Note: Descriptions are shown in the official language in which they were submitted.
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APPARATUS AND METHOD FOR
ABRASIVE JET PERFORATING
FIELD
[0001] The present disclosure relates to devices configured for jetting
abrasive fluid for
creating perforations within a wellbore, and thereby enabling fluid treatment
of a subterranean
formation, such as hydraulic fracturing, and methods using such devices.
BACKGROUND
[0002] In some hydraulic fracturing operations, the fracturing fluid enters
the subterranean
formation through one or more openings or bores. The openings may be formed
using a variety
of techniques including jetting, perforating using explosive charges, and
using casing valves.
Jetting requires that a fluid pass through a nozzle at high pressure, where
the fluid is generally
supplied through the use of pumps or other pressurization equipment at the
surface of the
wellbore.
SUMMARY
[0003] In one aspect, there is provided a perforating tool comprising a
housing, an inlet
defined within the housing, a perforator fluid passage defined within the
housing, and disposed
in fluid communication with the inlet, and a nozzle, press-fit into the
housing, and disposed in
fluid communication with the perforator fluid passage.
[0004] In another aspect, there is provided a perforating tool comprising a
housing, an inlet
defined within the housing, a perforator fluid passage defined within the
housing and disposed in
fluid communication with the inlet, a nozzle, extending through the housing to
define a jetting
orifice, and disposed in fluid communication with the perforator fluid
passage, cladding,
surrounds the jetting orifice, and a retainer, extending from the housing, and
including a
bevelled surface that retains the cladding in relative disposition to the
nozzles such that the
cladding surrounds the jetting orifice.
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[0005] In a further aspect, there is provided a perforating tool
comprising: a housing, an inlet
defined within the housing, a perforator fluid passage defined within the
housing and disposed in
fluid communication with the inlet, a nozzle, extending through the housing to
define a jetting
orifice, and disposed in fluid communication with the perforator fluid
passage, and cladding,
surrounding the jetting orifice, wherein the jetting orifice is oriented such
that, when the
perforating tool is disposed downhole and operational for perforating a
wellbore, a ray that is
extending along the axis of the jetting orifice, in an uphole direction, is
disposed at an acute
angle of at least ten (10) degrees relative to an axis that is orthogonal to
the axis of the perforator
fluid passage.
BRIEF DESCRIPTION OF DRAWINGS
[0006] Figure 1 is a side sectional view of an embodiment of an apparatus
of the present
disclosure;
[0007] Figure 2 is an elevation view taken from one end of a partially
assembled apparatus
of Figure 1, during the assembly of the apparatus of Figure 1, prior to press-
fitting of the nozzle
within a mandrel;
[0008] Figure 3 is a side sectional elevation view, taken along lines C-C
in Figure 2,
illustrating the partially assembled apparatus of Figure 1;
[0009] Figure 4 is an elevation view taken from one end of a partially
assembled apparatus
of Figure 1, during the assembly of the apparatus of Figure 1, and at a later
stage of assembly
than that illustrated in Figures 3 and 4, and after press-fitting of the
nozzle within the mandrel;
[0010] Figure 5 is a side sectional elevation view, taken along lines D-D
in Figure 4,
illustrating the partially assembled apparatus of Figure 1, and at a later
stage of assembly than
that illustrated in Figures 3 and 4;
[0011] Figure 6 is a side sectional view of a bottom hole assembly
incorporating the
apparatus of Figure 1, shown deployed within a casing; and
[0012] Figure 7 is an unwrapped view of an embodiment of a J-slot profile
that is integrated
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. .
,
,
within the bottom hole assembly of Figure 6.
DETAILED DESCRIPTION
[0013] As used herein, the terms "up", "upward", "upper", or
"uphole", mean,
relativistically, in closer proximity to the surface and further away from the
bottom of the
wellbore, when measured along the longitudinal axis of the wellbore. The terms
"down",
"downward", "lower", or "downhole" mean, relativistically, further away from
the surface and in
closer proximity to the bottom of the wellbore, when measured along the
longitudinal axis of the
wellbore.
[0014] There is provided an abrasive perforating tool 10. The
perforating tool 10 is shown as
one of several components in a bottom hole assembly ("BHA") 100. The BHA 100
is
configured for disposition within a wellbore, and is positionable therein with
a conveyance.
[0015] Suitable wellbores include vertical, deviated, horizontal or
multi-lateral wells.
[0016] The wellbore may be a cased wellbore having a casing disposed
therein. The casing
is provided for, amongst other things, supporting the subterranean formation
within which the
wellbore is disposed. The casing includes a plurality of successive casing
sections joined by a
corresponding plurality of collars. The casing lines the wellbore and is,
typically, cemented to
the subterranean formation. This enables fluid treatment of an interval or
zone of the
subterranean formation, through the casing (as will be further explained
below), while
preventing, or substantially preventing, fluid communication between the
treated zone and
another zone of the subterranean formation that is remote from the one being
treated. The
resulting installation is referred to as a cemented completion.
[0017] The conveyance includes a conduit. In some embodiments, for
example, the
conveyance 300 is in the form of a suitable tubing string, such as jointed
pipe, concentric tubing,
or coiled tubing. As used herein, the term BHA 100 refers to the combination
of tools supported
on the end of the conveyance. The conveyance extends from an oilfield surface
and is connected
to suitable oilfield surface equipment.
[0018] The perforating tool 10 includes a housing (or "body") 12. A
perforator fluid passage
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14 is defined within the housing 12 between an inlet 16 and an outlet 18. The
inlet 16 is
configured to receive a fluid from a supply source at the surface via the
conduit. In some
operational implementations, such as when the received fluid is supplied for
effecting hydraulic
fracturing, the outlet communicates at least a fraction of the received fluid
in a downhole
direction to other tools of the BHA 100.
[0019]
The perforating tool 10 also includes one or more jetting nozzles 20
extending
through the housing. The jetting nozzles 20 are operable to emit a high
velocity and or high
pressure stream of the received fluid, generally in the radially outward
direction relative to the
housing, for perforating the casing 202. In some embodiments, for example, the
nozzles 20
include a nozzle fluid passage 21 having a maximum cross-sectional flow area
of 0.0123 square
inches to 0.05 square inches. In some embodiments, for example, the nozzle 20
defines an axial
flow length of 0.5 inches to 1.0 inches.
[0020]
In some operational implementations, for example, the received fluid
is an abrasive
slurry. In some embodiments, for example, the abrasive slurry is a mixture
including water and
sand. In some embodiments, for example, the abrasive slurry includes 0.3
pounds to 1.2 pounds
of 100 to 12 mesh Ottawa sand, or 0.3 pounds to 1.2 pounds of manufactured
proppants, per
gallon of water or viscosified water.
[0021]
In some embodiments, for example, the nozzle 20 is configured to
conduct the
abrasive slurry at a speed of at least 300 feet per second. In some
embodiments, for example, the
nozzle 20 is configured to conduct the abrasive slurry at a speed of 500 feet
per second.
[0022]
In some embodiments, for example, the material of the nozzle 20 has a
hardness value
of at least 90.5 on the Rockwell A scale. In some embodiments, for example,
the hardness-value
is 93 on the Rockwell A scale.
[0023]
In some embodiments, for example, the material of the nozzle 20 has
relatively low
ductility (is relatively brittle) and can, therefore, be relatively difficult
to work with, such that
this characteristic is, in some respects, being compensated for by other
design features. In this
respect, in some embodiments, for example, the material of the nozzle is
characterized by an
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elongation of less than 5%.
[0024] In some embodiments, for example, the material of the nozzle 20
includes a carbide,
such as tungsten carbide or boron carbide. In some embodiments, the material
of the nozzle 20
is a composition including at least 85 weight % of tungsten carbide, based on
the total weight of
the nozzle 20. In some embodiments, the material of the nozzle 20 is a
composition including 85
weight % to 95 weight % of tungsten carbide, based on the total weight of the
nozzle 20.
[0025] In some embodiments, for example, the material of the nozzle 20 is a
ceramic
material, such as alumina.
[0026] The nozzle 20 is press-fit within a corresponding throughbore (or
hole) 1203 of the
housing 12. By integrating the nozzle 20 within the housing 12 by press-
fitting, the wall
thickness of the housing 12 may be made thinner, thereby permitting provision
of a fluid passage
14 having a relatively larger cross-sectional flow area. With a fluid passage
14 having a
relatively larger cross-sectional flow area, in some embodiments, for example,
the conducting of
hydraulic fracturing fluid, through the BHA (such as in a "coiled tubing
frac"), for hydraulic
fracturing of the subterranean formation, is made easier. As well, in some
embodiments, for
example, the deployment of a ball through the fluid passage 14, for
functioning as a check valve,
and thereby interfering with downhole flow of abrasive slurry that may be
supplied to the BHA
for perforating of the casing 202 by jetting through the nozzles 20, is
facilitated by the relatively
larger cross-sectional flow area of the fluid passage 14.
[0027] In some embodiments, for example, the nozzle 20 is a one-piece
nozzle.
[0028] In some embodiments, for example, the perforating tool 10 includes
cladding 22, and
the cladding 22 surrounds jetting orifices 24 defined within the nozzles 20.
The jetting orifices
24 are configured to eject the fluid being delivered through the nozzles 20.
The cladding
functions 22 to protect the jetting orifices 24 (and nozzles 20), and those
portions of the housing
12 surrounding the nozzles 20, from damage due to splashback or rebound of the
abrasive slurry
that is ejected by the nozzles 20. In some embodiments, for example, the
cladding 22 presents an
outermost surface configured to receive splashback while abrasive slurry is
being ejected by the
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nozzles 20 against casing 202 within a wellbore during perforating.
[0029] In some embodiments, for example, the material of the
cladding 22 has a hardness
value of at least 90 on the Rockwell A scale. In some embodiments, for
example, the hardness
value is 92 on the Rockwell A scale.
[0030] In some embodiments, for example, the material of the
cladding 22 has relatively low
ductility (is relatively brittle) and can, therefore, be relatively difficult
to work with, such that
this characteristic is, in some respects, compensated for by other design
features. In this respect,
in some embodiments, for example, the material of the cladding 22 is
characterized by an
elongation of less than 5%.
[0031] In some embodiments, for example, the material of the
cladding 22 includes a
carbide, such as tungsten carbide or boron carbide. In some embodiments, the
material of the
cladding 22 is a composition including at least 85 weight % of tungsten
carbide, based on the
total weight of the cladding 22. In some embodiments, the material of the
cladding 22 is a
composition including 85 weight % to 95 weight % of tungsten carbide, based on
the total
weight of the cladding 22.
[0032] In some embodiments, for example, the material of the
cladding 22 is a ceramic
material, such as alumina.
[0033] In some embodiments, for example, the cladding 22 is in the
form of a plate. In some
embodiments, for example, the cladding is in the form of a sleeve that extends
about the
perimeter of the housing. In some embodiments, for example the cladding 22
includes apertures
or holes 2201 that are disposed in alignment with the jetting orifices 24.
[0034] In some embodiments, for example, the perforating tool 10
further includes a retainer
26 that extends from the housing 12 and functions to retain the cladding 22
against the housing
12. In some embodiments, for example, the retainer 26 includes a bevelled
surface 28 that
retains the cladding 22 in relative disposition to the nozzles 20 such that
the cladding 22
surrounds the nozzles 20 (and protects the nozzles from splashback, as above-
described). In this
respect, in some embodiments, for example, the cladding 22 includes a bevelled
surface 30,
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corresponding to, and disposed in opposition to, the bevelled surface 30 of
the retainer 26. In
some embodiments, the retainer 26 is in the form of a sleeve lock ring that is
threaded to the
housing 12.
[0035] In some embodiments, for example, the retention of the cladding 22
by the bevelled
surface 28 of the retainer 26 is at least by way of interference.
[0036] The retention of the cladding 22 is made more robust by the bevelled
surface 28. In
the event that the cladding 22 fractures, the cladding 22 may still be
retained by the bevelled
surface 22.
[0037] In some embodiments, for example, the housing 12 is a generally
cylindrical-shaped
tube, with the inlet 16 and the outlet 18 disposed at opposite ends of the
tube and joined by the
perforator fluid passage 14. The nozzles 20 extend from the perforator passage
14 and through a
sidewall of the housing 12.
[0038] The following is a description of an embodiment of a method of
assembling of an
embodiment of the tool.
[0039] Referring to Figures 2 and 3, the nozzle 20 is pressed onto and over
a "press in" plug
402. After the nozzle 20 has become disposed over the press in plug 402, a
guide pin 404 is
threaded onto the press in plug 402 such that the guide pin 404 is disposed
over the nozzle 20,
and such that the nozzle 20 is retained between the guide pin 404 and a
shoulder 406 of the press
in plug 402. The resultant assembly defines the nozzle subassembly 400. The
cladding 22, in
the form a sleeve 22, is slid over a mandrel 500, and the cladding holes 2201
are aligned with
mandrel holes 501 defined by throughbores 503, provided within the mandrel 500
and
corresponding to the housing throughbores 1203. The retainer (sleeve lock
ring) 26 is then
threaded onto the mandrel 500 to retain the cladding 22. The nozzle
subassembly 400 is then
installed through one of the throughbores 503. The nozzle 20 is slightly
oversized relative to the
throughbore 503. A wedge tool 600 is then positioned within the mandrel 500
for pressing
against the nozzle subassembly 400. A snapshot of the assembly process, at
this stage, is
illustrated in Figures 2 and 3.
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[0040] The nozzle subassembly is pressed into the throughbore 503 by a
force translated by
the wedge tool 600 (in the embodiment illustrated, the force is applied in a
direction towards the
left). A snapshot of the assembly process, at this stage, is illustrated in
Figures 4 and 5.
[0041] The wedge tool 600 is then retracted, the guide pin 404 is removed
from the press in
plug 402, and the press in plug 402 is removed from the press fit nozzle 20.
The nozzle 20 is
subsequently machined by electrical discharge machining such that the nozzle
20 is flush with
the cladding 22.
[0042] Referring to Figure 6, in some embodiments, for example, the
perforating tool 10 is
incorporated within the BHA 100. In this respect, in some embodiments, for
example, the
perforating tool 10 is threadably connected to one or more other tools of the
BHA 100.
[0043] Referring to Figures 1 and 6, in some embodiments, for example, the
nozzle 20 when
integrated within the housing 12 of the tool 10, is oriented such that, when
the tool 10 is
integrated within the BHA 100, and the BHA 100 is disposed within a wellbore,
and while fluid
(such as an abrasive slurry) is being conducted through the tool 10, the
abrasive slurry is being
ejected through the nozzle 20 and directed in an uphole direction for
effecting perforation of
casing that is lining the wellbore, with effect that a portion of a casing,
disposed uphole relative
to the tool 10, is perforated. In some embodiments, for example, the
orientation is such that a ray
241 that is extending along the axis 243 of the jetting orifice 24 is
disposed, in an uphole
direction, at an acute angle of at least 10 degrees relative to an axis that
is orthogonal to the axis
141 of the perforator fluid passage 14. In some of these embodiments, for
example, the
orientation is such that the ray 241 that is extending along the axis 243 of
the jetting orifice 24 is
disposed, in an uphole direction, at an acute angle of 20 degrees relative to
the axis that is
orthogonal to the axis 141 of the perforator fluid passage 14. By virtue of
this orientation,
perforations are created uphole, relative to the tool 10. As a result, when
hydraulic fracturing
fluid is supplied through the annulus between the tool 10 and the wellbore,
the entirety of the
hydraulic fracturing fluid being supplied is not conducted past the tool 10,
and at least (and,
some examples, most) of the hydraulic fracturing fluid is conducted through
the perforation(s)
that have been created in the casing, uphole relative to tool 10. As such
erosion of the tool 10,
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by the hydraulic fracturing fluid being supplied, is mitigated.
[0044] As discussed above, the BHA 100 is deployable within a wellbore.
While the BHA is
deployed within the wellbore, a wellbore annulus is defined between the BHA
and the casing
202.
[0045] In some embodiments, for example, the BHA 100 includes a fluid
conducting
structure 102, a casing annulus sealing member 104, an equalization valve 106,
a lower mandrel
108, and the perforating tool 10.
[0046] The fluid conducting structure 102 includes a fluid passage 1021.
The fluid passage
1021 may be provided for effecting flow of fluid material for enabling, for
example, perforation
of the casing 202. The BHA 100 is configured such that, for some
implementations, while the
BHA 100 is disposed within the wellbore, the fluid passage 1021 extends
downhole from the
wellhead.
[0047] The fluid conducting structure 102 includes ports 107. While the BHA
100 is
deployed within the wellbore, each one of the ports 107 extends between a
wellbore annulus 204
and the fluid passage 1021. In this respect, in some implementations (see
below), fluid
communication is effected between the wellbore annulus 204 and the fluid
passage 1021 through
the ports 107.
[0048] The casing annulus sealing member 104 is provided and configured for
becoming
disposed in sealing engagement with the casing. The casing annulus sealing
member 104 is
mounted to the lower mandrel 108. The casing annulus sealing member 104 is
configured to be
actuated into sealing engagement with the casing, while the BHA 100 is
deployed within the
wellbore and has been located within a predetermined position at which fluid
treatment is desired
to be a delivered to the formation. In this respect, the casing annulus
sealing member 104 is
disposable between at least an unactuated condition and a sealing engagement
condition. In the
unactuated condition, the casing annulus sealing member 104 is spaced apart
(or in a retracted
state) relative to the casing. In the sealing engagement condition, the casing
annulus sealing
member 104 is disposed in the above-described sealing engagement with the
casing, while the
BHA 100 is deployed within the wellbore and has been located within a
predetermined position
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at which fluid treatment is desired to be a delivered to the formation. The
sealing engagement is
with effect that fluid communication, through the wellbore annulus, and across
the sealing
member 104, between a treatment material interval and a downhole casing
passage portion
disposed downhole of the sealing member 104, is sealed or substantially
sealed.
[0049] In some embodiments, for example, the casing annulus sealing member
104 is
defined by a resettable sealing member 105A of a packer 105. The packer 105 is
disposable
between unset and set conditions. In the unset condition, while the BHA 100 is
disposed within
the wellbore, in some implementations (such as while the BHA 100 is located
within a
predetermined position at which fluid treatment is desired to be delivered to
the formation) the
sealing member 105A is spaced apart (in the retracted state) relative to the
casing, nd thus, in
effect, renders the sealing member 104 in the unactuated condition. In the set
condition, the
sealing member 105A is disposed in sealing engagement with the casing, while
the BHA 100 is
deployed within the wellbore and has been located within a predetermined
position at which
fluid treatment is desired to be a delivered to the formation, and thus, in
effect, renders the
sealing member 105A in the sealing engagement condition. Mechanically actuated
locking
devices or slips 105B may be positioned below the sealing member 105A to
resist movement of
the sealing member 105A down the wellbore when the sealing member 105A is in
the set
position. The setting and unsetting of the packer 105 is further explained
below.
[0050] An equalization valve 106 is provided for at least interfering with
fluid
communication, through the fluid passage 1021, via ports 107 extending through
the fluid
conducting structure 202, between: (i) an uphole wellbore annulus portion that
is disposed
uphole relative to the casing annulus sealing member 104, and (ii) a downhole
casing passage
portion that is disposed downhole relative to the casing annulus sealing
member 104, while the
casing annulus sealing member 104 is sealingly engaging the casing. The uphole
wellbore
annulus portion is a portion of the wellbore annulus that is disposed uphole
of the sealing
member 104. In this respect, while the casing annulus sealing member 104 is
sealingly engaging
the casing, the equalization valve 106 is disposable between at least:
(a) a downhole isolation condition, wherein fluid communication, through the
fluid passage
1021, via the ports 107, between the uphole wellbore annulus portion and the
downhole casing
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passage portion, is sealed or substantially sealed, and
(b) a depressurization condition, wherein the uphole wellbore annulus portion
is disposed in fluid
communication, through the fluid passage 1021, via the ports107, with the
downhole casing
passage portion.
[0051] The equalization valve 106 includes a valve plug 110 and a
valve seat 112. The valve
plug 110 is connected to the conveyance 300 via a pull tube 214. In this
respect, the valve plug
106 is moveable, in response to forces translated by the pull tube 114, that
are being applied to
the conveyance 300, between a downhole isolation position, corresponding to
disposition of the
equalization valve 106 in the downhole isolation condition, and a
depressurization position,
corresponding to disposition of the equalization valve 106 in the
depressurization condition. The
valve seat 112 is connected to the lower mandrel 108 (see below).
[0052] The valve plug 110 is configured for sealingly engaging the
valve seat 112. While
the valve plug 110 is disposed in the downhole isolation condition, the valve
plug 110 is
disposed in sealing engagement with the valve seat 112. While the valve plug
110 is disposed in
the depressurization condition, the valve plug 110 is spaced apart from the
valve seat 112.
[0053] Movement of the valve plug 110 from the downhole isolation
position to the
depressurization position is in a direction that is uphole relative to the
valve seat 112. Such
movement is effected by application of a tensile force to the conveyance 300,
resulting in
translation of such force to the valve plug 110 by the pull tube 114. Uphole
movement of the
valve plug 110, relative to the valve seat 112, is limited by a detent surface
(or "stop") 111 that is
integral with the structure that forms the valve seat 112 (and is part of the
equalization valve
106). In this respect, the valve plug 110 includes a shoulder surface, and the
limiting of the
uphole movement of the valve plug 110, relative to the valve seat 112, is
effected upon contact
engagement between the shoulder surface and the stop 111.
[0054] A check valve 122 is provided within the fluid passage 1021,
uphole of the valve seat
112. The check valve 122 seals fluid communication between an uphole portion
1021A of the
fluid passage 1021 and the uphole wellbore annulus portion (via the ports 107)
by sealingly
engaging a valve seat 1221, and is configured to become unseated, to thereby
effect fluid
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communication between the uphole wellbore annulus portion and the uphole
portion 1021A, in
response to fluid pressure in the uphole wellbore annulus portion exceeding
fluid pressure
within the uphole portion 1021A by a minimum predetermined amount. In this
respect, the check
valve 122 permits material to be conducted through the fluid passage 1021 in
an uphole
direction, but not in a downhole direction.
[0055] In some implementations, for example, the material being supplied
downhole through
the wellbore annulus includes fluid for effecting reverse circulation (in
which case, the
equalization valve 106 is also closed), for purposes of removing debris from
the wellbore
annulus, such as after a "screen out".
[0056] In some embodiments, for example, the check valve 222 is in the form
of a ball that is
retained within a fluid passage portion of the fluid passage 2021, uphole
relative to the valve seat
221, by a retainer 2221.
[0057] After the casing has been perforated to form perforations within the
casing, while the
casing annulus sealing member 104 is disposed in the sealing engagement
condition, and while
the valve plug 110 is disposed in the downhole isolation position, treatment
material may be
supplied downhole and directed to the perforations, and through the
perforations and into the
treatment interval within the subterranean formation, through the uphole
wellbore annulus
portion. Without the valve plug 110 effecting the sealing of fluid
communication, through the
fluid passage 1021, between the uphole wellbore annulus portion and the
downhole casing
passage portion, at least some of the supplied treatment material may bypass
the perforations and
be conducted further downhole from the perforation via ports 107 to the
downhole casing
passage portion. Also, the check valve 122 prevents, or substantially
prevents, fluid
communication of treatment material, being supplied downhole through the
uphole wellbore
annulus portion, with the uphole fluid passage portion 1021A, thereby also
mitigating losses of
treatment material uphole via the fluid passage 1021.
[0058] The lower mandrel 108 is connected to the valve seat 112, and is
thereby configured
for receiving forces translated by the valve plug 110 (such as, for example,
tensile or
compressive forces applied to the conveyance 300) to the valve seat 112. The
lower mandrel
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108 is configured to receive compressive forces translated to the valve seat
112 by the valve plug
110 (and as applied to the conveyance 300) when the valve plug 110 has reached
the downhole
limit of its extent of travel relative to the valve seat 112 (i.e. the valve
plug 110 is sealingly
engaging the valve seat 112). The lower mandrel 108 is also configured to
receive tensile forces
in response to pulling up on the conveyance 300, which is translated to the
valve seat 112 by
virtue of the contact engagement between the shoulder surface of the valve
plug 110 and the
detent surface 111 that is connected to the valve seat 112.
100591 A J-slot 82 is formed within the lower mandrel, for enabling the
setting and unsetting
of the packer 205, in response to forces applied to the conveyance 300, which
are translated to
the lower mandrel 208, as above-described. An unwrapped view of an exemplary J-
slot is shown
in Figure 5 having three pin stop positions 821a, 821b, and 821c, that are
repeated about the
lower mandrel. The three pin stop positions correspond to various conditions
of the packer
assembly, namely, the set position 821a (in which the sealing member 205A is
disposed in
sealing engagement with the casing (and, specifically, the valve closure
member 16) and the
equalization valve 106 is disposed in the downhole isolation condition), the
release (or "pull")
position 821b (in which the sealing member 105A is spaced apart from the
casing), and the
running-in position 821c (in which the valve plug of the equalization valve
106 is unseated, and
the packer 105 is not set). A cam actuator or pin 105C, coupled to mechanical
slips 105B, is
disposed for travel within the J-slot. Debris relief apertures 823 may be
provided at various
positions within the J-slot 82 to permit discharge of settled solids as the
pin slides within the J-
slot 82.
[0060] In some embodiments, for example, the packer 105 is set by applying
compressive
forces to the conveyance 300. When the valve plug 110 is seated against the
valve seat 112,
these forces are translated to the lower mandrel 108. This results in
engagement between an
upper end of a setting cone 105D, mounted to the lower mandrel 108, and the
sealing member
105A, which forces the sealing member 105A outwardly, compressing the sealing
member 105A
into sealing engagement with the casing. In parallel, a lower end of the
setting cone 105D
engages the mechanical slips 105B and the J-slot slides relative to the pin
105C. Due to
frictional resistance provided by the locator 118, the setting cone 105D
forces the mechanical
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slips 105B outwardly against the casing, and the movement of the J-slot
relative to the pin 105C
results in the pin 105C becoming disposed in the set position 821a. The
mechanical slips 105B
are now gripping (or "biting into") the casing 11, and the pin is resisting
retraction of the
mechanical slips 105B from the casing.
[0061] In some embodiments, for example, the lower mandrel 108
further includes a
bullnose centralizer 1141 for centralizing the BHA 100.
[0062] In some embodiments, for example, the BHA 100 includes a
lower subassembly 116.
The lower subassembly 116 is slidably mounted to the lower mandrel 108,
between the packer
105 and the bullnose centralizer 1141 The lower subassembly 116 includes a
locator 118 for
effecting desired positioning of the tool assembly relative to the casing. The
locator 118 extends
outwardly, relative to the lower mandrel 108, and is configured to engage the
casing while the
BHA 100 is being moved uphole or downhole. In some embodiments, for example,
the locator
118 includes a locator collet 118A for engaging a corresponding recess within
the casing and
thereby resist movement of the BHA 100 relative to the casing.
[0063] The perforating tool 10 is disposed in fluid communication
wih the fluid passage
1021 for receiving abrasive slurry, from the surface, via the fluid passage
1021, and jetting the
received abrasive slurry, via the nozzles 20, against the casing 202, for
effecting perforating of
the casing 202 in the vicinity of the nozzles 20.
[0064] The following describes an exemplary deployment of the BHA
100 within a cased
wellbore, and subsequent supply of treatment material to a zone of the
subterranean formation
100.
[0065] The BHA 300 is run downhole through the cased wellbore, past
a predetermined
position. Once past the desired location, a tensile force is applied to the
workstring, and the
predetermined position, at which the selected treatment material port is
located, is located with
the locator 118. The conveyance 300 becomes properly located when the locator
becomes
disposed within a locating recess within the casing 202. In this respect, the
locator 218 and the
locating recess are co-operatively profiled such that the locator 118 is
configured for disposition
within and engagement to the locating recess when the locator 218 is moving
past the first
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locating recess. Successful locating of the locator 118 within the locating
recess 111 is
confirmed when resistance is sensed in response to upward pulling on the
conveyance 300.
[0066]
Once disposed in the pre-determined position, an abrasive slurry is
then supplied
through the fluid passage 1021. The supplied abrasive slurry is jetted through
the nozzles 20 and
against the casing 202, causing creation of perforations within the casing 202
so as to enable
subsequent supplying of treatment material to the subterranean formation.
[0067]
After the perforations are created, the conveyance 300 is forced
downwardly, and the
applied force is translated such that sealing engagement of the valve plug 110
with the valve seat
112 is effected. Further compression of the conveyance 300 results in setting
of the packer 205
(as the lower mandrel 108 receives the compressive forces imparted by the
conveyance 300),
including its associated mechanical slips 105B, for effecting sealing
engagement of the resilient
sealing member 105A to the casing 202, and also for effecting the engagement
(e.g. gripping) of
the packer 105 to the casing 202.
[0068]
Treatment material may then be supplied via the wellbore annulus 208,
defined
between the bottom hole assembly 100 and the casing 202, and through the
created perforations
and into the subterranean formation, thereby effecting treatment of the
subterranean formation
that is local to the perforations. The packer 105, in combination with the
sealing engagement of
the valve plug 110 with the valve seat 112, prevents, or substantially
prevents, the supplied
treatment material from being conducted downhole, with effect that all, or
substantially all, of
the supplied treatment material, being conducted via the wellbore annulus 208,
is directed to the
formation through the perforations.
[0069]
In the above description, for purposes of explanation, numerous details
are set forth in
order to provide a thorough understanding of the present disclosure. However,
it will be
apparent to one skilled in the art that these specific details are not
required in order to practice
the present disclosure.
Although certain dimensions and materials are described for
implementing the disclosed example embodiments, other suitable dimensions
and/or materials
may be used within the scope of this disclosure. All such modifications and
variations, including
all suitable current and future changes in technology, are believed to be
within the sphere and
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CA 02900716 2015-08-17
scope of the present disclosure. All references mentioned are hereby
incorporated by reference
in their entirety.
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