Wellbore tool for fracturing hydrocarbon formations, and method for fracturing hydrocarbon formations using said tool   

Abstract: A wellbore tool for adapted for insertion into a wellbore extending into a hydrocarbon-containing formation, for fracturing said formation, comprising an elongate, substantially cylindrical tubular member. The tubular member has at a first end external thread means adapted for threadable connection to internal thread means disposed on an end of a wellbore piping member, and at an opposite end having internal thread means. At least a pair of longitudinally-spaced apart radially-outwardly protruding annular rib members are located on an exterior periphery of said tubular member, each of an outer diameter greater than an outer diameter of said wellbore piping member to which said tool is adapted to be threadably coupled. A method for fracturing a hydrocarbon formation using such wellbore tool is further disclosed.

FIELD OF THE INVENTION

The invention relates to downhole tools used in fracturing of underground hydrocarbon formations, and more particularly to a downhole wellbore tool and a method for fracturing underground hydrocarbon formations.

BACKGROUND OF THE INVENTION

Fracturing systems are well known and are primarily used to increase the permeability to thereby enhance the recovery of hydrocarbons from an underground hydrocarbon reservoir. Prior art fracturing systems typically employ multi-staged selective fracturing tools. These tools usually possess a compression element, an inflatable element, or similar type of isolation member.

Fracturing of a well bore is usually necessary when a reservoir has pressure and economic hydrocarbon reserves, but lacks matrix permeability and porosity to sustain economic production rates. This is commonly known as a “tight formation”. Fracture stimulation is necessary when “near wellbore” formation damage requires stimulation to permit economic flow rates (i.e., the bypassing of skin damage). Fracturing or “frac\'ing” of the formation allows for the hydrocarbon bearing zone to increase in drainage radius, enhancing the permeability of hydrocarbon within the formation, and thereby better allow the hydrocarbons to flow into the wellbore. Before fracturing operations, wells could remain uneconomical (or marginal) to produce due to limited production inflow ability. Fracturing has allowed more economical production from areas of “tight” permeability and transformed uneconomic/marginal wells into cash generating assets.

Existing fracturing systems may utilize a variety of liquids and proppants. The fluid base can be hydrocarbon, produced water, fresh water, liquefied inert gas (CO2, N2, or alternate), liquefied natural gas, or a blend thereof. When chemically adjusted, proppant may be injected into the formation to stimulate the reservoir. Proppants can be any material capable of supporting the overburden weight surrounding the fracture channel(s) after the fracture treatment process is conducted. The fracture channel, by virtue of an enhanced permeability streak, ensures that there is enhanced connectivity within the formation. The enhanced connectivity improves drainage and enhances production rates.

Prior art multi-staged fracturing systems that are currently employed are complex and comparatively expensive. As mentioned above, many systems rely on a mechanical or inflatable seal packer in the external boundaries between the outside diameter of the liner and the bit diameter (ie wellbore diameter). In theory, a prior-art compression seal of this type isolates one fracture point from another. However, there is limited ability to downspace the fracture interval with the known technology. Such prior art equipment and methods are typically very costly and not always effective, since the fracture can permeate past the mechanical seal, creating communication around the seal of the set packers. The initiation of the fracture point can occur anywhere between the two packing elements, and, in the case of a cemented liner, may travel in a cement micro-annulus, a poor cement bond to formation, or a cutting bed permeability streak (typically along the bottom side of the lateral section).

Prior art systems such as those described above are used in conjunction with other systems of isolation in the casing. These systems include: (1) A ball drop technique, whereby a spherical ball seats into a seal assembly for the size of ball that is dropped. The fracturing occurs after the frac-port valve is open. A series of balls are dropped and actuate any number of consecutive mechanical opening ports; (2) A tubing conveyed perforating (TCP) system, whereby intervals are opened with the use of shaped explosive charges, which can be ran on coiled tubing or jointed pipe. Once reservoir access is had, the intervals are fracture stimulated with a selective cup tool that isolates each individual perforation set; (3) A series of burst discs ran on the production liner. With the use of a straddle system on either coiled tubing or jointed tubing, the burst disks are selectively opened and subjected to a fracture stimulation. The burst disk are blown, a feed rate is established, and then the resultant fracture stimulation can ensue; (4) Hydro-jetting (abrasa-jetting) technique. Subject to an Exxon Mobil patent that charges a 3% fracture stimulation premium on any number of stages equal to or greater than 7 cuts, the operator can use high-pressure sand and specialized nozzles to cut the liner with the use of coiled tubing and then perform a fracture stimulation down the liner/coiled tubing annulus. The various hydrojetted intervals are selectively isolated with a retrievable packer positioned below the hydrojetting tool itself, and the treatments occur from the deepest part of the well, in terms of measured depth, to the shallowest part of the well; (5) Pre-drilled liner technique. When running the production casing, pre-drilled holes are plugged with aluminium plugs. Once the liner is positioned, a mill is run to knock off the various plugs. The fracture stimulation can be pumped in one giant stage, or isolated with use of coiled tubing technology and straddle packers; (6) Retrievable ball drops in which successive ball catchers are used to retrieve the ball catcher next in the string. This permits a cleanout, sidesteps the need to mill out a ball catcher, and allows the ball catchers to be re-ran in additional fracture stimulations.

All of the above-described prior-art procedures have been tried in the field and have worked to some degree or fashion, and typically allow a very tight permeable reservoir to be now economically produced until depletion occurs. However, given inherent complexities of the tools and methods used to accomplish such fracturing, the costs of such applications are comparatively high when associated to such applications.

SUMMARY

The wellbore tool, frac\'ing tool, and method of frac\'ing of the present invention permits multi-staged fracture stimulations of a hydrocarbon-containing formation, and is relatively simple and inexpensive in comparison with certain of the prior art systems and apparatus.

Accordingly, in one broad aspect of the present invention, the invention comprises a wellbore tool for insertion in a wellbore and adapted for use in fracturing a hydrocarbon-containing formation into which said wellbore extends, comprising: (i) an elongate, substantially cylindrical tubular member, having at a first end thereof internal/external thread means adapted for threadable connection to thread means disposed on an end of a wellbore piping member, and at an opposite end having external/internal thread means; and (ii) at least a pair of longitudinally-spaced apart radially-outwardly protruding annular rib members located on an exterior periphery of said tubular member, each of an outer diameter greater than an outer diameter of said wellbore piping member to which said tool is adapted to be threadably coupled.

In a preferred embodiment the annular rib members are each of a diameter at least 24% greater than an outer diameter of said wellbore piping member to which said tool is adapted to be threadably coupled

In a further preferred embodiment the wellbore tool is adapted to provide a cross-sectional clearance area between at least one of the annular ring members and an inner diameter of said wellbore that is at least 80 percent less than an inner cross-sectional area of said tubular member of said wellbore tool, to thereby permit effective isolation of the wellbore from the high pressure frac\'ing fluid, in the manner more fully described below.

In a still-further preferred embodiment, the external/internal thread means at one end of the wellbore tool are opposite to the internal/external thread means situated at the opposite end of the wellbore tool.

In a further broad aspect of the invention, the invention comprises a method for fracturing a hydrocarbon formation through which extends a vertical, inclined, or horizontal wellbore, comprising the steps of: (i) threadably coupling one end of each of a pair of wellbore tools as alternatively described above to respectively opposite ends of a tubular member so as to situate said tubular member between said two tools; (ii) coupling another end of one of said tools to a wellbore piping member and inserting said pair of tools and intermediate tubular member downhole in said wellbore; and (iii) fracturing said hydrocarbon formation downhole by pumping fracturing fluid downhole under pressure into said tubular member and causing said fracturing fluid to flow into said formation via an aperture created in said tubular member between said pair of wellbore tools.

In yet a further broad aspect of the invention, the invention comprises a frac\'ing tool for insertion in a wellbore and adapted for use in fracturing a hydrocarbon-containing formation, adapted to be coupled at each end thereof to respectively first and second wellbore piping members, comprising: (i) an elongate, substantially cylindrical tubular member, having at a first end thereof external/internal thread means adapted for threadable connection to mating thread means disposed on an end of said first wellbore piping member, and at an opposite end having external/internal thread means adapted for threadable connection to thread means disposed on a distal end of said second wellbore piping member; (ii) at least two pairs of longitudinally-spaced apart radially-outwardly protruding annular rib members, each respectively located on an exterior periphery of said tubular member at respectively opposite ends thereof, each of a diameter greater than a nominal outer diameter of said first and second wellbore piping members. (iii) each of said at least two pairs of longitudinally-spaced apart radially-outwardly protruding annular rib members separated by an intermediate distance; and (iv) aperture means situated in said periphery and located within said intermediate distance, to allow pressurized fluid egress from an interior of said tubular member to an exterior of said tubular member.

In a preferred embodiment of the aforementioned frac\'ing tool, said annular rib members are each of a diameter at least 24% greater than a nominal outer diameter of said first and second wellbore piping members.

Still further, in a preferred embodiment the aforementioned frac\'ing tool is adapted to provide a cross-sectional clearance area between said annular ring members and an inner diameter of said wellbore that is at least 80 percent less than an inner cross-sectional area of said tubular member of said frac\'ing tool.

In yet a further broad aspect of the present invention, such invention comprises a method for fracturing a hydrocarbon formation through which extends a vertical, inclined, or horizontal wellbore, comprising the steps of: (i) threadably coupling an end of an integral frac\'ing tool as alternatively described above to a wellbore piping member, and further coupling said wellbore piping member to further wellbore piping members, and inserting said tool and connected wellbore piping members downhole in said wellbore; and (ii) fracturing said hydrocarbon formation downhole by pumping fracturing fluid downhole under pressure and causing such fracturing fluid to flow into said formation via said aperture means.

Advantageously, using the method and apparatus of the present invention as more fully described below, the formation can be subjected to multiple fracture stimulations, at various times throughout the life of the well, by virtue of selective or continuous fracturing techniques.

Further, existing fractures can be enhanced through a re-fracture process using isolation technology of the present invention. This system permit multiple fractures to occur and then allow the well to commence production. Once the production volumes have been depleted, the operator can elect to re-stimulate the existing fracture channels, or opening non-fractured ports.

In a preferred embodiment, the wellbore tool further has, on the exterior thereof, radially-outwardly extending but longitudinally-aligned “centralizers”. The centralizers may be placed in uniform circumferentially-spaced intervals around the outer periphery of the wellbore tool to allow centralization of the tool within either the wellbore or the fracturing application of the liner, casing, tubing or open hole of the well bore.

Smaller diameter wellbore tools for use in smaller diameter wellbores may only require 3 centralizers; this number will increase +1, each successively larger size until a maximum bore hole diameter is reached at a amount or maximum of 8 centralizers.

Placement of the wellbore tool is contemplated as being on opposite ends of an cylindrical tubular member, containing an aperture known in the industry as a fracture port, or more typically a “frac” port. Frac ports shall be defined as any formable aperture within the annulus formed between the “choke: points created by the annular ring members, be it an aperture which is opened via a sliding sleeve, an aperture formed after a disk in the periphery of a member “bursts” (ie a “burst disk”), a mechanically actuated frac port (such as a “ball drop” type, or a coil/tubing movement actuated port), a pre-perforated and open tubular port, a pre-perforated and plugged (ie “corked”) tubular (i.e., an aluminum plugged nipple), a perforated interval (wireline or TCP conveyed, or otherwise), a hydro-jetted/abrasa-jetted interval or otherwise as known in the art.

The frac\'ing fluids that are used with this embodiment may be varied in nature, proppant concentration, proppant type, chemistry and viscosity, all of which are determined by the fracturing programmer with regard to the geology and nature of the hydrocarbon formation.

The wellbore tool of the present invention may be comprised of any suitable material capable of withstand all frac\'ing, insertion, and formation Typical construction will be either L-80 or P-110 grade metals, but, again, metallurgy shall be determined by system parameters.

In the frac\'ing method of the present invention, the force of the flow of the fracturing fluid will initially travel through the inside diameter of the running assembly, exit the frac port, and then be restricted between the outside diameter of the tool and the formation face via the annular ring members. While flowing on the outer portion of the tubular member, undulations may further be provided in the outer periphery of such tubular member, to assist in creating a restriction point between the tool and the wellbore to assist in preventing egress of frac\'ing fluid between the tool and the wellbore, so as to thereby enter the interstial area upstream or downstream from the tool, and thereby not be pumped into the formation.

Pre-frac\'ing fluid may be supplied to the formation via the wellbore tool of the present invention, which fluid may be acidic in nature to establish a spearheading effect and reduce required stresses imposed by the fracture stimulation itself.

As used herein, the term “wellbore piping” or “wellbore piping member” means production piping members and also piping used in frac\'ing (often and typically one and the same), typically of standard nominal “id” and “od” diameters, typically having standardized external pipe threading (eg NPT standard) at one end, and internal standard pipe (eg NPT) threading at an opposite end, which thereby permit such wellbore piping members to be threadably coupled together so as to extend into the wellbore. In Canadian drilling applications standard wellbore piping has standardized nominal internal “id” diameter (eg. 5.5 inches), standard nominal “od” diameter (eg. 6.0 inches), and is adapted for insertion in wells of a standard bore size (eg. 7.785 inches).

The term “wellbore piping member” and “wellbore piping” used herein further includes coiled production tubing, which coiled tubing is likewise used in production and frac\'ing operations and is likewise in utilized in standardized sizes, typically the largest size available for a given wellbore diameter (eg. 5.5 inches internal ID) for a wellbore diameter of 7.785 inches.

BRIEF DESCRIPTION OF THE DRAWINGS

Further advantages and permutations and combinations of the invention will now appear from the above and from the following detailed description of a few particular embodiments of the invention taken together with the accompanying drawings, each of which are intended to be non-limiting and merely illustrative, in which:

FIG. 1 is a side elevation view of one embodiment of a wellbore tool of the present invention;

FIG. 2 is a cross-sectional view taken along plane A-A of FIG. 1;

FIG. 3 is a side elevation view of another embodiment of a wellbore tool of the present invention, having the external and interior threads repositioned on opposite ends of the tool in comparison to the wellbore tool shown in FIG. 1;

FIG. 4 is a cross-sectional view taken along plane B-B of FIG. 3;

FIG. 5. is a side elevation view of one embodiment of the integral frac\'ing tool of the present invention;

FIG. 6 is a cross-sectional view taken along plane C-C of FIG. 5;

FIG. 7a is an enlarged side elevational view of another embodiment of the frac\'ing tool of the present invention, wherein each of the two wellbore tools are identical and disposed on opposite sides of an intermediate member containing a frac port, with each reversed in longitudinal orientation;

FIG. 7b is an enlarged side elevational view of another embodiment of the frac\'ing tool of the present invention, wherein each of the two wellbore tools are identical and disposed on opposite sides of an intermediate member containing a frac port, with each tool aligned in similar longitudinal orientation;

FIG. 7c is a similar enlarged side elevational view of yet another embodiment of the frac\'ing tool of the present invention, wherein each of the two wellbore tools are non-dentical and disposed on opposite sides of an intermediate member containing a frac port.

FIG. 8 is a schematic side elevational view showing a vertical-horizontal wellbore pair employing a plurality of integral frac\'ing tools of the present invention so as to conduct a multi-frac\'ing operation of the hydrocarbon-bearing formation which is penetrated by the horizontal well bore;

FIG. 9 is an enlarged view of the horizontal wellbore and the multi-frac\'ing method shown in FIG. 8;

FIG. 10 is a perspective cut-away view showing one manner of construction of a frac\'ing tool of the present invention;

FIG. 11 is an enlarged perspective cut-away view showing the frac\'ing tool of the present invention coupled to a pair of well liner members;

FIG. 12 is an enlarged perspective cut-away view of a frac\'ing tool of the present invention similar to FIG. 10, however depicting an embodiment comprising an integral one-piece frac\'ing tool;

FIG. 13 is a reduced perspective view, showing the frac\'ing tool of FIG. 5 installed between sections of wellbore piping;

FIG. 14 is a schematic view of a test apparatus employed to determine necessary dimensional parameters and relationships with regard to the configuration of the wellbore tool of the present invention; and

FIG. 15 is a graph of certain test results obtained using a series of wellbore tools each having annular ribs of different diameters and thus each having areas of various restriction between such outer surfaces of such annular ribs and the interior of a wellbore, such graph indicating that in order to maintain a ten-fold or greater pressure differential it is necessary to have an area restriction of greater than 80%, as indicated by that portion of the graph to the right of arrow “F”.

DETAILED DESCRIPTION

FIG. 1 shows a wellbore tool 10 of the present invention for use in fracturing a hydrocarbon-containing formation 26 into which a wellbore 18 extends, as shown in FIG. 8.

The wellbore tool 10, in a simple embodiment shown in FIG. 1 showing a first version 10a thereof, and a likewise simple embodiment shown in FIG. 3 showing a second version 10b thereof, comprises a substantially cylindrical tubular member 40 having at a first end 43 thereof (external) pipe thread 44 adapted for threadable connection to pipe thread disposed on an end 21 of a wellbore piping member 22 (see FIGS. 9 & 13). Wellbore tool 10, at an opposite end 41, has (internal) pipe thread 42.

A plurality of longitudinally-spaced apart radially-outwardly protruding annular rib members 50 are located on an exterior periphery 60 of tubular member 40, as best shown in FIGS. 1 & 3. At least two of the annular ribs 50 have an outer diameter D3 that is at least 24% larger than a nominal outer diameter 23 of a wellbore piping member 22 which extends into the wellbore 18 to which the wellbore tool 10 is adapted to be threadably attached, for the advantages and reasons later explained herein.

Typically, the wellbore piping 22 (to which the wellbore tool 10 is threadably coupled) is of a nominal diameter D2 substantially less than the diameter D3 of the wellbore 18 or wellbore casing or liner 17 (see FIG. 8) in which such wellbore piping 22 is inserted. Such allows the wellbore piping 22 (which may be in straight lengths of approximately 35 feet) clearance, particularly in deviated wells and vertical-horizontal well pairs as shown in FIG. 8, in order to navigate gradual curvature in the wellbore 18 during transition of the wellbore 18 from vertical to horizontal, as shown in FIG. 8.

Disadvantageously howeverwith respect to frac\'ing operations, the lesser nominal diameter D4 of the wellbore piping 22 as compared to diameter D3 of the wellbore 18 allows a gap 70 (see FIGS. 8 & 9) between the wellbore piping members 22 and the wellbore 18 or wellbore liner or casing 17, which thereby prevents frac\'ing fluid (not shown) from being pumped under pressure via aperture 72 (see FIGS. 5, 7, 8 and 9) into the formation 19, 26, since such frac\'ing fluid will typically travel backwards along the gap 70, rather than into the formation 19, 26. For this reason, annular rib members 50 are provided on the exterior of wellbore tool 10, which serve to restrict the cross-sectional area between the exterior of the wellbore tool 10 and the wellbore 18 (ie π*(D3)2/4−π*(D2)2/4), and thus allow frac\'ing pressure to be directed, via aperture 50, into formation 19, 26 where it is desired.

Although the wellbore tool 10 of the present invention possesses a diameter D2 at its annular ribs 50 greater than the nominal outer diameter D3 of wellbore piping 22 (but no greater than wellbore diameter D3), due to wellbore tool 10\'s relatively short length (preferably limited about 2-7 times its internal diameter D1) and the relatively short longitudinal length of the annular ribs 50, wellbore tool 10 is thus still able to have sufficient clearance to be inserted downhole in wellbore 18 and navigate curved wellbores 18 as occurs in vertical-horizontal well pairs as shown in FIG. 8. For the reasons more fully explained herein, preferably the outer diameter D2 of the at least two annular rib members 50 on wellbore tool 10 is not only less than a diameter D3 of said wellbore (obviously, to allow wellbore tool 10 it to be inserted in the wellbore 18) but is further at least 24% greater than a nominal outer diameter D4 of the wellbore piping 22 in order to provide sufficient isolation with regard to gap 70 and thus allow pressurized frac fluid to flow into the formation 19, 26 via aperture 72 despite some (reduced) leakage of frac\'ing fluid exiting aperture 72 into interstitial gap 70 (see FIG. 8,9,).

Advantageously, by virtue of the wellbore tool 10 of the present design having a plurality of raised annular ribs 50, due to the nominal diameter D4 of wellbore tool being at least 24% less than rib diameter D2, annular isolated areas “a”, “2a”, “a+2a”, and “2a+(a+2a)” are created between each of respective rib members 50 (see FIGS. 1 & 7). Fines and other wellbore detritus may collect in such annular isolated areas during insertion of the wellbore tool 10 into a wellbore 18, thereby desirably increasing the sealing and thus the isolation of the gap 70 from pressurized frac\'ing fluid. Conversely, an alternative configuration for a wellbore tool such as a solid tubular member (not shown) with a consistently uniform diameter D2 and which does not possess a series of raised annular rib members 50 would thus undesirably tend to cause wellbore detritus to become lodged in the interstitial area between such diameter D2 and wellbore diameter D3, and thereby cause such a wellbore tool to become lodged in wellbore 18.

In a preferred embodiment as best shown in FIGS. 1 & 3, the wellbore tool 10 possess not just two, but preferably at least three longitudinally-spaced apart radially-outwardly protruding annular rib members 50 on an exterior periphery thereof. In the embodiment shown in FIGS. 1 & 3, five annular rib members 50 are shown on each wellbore tool 10a, 10b, separated by sequentially increasing longitudinal distances “a”, “2a”, “a+2a”, and “2a+(a+2a)” (ie in the form of a Fibonacci series) with the least longitudinally-separated pairs of ribs 50 being situated closest aperture 72 in tubular member 30.

As best seen from FIG. 1 and FIG. 3, each wellbore tool 10 of the present invention is preferably provided with a plurality of radially-outwardly extending (longitudinally-aligned) centralizer members 80, placed in uniform circumferentially-spaced intervals around the exterior periphery of the wellbore tool 10 to allow centralization of the wellbore tool 10a, 10b and frac\'ing tool 100 within wellbore 18. Centralizer members 80 may extend radially outwardly from the nominal periphery of the wellbore tool 10 a distance equal to, or less than, the distance which the annular rib members 50 extend.

In order to create a frac\'ing tool 100 for use in frac\'ing operations, a pair of a wellbore tools 10a & 10b may be threadably coupled at a respective same end 41 of each to a substantially tubular member 30, as shown in FIG. 5, and in cross-section in FIG. 6. Tubular member 30 may be a wellbore piping member 22 and have thread means (internal pipe thread at one end and external pipe thread at the opposite end), and thus be of the same diameter D4 of wellbore piping members 22, or alternatively may have a different diameter than wellbore piping members 22. Importantly, however, tubular member 30 which forms pat of frac\'ing tool 100 possesses at least one aperture 72 in the form of a “frac port” as earlier defined herein, which may be removed, burst, or revealed by means such as a sliding sleeve or provided in other manners known to persons of skill in the art, to provide an aperture 72 through which frac\'ing fluid may flow into the formation 19, 26 when frac\'ing tool 100 is lowered into position in a lower or horizontal portion of a wellbore 18. By placing a wellbore tool 10a, 10b of the above-described configuration at each of opposite ends 31, 32 of tubular member 30, at least two pairs of rib members 50 may be provided on opposite sides of aperture 72 to thereby isolate gap 70 (see FIG. 8,9) from pressurized frac\'ing fluid and allow pressure to be maintained in wellbore piping 22 and thus injected into formation 19, 26 via aperture 72.

FIG. 7a shows an alternate configuration for constructing the frac\'ing tool 100 of the present invention, comprising a tubular member 30 and frac port (aperture) 72 disposed between a pair of oppositely-facing wellbore tools 10a. Likewise, frac\'ing tool 100 Likewise, frac\'ing tool 100 may alternatively be constructed from a pair of oppositely facing wellbore tools 10b (not shown).

FIG. 7b shows an alternate configuration for frac\'ing tool 100 of the present invention, comprising a tubular member 30 and frac port (aperture) 72 disposed between a pair of similarly-facing wellbore tools 10a. Likewise, frac\'ing tool 100 may alternatively be constructed from a pair of similarly-facing wellbore tools 10b (not shown).

Whether configuration chosen for frac\'ing tool 100 is that of FIG. 7a or FIG. 7b will depend on the desired means of threadably coupling wellbore piping members 22 to frac\'ing tool 100.

FIGS. 8 & 9 show a variation, wherein instead of a pair of wellbore tools 10a, 10b being respectively disposed on opposite ends of a tubular member 30 having a frac port 72 therein, two pairs of wellbore tools 10a, 10b are respectively threadably coupled together, and each pair 10a, 10b threadably coupled to an opposite end of such tubular member 30 having frac port (aperture) 72 therein. Such an frac\'ing system using the wellbore tools 10 of the present invention and as shown in FIGS. 8 & 9 may be used to increase the number of annular ribs 50 interposed between frac port (aperture) 72 and gap 70, should further restriction be required.

FIG. 10 shows another embodiment of the frac\'ing tool 100 of the present invention, comprising a tubular member 30 which bears external pipe threads 25 at mutually opposite ends thereof. A pair of wellbore tools 10c, each having internal pipe threads 28 and at least a pair of longitudinally-spaced apart annular ribs 50 on an exterior periphery of each of wellbore tools 10c, may be threadably coupled to each of such mutually-opposite ends of tubular member 30 to form the frac\'ing tool 100 shown in FIG. 10.

FIG. 11 shows the frac\'ing tool 100 depicted in FIG. 10 threadably coupled via respective wellbore tools 10c to wellbore piping members 22, for subsequent insertion downhole in a wellbore 18 to conduct frac\'ing operations.

FIG. 12 shows a still-further embodiment of the frac\'ing tool 100 of the present invention, comprising a single unitary tubular member 30 having internally threaded mutual opposite ends, each of said mutually-opposite ends having as raised annular rib members 50 as described herein.

FIG. 13 shows a wellbore pipe string comprising a pair of wellbore piping members 22, having disposed between them and threadably coupled thereto a frac\'ing tool 100 of the configuration shown in FIG. 5. Alternatively, such wellbore piping members 22 could alternatively have threadably coupled to them (depending on whether externally or internally threaded at their mutually opposite ends) any of the frac\'ing tools 100 of the present invention shown in FIG. 7a, 7b, 10 or 12.

Various methods of conducting frac\'ing operations using the wellbore tool 10 and frac\'ing tool 100 of the present invention will now be described.

In a first method of the present invention for fracturing a hydrocarbon formation such method comprises the steps of firstly threadably coupling one end of a pair of wellbore tools 10, such as end 41 of respective wellbore tools 10a and 10b as shown in FIG. 5, to respectively opposite ends 31, 32 of a tubular member 30 having a frac port (aperture) 72 therein. Next, one end of the so-formed frac\'ing tool 100 is coupled to one end of wellbore piping to which further wellbore piping 22 is successively coupled to thereby successively insert said frac\'ing tool downhole in a pre-drilled wellbore 18 and to simultaneously thereby form a continuous pipe string leading down into the wellbore 18. Successive coupling of further wellbore piping members 22 is repeated until it is determined that frac port 72 has thereby is in a region of formation 19, 26 that is desired to be fractured. Advantageously, wellbore detritus may accumulate in the isolated regions a, 2a, a+2a, and 2a+(a+2a) extending between rib members 22 to better isolate gap region 70 from aperture 72.

Thereafter, fracturing fluid is pumped down such pipe string under pressure. Annular ribs 50 on frac\'ing tool 100 isolate gap 70 from aperture 72, and pressurized frac\'ing fluid flows into formation 19, 26 via aperture 72, thereby fracturing formation 19, 26 to thereby create fissures in said formation 19, 26 to thereby assist in increasing the permeability of the formation and the ability of hydrocarbon to more easily flow out of such formation.

In order to obtain an indication of the necessary dimensional parameters for a wellbore tool 10 of the present invention to properly function in the manner contemplated for effective frac\'ing, and in particular to determine dimensional parameters that allow a constructed frac\'ing tool 100 to provide an area intermediate two of such wellbore tools 10 that is sufficiently sealed from an interstitial area (ie gap 70) existing between the inner diameter D3 of a wellbore 18 and the outer diameter D4 of a wellbore piping 22, a proportional scale test apparatus 200 as shown in FIG. 14 was used.

As may be seen from FIG. 14, a fluid supply 210, having a fluid coupling 212 at one end thereof, was coupled to a tubular member 230 having two annular ribs 50a, 50b, separated by a distance “X1” of 4 inches.

A series of seven different-diameter annular rings 50a, 50b were successively placed about the periphery of tubular member 230, with each of rings 50a, 50b in each series having the identical outer diameter D2. Tubular member 230 had a series of apertures 270 therein placed about its circumference, to allow fluid flow into annular area A.

Diameter D2 for each of annular rings 50a, 50b was a series of fractions of Diameter D3, namely from 76.8%, 80%, 90%, 93%, 95%, 97%, and 98% of diameter D3. Tubular member 230 was situated in a simulated wellbore piping 222 of diameter D3, and fluid supplied at a constant volume to tubular member 230.

The dimensions D1, D3, and D4 were directly proportional to a particular typical wellbore pipe 22, namely to an internal diameter D1 of 5.5 inches, a nominal exterior diameter D4 of 6.0 inches, and a wellbore diameter D3 of 7.875 inches.

Pressure P1 of supplied fluid was measured using pressure gauge 250, at each of the series of ring Diameters D2 extending from 76.8% to 98% of wellbore diameter D3.

Table 1 below is a tabulation of the pressures (in MPa) achievable at location P2, for each of the seven ring sizes tested, using a constant volume supply of 108 L/min.

The fluid used was municipal water, at 10-15 degrees Celsius, filtered to City of Calgary standard.

TABLE 1 Pressure (D2 − D4)/ Area Restriction Differential D1 D2 D3 D4 D4 A1 A2 A3 100 − (A3 − A2)/A1 * 100 P1 − P2 (in) (in) (in) (in) (%) D2/D3 π * (D1)2/4 π * (D2)2/4 π * (D3)2/4 (in percent) (MPa) 5.5 6.048 7.875 6.0 0.8 .768 23.75 28.73 48.71 15.9

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