Note: Descriptions are shown in the official language in which they were submitted.
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MULTI-ZONE FRACTURING COMPLETION
Inventors: John Edward Ravensbergen
Lyle Erwing Laun
John G. Misselbrook
BACKGROUND
Field of the Disclosure
[0001] The present disclosure relates generally to a downhole
tool for use
in oil and gas wells, and more specifically, to a ported completion that can
be employed
for fracturing in multi-zone wells.
Description of the Related Art
100021 Oil and gas well completions are commonly performed after
drilling
hydrocarbon producing wellholes. Part of the completion process includes
running a well
casing assembly into the well. The casing assembly can include multiple
lengths of
tubular casing attached together by collars. A standard collar can be, for
example, a
is relatively short tubular or ring structure with female threads at either
end for attaching to
male threaded ends of the lengths of casing. The well casing assembly can be
set in the
wellhole by various techniques. One such technique includes filling the
annular space
between the wellhole and the outer diameter of the casing with cement.
100031 After the casing is set in the well hole, perforating and
fracturing
operations can be carried out. Generally, perforating involves forming
openings through
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the well casing and into the formation by commonly known devices such as a
perforating
gun or a sand jet perforator. Thereafter, the perforated zone may be
hydraulically
=
isolated and fracturing operations are performed to increase the size of the
initially-
formed openings in the formation. Proppant materials are introduced into the
enlarged
openings in an effort to prevent the openings from closing.
[0004] More recently, techniques have been developed
whereby
perforating and fracturing operations are performed with a coiled tubing
string. One such
technique is known as the Annular Coil Tubing Fracturing Process, or the ACT-
Frac
Process for short, disclosed in U.S. Patent Nos, 6,474,419, 6,394,184,
6,957,701. To
io practice the techniques described in the aforementioned patents,
the work string, which
includes a bottom hole assembly (BHA), generally remains in the well bore
during the
fracturing operation(s).
[0005] One method of perforating, known as the sand jet
perforating
procedure, involves using a sand slurry to blast holes through the casing, the
cement and
is into the well formation. Then fracturing can occur through the
holes. One of the issues
with sand jet perforating is that sand from the perforating process can be
left in the well
bore annulus and can potentially interfere with the fracturing process.
Therefore, in some
cases it may be desirable to clean the sand out of the well bore, which can be
a lengthy
process taking one or more hours per production zone in the well. Another
issue with
zo sand jet perforating is that more fluid is consumed to cut the
perforations and either
circulate the excess solid from the well or pump the sand jet perforating
fluid and sand
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into the zone ahead of and during the fracture treatment. Demand in industry
is going
toward more and more zones in multi-zone wells, and some horizontal type wells
may
have 40 zones or more. Cleaning the sand from such a large number of zones can
add
significant processing time, require the excessive use of fluids, and increase
the cost. The
excessive use of fluids may also create environmental concerns. For example,
the
process requires more trucking, tankage, and heating and additionally, these
same
requirements are necessary when the fluid is recovered from the well.
[0006] Well completion techniques that do not involve
perforating are
known in the art. One such technique is known as packers-plus-style
completion.
Instead of cementing the completion in, this technique involves running open
hole
packers into the well hole to set the casing assembly. The casing assembly
includes
ported collars with sleeves. After the casing is set in the well, the ports
can be opened by
operating the sliding sleeves. Fracturing can then be performed through the
ports.
[0007] For multi-zone wells, multiple ported collars in
combination with
Is sliding sleeve assemblies have been employed. The sliding sleeves are
installed on the
inner diameter of the casing and/or sleeves and can be held in place by shear
pins. In
some designs, the bottom most sleeve is capable of being opened hydraulically
by
applying a differential pressure to the sleeve assembly. After the casing with
ported
collars is installed, a fracturing process is performed on the bottom most
zone of the well.
This process may include hydraulically sliding sleeves in the first zone to
open ports and
then pumping the fracturing fluid into the formation through the open ports of
the first
zone. After fracturing the first zone, a ball is dropped down the well. The
ball hits the
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next sleeve up from the first fractured zone in the well and thereby opens
ports for
fracturing the second zone. After fracturing the second zone, a second ball,
which is
slightly larger than the first ball, is dropped to open the ports for
fracturing the third zone.
This process is repeated using incrementally larger balls to open the ports in
each
consecutively higher zone in the well until all the zones have been fractured.
However,
because the well diameter is limited in size and the ball sizes are typically
increased in
quarter inch increments, this process is limited to fracturing only about 11
or 12 zones in
a well before ball sizes run out. In addition, the use of the sliding sleeve
assemblies and
the packers to set the well casing in this method can be costly. Further, the
sliding sleeve
assemblies and balls can significantly reduce the inner diameter of the
casing, which is
often undesirable. After the fracture stimulation treatment is complete, it is
often
necessary to mill out the balls and ball seats from the casing.
[0008] Another method that has been employed in open-hole wells
(that
use packers to fix the casing in the well) is similar to the packers-plus-
style completion
described above, except that instead of dropping balls to open ports, the
sleeves of the
subassemblies are configured to be opened mechanically. For example, a
shifting tool
can be employed to open and close the sleeves for fracturing and/or other
desired
purposes. As in the case of the packers-plus-style completion, the sliding
sleeve
assemblies and the packers to set the well casing in this method can be
costly. Further,
the sliding sleeve assemblies can undesirably reduce the inner diameter of the
casing. In
addition, the sleeves are prone to failure due to high velocity sand slurry
erosion and/or
sand interfering with the mechanisms.
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[0009] Another technique for fracturing wells without
perforating is
= disclosed in co-pending U.S. Patent Application No. 12/826,372 entitled
"JOINT OR
COUPLING DEVICE INCORPORATING A MECHANICALLY-INDUCED WEAK
POINT AND METHOD OF USE," filed June 29, 2010, by Lyle E. Launy.
[0010] The present disclosure is directed to overcoming, or at least
reducing the effects of, one or more of the issues set forth above.
SUMMARY OF THE DISCLOSURE
[0011] The following presents a summary of the
disclosure in order to
it) provide an understanding of some aspects disclosed herein. This
summary is not an
exhaustive overview, and it is not intended to identify key or critical
elements of the
disclosure or to delineate the scope of the invention as set forth in the
appended claims.
[0012] One embodiment of the present disclosure is a
wellbore completion
system that includes a housing operatively connected to a casing string. The
housing
is includes at least one port through the housing and a sleeve
connected to the housing that
may be moved between an open position and a closed position. In the closed
position,
the sleeve prevents fluid communication through the port of the housing. The
system
includes a bottom hole assembly that has a packing element and an anchor. The
anchor is
adapted to selectively connected the bottom hole assembly to the sleeve. The
packing
zo element is adapted to provide a seal between the bottom hole
assembly and the sleeve.
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[0013] The wellbore completion system may also include a
shearable
device that is adapted to selectively retain the sleeve in an initial closed
position and
release the sleeve upon the application of a predetermined amount of force.
The system
may include an expandable device that is adapted to selectively retain the
sleeve in the
open position after it has been released and moved from the closed position.
The
expandable device may be adapted to engage a recess in the housing. The bottom
hole
assembly is connected to coiled tubing, which may be used to position the
bottom hole
assembly adjacent to the ported housing. The bottom hole assembly may include
a collar
casing locator. The anchor and packing element of the bottom hole assembly may
be
to pressure actuated. The wellbore completion system may include a
plurality of ported
housings along a casing string each including a sleeve movable between a
closed position
and an open position.
[0014] One embodiment of the present disclosure is a method for
treating
or stimulating a well formation. The method includes positioning a bottom hole
assembly within a portion of a casing string adjacent to a first sleeve
operatively
connected to the casing string. The sleeve is movable between a first position
that
prevents fluid communication through a first port in the casing string and a
second
position that permits fluid communication through the first port in the casing
string. The
method includes connecting a portion of the bottom hole assembly to the first
sleeve and
moving the bottom hole assembly to move the first sleeve from the first, or
closed,
position to the second, or open, position.
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[0015] The method may include treating the well formation
adjacent to the
first port in the casing string. The method may further include disconnecting
the bottom
hole assembly from the first sleeve and position the bottom hole assembly
adjacent a
second sleeve operatively connected to the casing string. The second sleeve
being
movable between a first position that prevents fluid communication through a
second port
in the casing string to a second position that permits fluid communication
through the
second port. The method may include connected a portion of the bottom hole
assembly
to the second sleeve and moving the bottom hole assembly to move the second
sleeve
from the closed position to the open position. The method may include treating
the well
to formation adjacent to the second port.
[00161 Connecting a portion of the bottom hole assembly to the
sleeve may
include activating an anchor to engage a portion of the sleeve. The method may
include
creating a seal between the bottom hole assembly and the sleeve. The method
may
include selectively releasing the sleeve from its first position prior to
moving the bottom
Is hole assembly to move the sleeve. Selectively the sleeve may comprise
shearing a
shearable device, which may be sheared by increasing pressure within the
casing string
above the bottom hole assembly, moving the coiled tubing down the casing
string, or a
combination of increasing the pressure and moving the coiled tubing. The
method may
include selectively retaining the sleeve in the open position. Positioning the
bottom hole
20 assembly and connecting the bottom hole assembly to the sleeve may
comprises moving
the coiled tubing in only an upward direction. The method may include pumping
fluid
down the coiled tubing to actuate an anchor of the bottom hole assembly.
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100171 An embodiment of the present disclosure is directed to a
wellbore
completion. The wellbore completion comprises a casing assembly comprising a
plurality of casing lengths. At least one collar is positioned so as to couple
the casing
lengths. The at least one collar comprises a tubular body having an inner flow
path and at
least one fracture port configured to provide fluid communication between an
outer
surface of the collar and the inner flow path. A length of coiled tubing can
be positioned
in the casing assembly. The coiled tubing comprises an inner flow path,
wherein an
annulus is formed between the coiled tubing and the casing assembly. A bottom
hole
assembly is coupled to the coiled tubing. The bottom hole assembly comprises a
lo fracturing aperture configured to provide fluid communication between
the inner flow
path of the coiled tubing and the annulus. A packer can be positioned to allow
contact
with the at least one collar when the packer is expanded. The packer is
capable of
isolating the annulus above the packer from the annulus below the packer so
that fluid
flowing down the coiled tubing can cause a pressure differential across the
packer to
is thereby open the fracture port.
100181 Another embodiment of the present disclosure is directed
to a
method for completing a hydrocarbon producing wellhole. The method comprises
running a coiled tubing into a casing assembly of the wellhole. The casing
assembly
comprises a plurality of casing lengths and one or more collars positioned so
as to couple
20 together the casing lengths. A first collar of the one or more collars
comprises a first
fracture port. Fluid is pumped through the coiled tubing to apply a pressure
differential
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to open the first fracture port of the casing assembly. The well formation is
fractured by
flowing fracturing fluid through the first fracture port.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] FIG. 1 illustrates a portion of a cemented wellbore
completion,
[0020] FIG. 2 illustrates a close up view of a collar and bottom
hole
assembly used in the wellbore completion of FIG. 1, according to an embodiment
of the
present disclosure.
[0021] FIG. 3 illustrates a close up view of a locking dog used
in the
[0022] FIG. 4 illustrates a perspective view of a collar,
according to an
embodiment of the present disclosure.
[0023] FIG. 5 illustrates a cross-sectional view of the collar
of FIG. 4,
according to an embodiment of the present disclosure.
15 [0024] FIG. 6 illustrates a valve used in the collar of FIG. 4,
according to
an embodiment of the present disclosure.
[0025] FIG. 7 illustrates a collar being used with a coiled
tubing string and
a straddle tool having packers for isolating a zone in the well to be
fractured, according to
an embodiment of the present disclosure.
20 [0026] FIG. 8 illustrates a portion of a well completion with open-
hole
packers, according to an embodiment of the present disclosure.
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[0027] FIG. 9 illustrates a close up view of a collar and bottom
hole
assembly, according to an embodiment of the present disclosure.
100281 FIG. 10 illustrates a bottom hole assembly used in a
wellbore
completion, according to an embodiment of the present disclosure.
[0029] FIG. 11 illustrates a close up view of the upper portion of a
collar
and bottom hole assembly embodiment shown in FIG. 10.
[0030] FIG. 12 illustrates a close up view of a lower portion of
the collar
and bottom hole assembly embodiment shown in FIG. 10.
[0031] FIG. 13 illustrates close up view of a portion of a
mandrel of a
io bottom hole assembly, according to an embodiment of the present
disclosure.
[0032] FIG. 14 illustrates a cross-sectional end view of the
collar of FIG.
11.
[0033] FIG. 15 illustrates a cross-section view of a collar
having a valve in
the closed position, according to an embodiment of the present disclosure.
[0034] FIG. 16 illustrates a collar being used with a coiled tubing string
and a straddle tool having packers for isolating a zone in the well to be
fractured,
according to an embodiment of the present disclosure.
[0035] FIG. 17 illustrates a cross-section view of a ported
wellbore
completion according to an embodiment of the present disclosure.
?o [0036] FIG. 18 illustrates a cross-section view of a bottom hole
assembly
anchored to a portion of the ported wellbore completion of FIG. 17, with the
sleeve of the
ported wellbore completion in a closed position.
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[0037] FIG. 19 illustrates a cross-section view of the bottom
hole assembly
anchored to a portion of the ported wellbore completion of FIG. 17, with the
sleeve of the
ported wellbore completion in an open position.
[0038] FIG. 20 illustrates a cross-section view of a wellbore
completion,
according to an embodiment of the present disclosure.
[0039] FIG. 21 illustrates a cross-section view of a wellbore
completion
that includes a sand jet perforator, according to an embodiment of the present
disclosure.
[0040] While the disclosure is susceptible to various
modifications and
alternative forms, specific embodiments have been shown by way of example in
the
io drawings and will be described in detail herein. However, it should be
understood that
the disclosure is not intended to be limited to the particular forms
disclosed. Rather, the
intention is to cover all modifications, equivalents and alternatives falling
within the
spirit and scope of the invention as defined by the appended claims.
DETAILED DESCRIPTION
[0041] FIG. 1 illustrates a portion of a wellbore completion 100,
according
to an embodiment of the present disclosure. Wellbore completion 100 includes a
bottom
hole assembly ("BHA") 102 inside a casing 104. Any suitable BHA can be
employed.
In an embodiment, the BHA 102 can be designed for carrying out fracturing in a
multi-
zone well. An example of a suitable BHA is disclosed in copending U.S. Patent
Application No. 12/626,006, filed November 25, 2009, in the name of John
Edward
Ravensbergen and entitled, COILED TUBING BOTTOM HOLE ASSEMBLY WITH
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PACKER AND ANCHOR ASSEMBLY.
[0042] As more clearly illustrated in FIGS. 2 and 3, casing 104
can include
multiple casing lengths 106A, 106B and 106C that can be connected by one or
more
collars, such as collars 108 and 110. Casing lengths 106A, 106B, and/or 106C
may be
pup joints, segments of casing approximately six (6) feet in length, which may
be
configured to aid in properly locating a BHA within a desired zone of the
wellbore.
Collar 108 can be any suitable collar. Examples of collars for connecting
casing lengths
are well known in the art. In an embodiment, collar 108 can include two female
threaded
portions for connecting to threaded male ends of the casing lengths 106.
[0043] A perspective view of collar 110 is illustrated in FIG. 4,
according
to an embodiment of the present disclosure. Collar 110 can include one or more
fracture
ports 112 and one or more valve vent holes 114. Fracture ports 112 can
intersect valve
holes 118, which can be positioned longitudinally in centralizers 116. A plug
128 can be
positioned in valve holes 118 to prevent or reduce undesired fluid flow up
through valve
is holes 118. In an embodiment, the inner diameter 113 (shown in FIG. 2) of
the collar 110
can be approximately the same or greater than the inner diameter of the casing
104. In
this way, the annulus between the collar 110 and the BHA 102 is not
significantly
restricted. In other embodiments, the inner diameter of the collar 110 can be
less than the
inner diameter of the casing 104. Collar 110 can attach to casing lengths 106
by any
zo suitable mechanism. In an embodiment, collar 110 can include two female
threaded
portions for connecting to threaded male ends of the casing lengths 106B and
106C.
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[0044] As more clearly shown in FIG. 5, fracture ports 112 can
be
positioned through centralizers 116, which can allow the fracture port 112 to
be
positioned relatively close to the formation. Where the casing is to be
cemented into the
wellbore, this can increase the chance that the fracture ports 112 will reach
through, or
nearly through, the cement.
[0045] Valves 120 for controlling fluid flow through fracture
ports 112 are
positioned in the valve holes 118 of centralizers 116. When the valves 120 are
in the
closed position, as illustrated in FIG. 6, they prevent or reduce the flow of
fluid through
the fracture ports 112.
to [0046] Valves 120 can include one or more seals to reduce leakage.
Any
suitable seal can be employed. An example of a suitable seal 122 is
illustrated in FIG. 6.
Seal 122 can be configured to extend around the fracture port 112 when valve
120 is
positioned in the closed position. Seal 122 can include a ring 122A that fits
around the
circumference of valve 120 at one end and a circular portion 122B that extends
only
Is around a portion of the valve 120 at the opposite end. This
configuration can provide the
desired sealing effect while being easy to manufacture.
[0047] A shear pin 124 can be used to hold the valve 120 in the
closed
position during installation and reduce the likelihood of valve 120 opening
prematurely.
Shear pin 124 can be designed so that when it is sheared, a portion of the pin
124 remains
20 in the wall of collar 110 and extends into groove 126 of valve 120. This
allows the
sheared portion of pin 124 to act as a guide by maintaining the valve 120 in a
desired
orientation so that seal 122 is positioned correctly in relation to fracture
port 112. The
113
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use of sheared pin 124 as a guide is illustrated in FIG. 2, which shows the
valve 120 in
open position.
[0048] Collar 110 can be attached to the casing lengths in any
suitable
manner. In an embodiment, collar 110 can include two female threaded portions
for
connecting to threaded male ends of the casing lengths 106, as illustrated in
FIG. 2.
[0049] As also shown in FIG. 2, a packer 130 can be positioned
in the
casing between the fracture ports 112 and the valve vent hole 114. When the
packer 130
is energized, it seals on the inner diameter of the collar 110 to prevent or
reduce fluid
flow further down the well bore annulus. Thus, when fluid flows downhole from
surface
to in an annulus between a well casing 104 and a BHA 102, a pressure
differential is formed
across the packer between the fracture port 112 and the valve vent hole 114.
The
pressure differential can be used to open the valve 120.
100501 Any suitable technique can be employed to position the
packer 130
at the desired position in the collar 110. One example technique illustrated
in FIG. 3
employs a dog 132 that can be configured so as to drive into a recess 134
between casing
portions 106A and 106B. As shown in FIG. 1, the dog 132 can be included as
part of the
BHA 102. The length of the casing portion 106B can then be chosen to position
the
collar 110 a desired distance from the recess 134 so that the packer 130 can
be positioned
between the fracture port 112 and the valve vent hole 114. During
installation, the well
operator can install the BHA 102 by lowering the dog past the recess 134 and
then raising
the BHA 102 up until the dog 132 drives into the recess 134. An extra
resistance in
pulling dog 132 out of the recess 134 will be detectable at the surface and
can allow the
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well operator to determine when the BHA 102 is correctly positioned in the
casing. This
can allow the well operator to locate the packer 130 relative to the standard
collar 108,
which can be the next lowest collar relative to collar 110.
[0051] The casing 104 can be installed after well drilling as
part of the
completion 100. In an embodiment, the casing 104, including one or more
collars 110,
can be cemented into the wellbore. FIG. 1 illustrates the cement 105, which is
flowed
into the space between the outer diameter of the casing 104 and the inner
diameter of the
wellhole 107. Techniques for cementing in casing are well known in the art. In
another
embodiment, the casing 104 and collars 110 can be installed in the wellbore
using an
open hole packer arrangement where instead of cement, packers 111 are
positioned
between the inner diameter of the wellbore 107 and the outer diameter of the
casing 104,
as illustrated in FIG. 8. Such open hole packer completions are well known in
the art and
one of ordinary skill in the art would readily be able to apply the collars of
the present
application in an open hole packer type completion.
[0052] The collars 110 can be positioned in the casing wherever ports are
desired for fracturing. For example, it is noted that while a standard collar
108 is shown
as part of the casing, collar 108 can be replaced by a second collar 110. In
an
embodiment, the collars 110 of the present disclosure can be positioned in
each zone of a
multi-zone well.
[0053] During the cementing process, the casing is run in and cement fills
the annular space between casing 104 and the well formation. Where the valve
120 is
positioned in the centralizer, there can be a slight depression 136 between
the outer
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diameter of the centralizer 116 and the outer diameter of valve 120, as shown
in FIG. 5.
The depression 136 can potentially be filled with cement during the cementing
process.
Therefore, before fluid flows through the valve 120, there may be a thin layer
of cement
that will have to be punched through. Alternatively, the depression 136 may
not be filled
with cement. In an embodiment, it may be possible to fill the depression 136
with grease,
cement inhibiting grease, or other substance prior to cementing so as to
reduce the
likelihood of the depression 136 being filled with cement.
100541 A potential advantage of the collar design of FIG. 4 is
that opening
valve 120 displaces fluid volume from the valve hole 118 into an annulus
between the
to casing 106 and the BHA 102 through the valve vent hole 114. Thus, all of
the displaced
volume that occurs when opening the valves 120 is internal to the completion.
This
allows filling the space between the wellbore and the outer diameter of casing
106 with
cement, for example, without having to necessarily provide a space external to
the collar
for the fluid volume that is displaced when valve 120 is opened.
IS 100551 Another possible advantage of the collar design of FIG. 4 is
that
little or no pressure differential is likely to be realized between the
fracture port 112 and
the valve vent hole 114 of a collar 110 until the inner diameter of the collar
is sealed off
between the fracture port 112 and the valve vent hole 114. This means that in
multi-zone
wells having multiple collars 110, the operator can control which fracture
port is opened
20 by position the sealing mechanism, such as the packer 130, in a desired
location without
fear that other fracture ports at other locations in the well will
inadvertently be opened.
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100561 The collars of the present disclosure can be employed in
any type
of well. Examples of well types in which the collars can be used include
horizontal
wells, vertical wells and deviated wells.
100571 The completion assemblies shown above with respect to
FIGS. 1 to
3 are for annular fracturing techniques where the fracturing fluid is pumped
down a well
bore annulus between a well casing 104 and a BHA 102. However, the collars 110
of the
present disclosure can also be employed in other types of fracturing
techniques.
100581 One such fracturing technique is illustrated in FIG. 7,
where a
coiled tubing string is employed with a straddle tool having packers 140A,
140B for
io isolating a zone in the well to be fractured. As shown in FIG. 7, the
packer 140B can be
positioned between the fracture port 112 and the valve vent hole 114. This
allows valve
120 to be opened by creating a pressure differential between fracture port 112
and valve
vent hole 114 when the area in the wellbore between packers 140A, 140B is
pressured
up. Pressuring up can be accomplished by flowing a fluid down the coiled
tubing at a
suitable pressure for opening the valve 120. The fluid for opening valve 120
can be a
fracturing fluid or another suitable fluid. After the valve 120 is opened,
fracturing fluid
(not shown) can be pumped downhole through coiled tubing, into the annulus
through
aperture 144 and then into the formation through fracture port 112. A
potential
advantage of the coiled tubing/straddle tool assembly of FIG. 7 is that any
proppant used
during the fracturing step can be isolated between the packers 140A and 140B
from the
rest of the wellbore annulus.
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[0059] A method for multi-zone fracturing using the collars 110
of the
present disclosure will now be described. The method can include running the
casing
104 and collars 110 into the wellhole after drilling. The casing 104 and
collars 110 can be
either set in the wellhole by cementing or by using packers in an openhole
packer type
assembly, as discussed above. After the casing is set in the wellhole, a BHA
102
attached to the end of coiled tubing string can be run into the well. In an
embodiment,
the BHA 102 can initially be run to, or near, the bottom of the well. During
the running
in process, the dogs 132 (FIG. 3) are profiled such that they do not
completely engage
and/or easily slide past the recesses 134. For example, the dogs 132 can be
configured
to with a shallow angle 131 on the down hole side to allow them to more
easily slide past
the recess 134 with a small axial force when running into the well.
[0060] After the BHA 102 is run to the desired depth, the well
operator can
start pulling the tubing string and BHA 102 up towards the surface. Dogs 132
can be
profiled to engage the recess 134 with a steep angle 133 on the top of the
dogs 132,
thereby resulting in an increased axial force in the upward pull when
attempting to pull
the dogs 132 out of the recesses. This increased resistance allows the well
operator to
determine the appropriate location in the well to set the packer 130, as
discussed above.
Profiling the dogs 132 to provide a reduced resistance running into the well
and an
increased resistance running out of the well is generally well known in the
industry.
After the packer 130 is positioned in the desired location, the packer 130 can
then be
activated to seal off the well annulus between the BHA 102 and the desired
collar 110
between the fracture port 112 and the valve vent hole 114.
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[0061] After the well annulus is sealed at the desired collar
110, the well
annulus can be pressured up from the surface to a pressure sufficient to open
the valves
120. Suitable pressures can range, for example, from about 100 psi to about
10,000 psi,
such as about 500 psi to about 1000 psi, 1500 psi or more. The collar 110 is
designed so
.5 that all of the fracture ports 112 in the collar may open. In an
embodiment, the pressure
to open the fracture ports 112 can be set lower than the fracturing pressure.
This can
allow the fracturing pressure, and therefore the fracturing process itself, to
ensure all the
fracture ports 112 are opened. It is contemplated, however, that in some
situations all of
the fracture ports 112 may not be opened. This can occur due to, for example,
a
io malfunction or the fracture ports being blocked by cement. After the
fracture ports 112
are opened, fluids can be pumped through the fracture ports 112 to the well
formation.
The fracture process can be initiated and fracturing fluids can be pumped down
the well
bore to fracture the formation. Depending on the fracturing technique used,
this can
include flowing fracturing fluids down the well bore annulus, such as in the
embodiment
is of FIGS. 1 to 3. Alternatively, fracturing fluids can be flowed down a
string of coiled
tubing, as in the embodiment of FIG. 7. If desired, a proppant, such as a sand
slurry, can
be used in the process. The proppant can fill the fractures and keep them open
after
fracturing stops. The fracture treatment typically ends once the final volume
of proppant
reaches the formation. A displacement fluid is used to push the proppant down
the well
20 bore to the formation.
[0062] A pad fluid is the fluid that is pumped before the
proppant is
pumped into the formation. It ensures that there is enough fracture width
before the
19
CA 02781721 2012-07-06
proppant reaches the formation. If ported collar assemblies are used, it is
possible for the
displacement fluid to be the pad fluid for the subsequent treatment. As a
result, fluid
consumption is reduced.
[0063] In multi-zone wells, the above fracturing process can be
repeated
for each zone of the well. Thus, the BHA 102 can be set in the next collar
110, the
packer can be energized, the fracturing port 112 opened and the fracturing
process carried
out. The process can be repeated for each zone from the bottom of the wellbore
up.
After fracturing, oil can flow out the fracture through the fracture ports 112
of the collars
110 and into the well.
[0064] In an alternative multi-zone embodiment, the fracturing can
potentially occur from the top down, or in any order. For example, a straddle
tool, such
as that disclosed in FIG. 7, can be used to isolate the zones above and below
in the well
by techniques well known in the art. The fracture ports 112 can then be opened
by
pressuring up through the coiled tubing, similarly as discussed above.
Fracturing can
Is then occur for the first zone, also in a similar fashion as described
above. The straddle
tool can then be moved to the second zone form the surface and the process
repeated.
Because the straddle tool can isolate a collar from the collars above and
below, the
straddle tool permits the fracture of any zone along the wellbore and
eliminates the
requirement to begin fracturing at the lower most zone and working up the
casing.
[0065] The design of the collar 110 of the present disclosure can
potentially allow for closing the valve 120 after it has been opened. This may
be
beneficial in cases were certain zones in a multi-zone well begin producing
water, or
CA 02781721 2012-07-06
other unwanted fluids. If the zones that produce the water can be located, the
collars
associated with that zone can be closed to prevent the undesired fluid flow
from the zone.
This can be accomplished by isolating the valve vent hole 114 and then
pressuring up to
force the valve 120 closed. For example, a straddle tool can be employed
similar to the
embodiment of FIG. 7, except that the packer 140A can be positioned between
the
fracture port 112 and the valve vent hole 114, and the lower packer 140B can
be
positioned on the far side of the valve vent hole 114 from packer 140A. When
the zone
between the packers is pressurized, it creates a high pressure at the valve
vent hole 114
that forces the valve 120 closed.
io [0066] Erosion of the fracture port 112 by the fracturing and other
fluids
can potentially prevent the valve 120 from sealing effectively to prevent
fluid flow even
through the fracture port 112 is closed. However, it is possible that the
design of the
collar 110 of the present disclosure, which allows multiple fracture ports in
a single collar
to open, may help to reduce erosion as compared to a design in which only a
single
is fracture port were opened. This is because the multiple fracture ports
can provide a
relatively large flow area, which thereby effectively decreases the pressure
differential of
the fluids across the fracture port during fracturing. The decreased pressure
differential
may result in a desired reduction in erosion.
[00671 FIG. 10 illustrates a portion of a wellbore completion
200,
20 according to an embodiment of the present disclosure. The wellbore
completion includes
casing lengths 206a, 206b connected to a collar assembly 210, herein after
referred to as
collar 210. FIG. 11 shows a close-up view of the upper portion of the collar
210 and
21
CA 02781721 2012-07-06
FIG. 12 shows a close-up view of the lower portion of the collar 210. The
collar 210
shown in FIG 11 comprises a mandrel 209, which may comprise a length of casing
length, a valve housing 203, and a vent housing 201. A valve, such as a sleeve
220, is
positioned within an annulus 218 between the mandrel 209 and the valve housing
203.
The sleeve 220 is movable between an open position (shown in FIG. 10) that
permits
communication between the inner diameter of the mandrel 209 and outer fracture
ports
212B through inner fracture port 212A located in the mandrel 209. The annulus
218A
extends around the perimeter of the mandrel and is in communication with the
annulus
218B between the vent housing 201 and the mandrel 209, which may be referred
to as a
single annulus 218. The sleeve 220 may be moved into a closed position (shown
in FIG.
15) preventing fluid communication between the inner fracture port 212A and
outer
fracture port 212B, which may be referred to collectively as the fracture port
212. The
sleeve 220 effectively seals the annulus 218 into an upper portion 218A and
218B thus,
permitting a pressure differential between the two annuluses to move the
sleeve 220
Is between its open and closed positions. A seal ring 215 may be used
connect the valve
housing 203 to the vent housing 201. Grooves 218C in the mandrel under the
seal ring
ensure good fluid communication past the seal ring 215 between the upper
portion 218A
and lower portion 218B of the annulus 218. Alternatively, the valve housing
and the vent
housing may be a single housing. In this embodiment, a seal ring to connect
the two
housings and grooves in the mandrel to provide fluid communication would not
be
necessary.
22
CA 02781721 2012-07-06
100681 FIG. 12 shows that the lower portion of the vent housing
201 and
the mandrel 209 having an annulus 218B between the two components. A lower nut
228
connects the lower end of the vent housing 201 to the mandrel 209 with sealing
elements
222 sealing off the lower portion of the annulus 218B. The mandrel 209
includes a vent
hole 214 that is in communication with the annulus 218. In one embodiment, a
plurality
of vent holes 214 are positioned around the mandrel 209. The mandrel may
include one
or more vent holes 214B at a different location the primary vent holes 214. In
operation a
burstable device, such as a burst plug, or cement inhibiting grease may fill
each of the
vent holes to prevent cement, or other undesired substances, from entering
into the
annulus 218. In addition to the burst plugs, cement inhibiting grease may be
injected into
the annulus 218 prior to the completion being run into the wellbore to prevent
the ingress
of cement into the annulus 218 while the completion is cemented into a
wellbore. The
vent housing 201 may include a fill port 227 to aid in the injection of grease
into the
annulus 218. Preferably, one of the vent holes may be significantly smaller in
diameter
Is than the rest of the vent holes and not include a burst plug. After
bursting the burst plugs,
the vent holes permit the application of pressure differential in the annulus
218 to open or
close the valve 220, as detailed above. In the event that the cement has
entered into the
annulus 218 via the vent holes 214, the vent housing may include secondary
vent hole(s)
214B farther uphole along the mandrel 209 that may permit communication to the
annulus 218.
100691 FIG. 13 illustrates the downhole portion of the mandrel
209 without
the vent housing 201. Burst plugs 231 have been inserted into vent holes 214,
214B.
23
CA 02781721 2012-07-06
Preferably, a burst plug is not inserted into the smallest vent hole 214A,
which may be
approximately 1/8 inch in diameter. The vent housing 201 is adapted to provide
predetermined distance between the fracture ports 212 and the vent hole(s)
214. The vent
holes 214 may be approximately two (2) meters from the fracture ports to
provide
adequate spacing for the location of a packing element to permit the
application of a
pressure differential. It is difficult to position the packing element
accurately, within half
of a meter, in the well bore. In addition, the position of the collars
relative to each other
is often not accurately known, largely due to errors in measurements taken
when the
completion is installed into the well bore. The challenge to accurately
position the
to packing element within the well bore is due to several factors. One
factor is the
equipment used to measure the force exerted on the coiled tubing while pulling
out of the
hole is not exact, often errors of 1000 lbs. force or more can occur. The
casing collar
locating profile (133) of FIG. 1 typically increases the force to pull out of
the hole by
2000 lbs. In addition, the frictional force between the coiled tubing and the
casing in a
horizontal well is high and not constant, while pulling out of the well. As a
result it can
be difficult to know what is causing an increase in force observed at the
surface. It could
be due to the casing collar locator pulling into a coupling or it could be due
to other
forces between the coiled tubing and the completion and/or proppant. A
strategy used to
improve the likelihood of determining the position of the packing element is
to use short
zo lengths of casing, typically two (2) meters long, above and below the
collar assembly. In
this way there are three or four couplings (dependent on the configuration of
the collar) at
known spacing distinct from the standard length of casing, which are typically
thirteen
24
CA 02781721 2012-07-06
(13) meters long. As a result of using short lengths of casing attached
directly to the
collar assembly, absolute depth measurement relative to the surface or
relative to a
recorded tally sheet are no longer required. However, this distance between
the fracture
port and the vent hole may be varied to accommodate various packing elements
or
configurations to pen-nit the application of a pressure differential as would
be appreciated
by one of ordinary skill in the art having the benefit of this disclosure.
100701 FIG. 9 illustrates a portion of a wellbore completion
200, according
to an embodiment of the present disclosure that includes a BHA inside of a
casing made
up of a plurality of casing lengths 206 connected together via a plurality of
collars, such
to as collar 210. The collar 210 in this embodiment is comprised of a
mandrel 209, a valve
housing 203, and a vent housing 201. A valve, such as a sleeve 220, is
positioned within
an annulus 218 between the mandrel 209 and the valve housing 203. The sleeve
220 is
movable between an open position (shown in FIG. 9) that permits communication
between the inner diameter of the mandrel 209 and the outer fracture ports
212B via the
is inner fracture ports 212A. The sleeve 220 includes a collet finger 221
that is configured
to engage a recess 223 (shown on FIG. 15) on the mandrel 209 to selectively
retain the
sleeve 220 in its open position. Sealing elements 222 may be used to provide
seal
between the valve housing 203, the mandrel 209, and the sleeve 220. The valve
housing
203 may include one or more fill ports 217 that permits the injection of
grease or other
20 cement inhibiting substances into the annulus 218 to prevent the ingress
of cement if the
completion 200 is cemented into the wellbore.
CA 02781721 2012-07-06
[0071] FIG. 15 shows a cross-section view of the upper portion
of the
collar 210 with the sleeve 220 in a closed position. A shear pin 224
selectively retains
the sleeve 220 in the closed position. The shear pin 224 can be used to hold
the sleeve
220 in the closed position during installation and reduce the likelihood of
sleeve 220 (or
valve 120) opening prematurely. The shear pin 224 may be adapted to shear and
release
the sleeve 220 upon the application of a predetermined pressure differential
as would be
appreciated by one of ordinary skill in the art. The mandrel 209 may include
one or more
ports 230 that are positioned uphole of the closed sleeve 220 to aid in the
application of a
pressure differential into the annulus 218A above the sleeve 220 when moving
the sleeve
220 to the open position. After opening the sleeve and fracturing the
wellbore, the sleeve
220 may be moved back to the closed position upon the application of a
pressure
differential as discussed above. The ports 230 in the mandrel 209 may permit
the exit of
fluid from the annulus 218A as the sleeve 220 passes the fracture ports 212 as
it moves to
the closed position. The mandrel 209 may include a recess 229 adapted to mate
with the
is collet finger 221 and selectively retain the sleeve 220 in the closed
position until the
application of another pressure differential. In the shown embodiment, the
sleeve 220
encompasses the entire perimeter of the mandrel 209. Alternatively, a
plurality of sleeves
may be used to selectively permit fluid communication with the fracture ports
212.
[0072] The collar 210 can include one or more inner fracture
ports 212A,
one or more outer fracture ports 212B, and one or more valve vent holes 214
(shown in
FIG. 12). The outer fracture ports 212B intersect the annulus 218 and may be
positioned
in centralizers 216 along the outside of the collar 210 (as shown in FIG. 14).
In an
26
CA 02781721 2012-07-06
embodiment, the inner diameter of the collar 210 can be approximately the same
or
greater than the inner diameter of the casing. In this way, the annulus
between the collar
210 and the BHA is not significantly restricted. One potential challenge of
this process is
the reliable use of a packer that is typically used within casings that
potentially have a
large variation in the inner diameter between the segments of casing. The use
of ported
collars 210 may decrease this potential problem because the ported collars 210
can be
made with a smaller variation in the inner diameter as well as having a less
oval shape
than typical casing. These improvements provide improved reliability for
properly
sealing off within the collars 210 with a typical packer. In other
embodiments, the inner
lo diameter of the collar 210 can be less than the inner diameter of the
casing. However, the
inner diameter of the collar 210 may still be within tolerance limits of the
inner diameter
of the casing. Collar 210 can attach to casing lengths 106 by any suitable
mechanism. In
an embodiment, collar 210 can include two female threaded portions for
connecting to
threaded male ends of the casing lengths 206b and 206c.
Is [0073] As more clearly shown in FIG. 14, the outer fracture
ports 212B can
be positioned through centralizers 216, which can allow the outer fracture
port 212B to
be positioned relatively close to the formation 107. Where the casing is to be
cemented
into the wellbore, this can increase the chance that the fracture ports 112
will reach
through, or nearly through, the cement 105. As shown in FIG. 14, one or more
of the
20 centralizers 216 may be in direct contact with the open hole formation
107, which may be
the centralizers 216 on the lower side in a horizontal well as would be
appreciated by one
of ordinary skill in the art having the benefit of this disclosure. A valve,
such as a sleeve
27
CA 02781721 2012-07-06
220, may be positioned in an annulus in fluid communication with both inner
fracture
ports 212A and outer fracture ports 212B. The annulus 218 may be between the
mandrel
209 and an outer valve housing 203. When the sleeve 220 is in the closed
position, as
illustrated in FIG. 1 5, it prevents or reduces the flow of fluid through the
fracture ports
112.
[0074] As shown in FIG. 9, a packer 230 can be positioned in the
casing
between the fracture ports 212 and the valve vent holes 214. When the packer
230 is
energized, it seals on the inner diameter of the collar 210 to prevent or
reduce fluid flow
further down the well bore annulus. Thus, when fluid flows downhole from
surface in
to the annulus between a well casing 104 and a BHA, a pressure differential
is formed
across the packer between the fracture ports 212 and the valve vent holes 214.
The
pressure differential can be used to open the valve 220. The user of the
packer in FIG. 9
to create a differential pressure is provided for illustrative purposes as
various tools and
techniques may be employed to create a differential pressure to open and/or
close the
Is valves, as would be appreciated by one of ordinary skill in the art. For
example, a rotary
jetting tool could potential run into casing and directed to the valve vent
holes to create
the pressure differential required to close the valve.
[0075] As discussed above, during the cementing process the
casing is run
in and cement is pumped down the central bore of the casing and out of the end
of the
20 casing 104 filling the annular space between casing 104 and the well
formation. To
prevent ingress of cement and/or fluids used during the cementing process,
grease or
other substance may be injected into the annulus 218 of the collar 210 prior
to running
28
CA 02781721 2012-07-06
the casing into the wellbore. Burst plugs may be inserted into the valve vent
holes 214
and grease may be injected into the annulus through injection ports in the
valve housing
203 and the vent housing 201. Afterwards the injection ports may be plugged.
100761 FIG. 16 shows one technique used to open the sleeve 220
to fracture
the formation. A coiled tubing string is employed with a straddle tool having
packers
140A,140B for isolating a zone in the well to be fractured. FIG. 16 shows only
a portion
of the straddle tool that may be used with the collar assembly of the present
disclosure.
As shown in FIG. 16, the downhole packer 140B can be positioned between the
fracture
ports 212 and the valve vent holes 214 (shown in FIG. 12). This allows sleeve
220 to be
to opened by creating a pressure differential between the fracture ports
212 and valve vent
holes 214 when the area in the wellbore between packers 140A, 140B is
pressured up.
Pressuring up can be accomplished by flowing a fluid down the coiled tubing
and out of
aperture 144 at a suitable pressure for opening the valve 220. The fluid use
to open the
sleeve 220 may be fracturing fluid. A potential advantage of the coiled
tubing/straddle
Is tool assembly of FIG. 16 is that any proppant used during the fracturing
step can be
isolated between the packers 140A and 140B from the rest of the annulus. In
one
embodiment the sleeve 220 may be adapted to open at predetermined pressure
differential
well above the desire fracturing pressure. Thus, energy may be stored within
the coiled
tubing prior to opening the sleeve 220 and the formation may be fractured very
rapidly
20 after opening the fracture ports 212.
100771 A method for multi-zone fracturing using the collars 210
of the
present disclosure will now be described. The method can include running the
casing
29
CA 02781721 2012-07-06
104 and collars 210 into the wellhole after drilling. The casing 104 and
collars 210 can be
either set in the wellhole by cementing or by using packers in an openhole
packer type
assembly, as discussed above. After the casing is set in the wellhole, a BHA
attached to
the end of coiled tubing string or jointed pipe can be run into the well. In
an
embodiment, the BHA can initially be run to, or near, the bottom of the well.
During the
running in process, the dogs 132 (FIG. 3) are profiled such that they do not
completely
engage and/or easily slide past the recesses 134. For example, the dogs 132
can be
configured with a shallow angle 131 on the down hole side to allow them to
more easily
slide past the recess 134 with a small axial force when running into the well.
[0078] After the BHA is run to the desired depth, the well operator can
start pulling the coiled tubing string and BHA up towards the surface. Dogs
132 can be
profiled to engage the recess 134 with a steep angle 133 on the top of the
dogs 132,
thereby resulting in an increased axial force in the upward pull when
attempting to pull
the dogs 132 out of the recesses. This increased resistance allows the well
operator to
Is determine the appropriate location in the well to set the packer 230, as
discussed above.
Profiling the dogs 132 to provide a reduced resistance running into the well
and an
increased resistance running out of the well is generally well known in the
industry.
After the packer 230 is positioned in the desired location, the packer 230 can
then be
activated to seal off the well annulus between the BHA and the desired collar
210
between the fracture port 212 and the valve vent hole 214.
100791 After the well annulus is sealed at the desired collar
210, the well
annulus can be pressured up from the surface to a pressure sufficient to open
the valve
CA 02781721 2012-07-06
220. Suitable pressures can range, for example, from about 100 psi to about
10,000 psi,
such as about 500 psi to about 1000 psi, 1500 psi or more. As discussed above,
the
suitable pressure may be adapted to exceed the desired fracturing pressure to
aid in the
rapid fracture of the formation.
[0080] After the fracture ports 212 are opened, fluids can be pumped
through the fracture ports 212 to the well formation. The fracture process can
be initiated
and fracturing fluids can be pumped down the well bore to fracture the
formation. If
desired, a proppant, such as a sand slurry, can be used in the process. The
proppant can
fill the fractures and keep them open after fracturing stops. After
fracturing, the BHA
to can be used to remove any undesired proppant/fracturing fluid from the
wellbore.
[0081] In multi-zone wells, the above fracturing process can be
repeated
for each zone of the well. Thus, the BHA can be set in the next collar 210,
the packer can
be energized, the fracturing ports 212 opened and the fracturing process
carried out. The
process can be repeated for each zone from the bottom of the wellbore up.
After
fracturing, oil can flow out the fracture through the fracture ports 212 of
the collars 210
and into the well. When the BHA as shown in FIG. 1 is used, the first
treatment may be
placed at the bottom of the well and each subsequent treatment may be placed
incrementally higher in the well. The fracturing treatments for each zone may
be done all
in a single trip of the BHA with minimal time required between the fracturing
of each
zone. The collar assemblies of the present disclosure that are positioned in
the zones
above the current treatment are exposed to current treatment well bore
pressures. This
pressure at times may be limited by the pressure rating of the casing.
However, there is
.31
CA 02781721 2012-07-06
no risk of the valves of these collar assemblies prematurely opening because
the pressure
is balanced across the valves. The valves of the present disclosure can only
be opened
with a pressure differential between the fracture port and the valve vent
hole. Further, the
present disclosure provides for an efficient use of fluid during the
fracturing process as
the displacement fluid for a current zone being fractured can act as the pad
fluid for the
next zone to be treated.
[0082] The design of the collar 210 of the present disclosure
can
potentially allow for closing the valve 220 after it has been opened. This may
be
beneficial in cases were certain zones in a multi-zone well begin producing
water, or
io some other unwanted fluids. If the zones that produce the water can be
located, the
collars associated with that zone can be closed to prevent the undesired fluid
flow from
the zone. This can be accomplished by isolating the valve vent hole 214 and
then
pressuring up to force the valve 220 closed. For example, a straddle tool can
be
employed similar to the embodiment of FIG. 16, except that the packer 140A can
be
is positioned between the fracture ports 212 and the valve vent holes 214,
and the lower
packer 140B can be positioned on the far side of the valve vent holes 214 from
packer
140A. When the zone between the packers is pressurized, it creates a high
pressure at the
valve vent holes 214 that forces the sleeve 220 closed. As discussed above,
the sleeve
220 may include a collet finger 221 that may help retain the sleeve 220 in its
closed
20 position.
[0083] FIGS. 17-19 illustrate a portion of a wellbore completion
300,
according to an embodiment of the present disclosure. The wellbore completion
300 may
32
CA 02781721 2012-07-06
includes a BHA 302 positioned inside of casing. The casing may be comprised of
various segments and connectors connected together, such as pup joints 306,
cross-overs
315 and 317, and a ported housing 310, as well as conventional casing
tubulars, as would
be appreciated by one of ordinary skill in the art having the benefit of this
disclosure.
100841 FIG. 17 shows a pup joint 306 connected to one end of a ported
housing 310 by an upper cross-over 315. The other end of the ported housing
310 is
connected to another pup joint 306 by a lower cross-over 317. The pup joints
306 may be
connected to conventional casing tubulars to comprise a section of a casing
string. The
segments of the casing string are secured together via threads 343. The
connection via
in threads and configuration of the casing segments are shown for
illustrative purposes as
different connection means and any suitable configurations may be used within
the spirit
of the disclosure. For example, the ported housing 310 could be connected
directly to
pup joints 306 without the use of cross-over connectors 315, 317.
100851 The ported housing 310 includes at least one fracture
port 312 that
IS permits fluid communication between the interior and exterior of the
housing 310. A
sleeve 320 may be slidably connected to the interior surface of the housing
310. In an
initial position, as shown in FIG. 17, the sleeve 320 may be positioned such
that seals 322
prevent fluid communication through port 312. A shearable device 324 may be
used to
selectively retain the sleeve 320 in an initial closed position. The shearable
device 324
20 may be a shear pin, crush ring, or other device adapted to selectively
release the sleeve
320 from the housing 310 upon the application of a predetermined force, which
may be
applied by hydraulic pressure as discussed in detail below.
33
CA 02781721 2012-07-06
[0086] FIG. 18 shows a BHA 302 connected to coiled tubing 342
that has
been inserted into the casing and has been positioned within the ported
housing 310. A
casing collar locator may be used to position the BHA 302 at desired proper
location
within the casing. For example, a lower cross-over 317 may include a profile
333 that is
adapted to engage a profile 332 of the casing collar locator to properly
position the BHA
302 within a specific ported housing 310 along the casing string.
100871 The BHA 302 includes a packer 330 that may be activated
to seal
the annulus between the exterior of the BHA 302 and the interior diameter of
the sleeve
320 of the ported housing 310. The BHA 302 also includes an anchor 350 that
may be
io set against the sleeve 320. Application of pressure down the coiled
tubing is used to
activate the anchor 350 and set it against the sleeve 320 as well as to set
the packer 330.
A potential advantage of the embodiment of the BHA 302 is that the BHA 302 may
be
set within a housing 310 of the casing string without the use of a J-slot
which requires the
downward movement, upward movement, and then downward movement of the coiled
is tubing 342 to set the BHA 302. This repeated cyclic up and down movement
of the
coiled tubing 342 to set the BHA 302 may lead to more rapid failure of the
coiled tubing
302. In comparison, the current embodiment of the BHA 302 and ported housing
310
and sleeve 320 provides for less movement of the coiled tubing 342. After a
sleeve 320
has been opened, as discussed below, the BHA 302 may be released, moved up the
casing
20 string to the next desired zone, and set within the selected housing 310
without any cyclic
up and down motion of the coiled tubing 342.
34
CA 02781721 2012-07-06
[0088] After setting the anchor 350 to secure the BHA 302 to the
sleeve
320 and activating the packer 330, fluid may be pumped down the casing
creating a
pressure differential across the packer 330. Upon reaching a predetermined
pressure
differential, the shearable device 324 will shear and thereby release the
sleeve 320 from
the housing 310. The shearable device 324 may be adapted to shear at a
predetermined
pressure differential as will be appreciated by one of ordinary skill in the
art.
[0089] After the shearable device releases the sleeve 320 from
the housing
310, the increase pressure differential across the packer 330 will then move
the BHA 302,
which is anchored to the sleeve 320, down the casing. In this manner, the
sleeve 320 can
io be moved from the closed position shown in FIG. 18 to an open position
as shown in
FIG. 19. Alternatively, the sleeve 320 may be moved to the open position by
applying a
downward force to the BHA 302 with the coiled tubing 342 or by the application
of
hydraulic pressure in combination with a downward force from the coiled tubing
342.
[0090] Upon moving to the open position, the sleeve 320 may be
is selectively locked into the open position. For example, the sleeve 320
may include an
expandable device 325, such as a "c" ring or a lock dog, which expands into a
groove 326
in the interior of the housing 310 selectively locking the sleeve 320 in the
open position.
In the open position, fluid may be communicated between the interior of the
housing 310
to the exterior of the housing 310, permitting the treatment and/or
stimulation of the well
20 formation adjacent to the port 312.
[0091] A plurality of ported housings 310 with sleeves 320 can
be
positioned along the length of the casing at locations where fracturing is
desired. After
CA 02781721 2012-07-06
fracturing is carried out using a first ported housing 310 and sleeve 320,
similarly as
discussed above, the BHA can be moved to a second ported housing 310
comprising a
second sleeve 320, where fracturing is carried out at a second location in the
well. The
process can be repeated until desired fracturing of the well is completed.
100921 The use of a BHA 302 in connection with a ported housing 310 and
sleeve 320 may provide an inexpensive system to selectively stimulate and/or
treat a well
formation as compared to other systems. For example, the configuration of the
embodiment may permit the use of various lengths of housing and sleeves to
locate a
plurality of ports 312 along the casing string, for larger contact with the
formation, as
desired. Further, the confirmation of the embodiment may permit a large
internal flow
diameter in comparison to other fracturing/treatment systems.
100931 The processes describe herein include both annular
fracturing
processes, in which the fracturing fluid is pumped down the well annulus, and
coiled
tubing fracturing processes. A potential problem with some annular fracturing
processes
is is that often the well bore annulus volume is greater than the volume of
the treatment pad
volume, especially as the stages get smaller and are placed closer together.
If no
additional fluids or time is taken, it may become necessary to pump the slurry
for the
subsequent treatment to displace the fluids of the current treatment. As a
result,
additional process risk may be taken because the process to unset, move the
BHA, and
initiate the subsequent fracture is performed with slurry already in the well.
In addition,
this process may start and stop slurry pumping, which can add operational
complication,
increase risk and decrease the quality of the treatment.
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[0094] The embodiments of the present disclosure that pump
treatment
fluids through the coiled tubing can have the advantage that the coiled tubing
volume is
typically less than the treatment pad volume, and therefore no extra time and
no
additional fluid may be required. In addition, because the cross sectional
area of the
coiled tubing is smaller than the wellbore and coiled tubing annulus, the
velocities of the
fluid are generally higher and proppant is less prone to drop out of solution
and remain in
the coiled tubing. This can be advantageous because residual proppant can
interfere with
the treatment process. For example, if proppant is introduced into the
treatment too early,
when the pad fluid is pumped the proppant can bridge off, preventing the
fracture width
io from increasing and causing a screen out. Pumping treatment fluid down
the coiled
tubing may also result in less sand in the well bore, which can allow easier
movement
and improved function of the BHA in the coiled tubing.
[0095] FIG. 20 illustrates a wellbore completion 400 designed
for coiled
tubing fracturing, according to an embodiment of the present disclosure. A
casing
IS assembly 404 comprises a plurality of casing lengths 406A and 406B and
at least one
collar 410 positioned so as to couple the casing lengths together, similarly
as in the other
embodiments described herein. The at least one collar 410 comprises at least
one fracture
port 412 configured to provide fluid communication between an outer surface of
the
collar and the inner flow path of the casing and collar assembly. For example,
the collar
20 can be any of the collars comprising a fracture port as described
herein. If desired, the
collar can include a plurality of centralizers, such as shown in FIGS. 4 and
5, where at
least one fracture port extends through the centralizers. By employing collars
that include
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fracture ports in each of the zones of a multi-zone well, the need for
perforating all of the
zones before fracturing begins can be reduced or eliminated. In another
embodiment, the
collar can be similar to that shown in FIGS. 17 to 19, which includes a ported
collar 310
and sleeve 320 as described above.
[0096] A length of coiled tubing 442 is positioned in the casing assembly
404. The coiled tubing 442 comprises an inner flow path for carrying fluid to
or from the
surface. An annulus 450 is formed between the coiled tubing 442 and the casing
assembly 404. A bottom hole assembly 402 is coupled to the coiled tubing. The
bottom
hole assembly 402 comprises a fracturing aperture 444 configured to provide
fluid
communication between the inner flow path of the coiled tubing 442 and the
annulus 450.
As illustrated, a plurality of fracturing apertures can be employed. The
fracturing
apertures can be sufficient large so that increased flow rates can be achieved
without
undue pressure drop when the treatment fluid exits the BHA. Suitable apertures
sizes
range, for example, from about 0.5 to about 0.75 inches wide and about 2
inches to about
IS 4 inches long. The size of apertures can vary depending on the number of
apertures,
among other things.
100971 The BHA 402 also includes a packer 430. Any suitable
packer can
be employed. Examples of suitable packers include those employed in the
SURESETTm
BHA, available from Baker Hughes Incorporated of Houston Texas, or MONGOOSETM
BHA, available from NCS Energy Service Inc., located in SPRING, Texas.
[0098] In an embodiment, a second packer is not positioned in
the annulus
above the first packer 430, as would be the case if the packer was a straddle
tool, such as
.3 8
CA 02781721 2012-07-06
the straddle tool in FIG. 7. Straddle tools can be used to isolate each stage
when
treatments are pumped through the coiled tubing, and the different stages are
generally
perforated before fracturing operations begin. While straddle tools have
certain benefits,
a problem with employing a straddle tool is that it can make it more difficult
to circulate
treatment fluid past the upper cup, or packer, of the straddle tool to remove
excess
proppant. Additionally, the straddle tool packers have large outer diameters
and can
easily become stuck when working in slurries. The straddle tool also relies on
a good
cement job to isolate each stage, Because the casing above the straddle tool
does not see
fracturing pressure, there is a risk that either the casing can collapse or
the treatment fluid
io can exit the casing at the next set of perforations located above the
current treatment
location.
100991 The packers employed in the embodiment illustrated in
FIG. 20 can
have relatively small diameters compared to cup straddle tools, and therefore
are less
likely to become stuck. In an embodiment, the outer diameter of the packers
can be, for
is example, about 0.25 inch to about 0.75 inch smaller than the inner
diameter of the casing.
Further, because a straddle tool is not employed in this embodiment, the well
bore
annulus above the packer is pressurized throughout during fracturing, which
can reduce
the dependency on the cement for zonal isolation.
1001001 Referring to FIG. 20, when the BHA 402 is run into the
casing
20 assembly 404 on the coiled tubing 442, the packer 430 can be positioned
proximate the
collar 410 so as to allow contact with the collar 410 when the packer is
expanded to
thereby isolate the portion of annulus 450 above the packer 430 from the
portion of
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CA 02781721 2012-07-06
annulus 450 below the packer 430. In this manner, after the packer is
expanded, fluid
flowing down the coiled tubing and into annulus 450 via apertures 444 can
cause a
pressure differential across the packer 430, similarly as described above with
respect to
FIG. 2.
1001011 FIG. 21 illustrates another embodiment of the present disclosure
that is similar to that of FIG. 20, except that the BHA 402 includes a sand
jet perforator
452. Sand jet perforators are generally well known in the art. The bottom hole
assembly
is configured to provide fluid flow isolation in the inner flow path of the
BHA 402
between the sand jet perforator 452 and the fracturing aperture 444, as will
be discussed
io in greater detail below. The sandjet perforator can act as a backup to
the fracture ports in
the collar. If the sleeve in the collar does not open, or if the formation
adjacent the sleeve
is so tough that it will not break down under fracture pressure, then the BHA
can be
moved a few feet and the casing can be perforated. The fracturing treatment
can then be
carried out through the newly created perforations in the casing.
1001021 Referring back to FIG. 20, the present disclosure is also directed
to
a method for completing a hydrocarbon producing wellhole. The method comprises
running the coiled tubing 442 into the casing assembly 404. The collars 410 of
the casing
assembly 404 comprise a plurality of apertures, such as a first fracture port
412 and a
valve vent hole 414.
1001031 As discussed above, a bottom hole assembly 402 attached to the
coiled tubing 442 includes a packer 430. During run-in of the coiled tubing,
the packer
430 can be positioned so that when the packer 430 is energized, the packer 430
contacts
CA 02781721 2012-07-06
the at least one collar 410 to isolate a portion of the annulus 450 above the
packer 430
from a portion of the annulus 450 below the packer 430. This allows fluid
pumped down
the coiled tubing 442 to cause a pressure differential across the packer 430
that can open
the fracture port 412.
[00104] Optionally, the sleeves can be designed so that mechanical force
may be used in combination with fluid pressure to open and/or close the
fracture port
412. For, example, the coiled tubing may be used to apply pressure to the
sleeve,
similarly as described with respect to FIGS. 18 and 19 above.
[001051 After the fracture port 412 is opened, the well formation
can then be
io fractured by flowing fracturing fluid through the fracture port 412.
This process can be
repeated a plurality of times to accomplish multi-zone fracturing.
[00106] In an embodiment where the bottom hole assembly 402
comprises a
sand jet perforator 452, the method can further comprise isolating fluid flow
between the
sand jet perforator and the fracturing aperture. This can be accomplished by
any suitable
is technique. For example, the bottom hole assembly 402 can include a
landing profile, such
as a ball seat (not shown), that constricts the diameter of the inner flow
path between
sand jet perforator 452 and the apertures 444. A ball, dart or other device
(not shown) for
blocking the flow path of the coiled tubing can then be pumped down the coiled
tubing so
that the device lands on the ball seat between the sand jet perforator and the
fracturing
20 aperture, thereby isolating the sand jet perforator 452 from the
apertures 444. Such
landing profile and ball or dart systems are generally well known in the art.
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[00107] Blocking the flowpath of the coiled tubing allows
abrasive slurry to
be pumped down the coiled tubing and out of the sandjet perforating tool.
After
operation of the sand jet perforator is complete, the flow in the coiled
tubing and BHA
402 can be reversed to lift the ball to the surface and thereby restore fluid
flow from the
coiled tubing through the aperture 444. Instead of the landing profile and
ball or dart
system, various other mechanisms could be used to isolate the sand jet
perforator 452
from the aperture 444, as would be recognized by one of ordinary skill in the
art having
the benefit of this disclosure.
[00108] Although various embodiments have been shown and
described, the
to disclosure is not so limited and will be understood to include all such
modifications and
variations as would be apparent to one skilled in the art.
42
