516 between the setting piston 534 and the mandrel body 530 guide this movement from unset to set.
  • the packing element 522 is comprised of a solid band of flexible material having a thickness such that an outer surface of the packing element 522 in its unset position sits flush with an outer surface of the upper and lower cones 520 .
  • Suitable materials for the packing element include any number of fluorocarbons and per-flourocarbons such as AFLASTM, HNBR, and VitonTM, although it would be understood by a person of skill in the art that any flexible material showing resiliency and sufficient strength to maintain packing against wellbore fluid pressure would be suitable for the purposes of the present invention.
  • the packing element 522 is thinner at its axial midpoint than everywhere else. More preferably, the packing element 522 is formed with a circumferential groove 540 of predetermined width and depth around its inner surface at the axial midpoint, such groove 540 creating a thinner middle portion of the packing element 522 .
  • the groove 540 ensures that the packing element 522 protrudes from its axial midpoint, thereby providing even contact with the wellbore and a positive seal.
  • a packing element ring 542 is provided on the mandrel 530 onto which the packing element groove 540 sits. The packing element ring 542 fills in the void of the groove 540 and ensures that the midpoint of the packing element 522 protrudes outwards upon actuation, and does not fold inwardly into itself.
  • One or more anti-extrusion expandable rings 524 hold the packing element 522 in place and press against the packing element 522 in actuation.
  • the anti-extrusion rings 524 are positioned between backup rings 544 and the upper and lower cones 520 respectively.
  • the backup rings 544 are preferably shaped to allow an end of the upper and lower cones 520 to travel along and wedge into one contour of the backup ring 544 while allowing the anti-extrusion ring 524 to travel along and wedge between the upper and lower cones 520 and another contour of the backup ring 544 at each end of the packing element 522 .
  • Such wedging prevents the packing element 522 from extruding internally and prevents packing element creep during high differential pressures and helps centralize the cased hole packer 500 while setting.
  • the use of the present anti-extrusion rings 524 creates a barrier around the packing element 522 after the cased hole packer 500 is set. Without this barrier the packing element 522 would not be able to maintain a seal at high differential pressures inside the casing.
  • a ratchet ring 528 is located between the mandrel body 530 and the setting piston 534 that serves to prevent the piston 534 from backing off from a set position, thus ensure that the packing element 522 remains in a set position once set.
  • the ratchet ring 528 is preferably comprised of a split ring with an inner surface ratchet profile and an outer surface ratchet profile.
  • the inner surface ratchet profile is finer than the outer surface ratchet profile.
  • the ratchet ring 528 is first assembled onto the mandrel 530 of the cased hole packer 500 , at least a part of the outer surface of the mandrel 530 having a ratchet profile that mates with the inner surface ratchet profile of the ratchet ring 528 .
  • the ratchet ring 528 is assembled over one or more spring pins 546 installed on the mandrel 530 to maintain the position and alignment of the ratchet ring 528 .
  • a locking body thread 532 formed on an inner surface of at least part of the setting piston 534 is then installed over the ratchet ring 528 .
  • the locking body thread 532 mates with the outer surface ratchet profile of the ratchet ring 528 .
  • Orientation of the inner surface ratchet profiles of the ratchet ring 528 allow the setting piston 534 and ratchet ring 528 to travel from unset to set position along the mandrel body 530 , while preventing the setting piston 534 and ratchet ring 528 from sliding back to an unset direction from a set position.
  • Orientation of the outer surface ratchet profile of the ratchet ring 528 allows the setting piston 534 to slide over the outer surface of the ratchet ring 528 when it is being installed onto the ratchet ring 528 .
  • the ratchet ring 528 and setting piston 534 have a larger ID than the mandrel body 530 OD, thereby being able to be installed on the mandrel 530 without having to split the locking body 532 from the setting piston 534 .
  • the tie back receptacle 502 acts as a sealing interface and latching mechanism between the liner and drill string, should a drill string be used in deployment, and as a sealing interface and latching mechanism between the liner and frac string during stimulation.
  • the cased hole packer 500 may also comprise one or more grooves (not shown) machined circumferentially around the O.D. of the cased hole packer 500 .
  • the grooves can receive a clamp to permit shop pressure testing of the cased hole packer 500 to high pressures to verify correct assembly.
  • the clamp prohibits the cased hole packer 500 from setting, while testing the integrity of the tool's internal seals.
  • the present cased hole packer can be deployed using three different deployment methods.
  • the cased hole packer 500 can be attached to a jay type latch seal assembly 506 , illustrated in FIG. 5 .
  • the latch seal assembly 506 is used to connect and seal the liner to the drill string, if a drill string is used, during deployment.
  • the latch seal assembly 506 will have an upper thread 508 compatible with the thread on the drill string. It also has an anchoring mechanism 510 compatible with the tie back receptacle 502 that serves to anchor it to the packer. Seals 512 located on the latch seal assembly 506 engage matching seal bore located on the tie back receptacle 502 to prevent fluid leak between the tie back receptacle 502 and the latch seal assembly 506 .
  • an upper thread 508 is sized to be compatible with the threads on the frac string.
  • the jay type latch seal assembly 506 is preferably full bore with an ID matching the liner I.D., and no restrictions in the mandrel 514 of the latch seal assembly 506 .
  • Shear screws 518 installed prior to deployment ensure that the liner and cased hole packer 500 cannot disengage from the drill/frac string prematurely.
  • the shear screws 518 are installed through the tie back receptacle 502 and engage a profile machined on the outer surface of the jay type latch seal assembly 506 . Torque is required to break these shear screws 518 .
  • the current design of the jay type latch seal assembly is illustrated as having an anchoring mechanism in the form of three jay pins, it could instead have two or more jay pins, and such embodiments are encompassed by the scope of the present invention.
  • the seals 512 are bonded seals, although other seal configurations could be used instead, including polypak type seals, o-rings or v-seals.
  • the seal design on the latch seal assembly 506 allows the latch to be removed under differential pressure, thus eliminating seal damage.
  • FIG. 6 A second deployment method that can be used with the cased hole packer 500 is depicted in FIG. 6 , which uses a collet type latch 536 , to deploy the liner and frac string.
  • the collet type latch seal assembly 536 has flexible fingers that can deflect and allow the seal assembly to be stabbed into the receptacle.
  • the flexible collet latch 536 can preferably comprise a tread profile machined on its external surface that matches a similar thread profile machined on the I.D. of the receptacle.
  • the collet type latch seal assembly 536 can preferably be removed from the receptacle by rotating the work string clockwise while picking up, which serves to screw the collet type latch 536 out of the receptacle.
  • FIG. 7 A third deployment method that can be used with the cased hole packer 500 is depicted in FIG. 7 , in the form of a casing string 538 screwed directly into top of cased hole packer 500 .
  • the casing string is used for both deployment and fracturing and the casing string is not retrieved when the process is complete.
  • a liner is assembled with the following components, as illustrated in FIG. 1 : a float shoe 50 , the present activation tool 100 , a liner, the present first stage frac valve tool 200 , and then a series comprising a liner, an open hole packer 300 , a liner and a frac valve 400 .
  • an open hole anchor 600 may be used between the activation tool 100 and the first stage frac valve tool 200 to anchor the liner to the wellbore.
  • Alternative to an open hole anchor 600 centralizers, stabilizers or other suitable means known in the art may also be used for this purpose.
  • frac valves 400 Preferably up to 40 frac valves 400 , on a 41 ⁇ 2′′ liner for example, separated with open hole packer 300 s can be used in a string.
  • a cased hole packer 500 is attached to the upper end of the casing.
  • a latch seal assembly 506 , collet type latch 536 or other known means can be used to attach the cased hole packer 500 to the casing.
  • the liner is run into the conditioned bore hole by a drill string or on a frac string.
  • ball 104 is circulated down to the activation tool 100 to stop fluid flow.
  • Pressure increase, thereby setting both the cased hole packer 500 and the open hole packers 300 .
  • a pressure test may optionally be performed inside the casing to determine if the cased hole packer 500 has set properly. If the liner was run on a drill string, the latch seal assembly 506 , collet type latch 536 or other connection means can next be removed from the cased hole packer 500 and the drill string and connecting means are removed from the well and a frac string and associated connecting means are deployed. Otherwise, if the liner was run downhole on a frac string, no replacement has to be made.
  • first stage frac valve tool 200 shifts to the open position and stimulation fluid is pumped into the formation to stimulate the formation from the toe of the wellbore to the first stage frac valve tool 200 .
  • Proppant is then pumped into the fracture.
  • Next subsequent frac valve tools 400 starting with that closest to the first stage frac valve tool 200 , are activated to thereby open communication between the inside of the liner and the isolated section of the formation between the two open hole packer 300 straddling the particular frac valve 400 .
  • the stimulation fluid pumped through the ports of the frac valve 400 fractures the exposed formation between the open hole packers 300 used to isolate that stage. Whenever this stage has been fractured, a next frac valve 400 is activated and the process is repeated. The process can be repeated up to 40 times in total in a 41 ⁇ 2′′ liner, for example. Other sizes of liners can have a different number of frac valve tools 400 and open hole packers 300 .
  • the well is allowed to flow and formation pressure from formation fluid flow acts to deactivate the frac valves 400 and allows formation fluid flow into the liner. Afterwards the frac string and connecting means can be removed from the well.
  • the seats of the frac valves 400 can be drilled out at a later date.
  • an open hole anchor 600 illustrated in FIG. 8 can replace the cased hole packer 500 .
  • This scenario can exist whenever dual horizontals are drilled in one well, as seen in FIG. 9 .
  • the hydraulic set open hole anchor 600 is full bore. It is run in conjunction with an open hole packer 300 and tie back receptacle (not shown) to act as a means to seal and anchor the liner in the open hole.
  • the tieback receptacle provides a means to deploy the liner then act as a means to seal and anchor the fracture string to the liner.
  • the open hole anchor 600 is preferably full bore with no mandrel restrictions and has the same I.D. as the liner. Preferably it is operated with slips 602 to anchor the liner to the formation. More preferably the open hole anchor 600 employs a similar setting piston and ratchet configurations of the cased hole packer 500 .
  • a reamer trip is performed.
  • the present reamer has a unique design to mimic the geometry of the stiffest components on the liner string.
  • the present reamer has one set of blades instead of multiple sets and its reduced O.D. and short length enable it to be deployed and retrieved quickly while still ensuring the bore hole has no obstructions to impede running the liner with the present suite of fracturing tools.
  • the reamer preferably has a small O.D. and a short length to mimic the geometry of the present tools of the frac string illustrated in FIG. 1 .
  • the geometry of the reamer permit ease of deployment and in some circumstances allows the reamer to trave to the toe end of the frac string without needing to ream any tight spots in the wellbore. This reduces rig time while ensuring that the present frac tools can be deployed into the wellbore.

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  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Piles And Underground Anchors (AREA)
  • Check Valves (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Lift Valve (AREA)
US14/646,667 2012-12-21 2013-12-20 Multi-stage well isolation and fracturing Abandoned US20170051574A1 (en)

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PCT/CA2013/001074 WO2014094137A1 (fr) 2012-12-21 2013-12-20 Isolation et fracturation de puits à étages multiples
US14/646,667 US20170051574A1 (en) 2012-12-21 2013-12-20 Multi-stage well isolation and fracturing

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US14/409,120 Active 2034-04-07 US9995111B2 (en) 2012-12-21 2013-12-20 Multi-stage well isolation
US15/923,942 Active US10584562B2 (en) 2012-12-21 2018-03-16 Multi-stage well isolation
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US15/923,942 Active US10584562B2 (en) 2012-12-21 2018-03-16 Multi-stage well isolation
US15/960,770 Abandoned US20180238142A1 (en) 2012-12-21 2018-04-24 Multi-stage well isolation and fracturing

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CN (3) CN104968888A (fr)
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US11261701B2 (en) 2017-08-22 2022-03-01 Weatherford Technology Holdings, Llc Shifting tool and associated methods for operating downhole valves
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US11111758B2 (en) 2019-01-24 2021-09-07 The Wellboss Company, Inc. Downhole sleeve tool
US11396792B2 (en) * 2019-01-24 2022-07-26 The Wellboss Company, Inc. Downhole sleeve tool
US11692420B2 (en) 2020-10-09 2023-07-04 The Wellboss Company, Inc. Systems and methods for multi-stage fracturing
US12264567B2 (en) 2020-10-09 2025-04-01 The Wellboss Company, Inc. Systems and methods for multi-stage well stimulation
US12352147B2 (en) 2022-10-25 2025-07-08 The Wellboss Company, Inc. Systems and methods for multistage fracturing
WO2025072807A1 (fr) * 2023-09-28 2025-04-03 Halliburton Energy Services, Inc. Ensemble de jonction multilatérale utilisant un matériau dégradable
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RU2015123022A (ru) 2017-01-27
CA2838094C (fr) 2015-02-17
WO2014094136A1 (fr) 2014-06-26
US20180238142A1 (en) 2018-08-23
US20180252074A1 (en) 2018-09-06
CA2838094A1 (fr) 2014-03-13
CN105143597A (zh) 2015-12-09
RU2015123020A (ru) 2017-01-27
AU2013362802A1 (en) 2015-07-09
US10584562B2 (en) 2020-03-10
WO2014094135A1 (fr) 2014-06-26
CA2837997A1 (fr) 2014-03-14
US9995111B2 (en) 2018-06-12
AU2013362803A1 (en) 2015-07-09
CA2873198A1 (fr) 2014-03-12
CA2838092A1 (fr) 2014-03-12
CA2874913A1 (fr) 2014-03-12
CA2838092C (fr) 2015-06-02
AU2013362804A1 (en) 2015-07-09
RU2597231C1 (ru) 2016-09-10
AU2013362803B2 (en) 2016-07-28
CN104968888A (zh) 2015-10-07
CA2837997C (fr) 2014-11-25
CA2873198C (fr) 2018-03-27
US20150330185A1 (en) 2015-11-19
US20150285025A1 (en) 2015-10-08
CN104428487A (zh) 2015-03-18
CA2903648A1 (fr) 2014-03-12
WO2014094137A1 (fr) 2014-06-26

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