U.S. patent application number 13/037036 was filed with the patent office on 2012-08-30 for wellbore tool for fracturing hydrocarbon formations, and method for fracturing hydrocarbon formations using said tool.
This patent application is currently assigned to FRAC ADVANTAGE STIMULATION TOOLS INC.. Invention is credited to Emil GROVES.
Application Number | 20120217014 13/037036 |
Document ID | / |
Family ID | 46718216 |
Filed Date | 2012-08-30 |
United States Patent
Application |
20120217014 |
Kind Code |
A1 |
GROVES; Emil |
August 30, 2012 |
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.
Inventors: |
GROVES; Emil; (US) |
Assignee: |
; FRAC ADVANTAGE STIMULATION TOOLS
INC.
Calgary
CA
|
Family ID: |
46718216 |
Appl. No.: |
13/037036 |
Filed: |
February 28, 2011 |
Current U.S.
Class: |
166/308.1 ;
166/177.5 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 17/10 20130101; E21B 33/12 20130101 |
Class at
Publication: |
166/308.1 ;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A wellbore tool for insertion in a wellbore and 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 first
thread means adapted for threadable connection to thread means
disposed on an end of wellbore piping extending into said wellbore,
and at an opposite end having second thread means; and (ii) a pair
of longitudinally-spaced apart radially-outwardly protruding
annular rib members located on an exterior periphery of said
tubular member intermediate said thread means, each rib member of
an outer diameter less than said wellbore but greater than said
outer diameter of said wellbore piping.
2. A wellbore tool as claimed in claim 1, wherein said outer
diameter of said annular rib members is at least 24% greater than
said outer diameter of said piping.
3. A wellbore tool as claimed in claim 1, wherein said wellbore
tool when situated in said wellbore is adapted to provide a
cross-sectional clearance area between at least one of 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 wellbore tool.
4. A wellbore tool as claimed in claim 1, having at least three
longitudinally-spaced apart radially-outwardly protruding annular
rib members located on an exterior periphery of said tubular
member.
5. A wellbore tool as claimed in claim 4, wherein a longitudinal
distance separating a second of said at least three annular rib
members from a first of said at least three annular rib members is
less than a distance separating a third of said at least three
annular rib members from said second annular ring member.
6. A wellbore tool as claimed in claim 5, wherein longitudinally
spaced apart distances between each of said annular ring members
follows and is proportional to a Fibonacci sequence.
7. A wellbore tool as claimed in claim 1, wherein said opposite end
is adapted for threaded connection to a threaded distal end of
another wellbore piping.
8. A wellbore tool as claimed in claim 2 wherein said opposite end
is adapted for threaded connection to a threaded distal end of
another wellbore piping.
9. A wellbore tool as claimed in claim 3 wherein said opposite end
is adapted for threaded connection to a threaded distal end of
another wellbore piping.
10. A wellbore tool as claimed in claim 1 further having a
plurality of radially-outwardly extending but
longitudinally-aligned centralizers members placed in uniform
circumferentially-spaced intervals around the exterior periphery of
the wellbore tool to allow centralization of the tool within said
wellbore.
11. A wellbore tool as claimed in claim 2 further having a
plurality of radially-outwardly extending but
longitudinally-aligned centralizers members placed in uniform
circumferentially-spaced intervals around the exterior periphery of
the wellbore tool to allow centralization of the tool within said
wellbore.
12. A wellbore tool as claimed in claim 3 further having a
plurality of radially-outwardly extending but
longitudinally-aligned centralizers members placed in uniform
circumferentially-spaced intervals around the exterior periphery of
the wellbore tool to allow centralization of the tool within said
wellbore.
13. A wellbore tool as claimed in claim 2 wherein said opposite end
is adapted for threaded connection to a threaded distal end of
another wellbore tool.
14. A wellbore tool as claimed in claim 2 having a length ranging
from at least a nominal outer diameter of said tool to a length
approximately 7 times said nominal outer diameter.
15. A wellbore tool as claimed in claim 3 having a length ranging
from at least a nominal outer diameter of said tool to a length
approximately 7 times said nominal outer diameter.
16. 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; (ii) external/internal thread means at
a first end thereof adapted for threadable connection to mating
thread means disposed on an end of said first wellbore piping
member, and at an opposite end thereof having external/internal
thread means adapted for threadable connection to thread means
disposed on an end of said second wellbore piping member; (iii) at
least one pair of longitudinally-spaced apart radially-outwardly
protruding annular rib members, each respectively located on an
exterior periphery of said tubular member proximate at respectively
opposite ends thereof, each of said rib members of a diameter
greater than a nominal outer diameter of said first and second
wellbore piping members; and (iii) each of said at least one pair
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.
17. The frac'ing tool as claimed in claim 16, each of said rib
members of a diameter at least 24% greater than a nominal outer
diameter of said first and second wellbore piping members.
18. A frac'ing tool as claimed in claim 16, said frac'ing tool when
situated in said wellbore adapted to provide a radial
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.
19. 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 claimed in claim 1, 2 or 3 to respectively
opposite ends of a tubular member so as to situate said tubular
member between said two tools; (ii) coupling a second 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 and causing said
fracturing fluid to flow into said formation via an aperture
created in said tubular member situated between said pair of
wellbore tools.
20. 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 a frac'ing tool as
claimed in claim 16, 17, or 18 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.
Description
FIELD OF THE INVENTION
[0001] 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 AND DESCRIPTION OF THE PRIOR ART
[0002] 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.
[0003] 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.
[0004] 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.
[0005] 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).
[0006] Prior art systems such as those described above are used in
conjunction with other systems of isolation in the casing. These
systems include: [0007] (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; [0008] (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; [0009] (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; [0010] (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; [0011] (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; [0012] (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.
[0013] 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 OF THE INVENTION
[0014] 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.
[0015] 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: [0016] (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 [0017] (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.
[0018] 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
[0019] 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.
[0020] 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.
[0021] 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: [0022] (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; [0023] (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 [0024] (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.
[0025] 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: [0026] (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; [0027] (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. [0028] (iii) each of said at least
two pairs of longitudinally-spaced apart radially-outwardly
protruding annular rib members separated by an intermediate
distance; and [0029] (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.
[0030] 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.
[0031] 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.
[0032] 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: [0033] (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 [0034] (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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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).
[0045] 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
[0046] 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:
[0047] FIG. 1 is a side elevation view of one embodiment of a
wellbore tool of the present invention;
[0048] FIG. 2 is a cross-sectional view taken along plane A-A of
FIG. 1;
[0049] 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;
[0050] FIG. 4 is a cross-sectional view taken along plane B-B of
FIG. 3;
[0051] FIG. 5. is a side elevation view of one embodiment of the
integral frac'ing tool of the present invention;
[0052] FIG. 6 is a cross-sectional view taken along plane C-C of
FIG. 5;
[0053] 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;
[0054] 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;
[0055] 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.
[0056] 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;
[0057] FIG. 9 is an enlarged view of the horizontal wellbore and
the multi-frac'ing method shown in FIG. 8;
[0058] FIG. 10 is a perspective cut-away view showing one manner of
construction of a frac'ing tool of the present invention;
[0059] 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;
[0060] 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;
[0061] FIG. 13 is a reduced perspective view, showing the frac'ing
tool of FIG. 5 installed between sections of wellbore piping;
[0062] 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
[0063] 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 OF PREFERRED EMBODIMENTS
[0064] 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.
[0065] 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.
[0066] 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.
[0067] 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.
[0068] 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 .pi.*(D3).sup.2/4-.pi.*(D2).sup.2/4), and
thus allow frac'ing pressure to be directed, via aperture 50, into
formation 19, 26 where it is desired.
[0069] 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,).
[0070] 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.
[0071] 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.
[0072] 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.
[0073] 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.
[0074] 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).
[0075] 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).
[0076] 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.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
Method of Conducting Frac'ing Operations Using Wellbore Tools and
Frac'ing Tools as Described Above
[0082] 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.
[0083] 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.
[0084] 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.
Example 1
[0085] 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.
[0086] 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.
[0087] 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.
[0088] 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.
[0089] 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.
[0090] 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.
[0091] 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.
[0092] The fluid used was municipal water, at 10-15 degrees
Celsius, filtered to City of Calgary standard.
TABLE-US-00001 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 .pi. * (D1).sup.2/4 .pi. *
(D2).sup.2/4 .pi. * (D3).sup.2/4 (in percent) (MPa) 5.5 6.048 7.875
6.0 0.8 .768 23.75 28.73 48.71 15.9 1.0 5.5 6.300 7.875 6.0 5.0
.800 23.75 31.17 48.71 26.2 2.1 5.5 7.088 7.875 6.0 18.1 .900 23.75
39.45 48.71 61.0 4.3 5.5 7.324 7.875 6.0 22.1 .930 23.75 42.17
48.71 72.3 6.7 5.5 7.481 7.875 6.0 24.7 .950 23.75 43.96 48.71 80.0
9.9 5.5 7.639 7.875 6.0 27.3 .970 23.75 45.83 48.71 87.9 13.2 5.5
7.718 7.875 6.0 28.6 .980 23.75 46.78 48.71 91.9 14.1
[0093] As may be seen from the above results, upon the percentage
of area restriction achieved by the rings 50a, 50b being equal to
or greater than 95% of the diameter of the wellbore (ie being equal
to or greater than 24.7% of the nominal outer diameter D4 of the
tubular member 230), was an order of magnitude pressure
differential (ie 9.9 times) able to be maintained.
[0094] Put in another manner, with an area restriction created by
the annular rings of 80% or greater (ie
100-(A3-A2)/A1*100.gtoreq.80%) an order of magnitude pressure
differential (ie 9.9 times) was able to be achieved, and up to a
pressure differential of 14.1 times achievable with an area
restriction of 91.9%.
[0095] The foregoing description of the disclosed embodiments is
provided to enable any person skilled in the art to make or use the
present invention. Specifically, various modifications to those
embodiments will be readily apparent to those skilled in the art,
and the generic principles defined herein may be applied to other
embodiments without departing from the spirit or scope of the
invention. 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.
[0096] Where reference to an element in the singular, such as by
use of the article "a" or "an", such is not intended to mean "one
and only one" unless specifically so stated, but rather "one or
more".
[0097] Moreover, no element of any of the claims appended to this
application is to be construed under the provisions of 35 USC
.sctn.112, sixth paragraph as being limited to the particular
embodiment shown, unless the claim element is expressly recited
using the exact phrase "means for" or "step for".
[0098] 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.
* * * * *