Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
SELECTIVE STIMULATION PORTS INCLUDING SEALING DEVICE RETAINERS
AND METHODS OF UTILIZING THE SAME
Field of the Disclosure
[0001] The present disclosure relates generally to selective stimulation
ports and more
particularly to selective stimulation ports that include and/or utilize
sealing device retainers and/or
to methods of utilizing the selective stimulation ports.
Background of the Disclosure
[0002] Hydrocarbon wells generally include a wellbore that extends from a
surface region
and/or that extends within a subterranean formation that includes a reservoir
fluid, such as liquid
and/or gaseous hydrocarbons. Often, it may be desirable to stimulate the
subterranean formation,
such as to enhance production of the reservoir fluid therefrom. Stimulation of
the subterranean
formation may be accomplished in a variety of ways and generally includes
supplying a stimulant
fluid to the subterranean formation to increase reservoir contact. As an
example, the stimulation
may include supplying an acid to the subterranean formation to acid-treat the
subterranean
formation and/or to dissolve at least a portion of the subterranean formation.
As another example,
the stimulation may include fracturing the subterranean formation, such as by
supplying a
fracturing fluid, which is pumped at a high pressure, to the subterranean
formation. The fracturing
fluid may include particulate material, such as a proppant, which may at least
partially fill fractures
that are generated during the fracturing, thereby facilitating flow of the
reservoir fluid into the
hydrocarbon well, via the fractures, after supply of the fracturing fluid has
ceased.
[0003] A variety of systems and/or methods have been developed to
facilitate stimulation of
subterranean formations, and each of these systems and methods generally has
inherent benefits
and drawbacks. Many of these systems and methods utilize a shape-charge
perforation gun to
.. create perforations within a wellbore tubular that defines a tubular
conduit and extends within the
wellbore, and the stimulant fluid then is provided to the subterranean
formation via the
perforations. However, such systems suffer from a number of limitations. As an
example, the
perforations may not be round or may have burrs, which may make it challenging
to seal the
perforations subsequent to stimulating a given region of the subterranean
formation. As another
example, the perforations often will erode and/or corrode due to flow of the
stimulant fluid, flow
of proppant, and/or long-term flow of reservoir fluid therethrough.
- 1 -
CA 3007078 2019-04-09
[0004] As yet another example, a stimulation process may involve sealing
perforations with
a sealing device, such as a ball sealer, in order to facilitate stimulation of
various zones, or regions,
of the subterranean formation. In such a stimulation process, a pressure
within the tubular conduit
must be maintained higher than a pressure within the subterranean formation
proximate the tubular
conduit or the sealing devices may unseat from corresponding perforations,
thereby unsealing the
corresponding perforations. In some circumstances, it may be difficult to
maintain the higher
pressure within the tubular conduit, especially if the perforations are only
partially sealed.
Additionally or alternatively, unexpected events may cause the pressure within
the tubular conduit
to drop, thereby unseating the sealing devices from the corresponding
perforations. Unseated
I() sealing balls may be difficult to reseat on the corresponding
perforations. Such events may be
costly and/or time-consuming to mitigate. Thus, there exists a need for
selective stimulation ports
with preformed sealing device seats and sealing device retainers that are
configured to retain
sealing devices proximate the corresponding sealing device seats.
Summary of the Disclosure
[0005] Selective stimulation ports including sealing device retainers and
methods of utilizing
the same are disclosed herein. The selective stimulation ports (SSPs) have a
conduit-facing region
and a formation-facing region and are configured to be operatively attached to
a wellbore tubular
that defines a tubular conduit. The wellbore tubular is configured to extend
within a wellbore that
extends within a subterranean formation. The SSPs include an SSP conduit,
which extends at
least substantially perpendicular to a wall of the wellbore tubular, and a
sealing device receptacle,
which defines at least a portion of the SSP conduit and is sized to receive a
sealing device. The
SSPs also include a sealing device seat, which defines at least a portion of
the SSP conduit, is
defined within the sealing device receptacle, and is shaped to form a fluid
seal with the sealing
device. The SSPs further include a sealing device retainer, which is
configured to retain the
sealing device within the sealing device receptacle.
[0006] The methods include methods of stimulating the hydrocarbon well.
These methods
include pressurizing a wellbore tubular and opening a selected SSP of a
plurality of SSPs, with
the plurality of SSPs being spaced-apart along a length of the wellbore
tubular. These methods
also include flowing a first volume of stimulant fluid into the subterranean
formation via an SSP
conduit of the selected SSP and releasing a sealing device within the tubular
conduit. These
methods further include receiving the sealing device within a sealing device
receptacle of the
- 2 -
CA 3007078 2019-04-09
selected SSP and retaining the sealing device within the sealing device
receptacle with a sealing
device retainer of the selected SSP. The retaining may include retaining while
a pressure within
the tubular conduit is greater than a pressure within the subterranean
formation, retaining while
the pressure within the subterranean formation is greater than the pressure
within the tubular
conduit, and/or retaining during pressure cycling of the hydrocarbon well.
These methods also
include seating the sealing device on a sealing device seat of the selected
SSP and repeating at
least a portion of the methods to stimulate a plurality of subsequent regions
of the subterranean
formation.
[0007] The methods also may include methods of conveying a downhole tool
within the
mi hydrocarbon well utilizing the SSPs. These methods include restricting
fluid flow through each
SSP in a plurality of SSPs, with the plurality of SSPs being spaced-apart
along a length of a
wellbore tubular, with a respective sealing device by receiving the respective
sealing device within
a respective sealing device receptacle and on a respective sealing device seat
of each SSP. These
methods also include retaining the respective sealing device within the
respective sealing device
.. receptacle with a respective sealing device retainer of each SSP and
establishing fluid
communication between the subterranean formation and a downhole region of the
tubular conduit.
These methods further include positioning a downhole tool within an uphole
region of the tubular
conduit, providing a conveyance fluid to the tubular conduit, and pumping the
downhole tool in a
downhole direction within the tubular conduit.
Brief Description of the Drawings
[0008] Fig. 1 is a schematic representation of examples of a hydrocarbon
well that may
include and/or utilize selective stimulation ports, wellbore tubulars, and/or
methods, according to
the present disclosure.
[0009] Fig. 2 is a schematic representation of examples of a selective
stimulation port,
.. according to the present disclosure, illustrating a seated sealing device.
[0010] Fig. 3 is another schematic representation of the selective
stimulation port of Fig. 2
illustrating an unseated sealing device.
[0011] Fig. 4 is another schematic representation of the selective
stimulation port of Fig. 2
illustrating a sealing device entering a sealing device receptacle.
[0012] Fig. 5 is a schematic representation of examples of a selective
stimulation port
according to the present disclosure.
- 3 -
CA 3007078 2019-04-09
[0013] Fig. 6 is a flowchart depicting methods, according to the present
disclosure, of
stimulating a hydrocarbon well.
[0014] Fig. 7 is a flowchart depicting methods, according to the present
disclosure, of
conveying a downhole tool within a hydrocarbon well.
Detailed Description and Best Mode of the Disclosure
[0015] Figs. 1-7 provide examples of hydrocarbon wells 10, of wellbore
tubulars 40, of
selective stimulation ports 100, of methods 1100, and/or of methods 1200,
according to the present
disclosure. Elements that serve a similar, or at least substantially similar,
purpose are labeled with
like numbers in each of Figs. 1-7, and these elements may not be discussed in
detail herein with
reference to each of Figs. 1-7. Similarly, all elements may not be labeled in
each of Figs.1-7, but
reference numerals associated therewith may be utilized herein for
consistency. Elements,
components, and/or features that are discussed herein with reference to one or
more of Figs. 1-7
may be included in and/or utilized with any of Figs. 1-7 without departing
from the scope of the
present disclosure. In general, elements that are likely to be included in a
particular embodiment
are illustrated in solid lines, while elements that are optional are
illustrated in dashed lines.
However, elements that are shown in solid lines may not be essential and, in
some embodiments,
may be omitted without departing from the scope of the present disclosure.
[0016] Fig. 1 is a schematic representation of examples of a hydrocarbon
well 10 that may
include and/or utilize selective stimulation ports 100, wellbore tubulars 40,
and/or methods 1100
and/or 1200, according to the present disclosure. Hydrocarbon wells 10 include
wellbore
tubular 40, which defines a tubular conduit 42. Hydrocarbon wells 10 also
include a wellbore 20,
which extends within a subterranean formation 34, and wellbore tubular 40
extends within the
wellbore. Wellbore 20 also may be referred to herein as extending within a
subsurface region 32
that includes subterranean formation 34 and/or as extending between a surface
region 30 and
subterranean formation 34. Subterranean formation 34 may include a reservoir
fluid 36, such as
a hydrocarbon, and hydrocarbon well 10 may be utilized to produce the
reservoir fluid from the
subterranean formation.
[0017] Hydrocarbon wells 10 also include a plurality of selective
stimulation ports (SSPs)
100. As discussed in more detail herein with reference to Figs. 2-5, each SSP
100 is operatively
attached to wellbore tubular 40 such that a corresponding conduit-facing
region 112 of the SSP
faces toward tubular conduit 42 and also such that a corresponding formation-
facing region 114
- 4 -
CA 3007078 2019-04-09
of the SSP faces away from tubular conduit 42, toward subsurface region 32,
and/or toward
subterranean formation 34.
[0018] As illustrated in Fig. 1, SSPs 100 may be spaced-apart from one
another, such as along
a length, or longitudinal length, of wellbore 20 and/or of wellbore tubular
40. Wellbore 20 and/or
wellbore tubular 40 may include, have, and/or define an uphole end, or region,
26 and a downhole
end, or region, 24. Downhole end 24 may be defined within subsurface region
32, may be defined
within subterranean formation 34, and/or may be distal surface region 30
relative to uphole end
26. Uphole end 26 may open to surface region 30 and/or may be proximal surface
region 30
relative to downhole end 24. Wellbore 20 further may define an uphole
direction 28 and a
to downhole direction 29. Uphole direction 28 may be defined along a length
of wellbore 20 and/or
may point toward surface region 30. Conversely, downhole direction 29 may be
defined along
the length of wellbore 20 but may point toward downhole end 24.
[0019] As illustrated in dashed lines in Fig. 1, hydrocarbon well 10 may
include a shockwave
generation device 190, which may be positioned within tubular conduit 42. As
illustrated in Figs.
2-5, SSPs 100 may include an isolation device 120, and shockwave generation
device 190, when
present, may be configured to generate a shockwave 194 within a wellbore fluid
22 that extends
within tubular conduit 42. Shockwave 194 may be utilized to transition
isolation device 120 of a
corresponding SSP 100 from a closed state to an open state. When in the closed
state, the
corresponding SSP may resist, block, and/or occlude fluid flow therethrough
and/or between
tubular conduit 42 and subterranean formation 34. When in the open state, the
corresponding SSP
may permit fluid flow therethrough and/or between the tubular conduit and the
subterranean
formation. Shockwave generation device 190 may be operatively attached to an
umbilical 192,
which may extend within tubular conduit 42 and/or may interconnect shockwave
generation
device 190 with surface region 30.
[0020] Wellbore tubular 40 may include and/or be any suitable elongate
tubular structure that
may extend within wellbore 20 and/or that may define tubular conduit 42. As an
example,
wellbore tubular 40 may include and/or be a casing string 50. As another
example, wellbore
tubular 40 may include and/or be inter-casing tubing 60.
[0021] When wellbore tubular 40 includes casing string 50, SSPs 100 may
be operatively
attached to any suitable portion, or region, of casing string 50. As examples,
one or more
SSPs 100 may be operatively attached to one or more of a casing collar 54 of
the casing string, a
- 5 -
CA 3007078 2019-04-09
casing segment 52 of the casing string, a blade centralizer 56 of the casing
string, and/or a
sleeve 58 that slides over the casing string.
[0022] It is within the scope of the present disclosure that SSPs 100 may
be operatively
attached to wellbore tubular 40 prior to wellbore tubular 40 being positioned
within wellbore 20.
In addition, it is also within the scope of the present disclosure that SSPs
100 may be operatively
attached to wellbore tubular 40 in any suitable manner. As examples, one or
more SSPs 100 may
be operatively attached to wellbore tubular 40 via one or more of a threaded
connection, a glued
connection, a press-fit connection, a welded connection, and/or a brazed
connection. As additional
examples, one or more SSPs 100 may be formed within wellbore tubular 40 and/or
may be formed
lo within a given segment, region, and/or portion of the wellbore tubular.
[0023] Figs. 2-5 provide additional and/or more detailed examples of SSPs
100 according to
the present disclosure. SSPs 100 of Figs. 2-5 may include and/or be more
detailed representations,
or illustrations, of SSPs 100 of Fig. 1, and any of the structures, functions,
and/or features that are
discussed herein with reference to SSPs 100 of Figs. 2-5 may be included in
and/or utilized with
hydrocarbon wells 10 of Fig. 1 without departing from the scope of the present
disclosure.
Similarly, any of the structures, functions, and/or features that are
discussed herein with reference
to hydrocarbon wells 10 of Fig. 1 may be utilized with SSPs 100 of Figs. 2-5
without departing
from the scope of the present disclosure.
[0024] Fig. 2 is a schematic representation of examples of an SSP 100,
according to the
present disclosure, illustrating a seated sealing device 142, while Fig. 3 is
another schematic
representation of SSP 100 of Fig. 2 illustrating an unseated sealing device
142 that is retained
within sealing device receptacle 134 by sealing device retainer 138. Fig. 4 is
another schematic
representation of SSP 100 of Fig. 2 illustrating sealing device 142 entering a
sealing device
receptacle 134 thereof, while Fig. 5 is a schematic representation of
additional examples of a
selective stimulation port 100 according to the present disclosure.
[0025] As illustrated in Figs. 2-5, SSPs 100 are configured to be
operatively attached to
wellbore tubular 40 and define conduit-facing region 112 and formation-facing
region 114. SSPs
100 include an SSP conduit 116 that extends perpendicular, or at least
substantially perpendicular,
to a wall 68 of wellbore tubular 40 and between conduit-facing region 112 and
formation-facing
region 114.
- 6 -
CA 3007078 2019-04-09
[0026] SSPs 100 also include a sealing device receptacle 134, which is
sized to receive a
sealing device 142 and defines at least a portion of SSP conduit 116. As
perhaps best illustrated
in Fig. 4, sealing device 142 may flow into sealing device receptacle 134 via
tubular conduit 42.
SSPs 100 further include a sealing device seat 140. Sealing device seat 140
defines at least a
portion of SSP conduit 116 and is defined within and/or by sealing device
receptacle 134. In
addition, sealing device seat 140 is shaped to form a fluid seal 144, as
illustrated in Figs. 2 and 5,
with sealing device 142.
100271 SSPs 100 further include a sealing device retainer 138. Sealing
device retainer 138
may be configured to permit sealing device 142 to enter and/or to be received
within sealing device
to receptacle 134, such as to seat upon sealing device seat 140 to form a
fluid seal therewith.
Subsequent to the sealing device being received within the sealing device
receptacle, sealing
device retainer 138 is configured to retain the sealing device within the
sealing device receptacle
and also to permit the sealing device to be unseated from sealing device seat
140 while remaining
within the sealing device receptacle, as illustrated in Fig. 3.
[0028] When sealing device 142 forms fluid seal 144 with sealing device
seat 140, as
illustrated in Figs. 2 and 5, the sealing device selectively restricts a fluid
outflow 35 from tubular
conduit 42 and into subsurface region 32 via SSP conduit 116. Stated another
way, fluid seal 144,
when present, blocks, restricts, and/or occludes fluid flow through the SSP
conduit. Conversely,
when sealing device 142 does not form the fluid seal with sealing device seat
140, when sealing
device 142 contacts sealing device retainer 138, and/or when sealing device
142 is unseated from
sealing device seat 140, SSP 100 permits a fluid inflow 33 from subsurface
region 32 into tubular
conduit 42 via SSP conduit 116, as illustrated in Fig. 1 Under these
conditions, sealing device
retainer 138 may be referred to herein as retaining sealing device 142 within
sealing device
receptacle 134. SSPs 100 that include sealing devices 142 received within
sealing device
.. receptacles 134 automatically may form fluid seal 144 when a pressure
within tubular conduit 42
is greater than a pressure within subsurface region 32, thus restricting fluid
outflow 35. In
addition, SSPs 100 automatically may permit fluid inflow 33 when the pressure
within tubular
conduit 42 is less than the pressure within subsurface region 32. Thus, and as
discussed, the
combination of a given sealing device 142 with a given SSP 100 may permit
repeated seating of
sealing device 142 on sealing device seat 140 and unseating of sealing device
142 from sealing
- 7 -
CA 3007078 2019-04-09
device seat 140, which may cause sealing and unsealing of SSP conduit 116,
respectively, during
pressure cycling of the hydrocarbon well.
[0029] Referring generally to Figs. 1-5, and during operation of
hydrocarbon wells 10, tubular
conduit 42 may be pressurized with a stimulant fluid and a selected SSP 100
then may be
transitioned from the closed state to the open state. A volume of stimulant
fluid then may be
flowed into subterranean formation 34, such as to stimulate the subterranean
formation.
Subsequently, a sealing device 142 may be released within tubular conduit 42
and may be received
by sealing device receptacle 134 of a corresponding SSP 100 and seated upon
sealing device seat
140 thereof. The sealing device then is retained within sealing device
receptacle 134 by sealing
to device retainer 138 of the SSP and permits fluid flow from the
subterranean formation into the
tubular conduit while restricting fluid flow from the tubular conduit into the
subterranean
formation. The combination of the SSP and the sealing device may be cycled
between a
configuration in which the sealing device restricts fluid flow and a
configuration in which the
sealing device permits fluid flow any suitable number of times. This cycling
may be based solely
upon a pressure differential between the tubular conduit and the subterranean
formation and across
the SSP and also may be referred to herein as pressure cycling the hydrocarbon
well. Thus, the
sealing device may be selectively and repeatedly seated on and unseated from
the sealing device
seat, with the sealing device retainer preventing the sealing device from
being dissociated from
the corresponding sealing device receptacle.
[0030] Sealing device retainer 138 may include and/or be any suitable
structure that may be
adapted, configured, designed, sized, shaped, and/or constructed to permit
sealing device 142 to
enter, or to be received within, sealing device receptacle 134 and/or to
retain the sealing device
within the sealing device receptacle. As an example, and as illustrated in
Figs. 2-5, sealing device
receptacle 134 may include and/or define an aperture 135 within conduit-facing
region 112 and
sealing device retainer 138 may extend and/or project at least partially
across the aperture.
[0031] As another example, sealing device retainer 138 may be biased, or
may include a
biasing structure, to permit motion of the sealing device into the sealing
device receptacle and also
to resist motion of the sealing device out of the sealing device receptacle.
Stated another way, the
sealing device retainer may be configured to permit the sealing device to
flow, from the tubular
conduit and past the sealing device retainer, into engagement, or sealing
engagement, with the
- 8 -
CA 3007078 2019-04-09
sealing device seat. However, the sealing device retainer may be configured to
resist flow of the
sealing device from and/or out of the sealing receptacle and to and/or into
the tubular conduit.
[0032] Such biasing may be accomplished in any suitable manner. As an
example, and as
illustrated in solid lines in Fig. 4, sealing device retainer 138 may be
configured to be compressed
and/or deformed to permit the sealing device to enter the sealing device
receptacle. As another
example, and as illustrated in dashed lines in Fig. 4, sealing device retainer
138 may be configured
to rotate and/or pivot to permit the sealing device to enter the sealing
device receptacle. However,
and subsequent to the sealing device entering the sealing device receptacle,
sealing device retainer
138 may return to a configuration in which the sealing device retainer
restricts movement of the
sealing device from and/or out of the sealing device receptacle, as
illustrated in Figs. 2-3 and 5.
[0033] As discussed, SSP 100 and/or sealing device retainer 138 thereof
may be configured
to permit sealing device 142 to be unseated from sealing device seat 140 and
to be reseated with
the sealing device seat a plurality of times. As an example, sealing device
retainer 138 may retain
the sealing device within the sealing device receptacle while the sealing
device is repeatedly seated
on, and unseated from, the sealing device seat. Thus, SSPs 100 that include
sealing devices 142
received within sealing device receptacles 134 may be configured to repeatedly
permit fluid inflow
33 and/or to repeatedly restrict fluid outflow 35 during construction,
completion, and/or operation
of a hydrocarbon well 10 that includes the SSPs.
[0034] It is within the scope of the present disclosure that sealing
device retainer 138 may
include and/or be a permanent, or at least substantially permanent, sealing
device retainer
configured to retain a respective sealing device indefinitely. This may
include retaining the
respective sealing device over an operational lifetime of hydrocarbon well 10
and/or while the
sealing device is seated upon, and unseated from, the sealing device seat any
suitable number of
times.
[0035] Conversely, it is also within the scope of the present disclosure
that sealing device
retainer 138 may be configured to temporarily retain the respective sealing
device, such as to
retain the respective sealing device for a predetermined, or desired,
retention time and then to
release the respective sealing device or otherwise permit the sealing device
to flow out of the
sealing device receptacle. Such a configuration may permit SSP 100 to
selectively permit the
fluid inflow and restrict the fluid outflow during the retention time and
subsequently to permit
- 9 -
CA 3007078 2019-04-09
increased and/or two-way fluid flow through SSP 100 subsequent to the removal
of the respective
sealing device from the sealing device receptacle.
[0036] The retention time may include and/or be any suitable time,
timeframe, and/or time
period. As an example, the retention time may be a fixed, predetermined, pre-
established, and/or
desired length of time. As more specific examples, the retention time may be
at least 1 hour, at
least 6 hours, at least 12 hours, at least 1 day, at least 5 days, at least 10
days, at least 20 days,
and/or at least 30 days. Additionally or alternatively, the retention time may
be at most 180 days,
at most 150 days, at most 120 days, at most 90 days, at most 60 days, at most
30 days, at most 20
days, at most 10 days, at most 5 days, and/or at most 1 day.
[0037] With the above in mind, sealing device retainer 138 may include
and/or be formed
from any suitable material and/or materials. As examples, sealing device
retainer 138 may include
and/or be formed from a soluble material configured to dissolve within the
wellbore fluid and/or
a corrodible material configured to corrode within the wellbore fluid. Such a
material may
degrade, dissolve, and/or corrode to permit release of the sealing device
after the retention time
has elapsed. As additional examples, sealing device retainer 138 may include
and/or be formed
from an insoluble material, a non-corrodible material, and/or an inert
material that does not
degrade upon contact with the wellbore fluid. Such a material may permit the
sealing device
retainer to retain the respective sealing device indefinitely and/or to retain
a plurality of different
sealing devices, as discussed in more detail herein.
[0038] As illustrated in dashed lines in Figs. 2-5, SSPs 100 may include
one or more
channels 152. Channels 152, when present, may be adapted, configured, sized,
and/or shaped to
permit and/or facilitate fluid inflow 33 to flow past sealing device 142
and/or sealing device
retainer 138 when sealing device 142 is received within sealing device
receptacle 134. As
examples, channels 152 may decrease a resistance to the fluid inflow and/or
may increase a cross-
sectional area for flow of the fluid inflow.
[0039] Channels 152 may include any suitable structure. As examples,
channels 152 may
include and/or be one or more of grooves, recesses, and/or flutes. In
addition, channels 152 may
be defined by and/or within any suitable portion of SSP 100. As an example,
channels 152 may
be defined by sealing device retainer 138. As another example, channels 152
may be defined by
an SSP body 110. SSP body 110, when present, also may define one or more of
SSP conduit 116,
sealing device receptacle 134, sealing device seat 140, and/or sealing device
retainer 138.
- 10 -
CA 3007078 2019-04-09
100401 Sealing device receptacle 134 may have and/or define any suitable
shape. As an
example, the shape of the sealing device receptacle may correspond to a shape
of a corresponding
sealing device 142 that is to be received by, or is received within, the
sealing device receptacle.
As another example, the sealing device receptacle may be a cylindrical, or at
least partially
cylindrical, sealing device receptacle. As yet another example, sealing device
142 may define a
sealing device diameter 147 and sealing device receptacle 134 may define a
receptacle diameter
137 that is greater than the sealing device diameter. This is illustrated in
Fig. 2.
[0041] It is within the scope of the present disclosure that sealing
device receptacle 134 may
be shaped and/or sized to contain and/or house an entirety of sealing device
142, at least when the
sealing device forms fluid seal 144 with sealing device seat 140. Stated
another way, sealing
device 142 may be contained entirely within sealing device receptacle 134 when
it is seated on
and unseated from the sealing device seat. Under these conditions, sealing
device receptacle 134
may be referred to herein as having a receptacle depth 136 that is greater
than the sealing device
diameter. Such a configuration may permit operation of SSP 100 without sealing
device 142
projecting into subsurface region 32 and/or into tubular conduit 42 and also
is illustrated in Fig. 2.
[0042] Alternatively, it is also within the scope of the present
disclosure that a portion
(typically a minority portion) of sealing device 142 may project from sealing
device receptacle
134 and into tubular conduit 42 and/or into subsurface region 32, as
illustrated in Fig. 5 when the
sealing device is seated upon and/or unseated from the sealing device seat.
Such a configuration
may permit SSP 100 to be narrower and/or may permit a width 101 of SSP 100 to
correspond to
a wellbore tubular thickness 44 of wellbore tubular 40.
[0043] Sealing device seat 140 may include any suitable structure that
defines at least a
portion of SSP conduit 116, is defined within sealing device receptacle 134,
and/or is shaped to
form the fluid seal with sealing device 142. As an example, and as discussed,
sealing device seat
140 may be formed and/or defined by SSP body 110. As another example, a shape
of sealing
device seat 140 may correspond to, or complement, a shape of sealing device
142. As yet another
example, sealing device seat 140 may have a seat radius of curvature that is
at least substantially
similar to, and optionally the same as, a sealing device radius of curvature
of sealing device 142.
As another example, sealing device seat 140 may be a pre-formed and/or
premanufactured sealing
device seat that may have a preconfigured geometry, or shape, that is
established prior to SSP 100
- 11 -
CA 3007078 2019-04-09
being operatively attached to tubular conduit 42 and/or prior to tubular
conduit 42 being installed
within subterranean formation 34.
[0044] It is within the scope of the present disclosure that sealing
device seat 140 may be
configured to resist damage and/or deterioration upon exposure to
environmental conditions
present within hydrocarbon well 10. As an example, sealing device seat 140 may
include and/or
be an erosion-resistant sealing device seat that is configured to resist
erosion by particulate matter
that may be present within a wellbore fluid when the wellbore fluid flows
through and/or past the
sealing device seat. As another example, sealing device seat 140 may include
and/or be a
corrosion-resistant sealing device seat configured to resist corrosion by the
wellbore fluid when
the wellbore fluid contacts the sealing device seat.
[0045] As discussed, SSPs 100 may be operatively attached to wellbore
tubular 40, and
SSPs 100 may define any suitable spatial relationship, orientation, relative
size, and/or geometry
relative to wellbore tubular 40. As an example, wellbore tubular 40 may have
and/or define wall
thickness 44, and sealing device receptacle 134 may define a receptacle depth
136 that is greater
is than, equal to, or less than, wall thickness 44.
[0046] When receptacle depth 136 is greater than wall thickness 44, and
as illustrated in Fig.
3, wellbore tubular 40, SSP 100, and/or SSP body 110 thereof may include a
projecting region 69
that projects from an external surface 41 of wellbore tubular 40. Under these
conditions, SSP 100
may be positioned within, or may define, projecting region 69. An example of
projecting region
69 includes a centralizer wing for wellbore tubular 40.
[0047] It is within the scope of the present disclosure that SSPs 100 may
be operatively
attached to wellbore tubular 40 in any suitable manner and/or that SSPs 100
may be operatively
attached to any suitable portion of wellbore tubular 40. As examples, SSPs 100
may be at least
partially defined by the wellbore tubular, at least partially formed within
the wellbore tubular, at
least partially defined by a tubular collar of the wellbore tubular, at least
partially formed within
the tubular collar, at least partially defined by a tubular segment of the
wellbore tubular, and/or at
least partially formed within the tubular segment.
[0048] Sealing device 142 may include and/or be any suitable structure
and/or structures that
is/are sized and/or configured to be received within sealing device receptacle
134, to form fluid
.. seal 144 with sealing device seat 140, and to be retained by sealing device
retainer 138. As an
example, sealing device 142 may include any known ball sealer or perforation
sealer. A
- 12 -
CA 3007078 2019-04-09
conventional ball sealer has a generally spherical shape and may include an
abrasion-resistant
and/or cut-resistant outer layer. Another example of a suitable sealing device
is a PERF PODSTM
sealing device that is available from Thru Tubing Solutions, Inc. of Oklahoma
City, Oklahoma.
A PERF PODSTM sealing device includes a primary sealing core from which a
plurality of
secondary tendrils extends to form secondary seals, such as of one or more
leakage pathways
between the primary sealing core and the sealing device seat.
[0049] Similarly, sealing device 142 may be formed from any suitable
material and/or
materials. As examples, sealing device 142 may be formed from a soluble
material configured to
dissolve within the wellbore fluid and/or from a corrodible material
configured to be corroded by
to the wellbore fluid. Such a configuration may permit the sealing device
to be retained within the
sealing device receptacle for the retention time and then to degrade such that
the sealing device is
released from the sealing device receptacle. Under these conditions, it is
within the scope of the
present disclosure that a second, or subsequent, sealing device later may be
received within the
sealing device receptacle.
[0050] As additional examples, sealing device 142 may be formed from an
insoluble material
and/or from a non-corrodible material that does not degrade upon contact with
the wellbore fluid.
Such a material may permit the sealing device to be retained within the
sealing device receptacle
indefinitely.
[0051] As illustrated in dashed lines in Figs. 2-4 and discussed herein,
SSPs 100 optionally
may include an isolation device 120 and a retention device 130. Isolation
device 120, when
present, may extend within SSP conduit 116. In addition, isolation device 120
may be configured
to selectively transition, or be transitioned, from a closed state, in which
the isolation device
restricts fluid flow through the SSP conduit, to an open state, in which the
isolation device permits
fluid flow through the SSP conduit. This transition may be, may occur, and/or
may be initiated
responsive to receipt of a shockwave, which has greater than a threshold
shockwave intensity, by
the isolation device. The shockwave may be generated by a shockwave generation
device, such
as shockwave generation device 190 of Fig. 1, within a wellbore fluid, such as
wellbore fluid 22
of Fig. 1, that extends within tubular conduit 42. Retention device 130 may be
configured to retain
isolation device 120 in the closed state prior to receipt of the shockwave.
[0052] It is within the scope of the present disclosure that isolation
device 120 may be
configured to exhibit only a single transition from the closed state to the
open state. As an
- 13 -
CA 3007078 2019-04-09
example, at least a portion of the isolation device may be configured to
separate from a remainder
of the SSP upon transitioning from the closed state to the open state.
[0053] As a more specific example, at least a portion of the isolation
device may be
configured to break apart, or disintegrate, upon transitioning from the closed
state to the open
state. As an example, and prior to transitioning from the closed state to the
open state, isolation
device 120 may have and/or define a first maximum dimension. However,
subsequent to
transitioning from the closed state to the open state, the isolation device
may define a second
maximum dimension that is less than the first maximum dimension. As another
example, and
prior to transitioning from the closed state to the open state, isolation
device 120 may include
and/or be a single-piece isolation device. However, and upon transitioning to
the open state, the
isolation device may define a plurality of spaced-apart segments and/or
pieces.
[0054] As yet another example, isolation device 120 may include an
isolation disk that may
be conveyed into the subterranean formation from a formation-facing end of SSP
conduit 116
when the isolation device transitions from the closed state to the open state.
[0055] Isolation device 120 may include and/or be formed from any suitable
material and/or
materials. As examples, isolation device 120 may include one or more of a
magnetic material, a
radioactive material, an acid-soluble material, and a frangible material.
[0056] As also illustrated in dashed lines in Figs. 2-4, SSP 100 further
may include an
isolation device recess 119. Isolation device recess 119 may be configured to
receive, house,
.. and/or contain at least a portion of isolation device 120 prior to the
isolation device transitioning
from the closed state to the open state.
[0057] It is within the scope of the present disclosure that isolation
device 120 may be
positioned within any suitable portion, or region, of SSP 100. As an example,
isolation device
120 may be positioned between sealing device seat 140 and subsurface region
32. Such a
configuration may prevent particulate matter, which may be present within the
subsurface region,
from contacting sealing device seat 140 and/or entering sealing device
receptacle 134 at least prior
to the isolation device being transitioned from the closed state to the open
state. As another
example, isolation device 120 may be positioned to separate, or to fluidly
separate, sealing device
seat 140 from tubular conduit 42. Such a configuration may protect the sealing
device seat from
materials that may be conveyed through the tubular conduit. As an example,
such a configuration
- 14 -
CA 3007078 2019-04-09
may protect the sealing device seat from abrasion by a proppant and/or from
corrosion by an acid
that may be conveyed into subsurface region 32 via the tubular conduit.
[0058] Fig. 6 is a flowchart depicting methods 1100, according to the
present disclosure, of
stimulating a hydrocarbon well. The hydrocarbon well includes a wellbore
tubular that defines a
tubular conduit and extends within a wellbore. The hydrocarbon well further
includes a plurality
of selective stimulation ports (SSPs) spaced-apart along a length of the
wellbore tubular.
Examples of the hydrocarbon well are illustrated in Fig. 1 and discussed in
more detail herein with
reference thereto.
[0059] Methods 1100 include pressurizing a tubular conduit at 1105,
opening a selected SSP
at 1110, flowing a first volume a stimulant fluid at 1115, and releasing a
sealing device at 1120.
Methods 1100 further include receiving the sealing device at 1125, retaining
the sealing device
at 1130, and seating the sealing device at 1135. Methods 1100 also may include
waiting a
threshold dissolution time at 1140, producing a reservoir fluid at 1145,
and/or permitting a
pressure change at 1150 and include repeating at least a portion of the
methods at 1155.
[0060] Pressurizing the tubular conduit at 1105 may include pressurizing
the tubular conduit
with a stimulant fluid. The pressurizing at 1105 may be accomplished in any
suitable manner. As
examples, the pressurizing at 1105 may include providing the stimulant fluid
to, or pumping the
stimulant fluid into, the tubular conduit, such as from a surface region.
[0061] Opening the selected SSP at 1110 may include opening a selected
SSP of the plurality
of SSPs to permit fluid flow, or a fluid outflow, from the tubular conduit and
into the subterranean
formation. The fluid flow may be through and/or via an SSP conduit of the
selected SSP. The
opening at 1110 may be accomplished in any suitable manner. As an example, the
opening at 1110
may include transitioning an isolation device of the selected SSP from a
closed state to an open
state. As a more specific example, the opening at 1110 may include generating,
within the tubular
.. conduit, a shockwave of greater than a threshold shockwave intensity to
transition the isolation
device from the closed state to the open state. Examples of the isolation
device are discussed
herein with reference to isolation device 120 of Figs. 2-4.
[0062] Flowing the first volume of the stimulant fluid at 1115 may
include flowing the first
volume of stimulant fluid into the subterranean formation via the SSP conduit.
This may include
.. flowing to stimulate a first region of the subterranean formation and/or
flowing responsive to, or
as a result of, the pressurizing at 1105 and/or the opening at 1110.
- 15 -
CA 3007078 2019-04-09
[0063] Releasing the sealing device at 1120 may include releasing the
sealing device in,
within, and/or into the tubular conduit. The releasing at 1120 may be
accomplished in any suitable
manner. As an example, the releasing at 1120 may include positioning the
sealing device within
the tubular conduit. As additional examples, the releasing at 1120 may include
releasing from the
surface region and/or releasing from a sealing device source that is
positioned within and/or forms
a portion of the hydrocarbon well. Examples of the sealing device are
disclosed herein with
reference to sealing device 142 of Figs. 1-5.
[0064] Receiving the sealing device at 1125 may include receiving the
sealing device within
a sealing device receptacle of the selected SSP. The receiving at 1125 may
include flowing the
it) sealing device along the tubular conduit and to the selected SSP,
receiving the sealing device from
the tubular conduit, and/or flowing the sealing device from the tubular
conduit and into the
selected SSP. Examples of the sealing device receptacle are disclosed herein
with reference to
sealing device receptacle 134 of Figs. 2-5.
[0065] Retaining the sealing device at 1130 may include retaining the
sealing device within
the sealing device receptacle with a sealing device retainer of the selected
SSP. It is within the
scope of the present disclosure that the retaining at 1130 may include
retaining the sealing device,
within the sealing device receptacle, during a remainder of methods 1100
and/or during at least a
portion of the repeating at 1155. As examples, the retaining at 1130 may
include retaining during
the seating at 1135, during the waiting at 1140, during the producing at 1145,
during the permitting
at 1150, and/or during the repeating at 1155. Examples of the sealing device
retainer are disclosed
herein with reference to sealing device retainer 138 of Figs. 2-5.
[0066] Seating the sealing device at 1135 may include seating the sealing
device on a sealing
device seat of the selected SSP. This may include seating to form a fluid seal
between the sealing
device and the sealing device seat and/or seating to resist the fluid outflow
of the stimulant fluid,
which may flow from the tubular conduit and into the subterranean formation
via the SSP conduit
of the selected SSP. Examples of the sealing device seat are disclosed herein
with reference to
sealing device seat 140 of Figs. 2-5.
[0067] Waiting the threshold dissolution time at 1140 may include waiting
any suitable
threshold dissolution time to permit the sealing device to dissolve and/or to
corrode, such as to
permit release of the sealing device from the sealing device receptacle of the
respective SSP. It is
within the scope of the present disclosure that the waiting at 1140 may be
performed subsequent
- 16 -
CA 3007078 2019-04-09
to at least a portion of the repeating at 1155. As an example, the waiting at
1140 may be performed
subsequent to repeating the pressurizing at 1105, the opening at 1110, the
flowing at 1115, the
releasing at 1120, the receiving at 1125, the retaining at 1130, and the
seating at 1135 a plurality
of times, via the plurality of SSPs, to stimulate a plurality of spaced-apart,
or different, regions of
the subterranean formation and to seal the plurality of SSPs with a
corresponding plurality of
sealing devices. This may include pressure cycling the hydrocarbon well and/or
repeatedly and
sequentially seating the sealing device on the sealing device seat and
subsequently unseating the
sealing device from the sealing device seat. The waiting at 1140 may include
waiting to permit
and/or facilitate dissolution and/or corrosion of the corresponding plurality
of sealing devices, to
to release the corresponding plurality of sealing devices from the
plurality of SSPs, and/or to permit
both fluid inflow and fluid outflow through the plurality of SSPs.
[0068] Producing the reservoir fluid at 1145 may include producing the
reservoir fluid from
the subterranean formation. This may include permitting the fluid inflow of
the reservoir fluid
into the tubular conduit via the SSP conduit of the respective SSP.
Additionally or alternatively,
the producing at 1145 also may include producing the reservoir fluid while
retaining the sealing
device within the sealing device receptacle with the sealing device retainer
of the respective SSP.
It is within the scope of the present disclosure that the producing at 1145
may be performed
subsequent to at least a portion of the repeating at 1155, such as is
discussed herein with reference
to the waiting at 1140. Stated another way, the producing at 1145 may be
performed subsequent
to stimulating the plurality of regions of the subterranean formation and/or
subsequent to retaining
a respective sealing device within a respective sealing device seat of each of
the plurality of SSPs
with a corresponding sealing device retainer of each of the plurality of SSPs.
Under these
conditions, the producing at 1145 may include permitting the fluid inflow via
a plurality of SSP
conduits of the plurality of SSPs while retaining the respective sealing
device within the respective
sealing device receptacle of each of the plurality of SSPs. The retaining may
permit and/or
facilitate re-seating of the respective sealing device with the respective
sealing device seat
subsequent to the producing at 1145, during the permitting at 1150, and/or
during the repeating at
1155.
[0069] Additionally or alternatively, the producing at 1145 also may be
performed subsequent
to the waiting at 1140. Under these conditions, the plurality of respective
sealing devices may be
- 17 -
CA 3007078 2019-04-09
released from, or not retained within the respective sealing device receptacle
of, the plurality of
SSPs during the producing at 1145.
10070] Permitting the pressure change at 1150 may include permitting, or
even facilitating,
any suitable pressure change within the wellbore tubular and/or within the
subterranean formation
and may be performed subsequent to at least the portion of the repeating at
1155 that is discussed
herein with reference to the waiting at 1140. The permitting at 1150 also may
include unintended,
inadvertent, and/or unexpected pressure changes, such as may be caused by
failure of a pump that
is utilized to pressurize the tubular conduit and/or failure of a sealing
device that restricts fluid
flow from the tubular conduit and into the subterranean formation. As an
example, the permitting
at 1150 may include permitting a pressure within the subterranean formation to
exceed a pressure
within the tubular conduit, such as to provide, or allow, a motive force for
flow of a reservoir fluid
into the tubular conduit via the SSP conduits of the plurality of SSPs. Under
these conditions, the
retaining at 1130 may include retaining during the permitting at 1150.
[0071] As another example, the permitting at 1150 may include permitting
a pressure within
a region of the tubular conduit that is associated with the selected SSP to
decrease to a conduit
pressure that is less than a formation pressure within a region of the
subterranean formation that
is associated with the selected SSP. Under these conditions, fluid may flow
from the subterranean
formation into the tubular conduit via the SSP conduit of the selected SSP,
and the retaining at
1130 may include retaining during the permitting at 1150. When methods 1100
include the
permitting at 1150, the repeating at 1155 may include re-seating the sealing
devices on their
respective sealing device seats to restrict fluid flow from the tubular
conduit into the subterranean
formation when the pressure within the tubular conduit is increased to a
pressure that is greater
than the pressure within the subterranean formation.
100721 Repeating at least a portion of the methods at 1155 may include
repeating any suitable
portion of methods 1100 in any suitable order and/or in any suitable manner.
As an example, and
as discussed, the repeating at 1155 may include repeating the pressurizing at
1105, repeating the
opening at 1110, repeating the flowing at 1115, repeating the releasing at
1120, repeating the
receiving at 1125, repeating the retaining at 1130, and/or repeating the
seating at 1135 a plurality
of times to stimulate the plurality of regions of the subterranean formation.
This portion of the
repeating at 1155 also may be referred to herein as repeating to stimulate the
subterranean
formation and/or as stimulating the subterranean formation.
- 18 -
CA 3007078 2019-04-09
[0073] Subsequent to repeating to stimulate the subterranean formation,
and as also discussed,
the repeating at 1155 may include performing one or more additional, or
optional, steps of methods
1100, such as by performing the waiting at 1140, the producing at 1145, and/or
the permitting at
1150. Additionally or alternatively, and subsequent to performing the
producing at 1145, the
repeating at 1155 also may include repeating the pressurizing at 1105 to seat
the plurality of
sealing devices on the corresponding plurality of sealing device seats of the
plurality of SSPs.
Additionally or alternatively, the repeating at 1155 may include sequentially
repeating the
pressurizing at 1105 and the producing at 1145 a plurality of times while
continuing the retaining
at 1130. This process also may be referred to herein as pressure cycling the
hydrocarbon well.
io [0074] Returning to Fig. 1, and as illustrated in dashed lines,
hydrocarbon well 10 may
include a fluid port 74, which may be positioned at, proximate, and/or near
downhole end 24.
Fluid port 74, when present, may be configured to be selectively transitioned
between an open
state and a closed state. When in the open state, fluid port 74 may permit
fluid flow between
tubular conduit 42 and subterranean formation 34; and when in the closed
state, fluid port 74 may
resist, block, and/or occlude fluid flow between the tubular conduit and the
subterranean
formation.
[0075] In general, fluid port 74 is different and/or distinct from SSPs
100. As an example,
fluid port 74 may include and/or be a toe sleeve. As another example, fluid
port 74 may exclude,
or may not include, a sealing device receptacle and/or a sealing device
retainer. In contrast, and
as discussed in more detail herein with reference to Figs. 2-5, SSPs 100
include both a sealing
device receptacle 134 and a sealing device retainer 138. However, this is not
required to all
embodiments, and it is also within the scope of the present disclosure that
fluid port 74 may
include, or be, an SSP 100.
[0076] As discussed in more detail herein with respect to methods 1200 of
Fig. 7, and during
operation of hydrocarbon well 10, fluid port 74 may be utilized to facilitate
conveyance of a
downhole tool, such as shockwave generation device 190, within hydrocarbon
well 10. As an
example, and while fluid flow through SSPs 100 is blocked and/or occluded,
such as by sealing
device 142, fluid port 74 may be transitioned to the open state. Subsequently,
a conveyance fluid
may be provided to tubular conduit 42, such as from surface region 30, and the
conveyance fluid
may be utilized to pump the downhole tool in downhole direction 29. Under
these conditions,
flow of the conveyance fluid through fluid port 74 may permit and/or
facilitate flow of the
- 19 -
CA 3007078 2019-04-09
conveyance fluid into the tubular conduit and/or pumping of the downhole tool
in the downhole
direction.
[00771 With the above discussion in mind, Fig. 7 is a flowchart depicting
methods 1200,
according to the present disclosure, of conveying a downhole tool within a
hydrocarbon well. The
hydrocarbon well includes a wellbore tubular that defines a tubular conduit
and extends within a
wellbore. The hydrocarbon well also includes a plurality of SSPs spaced-apart
along a length of
the wellbore tubular. Examples of the hydrocarbon well are illustrated in Fig.
1 and discussed in
more detail herein with reference thereto. Methods 1200 include restricting a
fluid flow at 1210,
retaining a sealing device at 1220, and establishing fluid communication at
1230. Methods 1200
further include positioning a downhole tool at 1240, providing a conveyance
fluid at 1250, and
pumping the downhole tool at 1260.
[0078] Restricting the fluid flow at 1210 may include restricting fluid
flow through each SSP
in the plurality of SSPs with a respective sealing device of a plurality of
sealing devices. The
restricting at 1210 may include receiving the respective sealing device within
a respective sealing
device receptacle and/or on a respective sealing device seat of each SSP.
Examples of the sealing
device receptacle are disclosed herein with reference to sealing device
receptacles 134 of Figs. 2-
5. Examples of the sealing device seat are disclosed herein with reference to
sealing device seat
140 of Figs. 2-5.
[0079] Retaining the sealing device at 1220 may include retaining each
respective sealing
device within the respective sealing device receptacle with a respective
sealing device retainer of
each SSP. Examples of the sealing device retainer are disclosed herein with
reference to sealing
device retainers 138 of Figs. 2-5.
[0080] Establishing fluid communication at 1230 may include establishing
fluid
communication between the subterranean formation and a downhole region, a
downhole portion,
and/or a toe-end of the tubular conduit. The establishing at 1230 may be
accomplished in any
suitable manner. As an example, the establishing at 1230 may include removing
a selected sealing
device from a downhole SSP of the plurality of SSPs that is present within the
downhole region
of the tubular conduit. This may include removing without removing the
respective sealing device
from a remainder of the plurality of SSPs. As an example, the selected sealing
device may be
soluble within the wellbore fluid, while a remainder of the sealing devices
may not be soluble, or
may not be as soluble, within the wellbore fluid. Under these conditions, the
removing may
- 20 -
CA 3007078 2019-04-09
include dissolving the selected sealing device within the wellbore fluid. As
another example, a
selected sealing device retainer of the downhole SSP may be soluble within the
wellbore fluid,
while a remainder of the sealing device retainers may not be soluble, or may
not be as soluble,
within the wellbore fluid. Under these conditions, the removing may include
dissolving the
selected sealing device retainer within the wellbore fluid.
[0081] As another example, the establishing at 1230 may include opening a
fluid port that is
present within the downhole region of the tubular conduit. This may include
opening the fluid
port without removing the respective sealing devices from the plurality of
SSPs and may be
accomplished in any suitable manner. As an example, the opening may include
dissolving a
selected sealing device, which seals the fluid port, within the wellbore
fluid. As another example,
the opening may include utilizing a pressure differential to unseat the
selected sealing device from
the fluid port. As yet another example, the opening may include transitioning
the fluid port from
a closed state to an open state. Examples of the fluid port are disclosed
herein with reference to
fluid port 74 of Fig. 1.
[0082] Positioning the downhole tool at 1240 may include positioning any
suitable downhole
tool within an uphole region, or portion, of the tubular conduit. An example
of the downhole tool
includes a shockwave generation device, such as shockwave generation device
190 of Fig. 1.
Additional examples of the downhole tool are disclosed herein.
[0083] Providing the conveyance fluid at 1250 may include providing any
suitable
conveyance fluid to the tubular conduit. This may include pumping the
conveyance fluid into the
tubular conduit, such as from a surface region, and may be at least
substantially similar to the
pressurizing at 1105, which is discussed herein with reference to methods 1100
of Fig. 6.
10084] Pumping the downhole tool at 1260 may include pumping the downhole
tool in a
downhole direction via flow of the conveyance fluid within the tubular
conduit. Stated another
way, the pumping at 1260 may include providing a motive force for motion of
the downhole tool,
within the tubular conduit, via the providing at 1250 and/or via flow of the
conveyance fluid
through the tubular conduit and into the subterranean formation. Flow of the
conveyance fluid
into the subterranean formation may be facilitated by the establishing at
1230.
[0085] In the present disclosure, several of the illustrative, non-
exclusive examples have been
discussed and/or presented in the context of flow diagrams, or flow charts, in
which the methods
are shown and described as a series of blocks, or steps. Unless specifically
set forth in the
- 21 -
CA 3007078 2019-04-09
accompanying description, it is within the scope of the present disclosure
that the order of the
blocks may vary from the illustrated order in the flow diagram, including with
two or more of the
blocks (or steps) occurring in a different order and/or concurrently.
[0086] As used herein, the term "and/or" placed between a first entity
and a second entity
means one of (1) the first entity, (2) the second entity, and (3) the first
entity and the second entity.
Multiple entities listed with "and/or" should be construed in the same manner,
i.e., "one or more"
of the entities so conjoined. Other entities may optionally be present other
than the entities
specifically identified by the "and/or" clause, whether related or unrelated
to those entities
specifically identified. Thus, as a non-limiting example, a reference to "A
and/or B," when used
h) in conjunction with open-ended language such as "comprising" may refer,
in one embodiment, to
A only (optionally including entities other than B); in another embodiment, to
B only (optionally
including entities other than A); in yet another embodiment, to both A and B
(optionally including
other entities). These entities may refer to elements, actions, structures,
steps, operations, values,
and the like.
[0087] As used herein, the phrase "at least one," in reference to a list of
one or more entities
should be understood to mean at least one entity selected from any one or more
of the entity in the
list of entities, but not necessarily including at least one of each and every
entity specifically listed
within the list of entities and not excluding any combinations of entities in
the list of entities. This
definition also allows that entities may optionally be present other than the
entities specifically
.. identified within the list of entities to which the phrase "at least one"
refers, whether related or
unrelated to those entities specifically identified. Thus, as a non-limiting
example, "at least one
of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at
least one of A and/or
B") may refer, in one embodiment, to at least one, optionally including more
than one, A, with no
B present (and optionally including entities other than B); in another
embodiment, to at least one,
optionally including more than one, B, with no A present (and optionally
including entities other
than A); in yet another embodiment, to at least one, optionally including more
than one, A, and at
least one, optionally including more than one, B (and optionally including
other entities). In other
words, the phrases "at least one," "one or more," and "and/or" are open-ended
expressions that
are both conjunctive and disjunctive in operation. For example, each of the
expressions "at least
.. one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and
C," "one or more of
A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C alone, A and B
together, A and
- 22 -
CA 3007078 2019-04-09
C together, B and C together, A, B and C together, and optionally any of the
above in combination
with at least one other entity.
[0088] In the event that any patents, patent applications, or other
references discussed herein
and (I) define a term in a manner that is inconsistent with and/or (2) are
otherwise inconsistent
with, either the present disclosure or any of the other references, the
present disclosure shall
control, and the term shall only control with respect to the reference in
which the term is defined.
[0089] As used herein the terms "adapted" and "configured" mean that the
element,
component, or other subject matter is designed and/or intended to perform a
given function. Thus,
the use of the terms "adapted" and "configured" should not be construed to
mean that a given
.. element, component, or other subject matter is simply "capable of'
performing a given function
but that the element, component, and/or other subject matter is specifically
selected, created,
implemented, utilized, programmed, and/or designed for the purpose of
performing the function.
It is also within the scope of the present disclosure that elements,
components, and/or other recited
subject matter that is recited as being adapted to perform a particular
function may additionally or
alternatively be described as being configured to perform that function, and
vice versa.
[0090] As used herein, the phrase, "for example," the phrase, "as an
example," and/or simply
the term "example," when used with reference to one or more components,
features, details,
structures, embodiments, and/or methods according to the present disclosure,
are intended to
convey that the described component, feature, detail, structure, embodiment,
and/or method is an
illustrative, non-exclusive example of components, features, details,
structures, embodiments,
and/or methods according to the present disclosure. Thus, the described
component, feature,
detail, structure, embodiment, and/or method is not intended to be limiting,
required, or
exclusive/exhaustive; and other components, features, details, structures,
embodiments, and/or
methods, including structurally and/or functionally similar and/or equivalent
components,
.. features, details, structures, embodiments, and/or methods, are also within
the scope of the present
disclosure.
Industrial Applicability
[0091] The selective stimulation ports, wellbore tubulars, hydrocarbon
wells, and methods
disclosed herein are applicable to the oil and gas industries.
[0092] It is believed that the disclosure set forth above encompasses
multiple distinct
inventions with independent utility. While each of these inventions has been
disclosed in its
- 23 -
CA 3007078 2019-04-09
preferred form, the specific embodiments thereof as disclosed and illustrated
herein are not to be
considered in a limiting sense as numerous variations are possible. The
subject matter of the
inventions includes all novel and non-obvious combinations and subcombinations
of the various
elements, features, functions and/or properties disclosed herein. Similarly,
where the claims recite
"a" or "a first" element or the equivalent thereof, such claims should be
understood to include
incorporation of one or more such elements, neither requiring nor excluding
two or more such
elements.
[0093] It is believed that the following claims particularly point out
certain combinations and
subcombinations that are directed to one of the disclosed inventions and are
novel and non-
obvious. Inventions embodied in other combinations and subcombinations of
features, functions,
elements and/or properties may be claimed through amendment of the present
claims or
presentation of new claims in this or a related application. Such amended or
new claims, whether
they are directed to a different invention or directed to the same invention,
whether different,
broader, narrower, or equal in scope to the original claims, are also regarded
as included within
the subject matter of the inventions of the present disclosure.
- 24 -
CA 3007078 2019-04-09
