WELLBORE SLEEVE INJECTOR AND METHOD OF USE

Abstract

Method, apparatus and a system is provided for injecting carrier sleeves into a wellbore. A selected carrier sleeve is aligned in an injector bore restricted therein from free fall and preventing a subsequent sleeve from indexing into the bore from a magazine of sleeves. The sleeve can be restricted from free fall from the bore using an annular restrictor. The selected sleeve is forcibly displaced from the injector bore into a staging bore, as part of an contiguous axial bore, that is isolated from the wellbore. The staging bore is fluidly isolated from the injector bore. The pressure in the staging bore is equalized with the wellbore and then opened to the wellbore for launching the sleeve. The staging bore can be isolated from the injection bore by valve or isolation mandrel sealably moveable within the axial bore.

Description

FIELD

Embodiments disclosed herein generally relate to the injection of actuators to downhole devices used in wellbore fracturing operations. More particularly, embodiments herein relate to apparatus and systems for introducing a plurality carrier sleeves into a wellbore.

BACKGROUND

Treatment of a wellbore includes fracturing or the introduction of other stimulation fluids to the wellbore by selectively isolating zones of interest in the hydrocarbon-bearing formation along the wellbore. Devices such as packers and sliding sleeves are used to selectively direct the treatment fluids to the selected zone. Treatment fluids, such as fracturing fluids, are then pumped down the wellbore and into the formation.

It is typically desired to stimulate multiple zones by introducing a sequence of actuators such a balls, darts, or carrier sleeves. In one technique, a completion string accessing the formation is fit with a plurality of spaced sliding sleeves that are individually and selectively actuable to open the string to the formation at the selected, isolated zone. It is known to drop a sequence of balls to selectively engage one of the sliding sleeves at the selected zone in order to block fluid flow thereat and hydraulically actuate communication to the formation. Once the selected zone has been stimulated, a subsequent ball is dropped to actuate a subsequent sleeve uphole of the previously actuated sleeve, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated.

Typically the balls range in diameter from a smallest ball, suitable to engage a small seat of the downhole-most sleeve, ranging upwardly is size to a largest diameter ball, suitable for engaging the uphole-most sleeve. A known disadvantage of ball-drop methods includes the wellbore-restricting ball seats remaining in the completion string, restricting pump rates therethrough during treatment or fracturing and production rates thereafter.

As an alternative method to dropping balls into downhole devices like sleeves or packers, carrier sleeves with balls preloaded therein can be dropped into the wellbore. The carrier sleeves for an operator are characterized by a consistent internal bore, regardless of how many carrier sleeves are sent downhole. Each carrier sleeve has an outer latch that is configured to correspond to a profile in the downhole device. Indexing the axial length or axial configuration of the latch and profile provides device selective control, each different latch/profile located at a different zone. The supported ball therein blocks fluid thereby as before to block fluid flow thereby to actuate and open a port into the selected zone uphole from the sleeve for subsequent treatment. A plurality of sleeves are required for engaging subsequent and corresponding downhole device profiles. The balls can be releasable or dissolvable for subsequent removal and clearing of the wellbore.

The use of carrier sleeves provides the treatment operator with advantages including a consistent diameter wellbore, which in turn enables larger treatment volumes, less fluid friction, a longer horizontal leg and greater production.

However, while means for injection of a multiplicity of balls is known, to date carrier sleeve have only been injected manually, one by one. At surface, the wellbore is fit with a wellhead including valves and a treatment fluid connection block, such as frac header. Treatment fluid, including sand, gels and acid treatments are injected at the frac header at high pressure an fluid rates into the wellbore. The wellhead as a generally vertical axial bore through which the carrier sleeves are introduces. As applicant understanding the convention practice, operators manually introduce sleeves to the wellbore, one by one, through a Tee-configuration. An operator isolates the Tee at a lower end from the wellhead, introduces one carrier sleeve into the Tee from an upper end. The Tee is closed in and a pumping source pressurizes the Tee before opening the lower end of the Tee to the wellhead for release of the sleeve to the wellbore below.

This operation is laborious, requires careful inventory control to release load the correct indexed carrier sleeve, and requires personnel work in close proximity to fluid lines under high pressure, high flow rates, which may be gas energized, and otherwise hazardous. Other operational problems may also occur, such as malfunctioning valves and sleeves becoming stuck in the Tee. These problems have resulted in failed well treatment operations, requiring re-working which is very costly and inefficient. At times, even re-working or re-stimulating of a well formation, after launch failure, may not be successful, which results in production loss.

There is a need for a safe and efficient apparatus and mechanism for introducing a plurality of sleeves into a wellbore.

SUMMARY

In an embodiment, tubular carrier sleeves, used for actuating compatible downhole devices in a wellbore, can be selectively injected from an injector. The sleeves are supplied from a magazine of sleeves, and injected through a fluid staging bore into the wellbore. The selected carrier sleeve is aligned in an injector bore and restricted therein from free fall by a restrictor, remaining therein until forcibly displaced by a guide rod from the injector bore into a staging bore, as part of a contiguous axial bore that is isolated from the wellbore. The sleeve or guide rod, or both, remain in the injector bore for blocking, preventing alignment of a subsequent sleeve until launch of the selected sleeve.

The staging bore is fluidly isolated from the injector bore. The pressure in the staging bore is equalized with the wellbore and then opened to the wellbore for launching the sleeve. The staging bore can be isolated from the injection bore by valve or by isolation mandrel sealably moveable within the axial bore. The isolation mandrel can include a guide rod, sealably movable therein for swabbing of the axial bore. Further, the staging bore can be pressure-equalized and the fluid level therein managed for impact protection of the components and carrier sleeves.

The magazines can be maintained at atmospheric pressure, and maintained fluidly isolated from well pressure, enabling viewing access to the carrier sleeves to confirm the selected sleeves and injection thereof. An acoustic sensor can also be provided in the system components for confirmation of carrier sleeve launch and even receipt downhole in the wellbore at corresponding sleeve-actuated device.

In one aspect, a sleeve injector is provided injecting carrier sleeves into an axial bore of a wellhead contiguous with a wellbore having sleeve-actuated devices therein. An injector head is adapted to be supported by the wellhead, the injector head having an injector bore therethrough in fluid communication with the axial bore. At least one sleeve magazine has an aperture in communication with the injector bore, each magazine storing at least one sleeve, each of the at least one sleeve magazine having an actuator operable for aligning a selected sleeve of the at least one sleeve with the injector bore. A fall restrictor is provided for preventing premature free fall of a carrier sleeve aligned in the injector bore. The restrictor can be an annular restriction in the axial bore, or an actuator operation to frictionally retain the sleeve in the injector bore.

In another aspect, a system for injecting carrier sleeves into the wellbore si provided. The sleeve injector above is operable to align a selected sleeve of the at least one carrier sleeve with the injector bore. A staging block, having a staging bore, is in communication with the injector bore and isolated intermediate the sleeve injector and wellbore for receiving the selected sleeve therein. The injector bore and staging bore form the axial bore. An upper isolation device fluidly isolates the injector bore from the staging bore and a lower isolation valve fluidly isolates the staging bore from the wellbore. A guide rod extends into an uphole end of the injector bore and is operable to displace the selected sleeve from the injector bore. A first port is in fluid communication with the staging bore for equalizing pressure between the staging bore and the wellbore. The upper isolation device can be an isolation valve or an isolation tool having a mandrel movable along the axial bore and sealable therewith.

In a method aspect, carrier sleeves are injected into a wellbore, comprising the steps of aligning a selected sleeve with an injector bore of the injector assembly and fluidly connecting the staging bore and the injector bore. After displacing the selected sleeve from the injector bore into the staging bore, the staging bore is the fluidly isolated from the injector bore. After pressurizing the staging bore, one fluidly connects the staging bore to the wellbore to drop the selected sleeve into the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a side cross-sectional view of an embodiment of a carrier sleeve injector mounted to a wellhead, illustrating a carrier sleeve loaded from a magazine into the injector bore, common with a contiguous axial bore of the wellhead over a wellbore;

FIGS. 1B through 1E are side cross-sectional views of the injector and wellhead according to FIG. 1A with the carrier sleeve at various steps of the injecting process according to FIG. 2, namely:

FIG. 1B illustrates the carrier sleeve injected into a staging block to rest upon a closed lower isolation valve;

FIG. 1C illustrates an closed upper isolation device or valve for isolating the carrier sleeve in the staging block for pressure equalization to the pressuring in wellbore below;

FIG. 1D illustrates the carrier sleeve descending into the wellbore after the lower isolation valve is opened;

FIG. 1E illustrates the lower isolation valve closed for optional bleeding of the fluid in the staging block;

FIG. 2 is a flow chart depicting the various stages of sleeve injection shown in FIGS. 1A-1E;

FIG. 3A is a side cross-sectional view of an alternative embodiment of a sleeve injector, having only a single isolation valve and an isolation tool for pressure control, a carrier sleeve loaded into the injector bore for launch;

FIGS. 3B through 3D are side cross-sectional views of the injector and wellhead according to FIG. 3A with the carrier sleeve and isolation tool deployed at various steps of the injecting process according to FIG. 4, namely;

FIG. 3B illustrates the carrier sleeve injected onto a closed lower isolation valve, the isolation tool sealing the carrier sleeve between the injector and the closed lower isolation valve;

FIG. 3C illustrates the carrier sleeve descending into the wellbore after the lower isolation valve is opened, the isolation tool continuing the isolate bore and the injector thereabove, while optionally swabbing the axial bore;

FIG. 3D illustrates the isolation tool swab retracted, the lower isolation valve closed and fluid drained from the axial bore;

FIG. 3E is a side cross-sectional view of an isolation tool for use in conjunction with the embodiment depicted in FIGS. 3A-3D;

FIG. 4 is a flow chart depicting the various stages of sleeve injection shown in FIGS. 3A-3D;

FIG. 5A is a side cross-sectional view of an alternative embodiment of a sleeve injector having a vertically-loaded magazine;

FIG. 5B is a side cross-sectional view of the embodiment of FIG. 5A showing the actuator having loaded a sleeve into the injector bore;

FIG. 6 is a close up side section view of a typical carrier sleeve in the injector bore, supported on the bore restrictor, poised for forcible injection by the guide rod; and

FIG. 7 is a schematic of a control system for selecting an active magazine of two or more magazines.

DESCRIPTION

In accordance with embodiments described herein, an injector 10 and a system is provided for selectably and sequentially injecting carrier sleeves 12 into a wellbore 14 for isolating zones of interest during wellbore operations such as hydraulic fracturing. The injector 10 is supported on, and in fluid communication with a wellhead 16. The wellbore 14 has carrier sleeve-actuated devices therein. The injector 10 can be opened to atmosphere at atmospheric pressure P1, the wellhead below being in fluid communication with the wellbore 14 at pressure P2. The wellhead 16 can include a frac head 18 for receiving treatment fluid into a throughbore 19, such as fracturing fluid, and directing same into the wellbore 14 below.

In embodiments herein, each sleeve 12 comprises a tubular member 22 having a bore-blocking ball 26 for temporarily blocking fluid flow therethrough. The ball 26 can be dissolvable to avoid a need to later drill through the ball so as to reestablish fluid flow in the wellbore. With reference to FIG. 6, a typical collet and ball-type carrier sleeve has a known length and outer diameter, each carrier sleeve having an external latch 23 corresponding to a downhole, carrier-actuated devices, such as those spaced along the wellbore for accessing various zones of the wellbore 14. Each selected carrier sleeve 12a has an outer latch 22 that corresponds to a profile in the downhole device. The carrier sleeve can include a collet 24 for spring loading the latch 23 outwardly to the device profile. The supported ball 26 therein blocks fluid from flowing thereby. The latch 23 will vary in configuration for engaging subsequent and corresponding downhole device profiles. The balls are releasable or dissolvable for subsequent removal and clearing of the wellbore.

Generally, with reference to FIGS. 1A-1E, an embodiment of a system incorporating the injector 10 comprises, the injector 10 having a magazine 30 for storing one or more carrier sleeve and, in an embodiment, a plurality of carrier sleeves 12,12 . . . .

The injector 10 has an injector head 32 having an injector bore 34. The magazine 30 is connected to the injector bore 34 for sequential deliver of the carrier sleeves 12 thereto. The injector head 32 is connected to the wellhead 16.

Upper Isolation Valve

The wellhead 16 comprises an upper isolation device, in this case a valve 40, located below the injector 10. A staging block 42, having a staging bore 44, is located between the upper isolation valve 40 and a lower isolation valve 46.

The injector bore 34, staging bore 44 and frac head bore 19 and wellbore are in fluid communication to form a common contiguous axial bore 54. The axial bore is interrupted by upper and lower isolation valves 40,46.

Continuing with FIG. 1A, injector 10 includes the injector head 32 and bore 34, the bore being connected to the magazine 30. The magazine comprises a magazine housing 60 having a sleeve storage chamber 62 for storing a linear array of carrier sleeves 12,12 . . . . The chamber 62 can be an elongated hollow body defining a laterally extending chamber having a height and a width to receive and store one or more carrier sleeves 12,12 side-by-side, in an upright orientation, and in direct communication with the injector bore 34, via a sleeve aperture 36, for delivery of carrier sleeves thereto.

For minimizing operational delays, two or more or more magazines 30,30 . . . can be installed radially about the injector head 32, all of which connect their respective chambers 62 at apertures 36 to the injector bore 34. With reference also to FIG. 7, two or more magazines 30a,30b can extend radially from injector head 32 circumferentially spaced around the injector 10, at about the same axial position to form a magazine array. Additionally, each magazine 30 can be removeably and replaceably connected to the injector head 32, or the chamber 62 can have one or more access ports for loading and reloading the magazine 30. More particularly, the magazines 30 can be removable from the injector head 32 for loading sleeve 12,12 into the storage chamber 62, such as through the aperture 36 at the open end thereof. In embodiments, multiple magazine arrays can be stacked vertically to significantly increase the number of sleeves 12 that can be applied to a frac program.

The magazine 30 can optionally comprise one or more indexing indicators, such as physical indicators or electronic sensors, to indicate carrier sleeve position, presence or injection. Alternatively, or as well, the magazines 30 can have a hatch or door for access to the chamber 62, actuable between open and closed positions, for loading sleeves 12 without need to disconnect the magazine 30 from the injector head 32. As the magazines 30 can be maintained at atmospheric pressure P1 during normal operations, a window or opening 66 (see FIG. 7) can be formed in the magazines 30, extending for substantially the length thereof to enable an operator to easily view the sleeves 12,12 stored within and their latch configuration. With a window or open access, the sleeves 12 can be further colour-coded, labelled, or otherwise possess a visual indication to allow the operator to readily determine which sleeves will be injecting into the wellbore.

The storage chamber 62, is configured to sequentially introduce sleeves 12 into the injector bore 34 for ultimate injection into the wellbore 14. A linear actuator 64 drives the linear array of sleeves 12 towards the aperture 36 and injector head 32. The actuator 64 injector can be indexed for one-by-one delivery of carrier sleeves 12, or can have individual sleeve release managed at the injector head 32 as described below. The actuator 64 can be an electric, or hydraulic, linear actuator for urging the carrier sleeves 12 to the injector bore 34. A hydraulic and/or spring-loaded ram, comprising an actuator rod 100 and a piston 102 can be located at a distal end of each magazine 30 to displace the sleeves 12. Actuator 64 can have indexed positions or simply apply a constant force on the array of sleeves 12,12 . . . such that the selected sleeve 12a at the end of the array is pushed through the sleeve aperture 36 as soon as the injector bore 34 is unobstructed. In embodiments having the guide rod 74, the rod 74 itself can be used to temporarily obstruct the sleeve aperture 36.

Actuator 64 can be operated manually or remotely. The skilled person understands that a remotely operated actuator 64 would typically comprise a double acting ram for hydraulic extension and hydraulic retraction. Each magazine can have its own hydraulics to avoid collision and ensure that the injector bore 34 is clear when required. In FIG. 1A the actuator is in line with the magazine's chamber 62 with linear extension indexing a sleeve 12 into the injector bore 34. In another embodiment, as shown in FIG. 3A, the actuator 38 can be mounted below the magazine 30 to save space, hydraulic retraction now advancing a sleeve 12.

With reference to FIG. 7, in embodiments having multiple magazines 30, a safety restraining device 110a,110b such as a pin, plate, or other device known in the art can be located at the open aperture 36 of each magazine 30a,30b respectively, or at the actuator 64, to preventing untimely actuation of an inactive magazine 30b. When it is desired to inject sleeves 12 from a particular magazine 30a, the restraining device 110 of that magazine can be disengaged. Restraining devices 110 can be manually actuated or also remotely actuated, such as by electronic or hydraulic means.

Alternatively, the actuators 64 of inactive magazines 30 can be disabled. As shown, a hydraulic interlock 112a,112b for each magazine 30a,30b, can be provided connected to a central controller 114 capable of remotely directing which magazine 30a of carrier sleeves is to be selected.

For example, once all of the programmed sleeves from a first magazine 30a (sleeves 12A-12e already launched downhole) have been injected into the wellbore W, the mechanical or hydraulic restraint 110b,112b from the second magazine 30b is released, for injection of sleeves 12j-12k. The restraint 110a for the first magazine 30a can be re-engaged, or its actuator 64 disabled at interlock 112a.

Fall Restrictor

A fall restrictor is provided to prevent premature free fall of a selected and injected carrier sleeve 12a into the staging bore. The fall restrictor restrains the sleeve 12a in the axial bore 54, such as the injector bore 34, until released. In one embodiment, the fall restrictor is an annular bore restrictor 70 positioned in the injector bore 34 below the sleeve aperture 36. In another embodiment, the fall restrictor is provided by sandwiching the selected sleeve 12a against the wall of the injector bore 34 using the actuator 64.

The annular bore restrictor 70 is provided by a resilient, partial obstruction in the injector bore 34 to prevent a selected carrier sleeve 12a from free-falling prematurely from the injector bore 34 and down the axial bore 54. Further, the bore restrictor 70 holds the sleeve in the injector bore 34 which restrains the subsequent sleeve from passing the otherwise open sleeve aperture 36. Furthermore, in embodiments implementing fluid level control in the staging bore, the restrictor reduces the impact energy of a sleeve on the sleeve itself or isolation valves 40,42 below.

The bore restrictor 70 can be a discrete element projecting radially into the bore, or an annular ring for circumferential restraint of the carrier sleeve 12. In an embodiment, the bore restrictor 70 is an annular seal such as that made of a resilient material or harder material such as polytetrafluoroethylene having a flexible cross-section to enable passage of sleeve on demand. The inner diameter of the bore restrictor 70 can be beveled or having a lip, decreasing in radius in the downhole direction. In other embodiments, further restrictors can be located further downhole, such above the staging bore 44, so as to absorb fall energy.

Additionally or alternatively, actuator 64 can maintain a lateral force on selected sleeve 12a, pushing the sleeve against a wall of the injector bore 34 to avoid free fall.

In embodiments, such as to reduce weight, the magazines 30 need not be pressure-capable, as wellbore pressure P2 is contained below the injector 10 such as through one or more isolation valves 40,46, or guide rod and bore restrictor 70, or isolation tool of FIG. 3E.

Forcible Launch

Further, a guide rod 74 can extend into the injector bore 34. The rod 74 is axially movable along at least the injector bore. The guide rod 74 can displacing the selected sleeve from the injector bore including mechanically engaging the selected sleeve to forcibly launch the selected carrier sleeve into the staging bore 44.

The guide rod 74 launches the selected carrier sleeve 12a out of the injector bore 34, past the bore restrictor 70 and forcibly displacing the sleeve 12a downhole into the axial bore 54. The guide rod is supported and axially actuated by apparatus, such as a hydraulic cylinder, mounted to and above the injector 10. When the rod 74 extends through the restrictor, a fluid seal can be established for further fluid isolation of the injector 10 from fluids F in the staging bore 44.

The guide rod 74 is fit with a guide head 76 at a distal end of the rod 74 and is configured to engage an uphole end of the selected carrier sleeve 12a. The guide head 76 can be shaped, such as a bullhead, to concentrically align and launch the selected carrier sleeve 12a along and out of the injector bore 32. The bullhead or tapered shape of the head 74 can releasably engage partially within the tubular sleeve 12a, or therearound.

In embodiments, the guide rod 74 can also serve to temporarily fill the injector bore 34, such as during launch, preventing premature sequencing of subsequent sleeves 12 into the injector bore 34.

As stated, upper isolation device or valve 40 and lower isolation valve 46, such as gate valves having respective gates 41,47, are actuable between open and closed positions. Upper isolation valve 40 is operable to isolate injection bore 34 from wellbore pressure P2 when in the closed position. When both upper and lower isolation valves 16 are in the closed position, staging bore 44 is isolated from both the injection bore 34 and the wellbore 14 and can be pressured up or down as described in further detail below. One or both of the isolation valve gates 41,47 can have a resilient surface applied to or embedded into their upper surfaces to reduce impact damage to either the selected carrier sleeve 12a, or the respective gate, upon receipt of the sleeve 12a.

Staging block 42 can further have a first fluid port 80 in communication with staging bore 44 through block valve 82. One or more pumps 84 can be connected to port 80 and configured to pump fluid into or out of the staging bore 44. The pump 84 can introduce fluid for pressurizing the staging bore 44, and for displacing a selected carrier sleeve 12a into the wellbore W. Pump 84 can also be configured to de-pressurize, or drain fluid, from the staging bore 44 in advance of receiving the subsequent carrier sleeve 12.

Alternatively, an equalization conduit 90 can fluidly connect at second port 91 into the staging bore 44 to third fluid port 93 into the portion of the axial bore 54 below the lower isolation valve 46. The location of the second and third fluid ports 91,93 straddle the lower isolation valve 46. In an embodiment, the first and second ports 80,91, both above the lower isolation valve 46, can be provided by a single port.

An equalization valve 92 can be located along the equalization conduit 90. The valve 92 is actuable between an open position (FIG. 1D) for permitting equalization of the pressure in staging bore 44 to wellbore pressure P2 and a closed position (FIG. 1A) for isolating the staging bore 44 from wellbore pressure P2.

In such embodiments, pump 84 need only be used to drain fluid F from the staging bore 44. A bleed valve 94 can also be in communication with a second port 55 formed in staging block 50 for depressurizing the staging bore 44 to atmospheric pressure P1 or for gravity drainage.

In Operation

With reference to FIG. 2, in use, at block 200 one commences the injection of carrier sleeves 12,12 . . . into a wellbore 14. With reference also to FIG. 1A, the guide rod 74 is lowered sufficiently to block magazine apertures 36. A magazine 30 is loaded, or is already loaded, with carrier sleeves and a restraining device 110, if any is removed to render that magazine active. The lower isolation valve 46 is already closed, isolating the wellbore pressure P2 from the axial bore 54. Not shown, as an intermediate step, to minimize sleeve drop energy, the upper isolation valve 40 can remain closed until the sleeve 12a is resting thereon. For FIG. 2, in this described operation, it is assume that upper isolation valve 40, immediately below the injector head 32, is already open.

At block 202, with pressure in the staging bore 44 at P1, the upper isolation valve 40 can be opened. At block 204, the guide rod 74 is raised to open the aperture 36 and admit a selected sleeve 12 to the injector bore 34. The selected sleeve 12a is prevented from free falling into the axial bore by bore restrictor 70, the sleeve blocking the aperture 36. At block 206, the guide rod 74 can be lowered and the rod head 76 engages the selected sleeve 12a, the rod and sleeve blocking the aperture.

At block 208, guide rod 74 is then actuated downwards to forcibly displace the selected sleeve 12a axially downwards, past bore restrictor 70.

The selected sleeve 12a, free falls past open upper isolation valve 40, into the staging bore 44 and onto gate 47 of upper isolation valve 46. Should rod head 74 stick to the sleeve 12a, guide rod 74 can be slightly retracted upwards to release the head 74 from the sleeve 12a, allowing it to fall into the lower isolation valve 46. Pump 84 can optionally fill the staging bore with fluid F to provide energy dampening for absorbing some of the energy of the falling sleeve 12a. Equalization valve 92 remains closed and staging bore 44 is less than wellbore pressure P2.

With reference to FIG. 1C, and at block 210, the guide rod 74 must be retracted to above the upper isolation valve 40 and gate valve 41 can be closed. At block 212, equalization valve 92 can now be opened, connecting the staging bore 44 to the wellbore 14 and pressurizing the staging bore 44 to at least wellbore pressure P2. In combination or alternatively, the staging bore 44 can be pressurized above wellbore pressure P2 by operating pump 84 to introduce additional fluid F and pressure therein.

With reference to FIG. 1D, lower isolation valve 46 can then be actuated to the open position at block 214 to allow selected sleeve 12a to fall into the wellbore 14. Selected sleeve 12a can fall by gravity or be assisted downhole by displacement fluid F from pump 84, and thereafter by fracturing fluid flowing into the wellbore 14 from the fracturing inlets of the frac head 18 therebelow. At block 216, the displacement fluid F from pump 84 can also act to purge the axial bore 54 below fluid port 80 of sand and other debris. In cold weather conditions, methanol or other suitable fluids could also be introduced into axial bore 54 by pump 84 to avoid freezing of wellhead components.

With reference to FIG. 1E, once the sleeve 12a′ has been injected into the wellbore 14, and at block 218, gate 47 of lower isolation valve 46 can be actuated into the closed position. At block 220, the staging bore 44 can be depressurized by removing fluid F therefrom via port 80, or via bleed valve 94 until the staging bore 44 is at about atmospheric pressure P1, such that it is ready for safe opening of the upper isolation valve 40 back to block 202, and further sleeve injection operations for subsequent sleeves 12.

Upper Isolation Tool

In alternative embodiments, with reference to FIGS. 3A-3E, upper isolation device, which is a valve 40 in the embodiment of FIGS. 1A-1E, can be replaced by an upper isolation tool 300 of FIG. 3E. The upper isolation device, used to separate the staging bore 44, from the injector bore 34, is now provided by an isolation tool 300. A tubular mandrel 302 is fit with seals 304 at a lower end thereof to form a movable seal along the axial bore 54. The seals 304 seal the annulus formed between the mandrel 302 and the axial bore 54. The seals 304 are suitable to restrain wellbore pressure P2 forming a dP thereacross. The guide rod 74 extends sealably through a bore of the isolation tool 300. The guide rod 74, mandrel 302, and seals 304 form a pressure plug in the axial bore 54.

The mandrel 302 seals against axial bore 54 to prevent wellbore pressure P2 and fluids from reaching the carrier sleeves 12 stored in injector 10. The lower isolation valve 46 remains located below staging block 42. The guide rod 74 and mandrel 302 can be independently actuated. Additionally, the guide rod 74 can also be fit with a swab cup 306, located at head 76 and sized swab the axial bore 54.

Operations

With reference to FIG. 4, and with reference to FIG. 3A, at the commencement of sleeve injection operations at block 320, lower isolation valve 46 is in the closed position and the mandrel 302 and guide rod 74 are both in starting positions in which the mandrel 302 obstructs the aperture 36 of the active magazine 30. The mandrel 70 and guide rod 62 can both be retracted upwards such that aperture 36 is temporarily unobstructed, thereby allowing a selected sleeve 12a to be introduced at block 322 into injector bore 34 by actuator 64 of the active magazine 30. As above, sleeve 12a is kept from falling by bore restrictor 70 and/or the restrictive frictional force of actuator 38. At block 324, the mandrel 302 and guide rod 74 are positioned to engage the sleeve and block the aperture 36.

Referring now to FIG. 3B, the mandrel 302 and guide rod 74 are then co-actuated downwards at block 326 such that rod guide 74 forcibly displaces the selected sleeve 12a axially downwards past bore restrictor 70 such that it free falls into the staging bore 44, resting on gate 47 of lower isolation valve 46. The mandrel 302 is positioned in the axial bore 54, below the injector 10 such that seals 304 isolate the magazine 30 from fluids and pressure below. The mandrel 302 then acts equivalent to an upper isolation valve as set forth in the previous embodiment. The staging bore 44 is pressurized to or above wellbore pressure P2.

Turning to FIG. 3C, at block 330, isolation valve 46 I opened to allow the selected sleeve 12a to fall into the wellbore 14. With mandrel 302 remaining in the sealing position below the injector 10, guide rod 74 can be actuated downwardly at 332 to ensure that carrier sleeve 12a has been successfully injected into the wellbore 14. The mechanical launch can be used as well as, or instead of, displacement fluid F. At block 334, the guide rid 74 can be further lowered below the lower isolation valve 46 so as to swab the axial bore 54 with swab cup 306, clearing the axial bore 54 of any sand and other debris.

Turning to FIG. 3D, and at block 336, guide rod 74 is retracted above the lower isolation valve 46 and at block 338, gate 47 is closed. Again in the resetting sequence, at block 340, the bore 44 of the staging block 42 is depressurized as described above. Thereafter, returning to FIG. 3A, the mandrel 302 and guide rod 74 can be retracted upwardly to their respective starting positions at block 322 to prepare for the injection of a subsequent selected sleeve 12.

At block 334, the swabbing of the bore 54 by guide rod 74 can replace the optional step of pumping displacement fluid F into the bore 54 to aid in launch and clear debris. However, the pumping of displacement fluid F is still desirable for more thorough debris clearing and, particularly in cold-weather conditions, to introduce methanol or other suitable fluids to prevent freezing of components.

Debris in the wellbore 14 can compromise the radial profile in the downhole device that a carrier sleeve 12 is intended to couple with. If the radial profile is sufficiently impeded, the carrier sleeve 12 can travel by the downhole device and therefore fail to isolate the desired stage.

In embodiments, prior to introducing a selected sleeve 12a into the axial bore 54, a gel slug other material suitable for swabbing the bore 12 can be introduced into the staging block 42 via port 80 and pumped downhole. The swab plug can purge sand and contaminants that may impede the sleeve 12a as it travels to the target device's radial profile for removing contaminants therefrom. For example, fracturing pumpers can pump a base gel through the frac head 18 and pump 84 can pump a burst of gel activator to create a viscous gel slug that travels down the wellbore 14.

In other embodiments, with reference again to FIG. 3D, an acoustic detection device/sensor 305 can be used on upper wellhead structure or lower isolation valve 46 as shown for receiving signal emanating from downhole, the signal indicative of the actuation of the target device, such as the opening of a sliding sleeve. Further, the detection device 305 can receive a signal when the selected sleeve 12a strikes one or more valve gates 47, as an indicator to communicate to an operator that the sleeve 12a had been successfully introduced into the axial bore 54.

Vertical Magazine

With reference to FIGS. 5A and 5B, in an alternative embodiment, a generally vertical magazine 530 is oriented generally vertically so as to enable gravity feeding of carrier sleeves 12 from the magazine 530 sequentially to an actuator for injection.

In FIG. 5A a single carrier sleeve has being indexed from the vertically-loaded magazine 630 into an actuator bore 534 as a selected sleeve 12a. In FIG. 5B, an actuator has introduced the selected sleeve 12a into the injector bore 34.

An actuator block 532 comprises the actuator bore 534, coupled to the injector head 32, the actuator bore receiving sleeves 12 from magazine 530 and introducing them into the injector bore 34. Again, communication is established between the actuator bore 534 and injector bore 34 via the sleeve aperture 36 at the injector bore 34. Communication between the actuator bore 534 and a storage chamber 540 of the vertical magazine is via a magazine aperture 542. Actuator 64 can be located at a distal end of the actuator block 532. The actuator 64 includes push piston 552, located inside the actuator bore 534, and a rod 554 extending through the actuator bore's distal end. The actuator 64 reciprocates the piston 552 between two positions, a retracted, loading position to permit a single sleeve 12 to fall through the magazine aperture 542 into the actuator bore 534, and an extended, injecting position to deliver the selected sleeve 12a to the injector bore 34.

With reference to FIG. 5B, in the extended position, one can better view the shape of piston 552, which is configured to have a trailing piston skirt 560, that partially obscures the magazine aperture 542 when in the extended injecting position to prevent a subsequent sleeve 12 from falling into the actuator bore 542.

The structure of the generally vertically or inclined magazines 530 for gravity dispensing can be generally be tubular. Each magazine 530 can also have a hatch or door, for example at a upper distal end, opposite the lower magazine aperture 542, actuable between open and closed positions for loading sleeves 12 without disconnecting the magazine 530 from the actuator block 532. As with the horizontal magazines 30 of FIGS. 1A and 3A, one or more restraining devices, such as pins, plates, or any other device known in the art, can be used adjacent the aperture 542 in inactive magazines 530 to prevent said sleeves 12 therein from falling into the actuator bore 534.

Generally, the configuration of the carrier sleeve, known as collet and ball, ball-on-seta collet systems, are tubular, the diameter and length of which are quite standard. The diameters are within a small range of variation due to the standardization of casing strings and wellheads. The magazines 30, 530 can therefore also be standardized or alternatively provided in dimensions specific to a completions operator's sleeve specifications. As the injector bore to wellhead is standardized, and particularly for atmospheric magazines, various slightly different sized magazines can be replaceably fit to the same injector head 32.

Claims

1. A sleeve injector for injecting carrier sleeves into an axial bore of a wellhead contiguous with a wellbore having sleeve-actuated devices therein, comprising: an injector head adapted to be supported by the wellhead, the injector head having an injector bore therethrough in fluid communication with the axial bore;at least one sleeve magazine has an aperture in communication with the injector bore, each magazine storing at least one sleeve, each of the at least one sleeve magazine having an actuator operable for aligning a selected sleeve of the at least one sleeve with the injector bore; anda fall restrictor for preventing premature free fall of a carrier sleeve aligned in the injector bore.

2. The sleeve injector of claim 1 further comprising a guide rod, the rod extending moveably through injector bore for forcibly launching the selected sleeve past the fall restrictor.

3. The sleeve injector of claim 2 wherein the guide rod extends into the injector bore for blocking subsequent sleeves from aligning with the injector bore.

4. The sleeve injector of claim 1 wherein the fall restrictor is an annular restrictor located in the injector bore downhole from a furthest downhole magazine of the at least one sleeve magazine for preventing free fall of the selected sleeve thereby.

5. The sleeve injector of claim 4 further comprising a guide rod, the rod extending moveably through the injector bore for forcibly launching the selected sleeve past the bore restrictor.

6. The sleeve injector of claim 1, wherein the at least one sleeve magazine is removeably connected to the sleeve injector.

7. The sleeve injector of claim 1, wherein the at least one sleeve magazine has at least one indicator for indicating successful alignment of the selected sleeve with the injector bore.

8. A system for injecting carrier sleeves into a wellbore, comprising: a sleeve injector having an injector bore and configured to store at least one carrier sleeve in at least one magazine and operable to align a selected sleeve of the at least one carrier sleeve with the injector bore;a staging block having a staging bore in communication with the injector bore and located intermediate the sleeve injector and wellbore for receiving the selected sleeve therein, the injector bore and staging bore forming an axial bore;an upper isolation device for fluidly isolating the injector bore from the staging bore;a lower isolation valve for fluidly isolating the staging bore from the wellbore;a guide rod extending into an uphole end of the injector bore and operable to displace the selected sleeve from the injector bore; anda first port in fluid communication with the staging bore for equalizing pressure between the staging bore and the wellbore.

9. The system of claim 8, further comprising an equalization conduit about the lower isolation valve for fluid communication between the staging bore and the wellbore.

10. The system of claim 8, further comprising a pump for selectably introducing fluid into the staging bore or removing fluid from the staging bore.

11. The system of claim 8, wherein the upper isolation device is an upper isolation valve.

12. The system of claim 8, wherein the upper isolation device is an upper isolation tool comprising a mandrel having at least one annular seal for sealing within the axial bore.

13. The system of claim 12, wherein the upper isolation tool further comprises a guide rod extending movably through a bore of the mandrel and sealable therein.

14. The system of claim 12, wherein the guide rod comprises an annular swab at a sleeve end of the guide rod for swabbing the axial bore.

15. The system of claim 8, further comprising a fall restrictor located downhole from a furthest downhole magazine of the at least one sleeve magazine for preventing freefall of the selected sleeve thereby.

16. A method for injecting carrier sleeves into a wellbore, comprising: aligning a selected sleeve with an injector bore of the injector assembly;fluidly connecting the staging bore and the injector bore;displacing the selected sleeve from the injector bore into the staging bore;fluidly isolating the staging bore from the injector bore;pressurizing the staging bore; andfluidly connecting the staging bore to the wellbore to drop the selected sleeve into the wellbore.

17. The method of claim 16, wherein the displacing the selected sleeve comprises mechanically engaging the selected sleeve to forcibly launch the selected carrier sleeve into a staging bore.

18. The method of claim 17, wherein the mechanically engaging the selected sleeve to forcibly launch the selected carrier sleeve further comprises extending a guide rod into the injection bore for displacing the selected sleeve and blocking the injection bore to prevent the aligning of a subsequent carrier sleeve.

19. The method of claim 16, wherein the fluidly isolating of the staging bore from the injector bore comprises sealing the axial bore between the staging bore and the injector bore with an upper isolation valve.

20. The method of claim 16, wherein the fluidly isolating of the staging bore from the injector bore comprises inserting an isolation tool mandrel into the axial bore between the staging bore and the injector bore.