Fracking tool further having a dump port for sand flushing, and method of fracking a formation using such tool

A tool for fracking a formation at spaced intervals, which has an actuatable “dump” port to flush an annular space surrounding the tool when in a wellbore to thereby flush sand and reduce tendency for “sanding-in” of the tool in the wellbore. An uphole and downhole packer is provided, intermediate of which is a frac port. The dump port is located uphole thereof. Locking jaw members and a ‘j’ slot subassembly downhole of both the dump port and frac port are together used to set and unset the tool in the wellbore. A slidable sleeve opens and closes the dump port, which sleeve may be actuated by movement of the tool in the wellbore or alternatively by an actuating tool inserted in the bore of the tool. A method of carrying out fracking of the formation and flushing of the tool after each fracking operation is further disclosed.

FIELD OF THE INVENTION

The present invention relates to a downhole tool for fracking an underground hydrocarbon formation. More specifically, the present invention relates to a tool which has a dump port in place of a perforating jet which tool allows successive flushing of an annular region surrounding the tool after each successive fracing operation carried out by the tool, to thereby avoid sanding in of the tool within the wellbore after each fracking operation. A method of fracking employing such tool is further taught.

BACKGROUND OF THE INVENTION AND DESCRIPTION OF THE PRIOR ART

The below provided background information and description of prior publications 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 below publications and information provided constitutes prior art against the present invention.

In order to prepare a cased wellbore drilled in a hydrocarbon formation for production, such cased wellbore first needs to be perforated along portions of its length in order for hydrocarbons to flow into such wellbore for pumping to surface.

Prior art apparati and methods for creating perforations in the wellbore casing have typically comprised placing a string of explosive charges, namely shaped charges adapted to explode radially outwardly, within and along a length of the wellbore, and igniting such charges and thereafter withdrawing the perforating string from the wellbore.

Other methods and apparati for creating perforations along a wellbore have involved insertion of a tool having one or more nozzles, adapted to direct radially outwardly therefrom an abrasive fluid under high pressure. Such abrasive high pressure fluid impacts the wellbore casing and due to its abrasive nature, cuts a hole or holes in the wellbore casing. Such tool is moved along the wellbore casing to create additional perforations in such wellbore along a desired length thereof.

Typically, after a wellbore has been perforated, as a means to increase the rate and volume of production from the formation prior to commencing production therefrom a fracking fluid (typically containing proppants, acids, diluents, and/or other flow-stimulating additives) is injected under high pressure into the wellbore in a fracking operation. Typically only portions of a wellbore are “fracked” at a time, requiring a zone of a wellbore that is to be fracked to be isolated from other regions of the wellbore, typically by rubberized packer elements which are actuated by hydraulic pressure.

In such fracking operation, when a particular one or number of perforations along a wellbore are isolated by packers, a high pressure fluid is flowed into the wellbore and thus into the formation in the region of the perforation(s). Such high pressure fluid creates fissures within the formation. The created fissures (typically lines of fracture within the formation) generally emanate radially outwardly from the wellbore and thereby create flow channels in the formation which lead to the wellbore, thereby assisting hydrocarbons to subsequently flow into and be collected by the wellbore.

Unsatisfactorily however, no tool exists that is able to both perforate using abrasive jets, as well as carry out fracking operations without having to use separate tools and trip the tool out, in an effective and efficient manner.

U.S. Pat. No. 4,781,250 to McCormick et al., entitled “Pressure Actuated Cleaning Tool” teaches a downhole tool for cleaning tubing, casing and flow lines with pressurized cleaning fluid pumped through coiled tubing. The cleaning tool is rotated by a “J”-slot indexing tool, which activated by fluid pressure changes and a spring, to effectively rotate the tool 360°. McCormick et al does not, however, disclose any apparati or method on the same tool for further being able to carrying out fracking of the formation via the perforations created by such same tool.

U.S. Pat. No. 7,963,332 to Dotson, entitled “Apparatus and Method for Abrasive Jet Perforating”, teaches a device using an abrasive jet for perforating, with a mechanical locating collar. Such patent however does not teach any sliding sleeve to open and close the perforating jet, nor does it teach use of such perforator jet, in combination with a packers, a bypass, a “j” slot used to set and release a setting tool, and frac ports, all incorporated into and for use by the same tool to permit both perforating and fracking using the same tool.

Likewise, and to similar effect, U.S. Pat. No. 8,757,262 similarly to Dotson, entitled “Apparatus and Method for Abrasive Jet Perforating and Cutting of Tubular Members”, teaches an abrasive jet perforating tool, coupled rotatably to a tubing string, and a horizontal indexing tool coupled thereto. An extension tool with a protective sleeve is used to protect the apparatus. Again, however, such patent fails to disclose any apparati or method on the same tool for further being able to carrying out fracking of the formation via the perforations created by such same tool.

U.S. Pat. No. 5,765,756 by Jordan et al., entitled “Abrasive Slurry Jetting Tool and Method” teaches an abrasive jet perforating tool with telescoping jet nozzles. The jetting nozzles are operated perpendicularly to the longitudinal axis of the tool body, although the nozzle assemblies can pivot back into the tool body for retrieval back up the wellbore. Jordan et al similarly fails to disclose a single tool with further components which allow not only perforation but also setting of the tool to frac as well as perforate, or a method by which fracking and perforation using an abrasive jet may be accomplished by a single tool.

Accordingly, a clear need exists in the wellbore completion industry for a tool which uses abrasive jetting to create perforations in wellbore casings, and which may further accomplish fracking of the formation using the same tool, to thereby save time and speed completion of wellbores in preparation for hydrocarbon production therefrom.

A clear and serious need further exists in fracking operations to provide a tool which is not prone to becoming “sanded-in” within the wellbore. In this regard, a “sanded-in” fracking tool at the end of a frack string cannot be removed after fracking to thereby allow oil production to commence from the completed well.

Specifically, it has been found that fracking tools at the end of a fracking tubing string and which are typically lowered to the bottom of a wellbore and thereafter moved upwardly to successively frac the formation along the wellbore during such upward movement, may frequently, due to the introduction of fracking sand within a fracking mixture at each fracking interval to thereby “prop” open the fractures created in the wellbore to allow better flow of oil, cause the fracking tool becoming “sanded in” within the wellbore and the frac string thus be unable to be removed from the wellbore.

This is a very serious and potential problem if it occurs, as no production of oil can thereafter be achieved. The fracking string will then need to be pulled up with such force that it will break, and a milling tool re-inserted down the wellbore to mill out any remaining sand-entrapped components of the frack string remaining in the well, to thereby clear the well for production.

Obviously, ‘sanding-in’ of fracking tools is a very serious problem as it results in significant lost production time, to say nothing of the time resulting lost time and expense of having to mill out damaged and “sanded-in” frac string components.

A very serious need thus exists for a fracking tool which is able to reliably or better prevent “sanding in” of the tool after one or more successive fracking operations along a wellbore.

SUMMARY OF THE INVENTION

It is thus an object of one aspect of the invention to provide a frac tool which is adapted to successively frac a wellbore along its length, but is further provided with means to avoid the fracking tool becoming sanded-in after a particular fracking operation along the wellbore.

Accordingly, in one particular aspect the present invention provides a downhole tool which not only successively fracs at spaced intervals along a perforated wellbore, but is further provided with what is figuratively referred to herein as a “dump valve” which may be opened, if desired or considered necessary, to allow flushing of an annular space surrounding the frac tool with a flushing fluid after every successive frac operation carried out, so as to reduce the risk of the fracking tool, and thus the frac string, from becoming “sanded-in”.

More particularly, the present invention in a third embodiment thereof comprises a downhole tool for injecting a fluid into a hydrocarbon formations at various spaced intervals along a wellbore and further having capability to flush an annular space around the tool after each interval of injection of said fluid into the hydrocarbon formation, comprising:(i) an elongate substantially cylindrical member, having a hollow bore and an outer periphery, adapted for insertion in a wellbore;(ii) an uphole cylindrical, hollow slidable sleeve within said bore;(iii) a dump port, situated in said outer periphery, configured to direct a stream of fluid radially outwardly from said tool into an annular space between said tool and the wellbore, fluid communication of said dump port with said annular space allowed and prevented by slidable movement of said uphole slidable sleeve;(iv) an uphole packer member, situated on a portion of said periphery downhole of said dump port;(v) a downhole packer member, situated on a portion of said periphery downhole of said uphole packer member and spaced apart therefrom;(vi) a frac port in said periphery of said cylindrical member, intermediate said uphole and said downhole packer members;(vii) a slidably moveable guide member, having radially protruding slip members thereon, said slip members configured to frictionally engage said wellbore casing when said tool is inserted therein, said guide member situated on said tool downhole of said downhole packer member, said guide member further having radially expandable jaw members on an uphole side thereof; and(viii) a ‘j’ slot subassembly within said tool, situated downhole of said downhole packer member, and having an associated cylindrical hollow mandrel with a slotted profile therein, said ‘j’ slot subassembly, when downward force is applied to said tool and said guide member frictionally engages said wellbore casing, does not allow further relative downward movement of a lower portion of said downhole packer member relative to said guide member and thus does not allow said jaw members to become actuated, and said ‘j’ slot sub-assembly when an upward pulling force is applied to said tool and thereafter a downward force is re-applied to said tool, is then in a ‘set’ position where said lower portion of said downhole packer member is allowed further downward downhole movement to allow said lower portion of said downhole packer member to be forced against said jaw members so as to expand them radially outwardly to engage said wellbore casing; andwherein slight upward movement of the tool after said tool has been configured in said ‘set’ position within said wellbore causes said slidable sleeve to uncover said dump port and allow a flushing fluid to be delivered via the bore of said tool to said annular space.

Preferably, the uphole slidable sleeve is adapted to be slidably moved so as to uncover said dump port when the guide member and the outer periphery possessing the dump port remain stationary at a specific location within said wellbore and a portion of the tool uphole of the dump port and including the slidable sleeve is raised uphole.

Alternatively, the uphole slidable sleeve is adapted to be moved so as to uncover the dump port by a pick-up tool insertable within said bore of said tool.

In a refinement of this third embodiment, the tool is provided with an annular cup seal on the periphery of said tool intermediate the dump port and the said downhole packer member, which reduces flow of abrasive pressurized fluid and associated wellbore casing cuttings downhole.

In a further refinement, an expandable chamber and associated piston member is provided, wherein the chamber is adapted to receive fluid under pressure from the bore and cause the associated piston member, when the fluid is supplied to said bore, to compress and outwardly expand said uphole packer member;

In a still-further refinement, the tool possesses a bypass port in the periphery to allow bypass of fluid in the wellbore so as to circumvent the packers, when repositioning the tool. The bypass port is preferably situated uphole of the downhole packer, configured when open to provide fluid communication between an exterior of the tool and the hollow bore thereof and permit fluid exterior to said tool and above the downhole packer member to flow into said hollow bore; and

a slidable valve member which slidably opens and closes the bypass port; and

wherein when an upward force is exerted on said tool the slidable valve member is in an open position thereby keeping open said bypass port, and

wherein subsequently actuating the ‘j’ slot to the ‘set’ position by subsequent downward force on the tool and/or fluid pressure being further applied to the hollow bore uphole of the slidable valve member, the slidable valve member moves to a closed position thereby closing the bypass port.

In a still further refinement, the bore of the tool, in the region of said frac port, is provided with a deflector to deflect fracking fluid out the frac port.

In a fourth embodiment, the invention relates to a method for fracturing a hydrocarbon formation by injecting a pressurized fracking fluid containing said into said formation and repositioning such tool at various spaced intervals along a wellbore, which advantageously provides for a flushing step immediately prior to repositioning the tool for another fracking operation at a further uphole site along the wellbore.

Accordingly, in such embodiment of the present invention the method comprises the steps of:

(i) running said tool, which possesses a hollow bore in the region of a dump port and a frac port thereon, into said wellbore to a desired depth within said wellbore;

(ii) pulling upwardly on said tool to configure a ‘j’ slot on said tool from a “running” position of step (i) to a “pulling” position and positioning an uphole and downhole packer member situated on said tool on mutually opposite sides of a region along said wellbore which is desired to be fracked;

(iii) pushing slightly down on an upper portion of said tool to cause said ‘j’ slot to allow movement of a portion of the tool wherein jaw members on said tool are forced against said wellbore and a downhole packer member on said tool is longitudinally compressed and caused to expand radially outwardly, so as to configure said tool in a “set” position;

(iv) injecting said pressurized fracking fluid into said wellbore and into a bore of said tool and causing said pressurized fluid to pass via a frac port in said tool into fissures created in said formation extending radially outwardly from said wellbore;

(v) ceasing supply of said pressurized fracking fluid to said bore of the tool;

(vi) pulling upwardly on the tool to disengage the jaw members and re-configure the ‘j’ slot into said “pulling” configuration, and simultaneously causing a slidable sleeve covering said dump port to move so as to uncover said dump port; and

(vii) providing a flushing fluid not containing sand to the hollow bore of the tool and causing said flushing fluid to be expelled from the bore of the tool via the dump port and thereby flushing an annular space between the wellbore and the tool with said flushing fluid, and

(viii) thereafter pulling the tool further uphole for further subsequent injection of pressurized fluid containing sand into additional fissures created in the formation.

In a refinement of the above method, such method further comprises the step, at the time of performing step (iv) and injecting said pressurized fracking fluid into said bore, of causing a piston member in said tool to longitudinally compress an uphole packer member on said tool and cause said uphole packer member to expand radially outwardly.

In a still further refinement of the above method, step (iii) further comprises the step, when pushing downwardly on a portion of the tool uphole of the downhole packer, of closing a bypass port to thereby prevent the otherwise bypass of frac fluid downhole.

Alternatively, step (iv) may instead further comprise the step, when supplying pressurized fluid to said bore of said tool, of closing a bypass port to thereby prevent the otherwise bypass of frac fluid downhole.

Lastly, in a still further refinement of the above method, step (vi) of causing the slidable sleeve covering said dump port to move so as to uncover said dump port comprises the step of inserting a pick up tool within said wellbore and said bore of said tool to move said slidable sleeve uphole to a position uncovering said dump port.

DETAILED DESCRIPTION OF SOME PREFERRED EMBODIMENTS

In the following description, similar components in the drawings figures are identified with corresponding same reference numerals.

FIG. 1andFIGS. 2A, 2B, 3A, 3B, 4A, 4Btogether illustrate one embodiment of the downhole tool10of the present invention, withFIG. 1depicting the tool10separated into three individual segments for illustrative purposes only, with remainingFIGS. 2A, 3A, and4A showing an upper portion of the same tool10in three successive stages of operation (as hereinafter further explained), with correspondingFIGS. 2B, 3B, and 4Bshowing the lower portion of the same tool10in the same three successive stages of operation.

As may be seen, tool10is adapted for insertion in a wellbore casing (not shown), and comprises an elongate substantially cylindrical member20. Cylindrical member20possesses a hollow bore16for receiving pressurized abrasive fluid and a frac fluid (which in one particular embodiment, as mentioned above, may be one and the same fluid), and further possesses an outer periphery17. A cylindrical hollow slidable sleeve14is positioned within bore16, adapted for longitudinal slidable movement along bore16in a reciprocating manner.

One or more jet ports18are provided in outer periphery17which are configured to direct a stream of pressurized abrasive fluid, typically a fluid containing quantities of sand and/or silica granules, radially outwardly from the tool10, for impacting and creating perforations in a surrounding wellbore casing. Jet ports18, typically two or more being located at a similar longitudinal position along cylindrical member20as shown inFIGS. 2A-4A and 6A-8A, typically comprise jet nozzles18′ of hardened steel having an single aperture therein, which are thread ably inserted into periphery17of tool10and are retained in periphery17by threaded bosses19.

In one preferred embodiment the diameter of an exit aperture in each jet nozzle18′ is 0.0241 inches (0.61 mm) for creating perforations in the wellbore casing of similar size. At pressures of approximately 3,000 psi (20,685 kPa), with production wellbore casing thicknesses of ¼ inch (6.35 mm) (Schedule 20) carbon steel for a nominal 8.625 inch (193 mm) o.d. casing, with fine silica sand of 20-40 API mesh size (0.84-0.42 mm) (i.e. diameter less than 0.241 inch) and three nozzles, the penetration time using a jet nozzle18′ will take in the range of 30 seconds to create a perforation of desired size in the casing. A similar time to perforate a wellbore casing exists when the casing is of cement as opposed to carbon steel.

The size of perforations desired to be created in wellbore casing (which is in turn dependent upon, inter alia, the characteristics (temperature, viscosity, and physical properties of the actual hydrocarbons which are being recovered from the underground formation) will determine the size of the aperture of each nozzle18″. Typically two, and up to four, jet nozzles18′ will be located at a similar longitudinal position on periphery17of cylindrical member20. For optimum adaptability of tool10, threaded bosses19on periphery17to tool10in which the jet port nozzles18′ are threadably inserted are adapted to receive a variety of nozzles18′ of varying apertures diameters, depending on the size of the perforations desired to be created in the wellbore casing.

Fluid communication between jet ports18(jet nozzles18′) and inner bore16is regulated by slidable sleeve14, which when slidably positioned over jet ports18prevents fluid communication between bore16and jet ports18, effectively closing the jet ports18. Movement of slidable sleeve14, either by: (i) application of an uphole force to draw slidable sleeve14upward (ref.FIG. 3A), (ii) use of a “pick-up” tool (not shown), inserted downhole into bore16when tool10is at a location along a wellbore where a perforation therein is desired to be created, or (iii) by injection of a pressurized fluid in bore16which thereafter enters chamber22and causes slidable sleeve14to act as a piston (ref.FIG. 7A, 8A) so as to thereby be caused to move so as to open jet port18, are all alternative and different ways in which slidable sleeve14may be actuated to respectively allow and prevent fluid access from bore16to jet ports18.

In the embodiment of the invention shown inFIGS. 2A, 3A, and 3B, slidable sleeve14is guided by a pin member24travelling in longitudinal slot26to ensure longitudinal guided movement of slidable sleeve14within cylindrical member20and bore16, and to provide extremities of movement for such slidable sleeve14.

An uphole packer member30is situated on a portion of periphery17of tool10, downhole of jet ports18. An expandable chamber40and associated piston member41are provided, wherein chamber40is adapted to receive fluid under pressure from bore16and cause said associated piston member41, when pressurized fluid is supplied to bore16, to compress and outwardly expand uphole packer member30to create a seal in the wellbore, between the tool and the wellbore casing.

A downhole packer member32is further provided, situated on a portion of periphery17of tool10downhole from uphole packer member30, as shown inFIGS. 1, 2B, 3B, &4B. Downhole packer member32is typically comprised of an elastomeric substance, and in uncompressed when in a non-activated state, as shown inFIGS. 2B & 3B. Upon high pressure fluid, such as a fracking fluid, being provided to bore16, such high pressure fluid flows into chamber40via aperture43in piston member41causing expansion of chamber40as may be seen inFIG. 3A. Expansion of chamber40causes piston member41to compress upone packer member30, thereby creating a seal between tool10and wellbore casing at the location of uphole packer member30in the wellbore.

One or more frac ports50are provided on tool10circumferentially about the periphery17of cylindrical member20. Frac ports50are located on tool10intermediate uphole packer member30and downhole packer member32.

A slidably moveable guide member60, having radially protruding slip members62which frictionally engage the wellbore casing when tool10is inserted in the casing, is provided. Guide member60is situated on tool10downhole of downhole packer member32. Guide member60is further provided with radially expandable jaw members78, on an uphole side thereof, as shown inFIGS. 2B, 3B & 4B.

A ‘j’-slot subassembly80is provided on tool10, situated downhole of downhole packer member32. ‘J’-slot subassembly80comprises an inner mandrel member64, having a slotted profile “P” therein, and a pin member65which travels in slotted profile “P”.

When the ‘j’-slot subassembly80is in the ‘run’ position (ref.FIG. 2A, 2B, andFIG. 6A) and downward force is applied to tool10guide member60frictionally engages the wellbore casing. In such “run” position, the slotted profile “P in associated mandrel member64does not allow further relative downward movement of a wedge-shaped lower portion90of downhole packer member32, and thus does not allow jaw members78to become actuated.

When an upward pulling force is applied to tool10(ref.FIG. 3A, 3B, andFIG. 7A) and thereafter a downward force is re-applied to said tool10(ref.FIG. 4A, 4B, andFIG. 8A), the ‘j’-slot subassembly becomes configured in the ‘set’ position where:(i) the wedge-shaped lower portion90of downhole packer member32is allowed further downward downhole movement to allow said lower portion90to be forced against jaw members78so as to expand them radially outwardly to engage the wellbore casing, and thereby fix the tool10within the wellbore casing to allow fracking to be carried out.

In a preferred embodiment a bypass port94is provided, uphole of the downhole packer member32, configured when open to provide fluid communication between an exterior of tool10and interior bore16and permit fluid exterior to tool10and above said downhole packer member32to flow into said bore. With such bypass port94the tool10may be more easily pulled uphole than would otherwise be the case. A slidable valve member95slidably opens and closes said bypass port94.

When an upward force is exerted on the tool10slidable valve member95is in an open position thereby keeping open bypass port94. When subsequently actuating said ‘j’ slot subassembly80to the ‘set’ position by subsequent downward force on tool10, and/or frac pressure is applied to bore16, slidable valve member95is moved to a closed position thereby closing bypass port94.

In the embodiments of the tool shown inFIGS. 2B, 3B, &4B, the slidable valve member95which is provided is moved to the closed position inFIG. 4B, by hydraulic frac fluid being applied to bore16, which thereby moves spring-biased conical deflector97downhole, thereby moving slidable valve member95to cover and thereby close bypass port94. In an alternative configuration (not shown) mandrel64may further or alternatively be configured, to that when the “j’-slot subassembly80is in the “set” position, that bypass port94is thereby closed, either by mandrel64itself, or by mandrel64actuating slidable valve member95to close bypass port94.

Numerous other configurations to effectively close bypass port94upon ‘j’ slot subassembly80moving to the “set” position (as shown inFIG. 4B) will now occur to persons of skill in the art, and all such variations are within the contemplation of this invention. Similarly, conical deflector97is shown inFIGS. 2B & 3Bas being biased by a helical coil spring99to close port50and leave bypass port94open, unless a fluid pressure is supplied to bore16, allow conical deflector97to leave slidable valve member95in a position where bypass port94is closed and port50is open (ref.FIG. 4B) open. Other means of biasing conical deflector97, other than by spring means, to accomplish the aforesaid result will now occur to persons of skill in the art, and such permutations and substitutions are likewise contemplated as forming the invention described herein.

FIGS. 6A, 7A, 8Ashow successive operation of an alternative embodiment of the upper portion of the tool10(the bottom portion of the tool10being identical to the configurations successively depicted in corresponding successiveFIGS. 2B, 3B, &4B) in particular with regard to the manner of actuation of the sliding sleeve14, where such embodiment is specifically adapted to both perforate and frac at the same time.

The components of the bottom portion of the tool10, for the embodiment shown in successiveFIGS. 6A, 7A, &8A, are identical and correspond to the configuration shown in corresponding successiveFIGS. 2B, 3B, and 4B. Specifically,FIG. 6A(and corresponding bottom portion of the tool10in such embodiment shown inFIG. 2B) shows the tool10of such embodiment in the “run in” position.FIG. 7A(and corresponding bottom portion of the tool10in such embodiment shown inFIG. 3B) shows the tool10of such embodiment in the “pulling” position. Lastly,FIG. 8A(and corresponding bottom portion of the tool10in such embodiment shown inFIG. 4B) shows the tool10of such embodiment in the “set” position.

In such alternative embodiment shown inFIGS. 6A, 7A, and 8A, slidable sleeve14has a port23therein and is configured so as to form a chamber22. After the tool10is moved slightly uphole to the “pulling” position shown inFIGS. 7A & 3B) and then moved downwardly to allow the ‘j’-slot to move to the “set” position (ref.FIGS. 8A & 4B) pressurized abrasive fluid is the supplied to bore16of tool10. Such pressurized fluid enters chamber22via port23and causes slidable sleeve14to automatically move uphole as shown inFIG. 8A, thereby uncovering jet port18to thereafter allow the perforation operation to be performed. In this alternative embodiment/alternative method, the pressurized abrasive fluid also serves as the fracking fluid. In such case, the foregoing embodiment allows simultaneous creation of an uphole perforation in the wellbore casing when such sliding sleeve14is opened, while at the same time fracking of the formation being simultaneously conducted by a lower portion of the tool10, since upper and lower packer members30,32respectively now “straddle” an earlier-created perforation in the wellbore casing, and pressurized abrasive/fracking fluid is injected into the formation via such lower earlier-created perforation.

In the preferred embodiments of the upper portion of the tool10shown inFIGS. 2A, 3A, &4A, and6A,7A, &8A, such upper portion10is provided with an annular cup seal100on periphery17of tool10. Such annular cup seal100is situated intermediate jet port18and said downhole packer member32, and serves to reduce flow of abrasive pressurized fluid and associated wellbore casing cuttings downhole during the casing perforation operation, which is part of the method of the present invention more fully explained below.

Manner of Operation of Tool, and Methods for Perforating Wellbore Casing and Fracking a Formation Using the Single Tool

A broad outline of a method for operating the tool10and methods for perforating a wellbore casing and fracking a formation using a single tool10are set out below and are depicted successively inFIGS. 2A, 2B, 3A, 3B & 4A,4B, and likewise successively for the alternative embodiment shown inFIGS. 6A, 7A & 8A(with corresponding lower portions of the tool10shown respectively inFIGS. 2B, 3B, &4B).

In the method, broadly described, tool10is initially run into a wellbore casing to a desired depth in the wellbore casing. During such run-in, and as shown inFIG. 2AandFIG. 6A, slidable sleeve14covers jet port18. Frac port50may be in an open or closed position (shown in the closed position inFIGS. 2b&3B and in the open position inFIG. 4B), and likewise for bypass port94may be in an open or closed position (shown in the open position inFIGS. 2B, 3Band in the closed position inFIG. 4B). Thereafter, when the tool10has been lowered to the lowermost portion of the wellbore which is desired to be perforated and fracked, slight upward movement of tool10(ref.FIGS. 3A, 3B) pulls slidable sleeve14uphole, while guide member60and slips62thereon generally keep the remainder of tool10at a fixed position within the wellbore, thusly opening jet port18and jet nozzles18′.

An abrasive pressurized fluid containing an abrasive compound such as uniformly sized sand particles or tungsten carbide filings of small uniform dimension, is then injected into bore16. Such fluid not only enters chamber40through port43and caused piston41to compress uphole packer member30to thereby create a seal between tool10and the wellbore casing at such location, thereby preventing flow of abrasive fluid downhole, at such time the pressurised fluid is further expelled in a radially outward manner from jet ports18and jet nozzles18′ to thereby impinge upon the wellbore casing, and after a short time interval of impingement, perforate the casing at such location, with perforations equal in number to the number of jet ports18(ref.FIGS. 3A, 3B)

It is noted that slidable sleeve14in the method of the present invention need not necessarily be opened by slight upward force on the tool string and tool10, as described above, but rather in an alternative embodiment shown inFIGS. 6A, 7A, and 8A, such slidable sleeve14is configured so as to form a chamber22, and is opened by pressurized fluid being supplied to such chamber22. This variation is described further below.

After the above perforation operation is performed, injection of pressurized abrasive fluid is ceased, and tool10may then be further drawn uphole to thereby position both the uphole packer member30and the lower (downhole) packer member32of tool10on the uphole and downhole side, respectively, of the created perforation, so as to effectively “straddle” the perforation with packer members30,32.

Thereafter, and as shown inFIGS. 4A&B, further downward force is re-applied reapplied to the tool10to move slidable sleeve14downward (downhole) to cover jet ports18and to further actuate ‘j’ slot subassembly to allow wedge-shaped lower portion90of lower packer member32to be forced against jaw members78, thereby causing such jaw members78to be forced radially outwardly and thus against the wellbore casing so as to thereby temporarily secure tool10within the wellbore casing. Simultaneously, by downhole packer member32being forced against jaw members78of guide member60, the downhole packer member32is compressed and caused to expand radially outwardly, thereby creating a seal between the tool10and the wellbore casing at that location.

Thereafter, as shown inFIGS. 4A&B, pressurized fracking fluid is injected into bore16, which causes piston member41in said tool10to compress said uphole packer member30and cause said uphole packer member30to expand radially outwardly, and thereby cause the pressurized fluid to pass into said the created perforation via frac port50in tool10.

Thereafter, after completion of the fracking of the wellbore and this particularly location, supply of the pressurized fracking fluid is ceased and an upward force is then re-applied to the tool10to disengage jaw members78and allow re-positioning of tool10further uphole for creating further perforations and injecting further fracking fluid into further created perforations at such locations.

FIG. 5shows a further elaboration/itemization of one particular method400of the present invention, using the tool10configuration shown inFIGS. 2A, B,3A,3B, &4A,4B, and where a bypass port94further is utilized.

In step401, tool10is run downhole. Jet port18remains closed, and frac port50remains open, and neither upper packer member30or lower packer member32are “set” (i.e. compressed), thereby allowing the tool10to be run in into the wellbore, to a desired lowest depth where perforations and fracking is desired to be conducted. The ‘j’ slot subassembly80, namely pin member65within slot “P” of mandrel62, is in the “run in” position as shown inFIG. 2B

If there is an existing perforation in the wellbore, the operator will, as shown in step402, elect to proceed to step403to pull up slightly on the tool10to move the j-slot80from the run-in” position to the “pulling position” as shown inFIG. 3B, to thereby align frac port50proximate the perforation, and thereby also open bypass port94(If no existing perforation, the operate will proceed with step407, described below). Thereafter, in step404the operator will push tool10slightly back down in the wellbore, to move ‘j’ slot subassembly80to the “set” position (ref.FIG. 4B), and simultaneously set (i.e. compress) the lower packer member32and jaw members78, close bypass port94, and close jet port18.

In subsequent step405, pressurized frac fluid is then supplied to bore16to tool10, to “set” (i.e. compress) upper packer member30by movement of piston41, and frac fluid is injected into the formation in the region of the created perforation by supply of frac fluid to frac port50and thereby to the formation.

After fracking, tool10is pulled uphole in step407to thereby open jet port18and bypass port94, release lower packer32and jaw member78, and allow movement of tool10to an uphole location in the wellbore where desired to further perforate the casing.

In subsequent step408, abrasive fluid is supplied to bore16of tool10, and subsequently through jet port18to perforate the wellbore casing at such new uphole position, and thereafter the supply of such abrasive pressurized fluid is ceased.

In subsequent step409, the tool10is pulled further uphole to position frac port50over the newly created perforation, and move ‘j’-slot80to the “pulling” position.

If the desired length of the wellbore has not been completely perforated and fracked, the completion engineer reverts to step404, and re-execute steps404-409at such further location in the wellbore. Otherwise, if at such point the wellbore has been completely perforated and fracked to the extent desired, the tool10can then be removed from the wellbore.

The operation of the configuration of tool10, having the configuration shown inFIGS. 6A, 7A, &8A, allows both perforation and fracking to be simultaneously carried out, and necessarily involves the abrasive fluid being one and the same as the frac fluid.

Such further refinement to the method400comprises simultaneously with step405injecting the abrasive/frac fluid, causing, by injection of such abrasive/frac fluid, the slidable sleeve14to move to an open position and expelling said abrasive/fracking fluid in a radially outward manner via said jet port18to thereby create a further perforation in the wellbore. Step409further comprises the step of repositioning the tool10further uphole so as to further position upper packer member30above the further created perforation, and again supplying the abrasive/fracking fluid to tool10when in such further position, to frac the formation in the region of the further perforation in the wellbore, and at the same time to further create an additional uphole perforation.

Third Embodiment of the Tool, and Method for Fracking Using Such Tool

As noted in the Summary of the Invention, in a further aspect the present invention provides a downhole tool which not only successively fracs at spaced intervals along a perforated wellbore, but is further provided with what is figuratively referred to herein as a “dump valve” which may be opened, if desired or considered necessary, to allow flushing of an annular space surrounding the frac tool with a flushing fluid after every successive frac operation carried out, so as to reduce the risk of the fracking tool, and thus the frac string, from becoming “sanded-in”.

More particularly, the present invention in a third embodiment thereof comprises a downhole tool for injecting a fluid into a hydrocarbon formations at various spaced intervals along a wellbore and further having capability to flush an annular space around the tool after each interval of injection of said fluid into the hydrocarbon formation.

All numerical references identified inFIGS. 9A & 9B,FIGS. 10A & 10b,FIGS. 11A & 11B,FIGS. 12 & 12Bhaving the same reference numerals as identified in respect of earlier Figures perform the same function and correspond to a similar component as those components identified in such earlier drawings figures, and their description is incorporated with regard to the aforementioned drawings.

FIGS. 9A & 9B,FIGS. 10A & 10b,FIGS. 11A & 11B,FIGS. 12 & 12B, andFIG. 13all teach a tool10and method800, respectively, which fracs a formation200at spaced intervals along a wellbore204but does not also perforate a wellbore or wellbore casing. Instead, in the variation of the aforementioned tool10as shown in the above Figures, the jet ports18and jetting nozzle18′ (if further provided) are merely used as (or comprise), or substituted with, “dump ports”300(ref.FIGS. 9A, 10A, 11A, &12A) for providing a flushing fluid (not shown) into an annular space202between the tool10and the wellbore or wellbore casing204when the tool10is situated in the wellbore204. Such configuration advantageously serves to reduce incidence of potential “sanding in” of the tool10within wellbore204after a fracking operation is completed at a particular interval along wellbore204.

Specifically,FIGS. 9A & 9Bshow the configuration of each of the top portion (FIG. 9A) and bottom portion (FIG. 9B) respectively of tool10, and in particular for the ‘j’-slot80thereof, during an initial “running in” configuration of the tool10.

FIGS. 10A, 10Bshow the configuration of each of the top portion (FIG. 10A) and bottom portion (FIG. 10B) respectively of tool10, and in particular for the ‘j’-slot80thereof, during a subsequent “pulling” stage where the tool10has then been pulled slightly uphole to re-configure ‘j-slot80to the ‘pulling position’

FIGS. 11A, 11Bshow the configuration of each of the top portion (FIG. 11A) and bottom portion (FIG. 11B) respectively of tool10, and in particular for the ‘j’-slot80thereof, during a subsequent “setting” stage where the tool10has then been pushed slightly downhole to re-configure ‘j-slot80to the ‘set’ or ‘setting’ position’ and align frac port50of tool10proximate a perforation (not shown) in wellbore casing204or proximate a desired location along wellbore204for the first fracking operation. Configuration of ‘j’-slot80to the ‘set’ position causes/allows wedge-shaped lower portion90of lower packer member32to be forced against jaw members78, thereby causing such jaw members78to be forced radially outwardly and thus against the wellbore casing so as to thereby temporarily secure tool10within the wellbore or wellbore casing204. Simultaneously, by downhole packer member32being forced against jaw members78of guide member60, the downhole packer member32is compressed and caused to expand radially outwardly, thereby creating a seal between the tool10and the wellbore or wellbore casing204at that location.

When tool10is positioned and thereby configured in the ‘setting’ position shown inFIG. 11A, 11B, a pressurized injection fluid (not shown) can then be supplied to the bore16of tool10. Supply of such pressurized injection (fracking) fluid which typically contains high percentages of silicates of uniform diameter, will then:(i) push down on spring-biased conical deflector, and cause bypass port94to then be closed;(ii) in a configuration where, as described above, uphole packer member30is actuated by an expandable chamber40and associated piston member41, chamber40receives fluid under pressure from bore16via port43and causes associated piston member41to compress and outwardly expand uphole packer member30to create a seal in wellbore204; and(iii) cause high pressure frac fluid to flow out frac port50and into wellbore204, and frac the formation200in a region between upper and lower packer members30,32not only creating fissures in the formation200but further allowing the sand particles in the injected fluid to “prop” open the fissures to allow in the formation200to flow into wellbore204via such fissures for subsequent production to surface.

After the aforesaid fracking operation at the desired interval along the wellbore204has been completed using the modified tool10described above, namely by subsequent cessation of supply of pressurized fluid to frac ports50, the tool10can then be configured as shown inFIGS. 12A & 12Bto conduct a flushing operation.

As may be seen from the configuration of the tool as shown inFIGS. 12A, 12B, cessation of supply of high pressurized fluid results in:(i) disengagement of sealing of uphole packer member30with wellbore204, by piston41returning to its initial position; and(ii) return of spring-biased conical deflector to a position closing frac port50, and opening bypass port94.

Tool10may then return to the configuration shown inFIGS. 12A, 12Bby pulling the tool10slightly upwardly while guide member62hold a lower portion of the tool10below downhole packer32stationary within wellbore204, so as to release jaws'78engagement with wellbore204and release downhole packer member32sealing engagement with wellbore32.

In addition, slight uphole movement of the upper portion of tool10, or by use of a “pick-up” tool as described below, will result in sliding sleeve14to be moved uphole, thereby uncovering dump ports300.

Accordingly, tool10when now configured to the configuration shown inFIG. 12A, 12B, may advantageously then have a flushing fluid (typical not containing any sand or low concentration of sand) supplied to bore16to tool10and caused to flow out dump port(s)300into annular space202, and caused to be circulated via such annular space202back uphole for collection and processing. In such manner annular space202intermediate tool10and wellbore204may be flushed of sand in the region around the tool10and in all areas above the tool, thereby freeing the tool10for further movement uphole for progressively carrying out further fracking operations at spaced intervals uphole.

WhileFIG. 11Ain comparison withFIG. 12Amerely shows that sliding sleeve10and a portion of tool10has been pulled uphole slightly to thereby cause slidable sleeve14to slidably uncover dump port(s)300, other manners of actuating the sliding sleeve14to uncover the dump ports300can be employed. For example, a commonly-known “pick-up” tool (not shown) may be inserted in hollow bore16of tool10and actuated to removably and temporarily grasp sliding sleeve14and when such pick-up tool is then moved uphole, causing slidable sleeve14to uncover dump ports300(as shown for example inFIG. 12A). Upon sliding sleeve14reaching an extremity of travel uphole, further uphole movement of sliding sleeve14causes disengagement of pick-up tool therewith, allowing pick-up tool to thereafter be drawn uphole and removed from the wellbore204, and the tool10, and particularly the bore16thereof, to be supplied with a flushing fluid (preferably free of sand) which flushing fluid when passing from inner bore16of tool10into annular space202via dump port(s)300then flushes annular space202of any entrained sand, thereby preventing tool10from becoming sanded in within wellbore204.

The first step801of method800, depicted inFIGS. 9A & 9B, involves running tool10, which possesses hollow bore16in the region of dump port300and frac port50, downhole to a desired depth within wellbore204, typically a lowermost position in wellbore204. Bypass port94will be open, and upper and lower packers30,32will not be set in wellbore204‘J’-slot80will be positioned in the “run in” position shown inFIG. 9B.

The second step802of method800depicted inFIGS. 10A & 10Bcomprises pulling slightly upwardly on tool10to configure ‘j’-slot80on tool10from a “running” position of step (i) to a “pulling” position, and positioning an uphole and downhole packer member30,32situated on tool10on mutually opposite sides of a region along wellbore204which is desired to be fracked.

The third step803of method800depicted inFIGS. 11A & 11Bcomprises pushing slightly down on an upper portion of tool10to cause said ‘j’ slot80to allow movement of a portion of tool10wherein jaw members78on tool10are forced against wellbore204and downhole packer member32on tool10is longitudinally compressed and caused to expand radially outwardly, so as to configure tool10in a “set” position. Pushing down on tool10will slidably close slidable sleeve14over dump ports300.

The fourth step804of method800, also carried out when the tool is configured as per the configuration shown inFIGS. 11A & 11B, involves injecting pressurized fracking fluid into bore16of tool10. Such causes conical deflector94to move to open frac port50and close bypass port94, and further causes the pressurized fluid to pass via a frac port50in tool10into fissures created in the formation extending radially outwardly from wellbore204.

The fifth step805of method800, also carried out when tool10is configured as per the configuration shown inFIGS. 11A and 11B, entails ceasing supply of said pressurized fracking fluid to bore16of tool10.

The sixth step806of method800, carried out when the tool is configured as per the configuration shown inFIGS. 12A and 12B, comprises pulling upwardly on tool10to disengage the jaw members78with wellbore204and re-configure the ‘j’ slot80into said “pulling” configuration, and simultaneously cause slidable sleeve14covering dump port300to move so as to uncover dump port300.

The seventh step807of method800comprises providing a flushing fluid not containing sand to hollow bore16of tool10and causing the flushing fluid to be expelled from bore16of tool10via dump port(s)300and thereby flushing the annular space202between wellbore204and tool10with said flushing fluid.

The eight step808of method800comprises thereafter pulling tool10further uphole for further subsequent injection of pressurized fluid containing sand into additional fissures created in formation200.

The foregoing description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article “a” or “an” is not intended to mean “one and only one” unless specifically so stated, but rather “one or more”. In addition, where reference to “fluid” is made, such term is considered meaning all liquids and gases having fluid properties.

For a complete definition of the invention and its intended scope, reference is to be made to the summary of the invention and the appended claims read together with and considered with the disclosure and drawings herein.