Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
PRESSURE PERFORATED WELL CASING SYSTEM
FIELD OF THE INVENTION
This invention relates in general to hydrocarbon well casing systems and, in
particular, to a novel well casing system that is pressure perforated after a
casing
string is assembled, inserted and cemented into a section of a recently
drilled
wellbore.
BACKGROUND OF THE INVENTION
Well casing is made up of casing joints and casing collars for connecting the
casing joints together to assemble a casing string. Well casing is well known
in
the art and used to line recently drilled hydrocarbon wellbores to prevent
borehole
collapse and provide a smooth conduit for inserting tools required to complete
the
well for production and to produce hydrocarbon from the well. Most hydrocarbon
wells drilled today are vertical bores extending down to proximity of a
production
zone and horizontal bores within the production zone. There are two ways
commonly used to complete a horizontal bore, plug-and-pen f (PNP) and openhole
multistage (OHMS).
The openhole multistage system has external casing packers that provide a seal
between a production casing and the horizontal bore. The production casing has
dropped-ball actuated sliding sleeves. The sliding sleeves open ports through
the
production casing. The sliding sleeves are opened in succession from the toe
to
the heel of the horizontal bore. The dropped balls are graduated in size to
pass
through each sliding sleeve until they reach the sliding sleeve to be opened
next.
When a ball is caught by a sliding sleeve the fracture fluid pressure opens
the
sliding sleeve exposing the ports, and the ball provides a seal to prevent
frac fluid
from going downhole past the opened sliding sleeve. This permits OHMS
systems to perform multiple fracture stimulations without the need to rig up
wireline or set plugs to perforate new intervals. Casing perforation is
unnecessary
because communication between the cased borehole and the productive
formation is afforded by each set of ports opened by the balls dropped to open
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sliding sleeves. When the entire horizontal bore has been fractured the balls
are
captured at the surface during flow back of the fracturing fluid.
With plug-and-perf, after assembly and insertion of the casing in the open
borehole, the casing is "cemented in" by circulating a cement slurry through
the
inside of the casing and out into the annulus through a casing shoe at the
bottom
of the casing string. The cement fills the annulus around the casing and
hardens
to prevent the migration of fluids between zones in the wellbore. Once
cemented
in, the casing is perforated in sections from toe to heel using a perforating
gun
system that is run into the well with wireline or completion tubing. The
perforating
guns are triggered from the surface to fire steel projectiles that penetrate
the
casing to let the hydrocarbon flow into the casing. After a section of casing
has
been perforated, the spent perforating guns are withdrawn and fracturing fluid
is
pumped down the casing to fracture the formation behind the perforations. When
fracturing of that section is completed, a fiber plug is run into the well
with the
next perforating gun system. The fiber plug is set in the casing up hole from
the
fractured section, before the perforating guns are fired to perforate a new
section
of the casing. This process is repeated until the entire horizontal bore has
been
plugged, perforated and fractured. Thereafter, the fiber plugs are milled out
to put
the horizontal bore into production.
OHMS and PNP each have their advantages and disadvantages. OHMS is more
expensive to install, but fracturing proceeds more quickly because the sliding
sleeves are opened in succession and fracturing can be performed with
virtually
no interruptions. However, OHMS is much less flexible in that once installed
it
cannot be reconfigured or changed. OHMS also has shorter reach because the
reach is restricted by the number of sliding sleeves that can be opened using
a
series of different sized balls that are pumped into the well. OHMS also
severely
restricts fracture fluid flow rates at the toe of the lateral well bore
because of the
ball seat size through which fracturing fluid must be pumped. OHMS bores are
likewise more difficult to re-complete, and the service life of the sliding
sleeves is
known to be limited. A further hazard is that sliding sleeves are sometimes
skipped because a wrong sized ball is dropped, a ball shatters before it can
seat
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in the sliding sleeve, or one or more of the openhole packers provide an
incomplete seal.
PNP offers complete flexibility because casing perforations can be located at
any
desired interval and the location can be dynamically determined as the
production
zone is being fractured. PNP also offers unlimited reach because newly
available
completion tubing can be pushed to the furthest extent that a horizontal bore
can
be drilled and cased. PNP is also secure because the casing is cemented in, so
fracture fluid has no place to migrate except into the formation. PNP can also
provide much more drainage area than OHMS, which can be advantageous. The
disadvantage of PNP is the time required to run the perforating gun strings
and
to set the plugs in the cased well bore. While each run is being performed the
fracturing crews sit idle. This .adds significantly to expense.
A disadvantage of both systems is the fracturing pump horsepower required to
complete the well. The interval fractured in OHMS systems is necessarily long
even though the fracture fluid ports are concentrated in a very small area
opened
by the sliding sleeve, and the interval fractured in PNP is preferably long in
order
to minimize idle time. Consequently, both OHMS and PNP require a large number
of high powered pump trucks; about 25,000 total horsepower, each with
attendant
crew. Those trucks must be scheduled, congregated and maintained onsite
throughout the well completion. This requires long term planning, complex
scheduling and significant expense.
Perforated casing is also known and is used for openhole completions in
certain
heavy oil reservoirs. However, perforated casing does not permit cementing or
well stimulation and its use is therefore limited.
There therefore exists a need for a novel well casing system that is pressure
perforated after it is assembled, inserted and cemented into a section of a
recently
drilled wellbore.
SUMMARY OF THE INVENTION
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It is therefore an object of the invention to overcome the disadvantages of
prior
art hydrocarbon well casing systems and provide a novel well casing system
that
is pressure perforated after it is assembled, inserted and cemented into a
section
of a recently drilled wellbore.
The invention therefore provides a pressure perforated well casing joint,
comprising: a pipe having a sidewall with a first end, a second end, an inner
surface, an outer surface and a burst pressure rating; an external tread on
each
of the first and second ends adapted to threadedly engage a casing collar; and
a
plurality of grooves cut in the .outer surface, each groove extending inwardly
from
the outer surface to an extent less than a thickness of the sidewall, so there
remains sidewall bottom material in each groove; whereby fluid pressure
applied
within the pressure perforated well casing will cause the sidewall bottom
material
in the grooves to rupture before the burst pressure rating of the pipe is
reached,
thereby opening a slot through the sidewall at each of the plurality of
grooves
subjected to the fluid pressure.
The invention further provides a pressure perforated well casing collar,
comprising: a pipe having a sidewall with a first end, a second end, an inner
surface, an outer surface and a burst pressure rating; an internal tread on
each
of the first and second ends adapted to threadedly engage an external thread
on
a casing joint; a plurality of grooves cut in the outer surface, each groove
extending inwardly from the outer surface to an extent less than a thickness
of
the sidewall, so there remains sidewall bottom material in each groove;
whereby
fluid pressure applied within the pressure perforated well casing collar will
cause
the sidewall bottom material in the grooves to rupture before the burst
pressure
rating of the casing collar is reached, thereby opening a slot through the
sidewall
at each of the plurality of grooves.
The invention yet further provides a pressure perforated well casing system,
comprising: a well casing joint and a well casing collar respectively having a
plurality of grooves cut in an outer surface thereof, the grooves being cut to
an
equal depth in the outer surface, each groove having sidewall bottom material
remaining in a bottom of the groove; whereby sufficient fluid pressure applied
to
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the grooves cause the sidewall bottom material in the respective grooves to
rupture before a burst pressure rating of the well casing joint or the well
casing
collar is reached, thereby opening slots through the sidewalls at each of the
respective grooves under sufficient fluid pressure.
BRIEF DESCRIPTION OF THE DRAWINGS
Having thus generally described the nature of the invention, reference will
now
be made to the accompanying drawings, in which:
FIG. 1 is a schematic view of an embodiment of a pressure perforated casing
joint
of the well casing system in accordance with the invention;
FIG. 2 is a schematic view of another embodiment of a pressure perforated
casing joint of the well casing system in accordance with the invention;
FIG. 3 is a schematic view of yet another embodiment of a pressure perforated
casing joint of the well casing system in accordance with the invention;
FIG. 4 is a schematic view of yet a further embodiment of a pressure
perforated
casing joint of the well casing system in accordance with the invention;
FIG. 5 is a schematic view of a pressure perforated casing collar in
accordance
with the invention;
FIG. 6 is a schematic cross sectional view of a groove cut in a sidewall of
the
casing joint or the casing collar in accordance with the invention;
FIG. 7a is a schematic cross sectional view of other grooves cut in the
sidewall
of a casing joint or the casing collar in accordance with the invention;
FIG. 7b is a top plan view of one embodiment of another groove cut in the
sidewall
of a casing joint or the casing collar in accordance with the invention;
FIG. 7c is a longitudinal cross sectional view taken along lines 5c-5c of the
groove
shown in FIG. 7b;
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FIG. 7d is a cross sectional view taken along lines 5d-5d of the groove shown
in
FIG. 7b;
FIG. 7e is a top plan view of yet another embodiment of a groove cut in the
sidewall of a casing joint or the casing collar in accordance with the
invention;
FIG. 7f is a cross sectional view taken along lines 5f-5f of FIG. 7e;
FIG. 8a is a schematic cross sectional view in longitudinal section of a
further
embodiment of a groove cut in the sidewall of a casing joint or the casing
collar
in accordance with the invention;
FIG. 8b is a schematic cross- sectional view in longitudinal section of the
groove
shown in FIG. 8a after the casing joint or the casing collar has been pressure
perforated and a formation in which the casing is cemented has been fractured;
FIG. 9 is a schematic diagram of one embodiment of a casing string in
accordance with the invention; and
FIG. 10 is a schematic diagram of another embodiment of a casing string in
accordance with the invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The invention provides a pressure perforated well bore casing system that
permits hydrocarbon wells to be completed and fractured with greater
efficiency
and at less expense than prior art casing and completion systems. The casing
system in accordance with the invention eliminates the need for sliding
sleeves,
openhole packers, wirelines, perforating gun systems, plugs and plug mills. In
one embodiment the casing system in accordance with the invention also reduces
the pump horsepower requirement for completing a well by up to 60%, thus
significantly reducing completion cost and simplifying job scheduling. The
well
casing system in accordance with invention also significantly reduces
fracturing
crew idle time while providing fracture location flexibility. The well casing
system
in accordance with invention may be used in vertical or horizontal well bores
and
is equally effective and efficient in either a vertical or a horizontal well
bore.
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FIG. 1 is a schematic view of an embodiment of a pressure perforated casing
joint 10 of the well casing system in accordance with the invention. The
casing
joint 10 has a first end 12, a second end 14 and a sidewall 16. An external
thread
18 cut on each of the first end 12 and the second end 14 is adapted to
threadedly
engage a casing collar (not shown but well known in the art) for connecting
one
casing joint 10 to another. The casing joint 10 has a length "L" and an
outside
diameter "OD". The outside diameter is typically 4.5" (11.4 cm), 5.5" (13.97
cm),
7.5" (19.05 cm) or 7.625" (19,37 cm), although 3" (7.62 cm), and other
diameters
of casing are ocassionally used. The length "L" is a matter of design choice
selected by a well consultant or operator. The length "L" may be as short as
3'
(91.4 cm) or as long as a drill rig can handle, typically 40' (12.19 m). A
plurality of
grooves 20 are cut into the sidewall 16. The grooves 20 in this embodiment are
shown to be straight axial grooves, but the shape of the grooves 20 is a
matter of
design choice. It is only important that the grooves 20 are spaced far enough
apart that any potential erosion (known in the art as "wash") from fracturing
operations will not join two or more grooves 20, which could compromise the
strength of the casing joint 10.
In one embodiment, each groove 20 is about 0.375"-0.5" (1-1.27 cm) wide and
1"-3" (2.5-7.6 cm) long. As will be explained below with reference to FIGs. 6
and
7, the grooves 20 are not cut through the sidewall 16. Rather, a predetermined
thickness of sidewall bottom Material is left between a bottom of each groove
20
and an inner wall 22 of the casing joint 10. The thickness of the sidewall
bottom
material is calculated to have a rupture pressure (yield strength) that is
less than
a burst pressure rating of the casing joint 16, yet greater than the fluid
pressure
normally required to cement the casing in the well bore, which is typically
about
3,000 psi (20,648 KPa). At the predetermined rupture pressure the sidewall
bottom material will rupture, opening a slot though the casing sidewall. The
rupture pressure is also far below the fluid pressure potential of modern
fracturing
pumps and completion tubing, which is at least 15,000 psi (103,421 KPa).
Consequently, the casing joint 10 can be run into a recently bored well bore
without hazard of well bore material intrusion, and it can be cemented in
without
danger of cement intrusion into the casing string. Once the casing 10 is
installed
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pumps and completion tubing, which is at least 15,000 psi (103,421 KPa).
Consequently, the casing joint 10 can be run into a recently bored well bore
without hazard of well bore material intrusion, and it can be cemented in
without
danger of cement intrusion into the casing string. Once the casing 10 is
installed
in a recently drilled well bore and cemented in, it can be selectively
perforated
using a downhole fracturing tool, the description of which is beyond the scope
of
this disclosure. In one embodiment, a shallow groove 24 is cut in the interior
wall
22 of each end 12, 14 of the casing joint 10 when the exterior threads 18 are
being cut. The groove 24 is detectable by a collar locator to provide a
positive
identification of any casing joint 10 in an assembled casing string, which
will be
described below in more detail with reference to FIG. 9.
FIG. 2 is a schematic view of another embodiment of a pressure perforated
casing joint 30 of the well casing system in accordance with the invention.
The
casing joint 30 has a first end 32, a second end 34, a sidewall 36 and an
external
thread 38 cut on each end of the sidewall 36. The casing joint 30 is identical
to
the casing joint 10 described above with an exception that the grooves 40 cut
in
the sidewall 36 are radial rather than axial grooves. It should be noted that
although the grooves 40 are shown to be straight radial grooves, that is a
matter
of design choice. It is only important that the grooves 40 are spaced far
enough
apart that any potential erosion from fracturing operations will not join two
or more
grooves 40, which could compromise the strength of the casing joint 30.
FIG. 3 is a schematic view of yet another embodiment of a pressure perforated
casing joint 50 of the well casing system in accordance with the invention.
The
casing joint 50 has a first end 52, a second end 54, a sidewall 56 and an
external
thread 58 cut on each end of the sidewall 56. The casing joint 50 is identical
to
the casing joint 10 described above with an exception that the grooves 60 cut
in
the sidewall 56 are circular trepans rather than axial grooves. It should be
noted
that although the grooves 60 are shown to be circular, they may be any shape
in
which the beginning and ending of the groove overlap. Consequently, the
grooves
60 may be oval, square, rectangular, triangular, oblong, obround or irregular
in
shape. It is only important that the grooves 60 are spaced far enough apart
that
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any potential erosion from fracturing operations will not join two or more
grooves
60, which could compromise the strength of the casing joint 50.
FIG. 4 is a schematic view of yet a further embodiment of a pressure
perforated
casing joint 70 of the well casing system in accordance with the invention.
The
casing joint 70 has a first end 74, a second end 76 and an external thread 78
on
each of the first and second ends adapted to threadedly engage a casing
collar.
In this embodiment, grooves 80 in the casing joint 70 are arranged in clusters
(cluster-1 - cluster-n). A total area of the clusters is less than a total
area of the
sidewall 72. The shape and the number of grooves in each cluster 1-n is a
matter
of design choice, as is the number of clusters on the pressure perforated
casing
joint 70. The pressure perforated casing joint 70 may have 1 cluster or
several
clusters. Typically, each pressure perforated casing joint has 1-3 clusters.
If there
is more than one cluster, the clusters 1-n are spaced apart. The shape of the
grooves in any cluster need not be the same, as shown in cluster 2. In this
example, cluster 1 is spaced from the first end 74 by an interval u-1 without
grooves. Cluster n is spaced from the second end 76 by an interval u-n without
grooves. Each cluster 1-n is spaced from any other cluster 2-(n-1) by an
interval
u-2, u-3, etc. without grooves. The intervals without grooves u-1 - u-n may be
the
same length or of different lengths. The purpose of the intervals u-1 - u-n is
to
provide an area for landing packers of the downhole fracturing tool (not shown
or
described). In one embodiment, the casing joint 70 has a length "L" of 40'
(12.19
m) and 3 clusters (cluster 1-3). Each cluster 1-3 is about 2'-3' (0.61-0.91 m)
in
length and each interval without grooves (u-1 - u-4) is about 7.75'- 8.5'
(2.29-
2.59 m) in length.
In one embodiment the number of grooves and the size of each of the grooves in
each cluster 1-n opens slots through the sidewall 72 having a predetermined
total
area when the grooves in that cluster are ruptured using frac fluid pressure,
that
predetermined total area being an area through which fracturing fluid can be
pumped at a constant rate by about 10,000 horsepower of pump capacity. This
reduces the pump horsepower requirement for completing a well bore by about
60%, thus significantly reducing completion cost and simplifying job
scheduling.
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length of the casing collar 82 is typically 2'-4' (0.61-1.22 m), though the
length is
a matter of design choice. The casing collar 82 has a first end 83, a second
end
84, a sidewall 85 and an internal thread 86 cut inside of each end of the
sidewall
85. The internal threads 86 mate with the external threads of a corresponding
size of casing joint, in a manner well understood in the art. Consequently,
the
outside diameter "O.D." of the casing collar 82 is the same as the outside
diameter of any casing collar of a corresponding weight and grade of casing. A
plurality of grooves 88 are cut in the sidewall 85, between the internal
threads on
the first end 83 and the second end 84. The number of grooves 88 cut in the
sidewall 85 is a matter of design choice. The grooves 88 may also be grouped
into clusters as described above with reference to FIG. 4, also as a matter of
design choice. In one embodiment when the collar 82 is pressure perforated,
the
grooves 88 cut in the sidewall 85 open slots through the sidewall 85 having a
predetermined total area through which fracturing fluid can be pumped at a
constant rate by about 10,000 horsepower of pump capacity. The shape and size
of the grooves 88 is also a matter of design choice. It is only important that
the
grooves 88 are spaced far enough apart that any potential erosion from
fracturing
operations will not join two or more grooves 88, which could compromise the
strength of the casing collar 82.
The casing collar 82 provides further flexibility to a well operator, who can
assemble casing strings with plain casing joints and the pressure perforated
casing collars 82, pressure perforated casing joints 10, 30, 50, 70 and plain
casing collars, or pressure perforated casing joints 10, 30, 50, 70 and
pressure
perforated casing collars 82, in any combination, as will be described below
in
more detail with reference to FIGs. 9 and 10.
FIG. 6 is a schematic cross sectional view of a groove 60 cut in the sidewall
56
of the casing joint 50 shown in FIG. 3. The sidewall 56 has a thickness "A".
The
thickness "A" is dependent on the outside diameter and the grade of the casing
joint. The groove 60 is cut to a depth that leaves sidewall bottom material 61
between the bottom of the groove and the inner wall of the casing joint 56.
The
sidewall bottom material 61 has a thickness "B". The thickness "B" of the
sidewall
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thickness "A" is dependent on the outside diameter and the grade of the casing
joint. The groove 60 is cut to a depth that leaves sidewall bottom material 61
between the bottom of the groove and the inner wall of the casing joint 56.
The
sidewall bottom material 61 has a thickness "B". The thickness "B" of the
sidewall
bottom material is computed using methods described below to rupture at a
desired rupture pressure (yield strength). Fluid pressure within the casing
sidewall that exceeds the rupture pressure causes the sidewall bottom material
to burst, opening a slot through the casing sidewall 56. Any material 62
surrounded by the groove 60 need not be removed. The material 62 may be
machined to a point or a wedge to facilitate well cement perforation, as will
be
explained below with reference to FIGs. 7e and 7f.
The thickness "B" may be calculated, for example, using a formula (Formula 1)
described on page 16 and 17 of American Petroleum Institute Bulletin 5C3,
Fifth
Edition, July, 1989. The formula is:
Py = 0.7854(D2 ¨ d2)Yp (Formula 1)
where: Py = pipe body yield strength in pounds rounded to nearest 1000;
Yp= Specified minimum yield strength for pipe, psi;
D = specified outside diameter, inches;
d = specified inside diameter, inches.
Table 1 shows examples of commonly used sizes and grades of well casing, and
the sidewall bottom material thickness (SBT) for each to achieve a perforation
rupture pressure of 4,000 psi (27,579 KPa) and 7,000 psi (48,263 KPa).
TABLE 1
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Pipe Outside Inside Burst SBT SBT
Grade Diameter Diameter Pressure (4,000 psi) (7,500 psi)
Lb/FT (inches) (inches) PSI
N80 4.5 4.0 7,778 0.122" 0.240"
11.60
P110 4.5 " 4.0 10,694 0.087" 0.169"
11.60
N80 5.5 4.5 12,727 0.137" 0.270"
26.30
P110 5.5 4.5 17,500 0.098" 0.191"
26.30
4140 5.5 4.00 28,636 0.079" 0.154"
38.03
FIG. 7a is a schematic cross sectional view of other grooves 40a, 40b and 40c
cut in the sidewall 36 of the casing joint 30 described above with reference
to
FIG. 2. As seen, the grooves may be V-shaped as shown at 40a, keystone
shaped as shown at 40b or U-shaped as shown at 40c. If the groove is U-shaped,
the bottom of the U is used as the measure of the thickness "B" of the
sidewall
bottom material described above with reference to FIG. 6. As understood by
those skilled in the art, if the casing joints 10, 30, 50, 70 or the casing
collars 82
are to be run into high-temperature, high-pressure production zones where they
will be subject to considerable hoop stress, U-shaped grooves or grooves
without
right angle cuts, i.e. cuts having corners with a radius, may be preferable.
In
general, square or U-shaped grooves are faster to cut as they require only one
machining pass, and bits for generally square grooves can be ground at the
corners to provide a radius to corners in the groove. However, the shape of
the
groove is not material to the practice of the invention provided that all
grooves 20,
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40, 60, 80 are cut to the same, consistent depth so the sidewall bottom
material
always has about the same thickness for any particular diameter and grade of
casing pipe, provided that excessive hoop stress is not a significant factor.
FIG. 7b is a top plan view of one embodiment of a groove 20a cut in the
sidewall
of a casing joint 10, 30, 50, 70 or a casing collar in accordance with the
invention.
In this embodiment, a narrow groove 43 is cut in a substantially rectangular
or
obround pattern to leave a sidewall bottom material thickness, computed as
described above with reference to Formula 1. A cross-wise groove 45 is then
optionally cut to form two narrow columns 44a, 44b of the sidewall material,
as
best visualized with reference to FIG. 7c, which is a longitudinal cross
sectional
view taken along lines 5c-5c. of the groove 20a shown in FIG. 7b, and FIG. 7d,
which is a cross sectional view taken along lines 5d-5d of the groove 20a
shown
in FIG. 7b. The narrow columns 44a, 44b function to break up cement
surrounding
a casing 10, 30, 50 when the casing is pressure perforated and the groove 20a
ruptures under fracturing fluid pressure. In one embodiment the grooves 43, 45
are filled with a coating compound 47 designed to protect the machined
surfaces
while the casing 10, 30, 50, 70 is in storage and while it is being run into a
recently
drilled well bore. The coating compound also prevents the intrusion of cement
into the grooves 20, 40, 60, 80, 20a, etc., and remains soft to facilitate
rupture of
the sidewall bottom material under fluid pressure. Such coating compounds are
available, for example, from Masterbond, Hackensack, NJ, U.S.A.
FIG. 7e is a top plan view of another embodiment 20b of a groove cut in the
sidewall of a casing joint 10, 30, 50, 70 or casing collar 82 in accordance
with the
invention. The groove 20b is similar to the groove 20a described above with
reference to FIGs. 5b-5d, except that the narrow columns are further machined
to form pointed wedges 48a, 48b. The pointed wedges 48a, 48b, best seen in
FIG. 7f, which is a cross sectional view taken along lines 5f-5f of FIG. 7e.
The
pointed wedges 48a, 48b slice through well cement surrounding the casing
joints
10, 30, 50, 70 described above when the well casing is pressure perforated. In
this embodiment the grooves 43, 45 are likewise filled with a coating compound
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47 designed to protect the machined surfaces while the casing 10, 30, 50, 70
is
in storage and while it is being run into a recently drilled well bore.
FIG. 8a is a schematic cross sectional view in longitudinal section of one of
the
grooves cut in the sidewall 16 of the casing joint 10 described above with
reference to FIG. 1, or the sidewall 85 of the casing collar 82 described
above
with reference to FIG. 5. As will be understood by those skilled in the art,
the
groove 20 has been cut with a wheel-type slotting cutter well known in the
art.
Consequently, the ends 26 are concave, reflecting the diameter of the slotting
cutter. This is one fast and convenient way of cutting the grooves 20. The
same
type of tool can be used to cut the grooves 40 seen in FIG. 2. In this
embodiment,
the casing joint is 4140 heat-treated steel casing pipe, having an outside
diameter
of 4.5" (11.43 cm) and the thickness "B" of the sidewall bottom material 28 of
the
groove 20 is about 0.15" (3.81mm), which will rupture at about 7,500 psi
(51,711
KPa) of fluid pressure, opening a slot through the sidewall 16 (see Table 1).
In
one embodiment, the groove.20 is filled with a coating compound 47 designed to
protect the machined surfaces while the casing 10 is in storage and while it
is
being run into a recently drilled well bore.
FIG. 8b is a schematic cross sectional view in longitudinal section of the
groove
shown in FIG. 8a after the casing has been pressure perforated to open a slot
20 through the casing 10 sidewall 16 or collar 82 sidewall 85, and
fracturing has
been completed in a formation 150 in which the casing 10 or collar 82 is
cemented
by cement slurry 148. As seen, fragments 28a of the sidewall bottom material
28
(see FIG. 8) of the casing 10 have been driven to varying degrees into the
formation 150. The coating compound and the hardened cement slurry 148 were
disintegrated by the force of the impact when the casing 10 was pressure
perforated, and ground into particles by the sand-laden fracturing fluid.
Fractures
152 have propagated deeply into the formation 150 and filled with sand carried
by the fracturing fluid, in a manner well known in the art. The ends of the
groove
26a, 26b have been eroded to some extent by the fracturing fluid pumped into
the formation 150. The amount of erosion is dependent on the concentration of
sand in the fracturing fluid, and other factors well understood in the art.
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FIG. 9 is a schematic diagram of a casing string 90 assembled in accordance
with the invention as it is inserted into a recently bored well bore. In this
embodiment the casing string 90 is made up of plain casing joints (pc)
connected
end-to-end between one or more joints of pressure perforated casing joints 10,
30, 50, 70, or casing collars 82 (pp) made from the same size and grade of
pipe.
Plain casing collars that are part of the casing string 90 are not shown. The
number of plain casing joints in each plain casing (pc) interval 92, 96, 100,
104,
108, 112, 116 is a matter of design choice dependent on formation properties
and
other factors. The number of plain casing joints in each plain casing (pc)
interval
is typically 1-3 plain casing joints. The number of pressure perforated casing
joints
in each pressure perforated casing (pp) interval 94, 98, 102, 104, 106, 110,
114
is typically 1, though any number of pressure perforated casing (pp) joints
may
be used. The number of pressure perforated casing collars 82 in each pressure
perforated casing collar (pp) interval 94, 98, 102, 104, 106, 110, 114 is 1.
The
length of each pressure perforated casing joint (pp) is also a matter of
design
choice, as is the length of each pressure perforated casing collar. Each
pressure
perforated casing joint (pp) may be as short as 3' (0.91 m) or as long as 40'
(12.19
m). Each pressure perforated casing collar (pp) is typically about 2'-3' (0.61-
0.91
m). Each pressure perforated casing joint or casing collar (pp) may have
grooves
of any size, any shape, and any number of clusters, as a matter of design
choice
and operative constraints described above and understood in the art.
FIG. 10 is a schematic diagram of another casing string 120 in accordance with
the invention. The casing collars required in the casing string 120 may be
plain
casing collars or pressure perforated casing collars 82. The casing string 120
is
entirely made up of the pressure perforated (pp) casing joints 10, 30, 50, 70
and
plain casing collars or pressure perforated (pp) casing collars 82 in
accordance
with the invention. Each pressure perforated casing joint (pp) in the casing
string
120 may be a casing joint 10, 30, 50 or 70, or any combination of same. In one
embodiment all of the casing joints in the casing string 120 are the same but
this
is also a matter of design choice. The casing string 120 offers more
flexibility in
terms of locating fracture zones during well completion.
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CA 2978566 2017-09-08
The explicit embodiments of the invention described above have been presented
by way of example only. The scope of the invention is therefore intended to be
limited solely by the scope of the appended claims.
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CA 2978566 2017-09-08
