WO2015149169A1 - Système de fracturation à haute pression multi-étages initiée par projectile - Google Patents

Système de fracturation à haute pression multi-étages initiée par projectile Download PDF

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Publication number
WO2015149169A1
WO2015149169A1 PCT/CA2015/050246 CA2015050246W WO2015149169A1 WO 2015149169 A1 WO2015149169 A1 WO 2015149169A1 CA 2015050246 W CA2015050246 W CA 2015050246W WO 2015149169 A1 WO2015149169 A1 WO 2015149169A1
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WO
WIPO (PCT)
Prior art keywords
projectile
caught
dart
downhole
catcher
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/CA2015/050246
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English (en)
Inventor
Robert James GRAF
Robert Steve SMOLKA
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.)
COMPLETIONS RESEARCH AG
Original Assignee
COMPLETIONS RESEARCH AG
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by COMPLETIONS RESEARCH AG filed Critical COMPLETIONS RESEARCH AG
Priority to CA2940852A priority Critical patent/CA2940852A1/fr
Priority to US15/120,998 priority patent/US20170122068A1/en
Publication of WO2015149169A1 publication Critical patent/WO2015149169A1/fr
Anticipated expiration legal-status Critical
Ceased 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
    • 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
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • 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
    • E21B23/08—Introducing or running tools by fluid pressure, e.g. through-the-flow-line tool systems
    • E21B23/10—Tools specially adapted therefor
    • 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
    • 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
    • E21B34/063—Valve or closure with destructible element, e.g. frangible disc
    • 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
    • E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
    • 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
    • E21B43/14—Obtaining from a multiple-zone well
    • 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
    • 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 invention generally relates to a system and method for fracturing multiple zones in an oil and gas well.
  • the invention specifically relates to a system and method comprising a series of multistage fracturing devices operatively connected along a tubing string, wherein the sealing of the tubing string where a multistage fracturing device is located is triggered by a dart of specific dimensions that is pumped down the tubing string and captured by the multistage fracturing device.
  • cased wells there have been a number of techniques that operators have utilized in cased wells to isolate one or more zones of interest to enable access to the formation as well as to conduct fracturing operations.
  • a cased well may simply need to be opened at an appropriate location to enable hydrocarbons to flow into the well.
  • the casing of the well (and any associated cement) may be penetrated at the desired location such that interior of the well casing is exposed to the formation and hydrocarbons can migrate from the formation to the interior of the well.
  • One such technique is to incorporate packer elements and various specialized pieces of equipment into one or more tubing strings, run the tubing string(s) into the well and conduct various hydraulic operations to effect opening of ports within the tubing strings.
  • a device for connection to a casing or completion tubing in a wellbore to enable fluid access between an inner cavity of the device and a zone of interest in a hydrocarbon formation adjacent the device, the inner cavity being continuous with an internal bore in the casing or completion tubing
  • the device comprising an outer sleeve for operative connection to the casing or completion tubing, the outer sleeve having at least one port to enable fluid access between the inner cavity and the zone of interest; a catchment system operatively retained within the outer sleeve for catching a projectile moving through the inner cavity; a sealing system operatively retained within the outer sleeve for sealing a downhole section of the device from an uphole section of the device when the projectile is caught; wherein the at least one port can be opened through hydraulic activation when the sealing system is sealed; and wherein an outer profile of the projectile determines whether the projectile will be caught.
  • the projectile includes at least one shoulder on the outer profile, and the location and dimensions of the at least one shoulder determines whether the projectile will be caught by the catchment system. Furthermore, a first projectile having an outer diameter and an outer profile will be caught, while a second projectile having the same outer diameter as the first projectile and a different outer profile will pass through the catchment system.
  • the catchment system comprises a plurality of levers pivotably connected around the circumference of the inner cavity, wherein the levers operatively engage with a projectile having a certain outer profile.
  • the catchment system may further comprise a biasing means in operative connection with the levers for biasing the levers in a first position.
  • the sealing system comprises a piston and a sealing member positioned uphole and adjacent to a caught projectile, the sealing member deformable against the caught projectile by hydraulic actuation of the piston to seal the downhole section from the uphole section of the device.
  • the catchment system is in a first shearing engagement with the outer housing, and wherein catchment of a projectile enables the first shearing engagement to disengage and the catchment system to move downhole with respect to the outer housing to enable the sealing system to seal.
  • the catchment system may be in a second shearing engagement with the outer housing, and wherein sealing of the sealing system enables the second shearing engagement to disengage and the catchment system to move further downhole with respect to the outer housing to open the at least one port.
  • the caught projectile can be released from the catchment system to re-open the inner cavity.
  • the caught projectile may be dissolvable.
  • a system for use in a wellbore comprising a plurality of the above-described devices, each device connected to the casing or completion tubing at a different location to selectively enable access to a zone of interest at each location by sending a projectile downhole from a well surface, the projectile having an outer profile configured to be caught by the catchment system at the desired location.
  • a method for selectively enabling fluid access to a plurality of zones in a wellbore comprising the steps of: (a) running an assembly having a plurality of actuatable devices into a wellbore having a plurality of zones, each device actuatable between a closed state and an open state, wherein in the open state fluid access between an internal bore of the assembly and a zone adjacent each device is enabled; (b) selectively actuating a device at the desired zone by dropping a projectile having an outer profile with dimensions to be caught by the device at the desired zone; catching the projectile in the device at the desired zone; applying hydraulic pressure in the internal bore from a well surface to seal a section downhole of the caught projectile from a section uphole of the caught projectile; and applying hydraulic pressure to move a member in the device downhole with respect to the assembly to open at least one port to provide fluid access between the internal bore and the adjacent zone; (c) performing well operations that require access to the desired zone
  • the outer profile of the projectile includes at least one shoulder, and the position and dimensions of the shoulder determine whether the projectile is caught by a device.
  • the projectile is caught by pivotable levers in the device.
  • the plurality of devices are successively actuated in a downhole to uphole direction.
  • the well operations include fracturing operations.
  • FIG. 1 is a schematic diagram of a deployed casing or completion tubing string incorporating several multi-stage fracturing devices in accordance with the invention together with corresponding packer elements.
  • FIG. 2 is a perspective view of a multi-stage fracturing device (MFD) in accordance with the invention.
  • the outer housing is removed for purposes of illustration.
  • FIGS. 3A, 3B and 3C are perspective views of a catcher mechanism of the MFD sequentially illustrating a dart being captured in accordance with the invention.
  • FIG. 4 is a partial perspective view of the MFD illustrating an outer housing having a plurality of ports in a closed position, wherein the ports can be opened to allow for fracturing operations to occur.
  • FIG. 5 is a perspective view of a support mechanism of the MFD.
  • FIGS. 6A, 6B and 6C are a series of a cross-sectional side view of the MFD illustrating the normal position of the MFD wherein a dart is entering the uphole end of the MFD but has not yet been captured.
  • FIGS. 7A to 7F are a sequence of partial cross-sectional side views of the MFD illustrating a dart being captured by the catcher mechanism.
  • FIGS. 8A to 8F are a sequence of partial cross-sectional side views of the MFD illustrating a dart passing through the catcher mechanism without being captured due to the geometry of the dart.
  • FIGS. 9A, 9B and 9C are a series of a cross-sectional side view of the MFD illustrating the first stage of operation wherein a dart is captured by the catcher mechanism.
  • FIGS. 10A, 10B and 10C are a series of a cross-sectional side view of the MFD illustrating the second stage of operation wherein the support mechanism has been set to brace the captured dart.
  • FIGS. 11 A, 11 B and 11 C are a series of a cross-sectional side view of the MFD illustrating the third stage of operation wherein the sealing mechanism has been set to seal off a downhole section from an uphole section of the tubing string.
  • FIGS. 12A, 12B and 12C are a series of a cross-sectional side view of the MFD illustrating the fourth stage of operation wherein the ports have been opened to ready the MFD for the commencement of fracturing operations.
  • FIG. 13 is a side view of a dart in accordance with one embodiment of the invention.
  • FIG. 14A is a partial cross-sectional side view of the MFD illustrating the sealing mechanism in the first (unsealed) stage of operation as in FIGS. 9A-9C.
  • FIG. 14B is a partial cross-sectional side view of the MFD illustrating the sealing mechanism in the second stage of operation as in FIGS. 10A-10C, wherein there is a pressure differential to allow the piston to set the sealing mechanism.
  • FIG. 14C is a partial cross-sectional side view of the MFD illustrating the sealing mechanism in the third (sealed) stage of operation as in FIGS. 1 1 A-1 1 C.
  • MFD multistage fracturing device
  • the MFD 10 may be configured to a casing or completion tubing string 4 together with appropriate packer elements 10a to enable the isolation of particular zones 8a within a formation as shown in Figure 1 .
  • the combination of MFDs 10 and packer elements 10a on a casing or completion tubing 4 enable fracturing operations to be conducted within a formation zone 8a within a well 8.
  • the system may be utilized without packer elements in situations for example where the completion tubing is cemented in place. While the following description assumes the use of packer elements 10a, this is not intended to be limiting.
  • a number of MFDs 10 are connected to a casing or completion tubing 4 between packer elements 10a at positions that correspond to zones of interest (formations) 8a within the well.
  • the assembled system can be pressurized at the surface 6 through wellhead equipment 6a to cause the packer elements 10a to seal against the well 8.
  • a dart 18 is released at the surface 6 within the casing or completion tubing and falls and/or is pumped through the casing or completion tubing to engage with a specific MFD, preferably the MFD located nearest the downhole end 4a of the tubing.
  • the dart has a specific external geometry and diameter that enables the dart to be captured by a specific MFD 10 and to pass through other MFD's without being caught.
  • the dart 18 When the dart 18 is captured, shown in zone 8a of FIG. 1 , the dart causes the interior of the casing or completion tubing to be sealed from the lower regions of the casing or completion tubing such that additional hydraulic events can be initiated to open a plurality of ports within the MFD that the dart is captured in. That is, when the dart has been captured and a port in the MFD 10 is opened, a fracturing operation can be completed within a zone of interest 8a adjacent that MFD.
  • the darts are designed such that over a period of time, typically a few days, the darts will at least partially dissolve such that their diameter is eroded and they will fall to the bottom of the well.
  • all the zones of the well are then opened to the interior of the casing or completion tubing to enable production of the well through the casing or completion tubing.
  • the lowermost zone of the completion string does not require an MFD 10 and that a simple hydraulic valve that opens on pressure would normally be utilized at the lowermost zone (not shown) to initially establish circulation and to enable fracturing of the lowermost zone.
  • the MFD 10 generally comprises an upper housing 14, a sealing mechanism 20, a catcher mechanism 30, a support mechanism 40, a lower housing 16, and a continuous inner cavity 50 extending from an uphole end 10b to a downhole end 10c of the MFD that is in fluid communication with the completion tubing and through which a dart 18 (not shown in FIG. 2) moves to trigger the setting and sealing mechanics of the MFD.
  • the components of the MFD illustrated in FIG. 2 are all contained within an outer housing, which has been removed for illustrative purposes. The operation and components of the system are described in greater detail below.
  • dart 18 is shown entering the uphole end 10b of the MFD inner cavity 50 in FIG. 6A.
  • the dart is cylindrical-shaped and has a leading end 18a with a beveled edge 18f and a circumferential leading shoulder 18b; a trailing end 18c with a circumferential trailing shoulder 18d; and an outer surface 18e.
  • the widest part of the dart's diameter is located between the leading shoulder 18b and the leading end 18a.
  • the geometrical configuration and diameter of the dart determines whether the catcher mechanism catches the dart or allows the dart to pass through and continue downhole to subsequent MFD's, one of which may have a catcher mechanism sized to catch the dart.
  • Other geometrical configurations of the dart than that which is illustrated could also be used as will be explained below.
  • the dart has an approximate diameter in the range of 3.25 to 3.75 inches and an approximate length of 4 to 6 inches.
  • the darts are released from the catcher mechanism and flowed back to the surface to re-open the inner cavity 50.
  • the dart is made of dissolvable, or degradable composite material, such that after a period of time, typically a few days, the dart will at least partially dissolve such that its diameter is reduced and it will fall to the bottom of the well, thereby re-opening the inner cavity.
  • Alternative means for releasing the dart could also be used including systems having dissolvable components within the catcher mechanism or electronic release systems.
  • FIGS. 6A to 6C illustrates the housing elements which comprise the outer housing 12, the upper housing 14 and the lower housing 16.
  • the outer housing 12 contains the components of the MFD and generally comprises an uphole end 12a, a downhole end 12b and a plurality of ports 12d, shown in FIG. 4, that when open, allow fluid access from the inner cavity 40 to the formation for completing fracturing operations, and when closed, seal the inner cavity from the formation.
  • the at least one piston shear pin 24c (FIGS. 2 and 4) removably connects the outer housing 12 to a piston sleeve of the sealing mechanism 20.
  • the upper housing 14 is partially retained within and in sealing connection with the outer housing uphole end 12a.
  • An uphole end of the upper housing is in sealing connection with the casing or completion tubing 4.
  • the lower housing 16 is partially retained within and in sealing connection with the outer housing downhole end 12b, and comprises an outer shoulder 16c for abutment with the outer housing downhole end, and an inner shoulder 16b for abutment with a support sleeve 44 of the support mechanism 40 when the system is in the final downhole position (FIGS. 12 to 12C).
  • the lower housing 16 includes a plurality of shear pin holes 16a through which the downhole shear pins 52 are inserted to connect the lower housing to the support sleeve 44.
  • a downhole end of the lower housing is in sealing connection with the casing or completion tubing 4.
  • sealing elements such as o-rings, are employed between the housing elements in circumferential grooves for sealing purposes.
  • the catcher mechanism 30 functions to "catch” or trap the dart 18 as it moves downhole through the MFD inner cavity 50 if the dart is dimensioned to be caught.
  • the catcher mechanism 30 generally comprises a catcher sleeve 32, a catcher member 34 and a catcher spring 36.
  • the catcher member 34 comprises a plurality of pivotable catcher fingers 34a spaced apart around the circumference of the catcher member, each pivotable catcher finger 34a having an uphole end 34b, a downhole end 34d and an inner surface 34g, and being pivotable about a dowel pin 34h that is connected to the catcher sleeve 32.
  • the inner surface 34g has an upper shoulder 34c and a lower shoulder 34e which are used to catch the dart 18.
  • the catcher fingers 34a are radially pivotable about a tangential axis of the catcher member, as shown in FIG. 3B, which allows the catcher member to either catch a dart 18 or allow the dart to pass through the catcher member.
  • the catcher fingers 34a also each have an outer tapered surface 34f at the downhole end 34d that engages the support mechanism 40, as explained in greater detail below.
  • the catcher sleeve 32 is connected to the catcher member 34 and generally comprises an uphole end 32c and a downhole end 32b, the downhole end having a plurality of rigid catcher sleeve fingers 32a spaced apart around the circumference of the catcher sleeve 32, interspersed between the pivotable catcher fingers 34a.
  • the catcher sleeve uphole end 32c is attached, preferably by a threaded connection, to the piston sleeve 24 that forms part of the seal setting mechanism.
  • the catcher spring 36 encircles a section of the catcher member 34 and the catcher sleeve 32 for biasing the pivotable catcher fingers 34a in a neutral position, wherein the catcher fingers are generally parallel with the axis of the inner cavity 50 (shown in FIG. 3A and 6B).
  • the catcher spring 36 is a collet spring that forms a collar around the catcher member 34 and catcher sleeve 32.
  • the catcher spring 36 has a plurality of fixed arms 36a interspersed with a plurality of biasing arms 36b.
  • the fixed arms are attached to the rigid catcher sleeve finger 32a by fastening means, such as screws or pins 36c operatively retained within apertures 32e in the catcher sleeve.
  • the biasing arms 36b are biased against the pivotable catcher fingers 34a.
  • the support mechanism 40 shown in FIG. 5, comprises a support member 42, a support sleeve 44, and a support spring 46.
  • the support member and the support sleeve work in conjunction with the catching mechanism 30 to support the dart 18 after it has caught.
  • Support Member 42
  • the support member 42 is similar to the catcher member 34 in that it comprises a plurality of radially pivotable support fingers 42a spaced apart around the circumference of the support member 42 that pivot about a tangential axis of the support member.
  • Each pivotable support finger 42a has an uphole end 42b with an upper shoulder 42c on the inner surface, and an outer tapered surface 42d.
  • Each pivotable support finger 42a is lined up end to end with a corresponding rigid catcher sleeve finger 32a along the longitudinal axis of the MFD, as shown in FIG. 2. The pivoting of the support fingers 42a allows a dart 18 to pass through the support member 42 if it was not caught by the catcher mechanism 30.
  • the support sleeve 44 is in operative connection with the support member 42, and has a similar structure to the catcher member 34.
  • the support sleeve 44 generally comprises an uphole end 44f and a downhole end 44b, the uphole end 44f having a plurality of rigid support sleeve fingers 44a spaced apart around the circumference of the support sleeve 44 each having an inner tapered surface 44e and interspersed between the pivotable support fingers 42a.
  • Each rigid support sleeve finger 44a is lined up end to end along the longitudinal axis of the MFD 10 with a corresponding pivotable catcher finger 34a, as shown in FIG. 2.
  • the support sleeve downhole end 44b is shearingly engaged with the lower housing 16 via at least one shear pin 52.
  • the support sleeve downhole end 44a has a circumferential groove 44c that receives the at least one shear pin 52.
  • the support sleeve 44 along with the entire support mechanism 40, catcher mechanism 30 and sealing mechanism 20, moves downhole with respect to the lower housing 16, outer housing 12 and upper housing 14 into a final downhole position, shown in FIGS. 12A to 12C.
  • the support spring 46 is similar in structure and function to the catcher spring 36.
  • the support spring 46 encircles a section of the support member 42 and the support sleeve 44, as shown in FIG. 5, for biasing the pivotable support sleeve fingers 44a in a neutral position, wherein the pivotable support sleeve fingers are generally parallel with the axis of the inner cavity 50 (shown in FIG. 5 and 6B).
  • the support spring 46 is a collet spring that forms a collar around the support member 42 and support sleeve 44 and has a plurality of fixed arms 46a interspersed circumferentially with a plurality of biasing arms 46b.
  • the fixed arms 46b are attached to the rigid support sleeve fingers 44a by fastening means, such as screws or pins 46c operatively retained within apertures 44d (shown in FIG. 6B) in the support sleeve 44.
  • the biasing arms 46b are biased against the pivotable support fingers 42a.
  • the sealing mechanism 20 generally comprises a piston 22, a piston sleeve 24 and a compressible seal 26.
  • the sealing mechanism 20 enables the sealing of a downhole section 54 of the MFD and casing or completion tubing located downhole from the seal 26, from an uphole section 56 located uphole of the seal when a dart 18 is captured to enable fracturing operations to occur.
  • FIGS. 14A, 14B and 14C are close up views of most of the sealing mechanism 20 (they do not show the entire piston sleeve 24) from FIGS. 9A-9C, 10A-10C, and 1 1 A-1 1 C, respectively, illustrating the sequence of setting the sealing mechanism.
  • the piston sleeve 24 is operatively retained within and connected to the outer housing by the at least one piston shear pin 24c (FIGS. 2 and 4) located in at least one shear pin groove 24f (FIG. 14A) .
  • the piston sleeve generally comprises an uphole end 24a and a downhole end 24b, the downhole end connected to the catcher sleeve 32 of the catcher mechanism 30, and the uphole end 24a adjacent but not connected to the upper housing 14.
  • At least one vent hole 24d exists between the piston sleeve and the catcher sleeve 32 for providing pressure to the piston 22, as discussed in more detail below.
  • the piston sleeve 24 is movable from a first uphole position, shown in FIGS. 9A-9C and FIG. 14A, to a second intermediate position, shown in FIGS. 10A-10C and FIG. 14B, to the final downhole position, shown in FIGS. 1 1 A-1 1 C and FIG. 14C.
  • the outer housing main ports 12 are covered by the piston sleeve 24 and therefore closed.
  • the piston sleeve 24 has moved downhole past the outer housing main ports 12, opening the ports 12 such that they are in fluid engagement with the inner cavity 50 in order for fracturing operations to occur.
  • the piston 22 comprises an uphole end 22a and a downhole end 22b and is operatively retained and moveable within a section of the piston sleeve 24 and the catcher sleeve 32.
  • At least one chamber 72 at atmospheric pressure or a pressure lower than the annulus pressure is provided between the piston 22 and catcher sleeve 32.
  • the compressible seal 26 is preferably a ring-shaped seal, having an uphole end 26a bordering the piston downhole end 22b, and a downhole end 26b bordering the catcher fingers uphole end 34b.
  • FIGS. 14A to 14C To stroke the piston 22 and move it downhole to compress the seal, a pressure differential is developed as shown in FIGS. 14A to 14C.
  • the piston Prior to the at least one shear pin 24c (contained within shear pin groove 24f) shearing (FIGS. 14A and 9A-9C), the piston is pressure balanced because the vent hole 24d, which provides pressure to the piston, is sealed from the annulus pressure by a seal in a seal groove 24e located between the piston sleeve 24 and the outer housing 12.
  • the at least one shear pin shears and the sealing mechanism 20 and catcher mechanism 30 move from the first uphole position to the second intermediate position, described above, and shown in FIGS.
  • the seal and seal groove 24e no longer seal, exposing the vent hole 24d to the downhole annulus pressure.
  • the chamber 72 which is at atmospheric pressure or a lower pressure than the downhole annulus pressure, remains sealed, which provides the pressure differential needed to stroke the piston 22 and cause the piston to move downhole and compress the seal, as shown in FIGS. 14C and 1 1 A-1 1 C.
  • the seal is made of rubber, such as hydrogenated nitrile butadiene rubber (HNBR), fluoroelastomer rubber (FKM) (e.g. VitonTM), or a combination of synthetic rubbers and composite material.
  • HNBR hydrogenated nitrile butadiene rubber
  • FKM fluoroelastomer rubber
  • VitonTM a combination of synthetic rubbers and composite material.
  • the compressible seal 26 is one example of a compressible element that can be compressed by the piston 22. Other types of compressible elements could be used.
  • the inner cavity 50 is continuous through the MFD from the uphole end 10b to the downhole end 10c when no dart 18 is caught by the catcher mechanism.
  • the inner cavity is comprised of the inner surfaces of the upper housing 14, piston sleeve 24, piston 22, seal 26, catcher sleeve 32, catcher member 34, support sleeve 44, support member 42 and lower housing 16.
  • Various sealing elements such as o-rings, are located between the components of the MFD to ensure the inner cavity is tightly sealed.
  • the dart When a dart 18 has been caught by the catcher mechanism 30, the dart creates a blockage in the inner cavity 50 that enables the ports 12d of the MFD to open using fluid pressure within the tubing string. Importantly, if a dart has not been captured within the catcher mechanism 30, maintaining or increasing the pressure within the tubing string and the inner cavity 50 does not enable the opening of the ports 12d.
  • FIGS. 6A to 6C illustrate the dart 18 entering the inner cavity 50.
  • the sequential process of the catcher mechanism 30 catching the dart is illustrated in a perspective view in FIGS. 3A to 3C and in a cross-sectional view in FIGS. 7A to 7F.
  • the dart 18 moves downhole such that the dart leading end 18a contacts the pivotable catcher finger uphole ends 34b, causing the spring loaded catcher fingers to pivot and allow the dart to continue moving downhole (FIGS. 7C to 7E). That is, as the dart leading end 18a moves past the catcher member upper shoulders 34c (FIGS.
  • each pivotable catcher finger 34a is pivoted radially outwards against the catcher spring 36, causing each catcher finger downhole end 34d to pivot radially inwards.
  • the dart continues to move downhole, with the dart outer surface 18e maintaining contact with the catcher finger inner surfaces 34g (FIG. 7D).
  • the biasing force from the catcher spring 36 causes the pivotable catcher fingers 34a to gradually pivot back towards the neutral position (i.e. the catcher finger downhole ends 34d pivots outward and the uphole ends 34b pivots inward) as the dart 18 progresses downhole (FIG. 7E).
  • the dart leading end 18a contacts the catcher finger lower shoulders 34e and attempts to push the fingers outwards and upwards so the dart can pass through.
  • the design of the system does not allow the catcher fingers to pivot out of the way, since the catcher finger uphole ends 34b are in contact with the dart lower shoulders 34e, thereby preventing the catcher fingers from pivoting out of the way and effectively trapping the dart. That is, the dart leading end 18a and trailing end 18c are trapped, respectively, by the catcher finger lower shoulders 34e and upper shoulders 34c. In this position, the dart has been "caught" by the catcher member 34 and provides a significant restriction in the cavity 50 of the MFD.
  • FIGS. 8A through 8F illustrate a sequence wherein the dart 18 is not caught by the catcher member 34 but instead passes through the catcher member.
  • the dart trailing shoulder 18d is positioned further towards the dart leading end 18a than in the previously referred to sequence illustrated in FIGS. 7A through 7F. In this case, when the dart leading shoulder 18b contacts the catcher finger lower shoulders 34e and forces them outwards (FIGS.
  • the catcher finger upper shoulders 34c contact the dart trailing end 18c at a location downhole from the dart trailing shoulder 18d (FIG. 8D), instead of uphole of the dart trailing shoulder as is the case when the dart is caught by the catcher fingers in the previous example (FIG. 7F).
  • This allows the catcher finger downhole ends 34d to be pivoted further outwards (FIG. 8E), allowing the dart leading shoulder 18b to pass by the catcher finger lower shoulders 34e (FIG. 8F), thus allowing the dart to pass completely through the catcher member 34.
  • the dart After the dart has passed through the catcher fingers 34a, the dart passes through the support mechanism 40 and continues downhole. Similarly, if a dart 18 has a smaller diameter than a dart that is sized to be caught by the catcher member 34, the dart would pass through the catcher fingers without being caught. Alternatively, all or some of the darts may have the same geometry and diameter, however the length, diameter, and/or inner surface profile of some or all of the catcher fingers is varied in subsequent catcher MFD's.
  • stage 1 to 10 use a 3.75" diameter dart; stages 1 1 to 20 use a 3.625" diameter dart; stages 21 to 30 use a 3.5" diameter dart; and stages 31 to 40 use a 3.375" diameter dart.
  • Stage 2 Setting of the Dart Support Mechanism
  • the catcher mechanism 30 and sealing mechanism 20 are prevented from moving beyond the second intermediate position by the abutment of the downhole end of the catcher mechanism (i.e. the catcher finger donwhole ends 34d and catcher sleeve fingers downhole ends 32b) with the uphole end of the support mechanism 40 (i.e. the support finger uphole ends 42b and support sleeve fingers uphole ends 44f).
  • each pivotable support finger 42a abuts the inner tapered surface 32d of the corresponding catcher sleeve finger, thereby causing the rigid catcher sleeve finger 32a to bear down on the pivotable support finger 42a, supporting the pivotable support finger and locking it in place.
  • Setting the dart support system has two purposes: to provide increased reinforcement to the dart 18 to prevent the dart from pushing through the catcher fingers when increased fluid pressures are applied to the system in further stages of operation, and to open a path for pressure to create a pressure differential between the uphole end of the piston 22 and the atmospheric chamber 70 in the piston, thereby allowing for setting of the sealing mechanism.
  • the creation of the pressure differential was described in more detail above with respect to FIGS. 14A-14C [0089] Stage 3) Setting of the Sealing Mechanism
  • the fluid pressure is further increased to open the ports 12d in the outer housing.
  • an increase in fluid pressure in the system causes the shear pins 52 connecting the support sleeve 44 to the lower housing 16 to break, thus releasing the sealing mechanism 20, catcher mechanism 30 and support mechanism 40 from the housing which then moves downhole as one unit from the second intermediate position to the final downhole position shown in FIGS. 12A to 12C.
  • the abutment of the downhole end 44b of the support sleeve with the lower housing inner shoulder 16b acts as a stop to prevent the sealing mechanism, catcher mechanism and support mechanism from moving beyond the final downhole position.
  • the piston sleeve uphole end 24a has moved downhole past the ports 12d, thereby opening the ports and allowing fluid and pressure communication between the inner cavity 50 and the adjacent formation 8a through the ports.
  • fracturing operations can commence in the zone of interest in the formation 8a adjacent the ports 12a. Upon completion of the fracturing operations in a particular zone, further darts can be successively introduced into the completion tubing to enable successive MFDs to be opened and fracturing operations to be completed within other zones.
  • the pressure in the completion string will be varied throughout the operation of the system to trigger the stages to occur. That is, various stages of the operation may have a threshold pressure that will enable each stage to be sequentially completed. For example, the pressure initially starts at typical fracturing circulation pressures for the type of formation being fractured, which is generally in the range of 2000 and 8000 psi.
  • the pressure may increase another 500 to 1500 psi over the circulation pressure to shear the piston shear pin 24c and move the sealing mechanism 20 and catcher mechanism 30 downhole to set the dart support mechanism.
  • the pressure may then increase another 500 to 1500 psi to stroke the piston 22 and set the seal 26, after which the second downhole shear pin 52 shears in order to open the ports 12d to allow fracturing operations to occur.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

La présente invention concerne un système et un procédé de fracturation de zones multiples dans un puits d'hydrocarbure. Le système comprend une série de dispositifs de fracturation multi-étages (MFD) qui sont raccordés le long d'un tubage ou d'un train de tubage de complétion et comportent des orifices qui peuvent être ouverts pour permettre la fracturation de la formation adjacente au MFD. Les orifices dans chaque MFD sont déclenchés pour s'ouvrir par un projectile ayant une géométrie spécifique qui est pompé au fond et saisi par un mécanisme d'accrochage qui comprend des leviers ou « doigts » dans le MFD. Lors de l'accrochage du projectile, la section de fond du projectile peut être hermétiquement fermée et les orifices situés verticalement en amont du projectile peuvent être ouverts pour permettre que des opérations de fracturation se produisent.
PCT/CA2015/050246 2014-04-01 2015-03-30 Système de fracturation à haute pression multi-étages initiée par projectile Ceased WO2015149169A1 (fr)

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CA2940852A CA2940852A1 (fr) 2014-04-01 2015-03-30 Systeme de fracturation a haute pression multi-etages initiee par projectile
US15/120,998 US20170122068A1 (en) 2014-04-01 2015-03-30 Dart-initiated multistage high pressure fracturing system

Applications Claiming Priority (2)

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US201461973346P 2014-04-01 2014-04-01
US61/973,346 2014-04-01

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WO2018148159A1 (fr) * 2017-02-09 2018-08-16 Schlumberger Technology Corporation Mécanisme à clapet et manchon pour actionnement de zones multiples
WO2019100137A1 (fr) * 2017-11-21 2019-05-31 Sc Asset Corporation Système de bague de verrouillage destiné à être utilisé dans des opérations de fracturation
US10947815B2 (en) 2017-05-02 2021-03-16 Advanced Completions Asset Corporation Tool assembly with collet and shiftable valve and process for directing fluid flow in a wellbore
US12031397B2 (en) 2018-08-03 2024-07-09 Interra Energy Services Ltd. Device and method for actuating downhole tool

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WO2017023808A1 (fr) 2015-07-31 2017-02-09 Akkerman Neil H Système de fracturation de haut en bas
CN110603369A (zh) * 2017-04-05 2019-12-20 Abd技术有限责任公司 上下压裂系统和方法
WO2020217051A1 (fr) * 2019-04-24 2020-10-29 Westfield Engineering & Technology Ltd Bouchon de puits de forage
US11352852B2 (en) * 2020-07-31 2022-06-07 Halliburton Energy Services, Inc. Shiftable covers, completion systems, and methods to shift a downhole cover in two directions

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WO2010129678A2 (fr) * 2009-05-07 2010-11-11 Baker Hughes Incorporated Configuration et procédé de siège mobile de façon sélective
WO2013053057A1 (fr) * 2011-10-11 2013-04-18 Packers Plus Energy Services Inc. Actionneurs de puits de forage, trains de tiges de traitement et procédés
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WO2018148159A1 (fr) * 2017-02-09 2018-08-16 Schlumberger Technology Corporation Mécanisme à clapet et manchon pour actionnement de zones multiples
US10316620B2 (en) 2017-02-09 2019-06-11 Schlumberger Technology Corporation Dart and sleeve mechanism for multiple zone actuation
US10947815B2 (en) 2017-05-02 2021-03-16 Advanced Completions Asset Corporation Tool assembly with collet and shiftable valve and process for directing fluid flow in a wellbore
WO2019100137A1 (fr) * 2017-11-21 2019-05-31 Sc Asset Corporation Système de bague de verrouillage destiné à être utilisé dans des opérations de fracturation
CN111433433A (zh) * 2017-11-21 2020-07-17 Sc 资产有限公司 用于压裂作业的锁定环系统
US12031397B2 (en) 2018-08-03 2024-07-09 Interra Energy Services Ltd. Device and method for actuating downhole tool

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US20170122068A1 (en) 2017-05-04

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