Patent Grant
9797228
This application claims priority from commonly-assigned/invented Canadian Patent Application CA 2,842,586, filed Feb. 11, 2014.
The present disclosure relates to the field of hydrocarbon extraction from subterranean formations and, in particular, to a combined perforating and fracking tool for hydrocarbon well completion and stimulation.
The extraction of hydrocarbons from subterranean formations involves drilling a well and undertaking completion operations to transform the drilled well into a producing one. The completion process typically involves casing the wellbore to ensure that the well does not close in upon itself. The casing is typically steel piping that is cemented into place to line the well. In order to achieve production, the casing and cement must be perforated to allow for the flow of hydrocarbons into the wellbore, but still provide a suitable amount of support and protection for the well.
Stimulation techniques have been developed to further improve the efficiency of hydrocarbon extraction. One such technique is hydraulic fracturing (“fracking”) which involves the injection of highly pressurized fracking fluids through the perforated casing and into the formation. Injection of such fluids creates small fractures/fissures that extend substantially perpendicularly outwardly from the well into the formation, through which distantly-located hydrocarbons can thereby flow into, and thus flow therealong and into the wellbore for pumping to surface.
Generally, perforating and fracking a well have involved separate processes in which a well casing is first perforated followed by the injection of high pressure fracking fluid. Processes for perforating the well casing have included, for example, running a perforation gun into the wellbore to discharge high pressure jets of fluid to penetrate the casing at various locations, or to fire “shaped” explosive charges at various intervals along the wellbore into the sides of the casing to create the perforations. Once the perforations are formed, the fracking fluid is pumped into the well to fracture the formation in the region surrounding the wellbore and preferably in outwardly extending fissures which extend perpendicularly outwardly from the wellbore. Disadvantageously, however, apart from the additional time and expense of a two step discrete process of inserting the perforating gun, perforating, and removing such perforating gun before perforating can occur, such prior art methods are further unsatisfactory, since the problem with prior art devices and methods which separately perforate the well bore with perforating “guns” which use explosive charges, withdrawing the guns, and then inserting the fracking tool, is that the fracking tool does not necessarily align with the created perforations. Such prior art methods are thus for this reason as well unsatisfactory.
Specialized tools have been described to improve the efficiency of such methods. U.S. Pat. No. 7,337,844 describes a perforating and fracturing tool that perforates the well using a jetting sub and a plurality of jets which eject high pressure fluid to perforate the well casing. The device comprises a fluid distributor which may be selectively configured to communicate high pressure fluid to supply the perforating operation or to concurrently or simultaneously communicate the high pressure fluid to supply the fracturing operation. By diverting the fluid flow, perforating and fracturing operations can be achieved while keeping the device in the wellbore.
Other tools have been described which involve mechanically perforating the well casing. U.S. Pat. No. 2,638,801 teaches a casing perforator that is attachable to a drill string in driving connection with at least one rotating drill. The casing perforator is lowered into a pipe or well casing to drill ports into the casing, and fluid under high pressure is then passed down through the drill string through the perforator and out through the drill while the drill is within the ports. Fluid is discharged through the hollow interior of the drill to hydraulic passages out into the surrounding formation. In this way, the drilling of the casing and the fracking of the formation are accomplished consecutively while maintaining the perforator in one position.
Similarly, Russian Patent No. 2069741 describes a device for mechanical perforation of wells in which a pair of hydraulically actuated puncturing units are caused to extend radially outwardly from the tool to pierce the casing. Fluid jets built within the puncturing units inject fluid through these puncturing units and into the formation to open channels therein. In this way, the device can mechanically puncture the casing while simultaneously opening channels in the formation while maintaining the device in one position.
International Patent Publication No. WO 2012/098377 describes a perforating tool that utilizes a plurality of pistons that cooperatively operate to outwardly deploy a cutter block along tracks to enable large perforations to be cut into the well casing. Once the perforations are made, the cutter block is inwardly retracted to allow the work string to be lowered in order to position a packer apparatus below the perforated section of the well casing. With the work string in this position, high pressure pumping of hydraulic fracturing fluid can be commenced to conduct a hydraulic fracturing operation.
This background information is provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention. No admission is necessarily intended, nor should be construed, that any of the preceding information constitutes prior art against the present invention.
An object of the present invention to provide a tool capable of providing the combined functions of both perforating and fracking of a wellbore, to avoid having to “trip-out” a perforating tool from a well in order to then be able to frack a well.
In a preferred embodiment, the tool has means, as described below, to allow lowering of the tool within the well when the well has fluid therein, and prevent passage uphole of downhole fluid when the tool is in the wellbore, where such downhole fluid typically contains sand. Such mechanisms of the tool of the present invention avoids and/or reduces the tendency of the tool to become “sanded in” within the wellbore and not able to be withdrawn therefrom after various perforating and fracking operations within the wellbore at various locations therein have been completed.
In one broad aspect of the tool of the present invention, a combined perforating and fracking tool for perforating a hydrocarbon well casing disposed in a formation, and for subsequently fracturing the formation while maintaining the tool in situ, is provided, the tool comprising:
(a) at least one cylinder arranged to be disposed in a well casing and adapted at an uphole end to receive fluid, said cylinder comprising a cooperating piston;
(b) a punch assembly disposed at a downhole end of said cylinder and co-operating piston, the punch assembly comprising a punch comprising a pointed piercing member for perforating the casing, wherein the punch assembly is actuated by the fluid exerting a pressure on the cooperating piston, and the cooperating piston exerting a force which causes outward extension of the pointed piercing member to perforate the casing;
(c) a fluid injection port disposed at an upper end of the tool to allow fluid to be injected into the formation through the perforations created in the well casing by the tool; and
(d) at least one sealing member disposed proximate an upper uphole end of the cylinder, downhole of said fluid injection port, adapted to prevent fracking fluid from travelling, when such tool is in a well casing, outside the cylinder in a direction downhole;
wherein fluid may be provided in a bore defined along the longitudinal axis of the cylinder; and
whereby a force is generated by fluid under pressure travelling in said bore and acting on the cooperating piston which then actuates the punch assembly to actuate, in a radially-outwardly protruding manner, said pointed piercing member to perforate the casing.
In a further refinement, the tool may comprise a plurality of sequential cylinders adapted to be disposed in a well casing and adapted at an uphole end to receive fluid, each of said cylinders comprising a cooperating piston, wherein each piston defines a bore along its longitudinal axis and an associated port for conducting fluid flow from the bore into each cylinder.
Accordingly, in a further preferred embodiment, the invention comprises a combined perforating and fracking tool for perforating a well casing disposed in an underground formation and for subsequently fracturing the formation while maintaining the tool in situ, the tool comprising:
(a) at least a pair of cylinders arranged to be disposed in a well casing and adapted at an uphole end to receive fluid, each of said cylinders comprising a cooperating piston, wherein each piston defines a bore along its longitudinal axis and an associated port for conducting fluid flow from the bore into each cylinder;
(b) a punch assembly disposed at a downhole end of the cylinders, the punch assembly comprising a punch for perforating the casing, wherein the punch assembly is actuated by a piston which outwardly extends a punch to perforate the casing;
(c) a fluid injection port disposed at the uphole end of the tool, and a valve member, to allow fluid to be diverted from the cylinders and injected into the formation through the perforations created in the well casing; and
(d) at least a pair of sealing members respectively disposed respectively at an upper and lower end of the tool, forming a seal between the casing and the tool such that fluid can be diverted through the fluid injection port for fracturing the formation;
wherein the cylinders remain isolated from the injected fluid flowing between the tool and well casing during fracturing; and
wherein during a perforation step fluid flowing through a bore defined along the longitudinal axis of tool sequentially fills each of the cylinders whereby a magnification of hydraulic force is generated by the cooperating pistons to actuate the punch.
In accordance with another aspect of the present invention, there is described a combined perforating and fracking tool for perforating a hydrocarbon well casing disposed in a formation, and for subsequently fracturing the formation while maintaining the tool in situ, the tool comprising:
(a) a series of connected cylinders arranged to be disposed in a well casing and adapted at an uphole end to receive fluid, the series of connected cylinders comprising:
(b) a punch assembly disposed at a downhole end of the series of connected cylinders, the punch assembly comprising a pointed punch member for perforating the casing, wherein the punch assembly is actuated by the first and second pistons to outwardly extend the punch member to perforate the casing;
(c) a fluid injection port disposed at the uphole end of the series of connected cylinders to allow fluid to be diverted from the series of connected cylinders and injected into the formation through the perforations created in the well casing; and
(d) at least one sealing member disposed at each end of the series of connected cylinders, each sealing member forming a seal between the casing and the tool such that fluid can be diverted through the fluid injection port for fracturing the formation, and wherein the series of cylinders remains isolated from the injected fluid flowing between the tool and well casing;
wherein fluid flowing through the second cylinder results in a force supplied by the associated piston to actuate indirectly or directly the punch assembly.
In a particular embodiment of the above aspect the valve assembly (and in particular the first cylinder thereof) comprises a slidable sleeve having a fluid passageway, and further preferentially a “J” type sleeve to allow a plurality of up and down movements of the tool prior to actuating the slidable sleeve in the manner set out below, said slidable sleeve being slidable along a mandrel on the tool at a location on the tool having radial aperture therein, said slidable sleeve on its exterior having a friction member to consistently frictionally engage the casing, wherein when the tool is lowered to a desired position downhole, upward movement of the tool thereafter and resultant frictional engagement of said friction member with said casing causes relative movement of said slidable sleeve relative to said mandrel and thus repositioning of said passageway therein so as to then become in fluid communication with said radial aperture so as to cause such valve assembly to be in an open position and allow supply of fluid to downstream pistons to thereby allow actuation of said punch.
In such above embodiment the sealing members disposed at each of the tool (but at the upper end of the tool the associated sealing member being disposed below the fluid injection port) also, on either end of the tool, advantageously prevent fluid (and any sand entrapped therein) being introduced in the wellbore area between the tool and the casing which could otherwise cause the tool to become “sanded in”. Specifically, such sealing members, preferably cup seals, are positioned and arranged on the tool so as to allow the upper seal to cause fracking fluid to flow into the formation via the created perforations in the casing during fracking and prevent such injected fluid from flowing past the tool downhole, and the lowermost cup seal prevents downhole fluids from flowing uphole past the tool during fracking and perforation operations to thereby avoid possibly entraining sand in the region of the wellbore between the tool and the wellbore, and thus the “sanding in” of the tool within the wellbore.
A selectively-operable bypass means is provided on the tool, however, to allow fluid in the wellbore which may come from perforations and fracking of the wellbore to bypass the downhole seal member so that such fluid may be displaced uphole during lowering of the tool into the wellbore. Such bypass means allows lowering of the tool in the wellbore where such lowering would otherwise be prevented by existing presence of fluid in the wellbore.
In accordance with a further aspect of the present invention, there is described a method for perforating a well casing disposed in a formation and for subsequently fracturing the formation while maintaining the tool in situ using a tool of any of the configurations described above. In accordance with such further aspect/method, such method comprises the steps of:
(a) supplying fluid to the combined perforating and fracking tool in any of the embodiments described above when such tool is disposed within a well casing, activating a valve therein so as to provide fluid flow through the series of connected cylinders and associated pistons whereby a combined force is generated by such pistons to actuate the punch assembly to form created perforations in the well casing;
(b) lowering the combined perforating and fracking tool to position the fluid injection port thereon adjacent to the created perforations in the well casing and to position the at least one sealing member downhole of the created perforations in the well casing; and
(c) pumping fluid through the fluid injection port and created perforations to fracture the formation.
A further refinement of the tool of the present invention is hereinafter described, wherein the tool allows not only perforation and fracking, but allows both perforation of the casing and fracking of the formation without having to further reposition the tool within the wellbore.
In such embodiment/refinement the tool, similar to the above-described embodiments, comprises a cylindrical member having thereon an upper and lower seal member, where the upper seal member is located below the punch assembly. In such configuration, such tool is adapted to perforate and inject fluid at a region of the tool above the upper seal member, without having to relocate the tool to allow injection of fluid in the created perforation.
Such revised configuration/embodiment of the tool allows to elimination of the otherwise necessary “up and down” repositioning motion of the tool which is necessary in the foregoing embodiments between the perforation step and the fracking step (which is necessary to position a frac port in the tool adjacent the created perforation in the wellbore casing to allow fluid injection). Thus a significant amount of time (and thus monetary expense) can be saved by elimination of this otherwise necessary repositioning of the tool within the wellbore.
In accordance with this further embodiment/refinement, a downhole tool for creating a perforation in a wellbore casing and immediately thereafter permitting injection of a fluid into a reservoir via said created perforation without having to trip out said tool from said wellbore nor reposition said tool within said wellbore is provided, such downhole tool comprising:
(a) a cylindrical member adapted at an uphole end to receive, when desired, fluid in a longitudinally-aligned bore therein, further comprising a cooperating piston;
b) a punch assembly, positioned downhole of said cooperating piston and mechanically coupled thereto, comprising a punch comprising a pointed piercing member for perforating the casing;
c) an upper cylindrical seal member positioned downhole of said punch assembly, adapted when said downhole tool is positioned in said wellbore to prevent passage downhole of fluid in an annular region between said wellbore casing and said downhole tool;
d) a fluid ingress port located on a periphery of said downhole tool uphole of said upper seal member and said punch assembly, adapted to allow fluid situated in said annular region to flow into said cylindrical member, but not into the bore therein, and to contact said co-operating piston;
e) a pressure equalization port, located uphole of said punch assembly, adapted to allow pressurized fluid from said annular region to enter said bore and contact an opposite side of said cooperating piston;
f) a shut-in valve regulating flow of liquid into said pressure equalization port and/or into said bore, which when closed prevents flow of pressurized fluid from said annular area into said bore;
g) a lower cylindrical seal member, spaced on said downhole tool downhole from said upper seal member, adapted when said downhole tool is located in said wellbore to prevent flow of said fluids in said annular region uphole; and
h) a longitudinal channel, extending intermediate said upper and lower seal members, through which fluid downhole of said lower seal member may travel uphole when said downhole tool is lowered in said wellbore;
i) a bypass port located in said longitudinal channel, intermediate said upper and lower seal members, adapted to allow, when open, said fluid downhole of said lower seal member to travel uphole and bypass said lower seal member to thereby allow insertion of said downhole tool into said wellbore; and
j) a slidable sleeve which frictionally engages said wellbore casing when said downhole tool is inserted in said wellbore casing, for opening said bypass port when said downhole tool is moved downhole in said wellbore casing and for slidably closing said bypass port when said downhole tool is moved uphole in said wellbore casing;
wherein pressurized fluid forced into said annular region and which flows into said fluid ingress port, upon closure of said shut-in valve, contacts said cooperating piston and causes radially-outward extension of the punch to thereby perforate the wellbore casing, and subsequently opening said shut-in valve allows the punch to be withdrawn from the casing and the pressurized fluid to flow into the formation via the created perforation.
In a still further refinement of the above preferred embodiment of the tool, a flushing port is provided immediately uphole of the upper seal member, which port when said tool is lowered downhole allows fluid flowing up a longitudinal channel to flush an annular region immediately uphole of said upper seal. Such flushing port and the flushing achieved thereby greatly reduces the incidence of sand impaction and thereby better allows the tool to be moved more easily uphole for further perforation and fluid injection into the formation.
In such embodiment, a longitudinal channel extends intermediate said upper and lower seals and further on opposite sides of said upper and lower seal members. The flushing port is located in the longitudinal channel, proximate to and immediately uphole from said upper seal member. In such manner, when passage of fluid is permitted in the longitudinal channel, downhole fluid may travel uphole in such longitudinal channel thereby bypassing the lower seal member and by being forced through said flushing port thereby flush the wellbore in the annular region between the tool and the wellbore immediately above the upper seal. Such region is typically prone to sand impaction, which otherwise prevents upward movement of the tool after creation of an initial perforation within the wellbore and injection of fluid (which often contains sand and proppants). The flushing port offers a significant advantage, and assists in avoiding sand impaction of such tool within a wellbore during perforation and fracking operations.
Since during the fracking step the longitudinal channel need typically be closed to allow injection of fluid into the formation via the created perforation in the casing without such fluid otherwise bypassing the upper seal and then passing downhole, in a further refinement the downhole tool further comprises a plug valve, which plug valve can when desired be closed to thereby prevent flow of fluid through the flushing port and down the longitudinal channel. In a preferred embodiment such plug valve is situated in said longitudinal channel, which plug valve becomes repositioned simultaneously with the closure of said bypass port so as to close said longitudinal channel and prevent flow of fluid therewithin.
In a further embodiment, namely a particular manner by which at least the bypass port may be opened and closed, a “j” slot is provided which cooperates with the sliding sleeve and which together allow relative movement between said slidable sleeve and a remainder of said downhole tool, and after initial upward movement of said remainder of said downhole tool relative to said sliding sleeve, thereafter allows downward movement of said remainder of said tool within said slidable sleeve to an extent to allow the sliding sleeve to cover and thereby close said bypass port.
In a still further refinement of the above embodiment, the tool may further be provided with jaw members, adapted to extend outwardly so as to engage the casing when the slidable sleeve closes said bypass port and comes into contact with the jaw members and forces them radially outwardly so as to engage the casing, to thereby maintain said slidable sleeve in a fixed position within said casing.
In a preferred embodiment of the above tool incorporating each of the above-mentioned features, the longitudinal channel extends intermediate said upper and lower seals and further on opposite sides of said upper and lower seal members respectively, and such tool further comprises:
a plug valve, situated within said longitudinal channel intermediate said first seal member and said second seal member;
a flushing port in said longitudinal channel proximate to and immediately uphole from said upper seal member, wherein when said plug valve is open and not obstructing said longitudinal channel, fluid is permitted to move uphole in said longitudinal channel and to flow out said flushing port into said annular area thereby flushing said annular area of sand in a region immediately proximate said upper seal member;
a “j” slot, regulating movement of said sliding sleeve, which allows relative movement between said slidable sleeve and a remainder of said downhole tool; and
wherein after lowering of said downhole tool in said wellbore, said “j’ slot, after initial upward movement of said tool relative to said sliding sleeve, thereafter allows downward movement of said remainder of said tool within said slidable sleeve to close said bypass port and cause said plug valve to move into said longitudinal channel and thereby close said longitudinal channel, thereby preventing fluids uphole of said upper seal member from moving uphole via said longitudinal channel.
Again, such tool as immediately above described may further comprising jaw members, adapted to be actuated when said remainder of said downhole tool is moved downhole and said slidable sleeve closes said bypass port.
In yet a further embodiment, since closure of the shut-in valve creates a closed system, wherein fluid already in the tool, such as in a region on a backside of the cooperating piston would not otherwise be able to exit and thus allow the cooperating piston to move and thus acutate the punch, in a preferred embodiment the tool may further comprise an accumulator. The accumulator is preferably positioned uphole of said punch, adapted to store fluid therein when said pressure equalization valve is closed.
In a further embodiment, to further prevent the tool from becoming sanded in and otherwise lodged in a wellbore and thus becoming incapable of being moved upwardly in the wellbore, in a further embodiment, in the alternative to being provided with a flushing port or in addition to being provided with a flushing port the tool further comprises shear means in said tool proximate to, and immediately above said upper seal member, adapted to shear upon a large uphole force being exerted on said tool to thereby allow said tool uphole of said shear means to be pulled uphole in the event said tool may becomes lodged in said wellbore. Advantageously the bulk of such tool can then be recovered from the wellbore, which would not otherwise be the case.
As in earlier embodiments, the refinement may further have a plurality of cylinders and a corresponding plurality of co-operating pistons, whereby a magnification of hydraulic force is generated by the cooperating pistons acting jointly to actuate said punch.
These and other features of the invention will become more apparent in the following detailed description in which reference is made to the appended drawings.
Definitions
Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.
As used herein, the term “hydrocarbon formation”, “subterranean formation”, or “formation”, may be used interchangeably to refer to subterranean formations that are explored and exploited for hydrocarbon resources through drilling and extraction techniques.
As used herein, the term “about” refers to an approximately +/−10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.
Completing a hydrocarbon well for production typically involves perforating the well casing to enable hydraulic fracturing techniques (“fracking”) to be used to facilitate the production the hydrocarbons flowing into the wellbore. Typically, perforating the well casing and fracking the formation are separately carried out using a variety of known techniques often requiring multiple tools and processes to be used. Thus, well completion can become inefficient and cumbersome to achieve.
The embodiments of the present disclosure provide in a single tool both perforating and fracking operability. By combining both functionalities in a single tool, hydrocarbon well completion can be achieved in a more efficient, reliable, and repeatable manner.
Perforating the Well Casing
Reference is to be had to
The combined perforating and fracking tool 10 of the present invention combines a fracking assembly 160, activation assembly 165, force-magnifying assembly 170, and punch assembly/mechanism 175 comprising mechanical piercing means 130 for piercing/perforating a casing of a well, all of which synergistically operate together to allow the single tool 10 to perforate and thereafter frack a well to thereby achieve well completion.
Referring to
At the uphole end 5 of the tool 10, the activation assembly 165 is comprised of a valve assembly 69 that operates to control activation of the perforating function of the tool 10. In one embodiment of valve assembly 69 shown in
The biasing mechanism 90 in the preferred embodiment comprises a plurality of circular washers 90 supported by a spring mandrel 100 (
As shown in
Total Hydraulic force=P*A1
where A1 refers to the area of the piston 110 within the magnifying assembly 170, and P refers to the pressure supplied to such piston 110 of area A1.
Additional pistons add to the force ultimately be applied to actuate the punch assembly. For example, additional third piston 120 will have not only the force exerted by the pressure on A2 (see
Specifically, it is contemplated that in certain embodiments additional magnifying piston assemblies may be added to the tool by inserting additional cylinders comprising such assemblies. In this way, the total force may be further increased which is applied to the perforating members. Where an additional (third) piston 120 of cross-sectional area A2 is added, in such instance the total hydraulic magnification of force F will increase as follows:
F=P*A1+P*A2
Using such above principle further successive pistons and cylinders may be added to further increase the force which is acting on pointed member end 130, if required.
Other means of increasing the force exerted by the pointed member end 150 of third piston 120 to cause extension of pointed members 130 and thereby perforation of the well casing will now occur to those of skill in the art of hydraulics.
For example, hydraulic arrangements where successive pairs of coupled pistons 1-2 and 3-4, each piston of each pair being of alternating larger and smaller respective associated cross-sectional areas A1, A2, A3, A4, where for example A1>A2, A3>A2, and A3>A4, could alternatively be used to obtain further successive increases of hydraulic pressures, where P1<P2<P3, and where P2=P1×A1/A2 and P3=P2×A3/A4. Resulting magnified pressure P3 which results from such arrangement of coupled pistons and respective cross-sectional areas produces the following magnified total force on last piston of area A5 (ie on last member 120):
F=P3×A5
or stated otherwise:
F=[P1×A1/A2×A3/A4]×A5
Referring to
In preferred embodiments, the pair of pointed perforating members 130 are connected by a biasing assembly, which in one embodiment comprises a coupling member 135 and base member 140 to inwardly retract the pair of perforating punch members 130 once the casing has been perforated, the hydraulic pressure reduced, and the punch members 130 thereafter desired to be refracted to allow the tool to be repositioned to allow perforation of the casing at another desired location.
Alternatively, instead of using a coupling member 135 and a base member 140 to bias the perforating member 130 within the tool 10 as best shown in
For example, a pair of resiliently-biased helical springs (not shown) could alternatively be used to bias the perforating members 130 inwardly when not in the actuated position, to thereby allow displacement of the tool 10 uphole or downhole to a new fracking or perforating location after the perforations have been created in the casing.
Hydraulic Fracturing of the Formation
When the perforation operation has been completed at one location along the wellbore, in one embodiment of the method of the present invention the tool 10 is simply lowered further downhole in the well. Slidable member 205 (see
Referring to
The fracking assembly 160 located at the uphole end 5 of the tool 10, is spaced apart from the punch assembly and punch port 30 located at the downhole end 15 of the tool 10, at a fixed and known distance. Accordingly, when the perforation operation has been completed, the tool 10 can simply be lowered into the well by the fixed distance to position the fracking assembly, and more specifically the fracking fluid injection ports 20, at the perforations made in the casing. In this way, the perforated sections of the casing can be located easily without the need for additional equipment such as cameras or sensors, ensuring accuracy and repeatability of the operation. The length of the tool 10, according to certain embodiments, can be adjusted to the desired operation. In one embodiment, the tool has a length of between about 2,500 to about 3,000 mm. In a further embodiment, the tool has a length of between about 2,600 to about 2,900 mm. In another embodiment, the tool has a length of between about 2,700 to about 2,800 mm.
In preferred embodiments, the tool 10 comprises at least one sealing member 40 disposed proximate an upper region of the tool 10, and a further sealing member 50 at an opposite downhole end of the tool 10 (
As shown, one sealing member 40 is located at the uphole end 5 of the tool 10, downhole of the fluid injection port 20, with the flared end oriented uphole (ref.
In certain embodiments, an additional third sealing member 45 (ref.
In one embodiment of the method of using a combined fracking and perforating tool 10 of the present invention, the process of fracking and perforating may commence from the top of the wellbore, and the tool 10 is lowered downhole an incremental desired distance, the punch members, namely the pointed perforating members 130 actuated to perforate the casing, and then tool 10 is lowered further downhole a known distance, namely the distance on the tool 10 between the perforating members and the frack fluid injection port 20, so as to position the frac port 20 over the created perforation in the well casing. Such process is successively repeated until the tool perforates and fracks along the entire length of the wellbore until the tool reaches the bottom of the wellbore, wherein the tool is then withdrawn from the well.
In the above method when the tool 10 reaches the bottom of the wellbore the perforations and fracs in the wellbore are all above the tool 10 with direct access to the formation. Ingress of fluid into the wellbore above the tool 10 may contain sand, and with the result with the possible ingress of sand tool 10 could become “sanded in”, and thus be not able to be removed from the well.
Accordingly, in an alternative embodiment of the method of using the combined fracking and perforating tool 10 of the present invention, the process of fracking and perforating may instead commence close to the bottom of the wellbore. In such method, the tool 10 is first lowered to the bottom of the wellbore, a slight distance from the bottom of the wellbore. The perforating members 130 are actuated to perforate the casing in such location. Thereafter, tool 10 is lowered further downhole a short known distance, namely the distance on the tool 10 between the perforating members 130 and the frac port 20, so as to position the frac port 20 over the created perforation in the well casing, and frac fluid supplied to frac port 20 to frac the formation at such location along the wellbore via the created perforations. Thereafter, the tool 10 is raised uphole to a desired further location for perforating and fracking, and the perforating members 130 again actuated to perforate in such location. Tool 10 again lowered the same short known distance to position the frac ports 20 over the newly-created additional perforations in the well casing, and frac fluid supplied to frac port 20 to frac the formation at such new location. The tool 10 is then further moved uphole an incremental distance, and the process repeated until the entirety of wellbore has been perforated and fracked, at which point the tool 10, now proximate the top of the wellbore, is then removed from the wellbore. In such manner, all communication between the wellbore and the formation is then below the tool 10, with the result that any potential “sanding in” problems may be avoided.
As discussed above,
Notably, however, other types of valve assemblies 69 for selectively, when desired, allowing pressurized fluid into bore 60 to actuate downhole pistons such as 110, and 120 to actuate punch mechanism 175, are possible.
Below described are three (3) further types of valve assemblies 69.
Specifically, one such other embodiment of valve assembly 69 which may be incorporated in the tool 10 of the present invention is best shown in
Another embodiment of valve assembly 69 which may be incorporated in the tool 10 of the present invention is best shown in
Second ball valve 69″ in effect acts as a redundancy, to ensure any leakage from ball valve 69′ does not inadvertently actuate punch assembly 175.
Upon supply of fluid in the direction of the “arrow” shown in
Thereafter, continued supply of pressurized fluid to second ball valve 69″, as shown in
A third embodiment 69′″ of the valve assembly 69 for the tool 10 of the present invention is shown in
A plurality of flexible curvilinear spring elements 436 are fixed about an exterior of the valve assembly 69′″, which spring elements 436 serve, when the tool is inserted in the wellbore, to frictionally engage the interior of the casing of the wellbore. Milled within the interior of sliding sleeve 400 is a slot 412, which like sliding sleeve 400, is thus laterally moveable along exterior surface of mandrel 438 and thence positionable over radial ports 404 and 406 to allow fluid communication therebetween.
In operation, due to frictional engagement of spring elements 436 with exterior of the wellbore casing, upon lowering of the tool 10 downhole within the wellbore, sliding sleeve 400 of valve assembly 69′″ will be moved so that slot 412 in sliding sleeve 400 is positioned over radial ports 404, 406, thus allowing fluid communication therebetween, and in particular pressurize fluid coming from uphole to be provided to bore 60. When tool 10 is positioned in the wellbore at a desired location for perforating the casing therein, high pressure fluid may then be supplied to the tool 10 and due to fluid communication permitted between ports 404 and 406 such high pressure fluid is subsequently then supplied to pistons 110, 120 via bore 60″ as shown in
Thereafter, flow of high pressure fluid to the tool 10 is stopped, and the tool 10 further lowered so that the injection ports 20 thereon are positioned a known short distance below the created perforations. Thereafter, tool 10 is raised the known distance to align the injection ports 20 with the created perforations, and in so raising tool 10 within the wellbore frictional engagement of the spring members 436 thereof with the interior of the wellbore casing causes a slidable repositioning of sliding sleeve 400, wherein slot 412 no longer is positioned over radial ports 404, 406 and fluid communication between them is halted, as shown in
The tool 10 may then be moved uphole to proximate a new (uphole) location for perforating the casing, and then lowered a slight distance to again reposition the sliding sleeve 400 and slot 412 therein over ports 404, 406 to re-establish fluid communication between ports 404 and 406, and the process as above repeated to conduct further perforation and fracing operations until an entire length of formation is fraced, wherein the tool 10 can then be removed from the wellbore.
Such bypass assembly on tool 10 provides for a sliding cylinder 205, positioned on mandrel 275, further having arcuate flexible spring members 436 thereon which frictionally engage the interior of the wellbore. A cup seal 50 is provided, with the cup positioned downhole to thereby permit the cup seal 50 to be biased into sealing contact with the casing when pressurized fluid attempts to enter a region between the tool 10 and well casing in a region between the upper and lower ends of the tool 10 between the sealing members 40 and 50.
In operation, when tool 10 is lowered downhole in the wellbore, sliding cylinder 205, positioned on mandrel 275, due to frictional engagement of arcuate flexible spring members 436 thereon which frictionally engage the interior of the wellbore, is caused to move uphole relative to mandrel 275, thereby opening port 251 and allowing downhole fluid which is being displaced by the lowering of the tool 10, to bypass cup seal 50 via bore 500 and pass uphole in the region intermediate the tool 10 and the wellbore, as shown in
Raising of the tool 10 in the wellbore, due to due to frictional engagement of arcuate flexible spring members 436 thereon which frictionally engage the interior of the wellbore, causes slidable cylinder 205 to be slidably repositioned on tool 10, wherein cylinder 205 then covers, and thereby closes port 251, as shown in
As may be best seen from
As best seen from
Tool 600 further comprises a cylindrical member 620 adapted at an uphole end to receive, when desired, fluid within a longitudinally-aligned bore 630 therein. Cylindrical member 620 further contains therewithin at least one cooperating piston 110, and in the embodiment shown in
One or more fluid ingress ports 631 (ref.
A pressure equalization port 605 is provided in tool 600, located uphole of said punch assembly 175. Pressure equalization port 605 is adapted to allow pressurized fluid supplied to annular region 701 to enter bore 630 and contact an opposite sides 112, 123 of respective cooperating pistons 110, 117.
A shut-in valve 604 is provided, which regulates flow of fluid into pressure equalization port 605 and/or into bore 630, which when closed prevents flow of pressurized fluid from said annular region 701 into bore 630.
Shut-in valve 604 is typically an electrically-powered valve which serves to open and close a pressure equalization port 605 and/or otherwise regulate entry of fluid into longitudinal bore 630. Shut-in valve 604 receives electrical power via wires extending within coiled tubing (not shown) to which downhole tool 600, at an upper (uphole) end thereof, is typically attached.
One such shut-in valve 604 suitable for the uses set out herein is model SS3100 Series manufactured by Spartak Systems of Sylvan Lake, Alberta, Canada. Model SS3100 has a 10,000 psi differential pressure rating. Other types of shut-in valves, as will now readily appear apparent to persons of skill in the art, may be suited or adapted for the uses described herein, where higher differential pressures may be encountered. Where higher differential pressures may be encountered in excess of 10,000 psi (which is the maximum pressure differential to which such model of shut-in valve 604 is suited), a pressure-balanced shut-in valve 604 may be used, to achieve the same purpose but not having to directly overcome such a large pressure differential. Alternatively, shut-in valves 604 having worm gears or other linear actuation means with greater mechanical advantage, or with larger linear actuation motors receiving greater amounts of electrical current, may be provided if larger pressure differentials are needed to actuate punch assembly 175 and achieve perforation of thicker casings 708.
Shut-in valve 604 in one embodiment thereof best shown in
When equalization port 605 is closed, flow of pressurized liquid into longitudinal bore 630 is blocked in the region of port 605, and fluid behind pistons 110, 117 can then flow into accumulator chamber 613 thereby compressing piston 613 and spring 614 therein. The secondary related function of shut-in valve 604 is to open the pressure equalization port 605 after the perforation step has been completed, thereby allowing spring 614 and piston 611, in absence of any differential pressure then existing, to then force fluid from accumulator 613 to allow piston 611 to return to its original position. Likewise when port 605 is opened, springs 641 and 642 force respective pistons 110 and 117 back to their original positions shown in
Reference is now to be had to
As may be seen from
A longitudinal channel 901, extending intermediate the upper and lower seal members 602, 801, respectively, is further provided, through which fluid downhole of lower seal member 801 may travel uphole when downhole tool 600 is lowered in wellbore 700.
A bypass port 251 is located in longitudinal channel 901, intermediate upper and lower seal members 602, 801, which allows, when open (see also discussion of function of plug valve 970 below), fluid downhole of lower seal member 801 to travel uphole and bypass lower seal member 801 to thereby allow insertion of downhole tool 600 into wellbore 700.
A slidable sleeve 205 is provided which frictionally engages wellbore casing 708 when downhole tool 600 is inserted in said wellbore casing 708. Slidable sleeve 205 allows for opening bypass port 251 when downhole tool 600 is moved downhole in wellbore casing 708 and for slidably closing bypass port 251 when downhole tool 600 is moved uphole in wellbore casing 708.
Operation of Refined Tool 600 Broadly Described
Upon insertion downhole of tool 600 in wellbore 700, slidable sleeve 205, due to frictional engagement of flexible spring members with wellbore casing (ref.
Upon shut-in valve 604 then being opened, fluid is then allowed to flow into bore 630 via pressure equalization ports 605. Due to equalization of pressure, fluid in accumulator chamber 613, due to pressure exerted by spring 614, pushes accumulator piston 611 downhole, thereby allowing fluid from accumulator chamber 613 to flow into rearward piston areas 651, 652 as respective springs 641, 652 force respective pistons 110, 117 back uphole (i.e. to the left in
Thereafter downhole tool 600 can be pulled slightly uphole to a new perforating and fracturing location in wellbore 700, and the above process repeated numerous times until the desired length of wellbore 700 has been both perforated and fracked. Thereafter, the downhole tool 600 can be withdrawn from the wellbore 700, and the well produced.
Advantageously, as the downhole tool 600 is drawn upwardly, downhole fluids which enter wellbore 700 due to connectively of the wellbore with the formation, are prevented from passing uphole, until downhole tool 600 is removed from the wellbore and the well desired to be produced.
Further Preferred Embodiment
At all other times, flow of fluid through the “flow-through” section would be prevented, in the manner described below, by configuring sub-components ‘S’, ‘T’, ‘U’, and ‘V’ in the manner shown in
Specifically, during lowering of tool 600 in wellbore 700, subcomponent “U” of the “flow through” section comprising sliding sleeve 205 which slides on mandrel 980 having longitudinal channel 901 therein, due to frictional engagement of spring members 436 with wellbore casing 708 and due to pin member 412 (see
When fracking and injecting high pressure fluid uphole and into annular region 701 it is then desired to prevent escape of such fracking fluid out flushing port 999 and downhole. In such circumstances the “flow through” section, and the various sub-components become configured as shown in
Specifically, using the capability of “j” slots 410, 410′, downhole tool 600 (at least the portion thereof uphole of sliding sleeve 205) is able to be moved downwardly, forcing plug valve 981 within longitudinal channels 901 on either side thereof, thereby effectively plugging such longitudinal channels 901.
In an further refinement, jaw members 988 may be provided on sliding sleeve 205. Jaw members 988 become actuated upon wedge-shaped member 988 thereof (ref.
In a further optional embodiment, shear means in said tool 600 situated proximate to and above said upper seal member 602 may be provided. Such shear means is adapted to shear upon a large uphole force being exerted on said tool to thereby allow a portion of said tool 600 immediately uphole for seal member 602 to be separated at said shear means and be pulled uphole.
In one embodiment such shear means may take the form of a structurally weakened section 990 in coupling member 991 immediately uphole of upper seal member 602, as shown in
The above disclosure represents embodiments of the invention recited in the claims. In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent that these and other specific details are not required to be specified herein in order for a person of skill in the art to practice the invention.
The scope of the claims should not be limited by the preferred embodiments set forth in the foregoing examples, but should be given the broadest interpretation consistent with the description as a whole, and the claims are not to be limited to the preferred or exemplified embodiments of the invention.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2842586 | Feb 2014 | CA | national |
| Number | Name | Date | Kind |
|---|---|---|---|
| 2214320 | Brown | Sep 1940 | A |
| 5327970 | McQueen et al. | Jul 1994 | A |
| 20030136562 | Robison | Jul 2003 | A1 |
| 20050211439 | Willett | Sep 2005 | A1 |
| 20070261852 | Surjaatmadja | Nov 2007 | A1 |
| 20110162846 | Palidwar | Jul 2011 | A1 |
| 20130175035 | Lee | Jul 2013 | A1 |
| 20130312949 | Pasvandi | Nov 2013 | A1 |
| Number | Date | Country | |
|---|---|---|---|
| 20150226032 A1 | Aug 2015 | US |
