U.S. patent application number 15/367036 was filed with the patent office on 2017-06-08 for downhole devices for providing sealing components within a wellbore, wells that include such downhole devices, and methods of utilizing the same.
The applicant listed for this patent is P. Matthew Spiecker, Randy C. Tolman. Invention is credited to P. Matthew Spiecker, Randy C. Tolman.
Application Number | 20170159397 15/367036 |
Document ID | / |
Family ID | 58798197 |
Filed Date | 2017-06-08 |
United States Patent
Application |
20170159397 |
Kind Code |
A1 |
Tolman; Randy C. ; et
al. |
June 8, 2017 |
DOWNHOLE DEVICES FOR PROVIDING SEALING COMPONENTS WITHIN A
WELLBORE, WELLS THAT INCLUDE SUCH DOWNHOLE DEVICES, AND METHODS OF
UTILIZING THE SAME
Abstract
Downhole devices, wells that include the downhole devices, and
methods of utilizing the same are disclosed herein. The downhole
devices include a core; a sealing component holder positioned
within the core including an opening to an external surface of the
core; a plurality of sealing components positioned within the
sealing component holder; a metering device; and a cover positioned
over the opening. The metering device is constructed and arranged
to displace an internal volume of the sealing component holder and
discharge through the opening a portion of the plurality of sealing
components contained within the sealing component holder. The cover
is constructed and arranged to allow the portion of the sealing
components to exit the opening upon displacement of the internal
volume of the sealing component holder.
Inventors: |
Tolman; Randy C.; (Spring,
TX) ; Spiecker; P. Matthew; (Manvel, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Tolman; Randy C.
Spiecker; P. Matthew |
Spring
Manvel |
TX
TX |
US
US |
|
|
Family ID: |
58798197 |
Appl. No.: |
15/367036 |
Filed: |
December 1, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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15264076 |
Sep 13, 2016 |
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15367036 |
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62423801 |
Nov 18, 2016 |
|
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62263069 |
Dec 4, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/1208
20130101 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 41/00 20060101 E21B041/00; E21B 43/116 20060101
E21B043/116 |
Claims
1. A downhole device for providing sealing components within a well
comprising: a core; a sealing component holder positioned within
the core including an opening to an external surface of the core; a
plurality of sealing components positioned within the sealing
component holder; a metering device constructed and arranged to
displace an internal volume of the sealing component holder and
discharge through the opening a portion of the plurality of sealing
components contained within the sealing component holder; and a
cover positioned over the opening, the cover constructed and
arranged to allow the portion of the sealing components to exit the
opening upon displacement of the internal volume of the sealing
component holder.
2. The device of claim 1, wherein the sealing component holder is
positioned at least proximal the distal end of the core.
3. The device of claim 1, wherein the plurality of sealing
components are ball sealers or chemical diverters.
4. The device of claim 1, wherein the plurality of sealing
components are ball sealers.
5. The device of claim 4, wherein the sealing component holder
includes a plurality of spaced-apart regions, each region including
a plurality of ball sealers, the plurality of ball sealers within
one region having a substantially different rate of degradation
than the plurality of ball sealers in each adjacent region.
6. The device of claim 4, wherein the well includes a wellbore
tubular forming a tubular conduit having in inner diameter in the
range of from 90 mm to 178 mm, and wherein the sealing component
holder and metering device are placed proximal the distal end of
the core and a portion of the plurality of the ball sealers have a
maximum outer dimension greater than 32 mm.
7. The device of claim 6, wherein a portion of the plurality of the
ball sealers have a maximum outer dimension of less than 15 mm.
8. The device of claim 4, wherein a portion of the plurality of the
ball sealers have a maximum outer dimension of less than 15 mm.
9. The device of claim 1, wherein the plurality of sealing
components are chemical diverters which are selected from benzoic
acid flakes, polyglycolic acid polymer beads, and polylactic acid
polymer beads.
10. The device of claim 1, wherein the metering device includes a
pump or a motor operatively connected to a member positioned within
the sealing component holder such that, upon actuation of the pump
or motor, the member displaces an internal volume of the sealing
component holder.
11. The device of claim 1, wherein the metering device includes a
pump operatively connected to the sealing component holder such
that, upon actuation of the pump, a displacement fluid is
introduced into an inlet of the sealing component holder displacing
an internal volume of the sealing component holder.
12. The device of claim 11, wherein the metering device includes a
pump and the pump is a solid state, piezoelectric pump.
13. A method for providing sealing components within a well
including a wellbore and a wellbore tubular extending within the
wellbore, the wellbore tubular defining a tubular conduit, the
method comprising: positioning a downhole device proximal to or
within a first region within the tubular conduit radially interior
of a first section of the wellbore tubular, the downhole device
comprising: a core, a sealing component holder positioned within
the core including an opening to an external surface of the core, a
plurality of sealing components positioned within the sealing
component holder, a metering device constructed and arranged to
displace an internal volume of the sealing component holder and
discharge sealing components through the opening, and a cover
positioned over the opening, the cover constructed and arranged to
allow the sealing components to exit the opening upon displacement
of the internal volume of the sealing component holder; actuating
the metering device to displace a first internal volume of the
sealing component holder to discharge a first portion of the
plurality of sealing components through the opening into the
tubular conduit; positioning the downhole device proximal to or
within a second region within the tubular conduit radially interior
of a second section of the wellbore tubular, the second region
spaced apart from the first region along the length of the wellbore
tubular; and actuating the metering device to displace a second
internal volume of the sealing component holder to discharge a
second portion of the plurality of sealing components through the
opening into the tubular conduit.
14. The method of claim 13, wherein the downhole device includes a
plurality of explosive charges arranged on an external surface of
the core and a plurality of triggering devices, each of the
plurality of triggering devices is constructed and arranged to
selectively initiate explosion of a selected portion of the
plurality of explosive charges; and wherein the wellbore tubular
includes a plurality of selective stimulation ports disposed along
a length of the wellbore tubular; and wherein the method further
comprises: actuating a first triggering device of the plurality of
triggering devices to initiate explosion of a first portion of the
plurality of explosive charges to generate a first shockwave within
the first region of the tubular conduit to transition a first
portion of the selective stimulation ports to an open state; and
actuating a second triggering device of the plurality of triggering
devices to initiate explosion of a second portion of the plurality
of explosive charges to generate a second shockwave within the
second region of the tubular conduit to transition a second portion
of the selective stimulation ports to an open state, wherein the
first portion of the plurality of sealing components seal the first
portion of the selective stimulation ports and the second portion
of the plurality of sealing components seal the second portion of
the selective stimulation ports.
15. The method of claim 13, wherein the sealing component holder
forms a majority of an internal volume of the core, the wellbore
tubular has been previously perforated at spaced-apart intervals
along its length, and at least a portion of the plurality of the
sealing components are used to seal the previously perforated
spaced-apart intervals within a re-fracturing area of interest
along the length of the wellbore tubular.
16. The method of claim 15, wherein the plurality of sealing
components includes at least a first plurality of degradable
sealing components within a first region of the sealing component
holder occupying the first internal volume and a second plurality
of degradable sealing components within a second region of the
sealing component holder occupying the second internal volume, the
first plurality of degradable sealing components having a different
rate of degradation than the second plurality of degradable sealing
components, and wherein the first section of the wellbore tubular
is one of the previously perforated spaced-apart intervals along
the length of the wellbore tubular and the second section of the
wellbore tubular is another of the previous spaced-apart intervals
along the length of the wellbore tubular.
17. The method of claim 16, further comprising: positioning a
perforation gun within a region of the tubular conduit radially
interior of an unperforated section of the wellbore tubular within
the re-fracturing area of interest after the previously perforated
spaced-apart intervals have been sealed with degradable sealing
components, positioning the downhole device such that detonation of
the perforation gun does not significantly damage the downhole
device; detonating the perforation gun to form new perforations
within the unperforated section of the wellbore tubular,
positioning the downhole device proximal to or within the region of
the tubular conduit radially interior of newly perforated section
of the wellbore tubular, displacing an additional internal volume
of the sealing component holder to discharge an additional portion
of the plurality of sealing components through the opening, wherein
the additional internal volume includes a plurality of
non-degradable sealing components within an additional region of
the sealing component holder.
18. The method of claim 17, wherein the positioning, detonating,
and displacing are continued until the re-fracturing of the
wellbore tubular within the area of interest is completed.
19. The method of claim 13, wherein the well is an injection well
and includes at least three sections of the wellbore tubular that
are passing injection fluid into the subterranean formation to
create pressure and displace hydrocarbons within the reservoir to
assist a hydrocarbon well producing hydrocarbons, the at least
three sections include the first section, the second section, and a
third section of the wellbore tubular, each of the at least three
sections spaced apart from each other along the length of the
wellbore tubular, and wherein the subterranean formation proximate
the first section and the second section is sealed such that the
injection fluid is diverted to the subterranean formation proximate
the third section of the wellbore tubular.
20. The method of claim 19, the method further comprises:
identifying locations of the first section and the second section
using production logs to determine the sections of the injection
well that are ineffective in creating pressure within the
reservoir.
21. A well comprising: a wellbore; a wellbore tubular extending
within the wellbore, the wellbore tubular defining a tubular
conduit; and a downhole device disposed within the tubular conduit,
the downhole device comprising: a core; a sealing component holder
positioned within the core including an opening to an external
surface of the core; a plurality of sealing components positioned
within the sealing component holder; a metering device constructed
and arranged to displace an internal volume of the sealing
component holder and discharge through the opening a portion of the
plurality of sealing components contained within the sealing
component holder; and a cover positioned over the opening, the
cover constructed and arranged to allow the portion of the sealing
components to exit the opening upon displacement of the internal
volume of the sealing component holder.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application Ser. No. 62/423,801, filed Nov. 18, 2016 entitled
"Downhole Devices for Providing Sealing Components Within A
Wellbore, Wells That Include Such Downhole Devices, and Methods of
Utilizing the Same," U.S. Provisional Application Ser. No.
62/263,069, filed Dec. 4, 2015 entitled "Select-Fire, Downhole
Shockwave Generation Devices, Hydrocarbon Wells That Include The
Shockwave Generation Devices, and Methods of Utiizing the Same;"
and U.S. application Ser. No. 15/264,076 filed Sep. 13, 2016
entitled, "Select-Fire, Downhole Shockwave Generation Devices,
Hydrocarbon Wells That Include The Shockwave Generation Devices,
and Methods of Utiizing the Same," the entireties of which are
incorporated by reference herein.
[0002] This application is related to U.S. Provisional Application
Ser. No. 62/262,034 filed Dec. 2, 2015, entitled, "Selective
Stimulation Ports, Wellbore Tubulars That Include Selective
Stimulation Ports, and Methods of Operating the Same," (Attorney
Docket No. 2015EM360); U.S. Provisional Application Ser. No.
62/262,036 filed Dec. 2, 2015, entitled, "Wellbore Tubulars
Including A Plurality of Selective Ports and Methods of Utilizing
the Same," (Attorney Docket No. 2015EM361); U.S. Provisional
Application Ser. No. 62/263,065 filed Dec. 4, 2015, entitled,
"Wellbore Ball Sealer and Methods of Utilizing the Same," (Attorney
Docket No. 2015EM369); U.S. Provisional Application Ser. No.
62/411,890 filed Oct. 24, 2016, entitled, "Sealing Devices,
Wellbore Tubulars Including The Sealing Devices, And Hydrocarbon
Wells Including The Wellbore Tubulars," (Attorney Docket No.
2015EM369); U.S. Provisional Application Ser. No. 62/263,067 filed
Dec. 4, 2015, entitled, "Ball-Sealer Check-Valves for Wellbore
Tubulars and Methods of Utilizing the Same," (Attorney Docket No.
2015EM370); and U.S. Provisional Application Ser. No. 62/411,004
filed Oct. 21, 2016, entitled, "Selective Stimulation Ports
Including Sealing Device Retainers and Methods of Utilizing the
Same," (Attorney Docket No. 2015EM370), the disclosures of which
are incorporated herein by reference in their entireties.
FIELD OF THE DISCLOSURE
[0003] The present disclosure is directed to downhole devices for
providing sealing components proximal a section of the well to be
sealed, to wells that include such downhole devices, and to methods
of utilizing such downhole devices and/or wells.
BACKGROUND OF THE DISCLOSURE
[0004] Hydrocarbon wells generally include a wellbore that extends
from a surface region through a subterranean formation to a
reservoir within the subterranean formation containing reservoir
fluid, such as liquid and/or gaseous hydrocarbons. Often, it may be
desirable to stimulate the subterranean formation 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 as the stimulant fluid to
the subterranean formation to acid-treat the subterranean formation
to dissolve at least a portion of the subterranean formation and/or
remove cement materials placed between the casing tubular conduit
and the subterranean formation. As another example, the stimulation
may include fracturing the subterranean formation, such as by
supplying a fracturing fluid as the stimulant fluid, which is
pumped at a high pressure, into 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 fluid flow
within the fractures after supply of the fracturing fluid has
ceased.
[0005] A variety of systems and methods have been developed to
facilitate stimulation of subterranean formations. Such systems and
methods utilize a shape-charge perforation gun to create
perforations within a section of the tubular casing string
extending within the wellbore, and the stimulant fluid then is
provided to the subterranean formation via the perforations. Once
stimulation is complete in the particular region of the
subterranean formation proximal to the perforated section of the
tubular casing string, ball sealers are introduced into the
perforated section of the tubular casing string to seal the
perforations and an additional section of the tubular casing string
is perforated proximal an additional region of the subterranean
formation to stimulate the additional region of the subterranean
formation. This process is repeated until stimulation of the
subterranean formation is complete.
[0006] With respect to sealing the perforations after stimulation
within a region is complete, ball sealers may be introduced from
the surface region via a ball injector, transported down into the
tubular casing string via a high velocity carrier fluid having a
suitable density, and allowed to engage with the perforations
within the section. However, the flow profile in the tubular casing
string, changing pump rates, and the fluid properties of the high
velocity carrier fluid tend to distribute the ball sealers along
the axial length of the tubular casing string and, thus, delivers
the ball sealers at the desired location within the tubular casing
string at different times. Ball sealers can sometimes be
distributed within as much as ten percent (10%) of the calculated
arrival volume of the wellbore fluid and, thus, arrive at the
desired location either too early or too late.
[0007] Alternatively, the ball sealers may be introduced locally to
the section of the tubular casing string to be sealed. U.S. Patent
Application Publication No. 2016/0168962 to Tolman et al. is
directed to multizone fracture stimulation of a reservoir which
utilizes a plurality of perforation gun assemblies made of a
friable material. A first perforation gun assembly is deployed into
the wellbore to perforate a first selected zone of interest. A
second perforating gun assembly is subsequently deployed into the
wellbore to perforate a second selected zone of interest; however,
the second perforating gun assembly additionally includes a ball
container including a sufficient amount of ball sealers to seal the
perforations of the first selected zone of interest. The ball
sealers may be released from the ball container prior to or
simultaneously with the firing of the second perforating gun
assembly. A single container containing an amount of ball sealers
to seal only the first selected zone of interest is used because
the friable perforating gun assemblies are destroyed upon firing
the explosive shape-charges contained therein.
[0008] U.S. Pat. No. 8,561,696 to Trummer et al. is also directed
to multizone fracture stimulation of a reservoir which either
utilizes tags within the ball sealers or high velocity carrier
fluid to determine the location of the ball sealers as they are
transported from the surface to the desired section of the well or
containers positioned locally within the well at axially spaced
apart locations to release the ball sealers contained therein to
seal perforations within a desired section of the well. The
containers may be coupled to the tubular casing string or may be
provided with the perforating gun assembly below an associated
perforating gun section on the assembly. Each container is
configured for a single release of ball sealers, therefore, only an
amount of ball sealers required to seal perforations within a
particular perforated zone are included within a container. When
the containers are included within the perforating gun assembly, a
container located below the fired perforating gun section and/or
the connections thereto will be destroyed upon firing. Further,
when containers are coupled to the tubular casing string, the
placement of such containers must be determined prior to coupling
to the tubular casing string limiting the flexibility in deployment
of the ball sealers.
[0009] Such methods of introducing ball sealers to seal
perforations of multiple, axially spaced-apart sections of the
tubular casing string introduce ball sealers from the surface or
use multiple local sources of ball sealers to separately seal each
particular perforated zone and do not provide an individual local
source capable of delivering ball sealers to perforations within
multiple, axially spaced-apart sections of the tubular casing
string at different time periods.
[0010] Thus, there exists a desire to provide a downhole device to
deliver specific and varying amounts of sealing components, as
needed during operations, into multiple, axially spaced-apart
sections of a well from a single local source capable of being
positioned at variable depths within a wellbore providing variable
depth control.
SUMMARY OF THE DISCLOSURE
[0011] Downhole devices, wells that include the downhole devices,
and methods of utilizing the same are disclosed herein. The
downhole devices are configured to provide sealing components
within a well to a plurality of axially spaced-apart sections of
the well. The downhole devices include a core, a sealing component
holder, a plurality of sealing components, a metering device, and a
cover. The sealing component holder is positioned within the core
and includes an opening to an external surface of the core. The
plurality of sealing components are positioned within the sealing
component holder. The metering device is constructed and arranged
to displace an internal volume of the sealing component holder and
discharge through the opening a portion of the plurality of sealing
components contained within the sealing component holder. The cover
is positioned over the opening and constructed and arranged to
allow the portion of the sealing components to exit the opening
upon displacement of the internal volume of the sealing component
holder.
[0012] As an example, the downhole device may be a shockwave
generation device additionally configured to generate a shockwave
within a wellbore fluid that extends within a tubular conduit of a
wellbore tubular. The shockwave generation devices may additionally
include a plurality of explosive charges arranged on an external
surface of the core and a plurality of triggering devices. Each of
the plurality of triggering devices is associated with a selected
portion of the plurality of explosive charges and is configured to
selectively initiate explosion of the selected portion of the
plurality of explosive charges.
[0013] Also described in the present disclosure are methods for
providing sealing components within a well. The well includes a
wellbore and a wellbore tubular extending within the wellbore, the
wellbore tubular defining a tubular conduit. The method includes
positioning a downhole device proximal to or within a first region
within the tubular conduit radially interior of a first section of
the wellbore tubular. The downhole device includes a core, a
sealing component holder, a plurality of sealing components, a
metering device, and a cover. The sealing component holder is
positioned within the core and includes an opening to an external
surface of the core. The plurality of sealing components are
positioned within the sealing component holder. The metering device
is constructed and arranged to displace an internal volume of the
sealing component holder and discharge through the opening a
portion of the plurality of sealing components contained within the
sealing component holder. The cover is positioned over the opening
and constructed and arranged to allow the portion of the sealing
components to exit the opening upon displacement of the internal
volume of the sealing component holder. The method also includes
actuating the metering device to displace a first internal volume
of the sealing component holder to discharge a first portion of the
plurality of sealing components through the opening into the
tubular conduit; positioning the downhole device proximal to or
within a second region within the tubular conduit radially interior
of a second section of the wellbore tubular, the second region
spaced apart from the first region along the length of the wellbore
tubular; and actuating the metering device to displace a second
internal volume of the sealing component holder to discharge a
second portion of the plurality of sealing components through the
opening into the tubular conduit.
[0014] As an example, the methods may additionally include
positioning the downhole device, such as a shockwave generation
device, within the first region of the tubular conduit and
actuating a first triggering device. The first triggering device
initiates explosion of a first explosive charge and generates a
first shockwave within the first region of the tubular conduit. The
first shockwave causes one or more selective stimulation ports
(SSPs) present in the wellbore tubular to transition from a closed
state to an open state. The methods may further include positioning
the shockwave generation device within the second region of the
tubular conduit and actuating a second triggering device
simultaneously with or subsequently to the first region of the
tubular conduit being sealed. The second triggering device
initiates explosion of a second explosive charge and generates a
second shockwave within the second region of the tubular conduit.
The second shockwave causes one or more SSPs present in the
wellbore tubular to transition from a closed state to an open
state. Once an SSP is opened by a shockwave from the shockwave
generation device, the SSPs may permit fluid flow between the
wellbore tubular and the subterranean formation until subsequently
sealed with sealing components.
[0015] Also described herein are wells including such downhole
devices; methods for fracturing a subterranean formation which
includes the methods for providing sealing components within a
hydrocarbon well; and methods for diverting injection fluid within
an injection well which includes the methods for providing sealing
components within the injection well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] While the present disclosure is susceptible to various
modifications and alternative forms, specific exemplary
implementations thereof have been shown in the drawings and are
herein described in detail. It should be understood, however, that
the description herein of specific exemplary implementations is not
intended to limit the disclosure to the particular forms disclosed
herein. This disclosure is to cover all modifications and
equivalents as defined by the appended claims. It should also be
understood that the drawings are not necessarily to scale, emphasis
instead being placed upon clearly illustrating principles of
exemplary embodiments of the present disclosure. Moreover, certain
dimensions may be exaggerated to help visually convey such
principles. Further where considered appropriate, reference
numerals may be repeated among the drawings to indicate
corresponding or analogous elements. Moreover, two or more blocks
or elements depicted as distinct or separate in the drawings may be
combined into a single functional block or element and blocks or
elements may be arranged in any suitable manner. Similarly, a
single block or element illustrated in the drawings may be
implemented as multiple steps or by multiple elements in
cooperation and may be implemented in any suitable order or
sequence.
[0017] FIG. 1 is a schematic representation of a side (axial
cross-sectional) view of a hydrocarbon well that may include and/or
utilize a downhole device according to the present disclosure.
[0018] FIG. 2 is a schematic representation of a side (axial
cross-sectional) view of a downhole device according to the present
disclosure.
[0019] FIG. 3 is a more detailed but still schematic representation
of a front view of a cover for the downhole device of FIG. 2.
[0020] FIG. 4 is a more detailed but still schematic representation
of a front view of a cover for the downhole device according to the
present disclosure.
[0021] FIG. 5 is a more detailed but still schematic representation
of a front view of a cover for the downhole device of FIG. 2.
[0022] FIG. 6 is a more detailed but still schematic representation
of a front view of a cover for the downhole device of FIG. 2.
[0023] FIG. 7 is schematic representation of a partial side (axial
cross-sectional) view of a downhole device.
[0024] FIG. 8 is a schematic representation of a partial side
(axial cross-sectional) view of a downhole device according to the
present disclosure.
[0025] FIG. 9 is a schematic representation of a partial side
(axial cross-sectional) view of a downhole device according to the
present disclosure.
[0026] FIG. 10 is a schematic representation of a partial side
(axial cross-sectional) view of a downhole device according to the
present disclosure.
[0027] FIG. 11 is a schematic representation of a partial side
(axial cross-sectional) view of a downhole device according to the
present disclosure.
[0028] FIG. 12 is a schematic representation of a side (axial
cross-sectional) view of a hydrocarbon well that may include and/or
utilize a shockwave generation device according to the present
disclosure.
[0029] FIG. 13 is a schematic representation of a side (axial
cross-sectional) view of a shockwave generation device according to
the present disclosure.
[0030] FIG. 14 is a more detailed but still schematic
representation of a side (axial cross-sectional) view of a
selective stimulation port according to the present disclosure.
[0031] FIG. 15 is a more detailed but still schematic
representation of a side view of a portion of the shockwave
generation device of FIG. 13.
[0032] FIG. 16 is a less detailed schematic side view of a
shockwave generation device according to the present
disclosure.
[0033] FIG. 17 is a transverse (radial cross-sectional) view of a
shockwave generation device showing examples of flutes and
protective barriers that may be included in shockwave generation
device according to the present disclosure.
[0034] FIG. 18 is a less detailed schematic side view of a
shockwave generation device according to the present
disclosure.
[0035] FIG. 19 is a transverse (radial cross-sectional) view of the
shockwave generation device of FIG. 18 taken along line 7-7 of FIG.
18.
[0036] FIG. 20 illustrates examples of various transverse (radial
cross-sectional) views of shapes for flutes that may be defined by
a core of a shockwave generation device according to the present
disclosure.
[0037] FIG. 21 is a flowchart depicting a method, according to the
present disclosure, of metering sealing components within a tubular
conduit.
[0038] FIG. 22 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0039] FIG. 23 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0040] FIG. 24 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0041] FIG. 25 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0042] FIG. 26 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0043] FIG. 27 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0044] FIG. 28 is a schematic side (axial cross-sectional) view of
a portion of a process flow for generating a plurality of
shockwaves within a subterranean formation.
[0045] FIG. 29 is a flowchart depicting a method, according to the
present disclosure, of metering sealing components within a tubular
conduit.
[0046] FIG. 30 is a schematic side (axial cross-sectional) view of
a portion of a process flow for metering sealing components within
a tubular conduit during refracturing operations.
[0047] FIG. 31 is a flowchart depicting a method, according to the
present disclosure, of metering sealing components within a tubular
conduit of an injection well.
[0048] FIG. 32 is a schematic side (axial cross-sectional) view of
a portion of a process flow for metering sealing components within
a tubular conduit during injection operations.
DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE
[0049] The present disclosure is directed to a downhole device
constructed and arranged to provide multiple, metered amounts of
sealing components (sealing devices) from an individual sealing
component holder contained within the downhole device. The metered
amounts of sealing components are discharged from the downhole
device proximal the section of the wellbore tubular or subterranean
formation to be sealed. Such a downhole device releases the sealing
components locally over a short period of time which provides the
sealing components to the targeted section of the wellbore tubular
in a concentrated manner. As discussed above, releasing sealing
components into the wellbore tubular from the surface results in
the axial distribution or dispersion of the sealing components
within the carrier fluid used to transport the sealing components
to the targeted section of the wellbore tubular. Distribution or
dispersion of the sealing components occurs due to the flow profile
within the wellbore tubular and the fluid properties of the carrier
fluid. Further, in order to minimize or prevent contact of the
sealing components with stimulant fluid or fracturing fluid
traveling ahead of the carrier fluid while the sealing components
are transported to the target section of the wellbore tubular, a
significant amount of carrier fluid is introduced into the wellbore
prior to the release of the sealing components from the surface.
The introduction of the excess carrier fluid can lead to over
displacement of proppant in the fracture which can in turn
negatively affect well performance.
[0050] As discussed above, including a container within a
perforation gun can limit the ability to use an individual source
of ball sealers to provide multiple, metered amounts of ball
sealers to perforations within multiple, axially spaced-apart
sections of the tubular casing string at different time periods.
This results from the fact that the area near the detonated portion
of the perforation gun and below, including any container and
connections thereto, is significantly damaged upon firing of the
shape-charges. The downhole device of the present disclosure
overcomes such limitations and provides the ability to locally
release multiple, metered amounts of sealing components from an
individual sealing component holder within the downhole device
which can provide the sealing component to the target section of
the wellbore tubular in a concentrated manner without significant
axial displacement or dispersion, eliminate introducing excess
stimulant fluid or fracturing fluid into the fracture, allow the
use of sealing components that are oversized or undersized, provide
multiple, precise placements of the sealing components contained
within a sealing component holder of a downhole device in a single
trip downhole, precise placement of multiple portions of a
plurality of sealing components contained within a sealing
component holder wherein the portions of sealing components can
have different properties or different amounts, and/or provide
sealing components that may be oversized or undersized.
[0051] Elements that serve a similar, or at least substantially
similar, purpose may be labeled with like numbers in each of FIGS.
1-32, and these elements may not be discussed in detail herein with
reference to each of FIGS. 1-32. Similarly, all elements may not be
labeled in each of FIGS. 1-32, 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. 1-32 may be included in and/or
utilized with any of FIGS. 1-32 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 may be 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.
[0052] FIG. 1 is a schematic representation of a hydrocarbon well
10 that may include and/or utilize a downhole device 190 according
to the present disclosure. Hydrocarbon well 10 may include a
wellbore 20 that extends from a surface region 30 to subterranean
formation 34 through subsurface region 32. Subterranean formation
34 includes a reservoir fluid 36, such as a liquid hydrocarbon
and/or a gaseous hydrocarbon, and hydrocarbon well 10 may be
utilized to produce, pump, and/or convey the reservoir fluid 36
from the subterranean formation 34 to the surface region 30.
Wellbore 20 may include a vertical section 20A, as illustrated in
FIG. 1. Wellbore 20 may also include a horizontal section 20B.
Wellbore 20 may also include a deviated section 20C located between
vertical section 20A and horizontal section 20B. Hydrocarbon well
10 may further include wellbore tubular 40, which extends within
wellbore 20 and defines a tubular conduit 42. Wellbore fluid 22
extends within the tubular conduit 42.
[0053] As shown in FIG. 1, downhole device 190 may be an
umbilical-attached downhole device 190 that may be operatively
attached to and may be positioned within tubular conduit 42 via, an
umbilical 192, such as a wireline, a tether, tubing, jointed
tubing, and/or coiled tubing. The umbilical 192 may permit and/or
facilitate positioning of the downhole device 190 within the
tubular conduit 42 and/or may permit and/or facilitate
communication with and/or power to the downhole device 190 from
surface region 30. Umbilical 192 may convey one or more status
signals from downhole device 190 to a control system (not shown)
located at surface region 30 and/or may convey one or more control
signals from the control system located at surface region 30 to
downhole device 190. Such an umbilical-attached downhole device 190
may include an anchor 193 that may be configured to receive and/or
to be operatively attached to the umbilical 192, as illustrated in
FIG. 2.
[0054] As another example, the downhole device 190 may be an
autonomous downhole device that may be flowed into and/or within
tubular conduit 42 without an attached umbilical. When downhole
device 190 is an autonomous downhole device, hydrocarbon well 10
may further include a wireless downhole communication network 39,
which may be configured to wirelessly communicate with the downhole
device 190, such as to convey one or more status signals from the
downhole device 190 to a control system located at surface region
30 and/or to convey one or more control signals from the control
system located at surface region 30 to the downhole device 190. One
or more batteries may be included within the autonomous downhole
device to provide electrical power to the components of the
downhole device 190.
[0055] FIG. 2 is a schematic representation of a downhole device
190 according to the present disclosure. Downhole device 190
includes a core 102, a sealing component holder 180, sealing
components 182, and a metering device 186. The sealing components
182 are positioned within the sealing component holder 180. Member
184 may also be positioned within the interior of the sealing
component holder 180. Sealing component holder 180 includes an
opening 189 which is configured, shaped and sized such that the
sealing components contained therein may be released from the
interior of the sealing component holder 180 upon displacement of
an internal volume of the sealing component holder 180. A cover 187
is positioned over opening 189.
[0056] The core of the downhole device may include any suitable
structure and/or material that may have, form, and/or define at
least a portion of the external surface of the downhole device. As
examples, the core may include and/or be an elongate core, a rigid
core, a metallic core, a partially solid core, a hollow core,
and/or an elongate rigid core. The external surfaces of the core
may be substantially solid except for an opening to a sealing
component holder and openings to accommodate connections to the
downhole device such as an umbilical connection. It is within the
scope of the present disclosure that the core may or may not be an
enclosed tubular. The core may be a single-piece and/or monolithic
structure. Alternatively, the core may be a multi-piece core that
includes a plurality of core segments. Each core segment may be
operatively attached to one or more adjacent core segments to form
and/or define the core. As an example, the core segments may be
hermetically sealed to one another to form and/or define the
core.
[0057] The downhole device includes a sealing component holder. The
downhole device may include more than one sealing component holder,
such as a plurality of sealing component holders. Each sealing
component holder includes an opening to an external surface of the
core. As an example, the opening may be in a bottom surface of the
downhole device such that the sealing components do not pass
between a side surface of the downhole device and an inner surface
of the wellbore tubular. A cover is positioned over each sealing
component holder opening and is constructed and arranged to allow a
portion of the sealing components to exit the opening upon
displacement of an internal volume of the sealing component holder.
The cover may be any suitable structure and/or material that allows
the sealing components to exit the holder upon displacement of an
internal volume and otherwise retains the sealing components within
the sealing component holder. As an example, FIG. 3 illustrates
cover 187 may be a spring loaded cover including a spring 187A
disposed about a rod 187 B which is disposed through openings 187C
in the cover 187 providing suitable tension to hold the cover tight
against an external surface of the core proximal the opening (not
shown) except when an internal volume is being displaced. As
another example, FIG. 4 illustrates cover 187 may be a rotating
cover which overlaps the opening (not shown) of the core and is
constructed and arranged to rotate the cover to align an opening
187D with the opening 189 (not shown) of the core to release
sealing components. The rotating mechanism (not shown) may be
operatively connected to the cover 187 in any suitable manner. As
another example, FIGS. 5 and 6 illustrate cover 187 may be a
flexible cover made of a flexible material overlapping the opening
(not shown) in the surface of the core and including an opening
1871 or slit 187H proximate the center of the flexible cover. The
slit may be constructed and arranged to allow the sealing
components to pass through the slit upon actuation of the metering
device. The cover opening 1871 of FIG. 6 may be constructed and
arranged to retain the sealing components until the metering device
is actuated to push the sealing components through the cover
opening 1871.
[0058] A sealing component holder may have any suitable shaped
interior which is able to contain the sealing components and
release the sealing components upon displacement of an internal
volume of the sealing component holder. The sealing component
holder may form a portion of the internal volume of the core. As an
example, the sealing component holder may form a majority of the
internal volume of the core. As an example, the radial
cross-section of the sealing component holder may be circular or
elliptical. As an example, the radial cross-sectional dimension or
diameter of the interior of the sealing component holder may be
constructed and arranged to be of similar dimension or diameter of
the sealing component or may be constructed and arranged to house
sealing components two, three, or more radially across. As an
example, the internal volume of the sealing component holder may
include a plurality of members that extend radially inward of an
inner surface of the sealing component holder to form slots to hold
the sealing components within the sealing component holder.
[0059] The internal volume of the sealing component holder may
include a plurality of axially spaced apart regions. Each region
including a portion of the plurality of sealing components. As
illustrated in FIG. 7, a sealing component holder 180 may include a
first region 180A containing a first portion of the plurality of
sealing components 182A, a second region 180B containing a second
portion of the plurality of sealing components 182B, a third region
180C containing a third portion of the plurality of sealing
components 182C, etc. As an example, the different portions of the
plurality of sealing components may have different properties from
the sealing components in adjacent regions within the sealing
component holder. As another example, each region within a sealing
component holder may contain a portion of the plurality of sealing
components with different properties from each of the other
portions of the plurality of sealing components. The properties may
include composition, size, specific gravity, rate of degradation,
non-degradability, and any combinations thereof. Size of the
sealing components includes the maximum outer dimension and/or
diameter of the sealing component.
[0060] As an example, each region within a sealing component holder
contains a plurality of sealing components, such as ball sealers,
the rate of degradation being different from the plurality of
sealing components of each of the other regions within the sealing
component holder. The rate of degradation being the greatest for
the first region within the sealing component holder proximal the
opening and being the least for the last region within the sealing
component holder distal the opening. Additionally or alternatively,
the size and/or specific gravity being different from the plurality
of sealing components of each of the other regions within the
sealing component holder.
[0061] The downhole device may include a plurality of sealing
component holders. The sealing components within each sealing
component holder may be the same or may be different. As an
example, the downhole device may include a first sealing component
holder containing a plurality of ball sealers as the sealing
components and a second sealing component holder containing a
plurality of chemical diverters as the sealing components. This
arrangement allows the same downhole device to be used to seal the
wellbore tubular with ball sealers and to seal the subterranean
formation exterior of openings in a wellbore tubular with chemical
diverters which may be performed in a single trip from the surface
downhole.
[0062] As another example, the downhole device may include a first
sealing component holder including a plurality of degradable ball
sealers as the sealing components and a second sealing component
holder including a plurality of non-degradable ball sealers as the
sealing components. The first sealing component holder may include
a plurality of regions, each region within the first sealing
component holder may contain a plurality of sealing components,
such as ball sealers, having a substantially different rate of
degradation, as discussed in more detail herein. This arrangement
allows the same downhole device to be used to temporarily seal
sections of the wellbore tubular with degradable ball sealers and
to subsequently seal sections of the wellbore tubular with
non-degradable ball sealers.
[0063] The plurality of sealing components may be any suitable
structure and/or material to seal a wellbore tubular or
subterranean formation exterior of the wellbore tubular. The
plurality of sealing components may be selected from ball sealers,
chemical diverters, other physical components sized and dimensioned
to physically seal a wellbore tubular or subterranean formation,
and any combinations thereof. An example of a suitable sealing
component may be a PERF PODS'' sealing component that is available
from Thru Tubing Solutions, Inc. of Oklahoma City, Okla. A PERF
PODS' sealing component 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.
[0064] The term "ball sealers" as used herein is meant to include
any solid, semi-rigid, deformable object having suitable dimensions
to individually seal an opening, such as a perforation or a SSP,
within the wall of the wellbore tubular. Ball sealers may be made
of a single material or a composite material, either material
suitable for deforming into a shape sufficient of sealing, but not
extruding through, the opening onto which it is seated. The
composite material for the ball sealers may include two or more
regions or layers of different composition. As an example, ball
sealers may be formed having a hard inner core region and a soft
outer region sufficiently compliant to sealingly engage an opening
within the wellbore tubular. The material for the inner core may be
selected from nylon, phenolic resin, neoprene rubber, syntactic
foam, and metallic materials such as aluminum. The material for the
outer region may be selected from elastomers and soft rubbers, such
as ethylene propylene diene monomer (EPDM), nitrile butadiene
rubber (NBR), hydrogenated nitrile butadiene rubber (HNBR), and the
like.
[0065] Ball sealers may be made of degradable or non-degradable
materials. "Degradable" as used herein is meant to include
materials that decompose over a period of time and/or at least
partially dissolve upon contact with a fluid. Degradation may be
characterized by time, temperature, and/or fluid type (e.g., oil,
water, acidity). The fluid may be a water-based fluid or an
oil-based fluid. The water-based fluid may be an acidic fluid.
"Non-degradable" as used herein is meant to include materials that
are stable and do not decompose over a reasonable period of time
for intended operations.
[0066] Ball sealers may be made of degradable materials which
degrade in the presence of water and may be selected from
polyglycolic acid polymer materials, such as polyglycolic acid
semicrystalline polyester, polylactic acid polymer materials, and
the like. Ball sealers may be made of degradable materials which
degrade in the presence of oil, such as alpha-olefins. Ball sealers
may be made of degradable materials which degrade in the presence
of acid such as nylon.
[0067] All or a portion of a ball sealer may be made of a
degradable material. As an example, a ball sealer may have an inner
core formed of a non-degradable material and one or more outer
regions of degradable material.
[0068] Other materials which may be used to form ball sealers may
be selected from poly-L-lactic acid, polyetheretherketone, epoxy
resin, polystyrene, poly-methylmethacrylate, high density
polyethylene, polypropylene, polyamide, polycarbonate,
poly-phenylene sulfide, and any combinations thereof.
[0069] Ball sealers may be buoyant, neutrally buoyant, and/or
non-buoyant with respect to the wellbore fluid in which the ball
sealers are disposed. Ball sealers may be of any suitable size and
shape to sealingly engage with an opening within the wall of the
wellbore tubular. Ball sealers may be spherical or polygonal. Ball
sealers may have a maximum outer dimension and/or diameter in the
range of from 5 millimeters (mm) to 76 mm or from 10 mm to 50 mm.
Ball sealer may have a maximum outer dimension and/or diameter in
the range of from 15 mm to 30 mm or from 22 mm to 25.5 mm. Ball
sealers may be oversized or undersized. "Undersized" is meant to
include ball sealers having a maximum outer dimension and/or
diameter that is less than what could typically be delivered
downhole from the surface. Undersized ball sealers may have a
maximum outer dimension and/or diameter of less than 15 mm or less
than 12 mm. Undersized ball sealers may have a maximum outer
dimension and/or diameter in the range of from 5 mm to less than 15
mm or from 5 mm to less than 12 mm. "Oversized" is meant to include
ball sealers having a maximum outer dimension and/or diameter that
is greater than what could typically be delivered downhole having
to pass between the inner surface of the wellbore tubular and the
outer surface of the downhole device. Oversized ball sealers may
have a maximum outer dimension and/or diameter of greater than 25.5
mm, or greater than 32 mm or greater than 50 mm. Oversized ball
sealers may have a maximum outer dimension and/or diameter in the
range of from greater than 25.5 mm to 76 mm or from greater than 32
mm to 76 mm or from greater than 50 mm to 76 mm.
[0070] The plurality of sealing components may include chemical
diverters. Chemical diverters may be solid particles of chemical
components, viscoelastic surfactants, polymer gels, foams, and any
combinations thereof used to seal porous and permeable portions of
the subterranean formation and/or fractures formed within the
subterranean formation. The chemical diverters may be contained
within a package or pod using a layer, membrane, film, and the like
so that the chemical diverter contained therein is released upon
the package or pod dissolving or otherwise rupturing within the
wellbore. Chemical diverters may be used in linear, crosslinked,
slick water, or acid hydraulic fracturing operations.
[0071] The chemical components may be selected from benzoic acid,
polyglycolic acid polymer, polylactic acid polymer, sodium
chloride, oil-soluble resins, waxes, polyesters, poly carbonates,
polyacetals, polyvinyl chlorides, polyvinyl acetates, nylon,
polytetrafluoroethylene, and any combinations thereof. The chemical
diverter particles may have any suitable particle size effective to
seal portions of the subterranean formation. As an example, the
chemical diverter particles may have a particle size in the range
of from 0.1 mm to less than 5 mm or from 0.1 mm to 4 mm or from 0.5
mm to 2 mm. The particles may be flakes, pellets, beads, and the
like.
[0072] Viscoelastic surfactants may be selected from
cetyltrimethylammonium bromide, cationic/anionic surfactant blends
with a nonaqueous solvent, salicylic acid or phthalic acid with
cationic or amphoteric surfactants, cationic surfactants such as
erucyl methyl bis(2-hydroxyethyl) ammonium chloride,
4-erucamidopropyl-1,1,1,-trimethyl ammonium chloride,
zwitterionic/amphoteric surfactants such as oleylamidopropyl
betaine, erucylamidepropy betaine, and anionic surfactants such as
alkyl taurate surfactants, methyl ester sulfonates,
sulfosuccinates. Polymer gels may be selected from
hydroxyethylcellulose, acrylamide, polysaccharides such as guar,
xanthan, scleroglucan, and succinoglycan, and any combinations
thereof.
[0073] The metering device may include a pump, a motor, a source of
stored energy, and combinations thereof. The pump may be selected
from a solid state, piezoelectric pump, a positive displacement
pump, or a hydraulic pump. As an example, the pump may be a solid
state, piezoelectric pump. An example of a solid state,
piezoelectric pump is described in U.S. Patent Publication No.
2015/0060083, titled "Systems and Methods for Artificial Lift Via a
Downhole Piezoelectric Pump", which description of a piezoelectric
pump is incorporated herein by reference. As another example, the
pump may be selected from a positive displacement pump or a
hydraulic pump. It is understood that a positive displacement pump
or a hydraulic pump may include an associated motor for the
operation of the pump which is different from a motor acting as the
primary component for the metering device.
[0074] The motor as the primary component of the metering device
may be an electric motor. The electric motor may be powered by an
alternating current (AC) voltage or a direct current (DC) voltage.
As an example, the primary component of the metering device may be
a brushless DC motor.
[0075] The source of stored energy may include a stored energy
device, such as a spring or pre-charged cylinder of a fluid, that
may be operatively coupled to the member within the sealing
component holder, thus replacing the need for a motor or a pump.
The stored energy devices may be operatively coupled to the member
within the sealing component holder similar to a motor or pump, as
further described herein.
[0076] Electrical power to the components of the metering device
and other components of the downhole device may be supplied locally
or remotely from the surface. A local source of electrical power
may include one or more batteries. The batteries may be positioned
within the core and operatively connected to the components of the
metering device. The remote source of power may be operatively
connected to the downhole device via an umbilical, as discussed in
more detail herein, and/or a separate electrical cable. Electrical
connections from the batteries, the umbilical and/or the separate
electrical cable may be provided within the core to connect the
components of the metering device and other components of the
downhole device requiring electricity to the source of electrical
power.
[0077] The metering device may be operatively connected to a member
positioned within a sealing component holder such that, upon
actuation of the metering device, the member displaces an internal
volume of the sealing component holder. As an example, FIG. 2
illustrates the member 184 may be a bellow 175 having substantially
the same cross-sectional dimension as the sealing component holder
180 in which bellow 175 is positioned. The metering device 186 may
be operatively connected to the bellow 175 using a connection 179
constructed and arranged to deliver a displacement fluid 183 from
the displacement fluid storage 181 to an inlet 171 of the bellow
175 via the metering device 186 which may be a pump 177, such as a
solid state, piezoelectric pump. As illustrated in FIG. 2, the pump
177 is arranged transverse to the longitudinal axis of the downhole
device 190; however, the pump 177 may have any suitable orientation
within the core, such as parallel to the longitudinal axis of the
downhole device. The displacement fluid 183 entering the inlet 171
expands the bellow 175 to displace an internal volume of the
sealing component holder 180. The displacement fluid 183 may be any
fluid having a sufficient density capable of displacing an internal
volume of a sealing component holder.
[0078] As another example, the member may be a moveable bulkhead
having substantially the same cross-sectional dimensions as the
sealing component holder in which it is positioned forming a
barrier between the backside of the member and the sealing
components. As an example, the metering device may be operatively
connected to the member using a connection including a mechanical
actuator that may be longitudinally displaced to move the member
within the sealing component holder to displace an internal volume.
The mechanical actuator may include a piston, a hydraulic cylinder,
and any combinations thereof. As illustrated in FIG. 8, member 184
is a moveable bulkhead 173 operatively connected to the metering
device 186, which is pump 177, via connection 188. Connection 188
may be attached to the back side 173B of bulkhead 173. Connection
188 may include a piston 188A. Although not shown, a hydraulic
cylinder may alternatively be included in connection 188. The
sealing components 182 may be positioned within the interior of the
sealing component holder 180 between the opening 189 and the front
side 173A of bulkhead 173.
[0079] As another example, the metering device may be operatively
connected to the member using a conduit between a displacement
fluid storage and an inlet port into the sealing component holder
proximate the backside of the member and using the metering device
to introduce the displacement fluid into the sealing component
holder to move the member within the sealing component holder to
displace an internal volume. FIG. 9 is a schematic representation
of an operative connection between pump 177 as the metering device
186 and an inlet port 185 which is in fluid communication with the
back side 184B of member 184. Sealing components are not shown for
clarity purposes. Connection 188 may include a conduit 188B
connecting a supply of displacement fluid 183 within the
displacement fluid storage 181, pump 177 and inlet port 185. Member
184 may include a sealing material 184C disposed on the outer
surface of member 184 in contact with an inner surface of the
sealing component holder 180. The sealing components (not shown)
may be positioned within the interior of the sealing component
holder between the opening and the front side 184A of the member
184.
[0080] As another example, the metering device may be operatively
connected to a member which may be an auger. The metering device
may be attached to the auger in any suitable manner to be able to
rotate the auger within the sealing component holder to displace an
internal volume of the sealing component holder. FIG. 10 is a
schematic representation of an operative connection between a motor
174 as the metering device 186 and an auger 172 as member 184.
Connection 188 includes a gear box 188C to rotate and control the
speed and torque of the rotation of auger 172 to displace an
internal volume of the sealing component holder 180 to release
sealing components (not shown) through the opening (not shown) in a
surface of the core.
[0081] As another example, the metering device may be operatively
connected to a member which may be moveable bulkhead. The metering
device may be a motor and a ratcheting arrangement may be
positioned between the motor and the bulkhead to displace an
internal volume of the sealing component holder. FIG. 11 is a
schematic representation of an operative connection between a motor
174 as the metering device 186 and moveable bulkhead 173 as member
184. Connection 188 includes a ratcheting arrangement 188D which
provides longitudinal movement to connection 188 to displace an
internal volume of the sealing component holder 180 to release
sealing components through the opening. Although not shown in
detail, the ratcheting arrangement may include a ratchet wheel and
a pawl and the motor is operatively coupled to the ratchet wheel
and the ratchet wheel is operatively coupled with the pawl. The
pawl is operatively coupled with the connection rod to
longitudinally move the rod forward to displace the member within
the sealing component holder.
[0082] As illustrated in FIG. 2, opening 189 may be positioned
proximal the distal (lower) end 109 of core 102. Alternatively, an
opening 189 may be positioned proximal the upper end 115 of the
core. Alternatively, opening 189 may be positioned at any location
along the length of the core. If two or more sealing component
holders are to be included with the downhole device 190, the
associated openings may be located at substantially the same axial
length of the core but circumferentially offset from each other or
the associated openings may be located at substantially different
axial lengths of the core and may or may not be circumferentially
offset.
[0083] Referring to FIG. 2, the downhole device 190 may further
include a detector 191. Detector 191 may be configured to detect
any suitable property and/or parameter of downhole device 190, of
fluid within tubular conduit 42, of wellbore tubular 40, and/or of
tubular conduit 42 (as illustrated in FIG. 1). As an example,
detector 191 may be configured to detect a location of the downhole
device 190 within the wellbore tubular 40.
[0084] An example of detector 191 includes a casing collar locator
that is configured to detect, or count, casing collars of the
wellbore tubular and monitor the relative length and relationship
to one another. The casing collar locator may also be configured to
locate any substantial variation in casing components which may
disturb magnetic lines flux coming from the casing components.
Another example of detector 191 includes a depth detector that is
configured to detect a depth of the downhole device within the
tubular conduit. Yet another example of detector 191 includes a
speed detector that is configured to detect a speed of the downhole
device within the tubular conduit. Another example of detector 191
includes a timer that is configured to measure a time associated
with motion of the downhole device within the tubular conduit. Yet
another example of detector 191 includes a downhole pressure sensor
that is configured to detect a pressure within the fluid that is
proximal thereto. Another example of detector 191 includes a
downhole temperature sensor that is configured to detect a
temperature within the fluid that is proximal thereto.
[0085] Referring to FIG. 2, the downhole device 190 may further
include a controller 150 programmed to control the operation of the
downhole device, such as the metering device. The controller may
include any suitable structure. As an example, a controller may
include and/or be a special-purpose controller, an analog
controller, a digital controller, and/or a logic device.
Communication linkage 108 may be included between the metering
device and the controller to provide a signal to the metering
device to actuate the metering device and displace a given internal
volume of the sealing component holder. Communication linkage 108
may also be included between the controller 150 and a control
system (not shown) located remotely at the surface. Communication
linkage 108 positioned within core 102 may be positioned within
pass-through holes 106, as illustrated in FIG. 2. The
communications linkage 108 may be provided via the umbilical, as
discussed in more detail herein. The controller may be programmed
to receive actuation signals via the umbilical and provide
actuation signals to the metering device. Alternatively, the
controller may communicate with the metering device or the surface
control system via a wireless communication network. Alternatively,
the metering device may be controlled directly by the surface
control system via the umbilical and communications linkage or
wireless communication network.
[0086] As an example, detector 191 may be configured to generate a
location signal that is indicative of the location of the downhole
device within the wellbore tubular and to convey the location
signal to the controller via communication linkage. In addition,
the controller may be programmed to control the operation of the
downhole device based, at least in part, on the location
signal.
[0087] As another example, detector 191 may be configured to detect
a shockwave generated within the wellbore conduit. Under these
conditions, detector 191 may generate a signal responsive to
receipt of the shockwave and may provide the shockwave signal, via
the communications linkage, to the controller or surface control
system which in turn may generate a signal to actuate the metering
device in response to the detected shockwave.
[0088] As another example, detector 191 may be configured to detect
a pressure pulse within the wellbore fluid, such as may be
deliberately and/or purposefully generated within the wellbore
fluid by an operator of the hydrocarbon well. Under these
conditions, detector 191 may generate a pressure pulse signal
responsive to receipt of the pressure pulse and may provide the
pressure pulse signal, via the communications linkage, to the
controller or surface control system.
[0089] In some embodiments, the downhole device may include
additional components such that it may be used as a shockwave
generation device. Shockwave generation devices may be used with
systems and methods for stimulating a subterranean formation which
include placing selective stimulation ports (SSPs) within the
wellbore tubular. Each SSP includes an isolation device that is
configured to selectively transition from a closed state to an open
state responsive to the receipt of a shockwave having an intensity
upon contact with the isolation device greater than a threshold
shockwave intensity for the isolation device. The shockwave
generation device may be utilized to provide the shockwaves to
selectively transition the SSPs from a closed state to an open
state to permit stimulation of a subterranean formation, such as
subterranean formation 34, and/or to permit an inrush of reservoir
fluid into the wellbore tubular from the subterranean formation.
Unlike perforation guns which detonate high energy shape-charges to
form perforations within the wellbore tubular and the subterranean
formation proximate thereto, the shockwave generation device
requires much less energy since the device only has to generate the
required shockwave intensity to transition the isolation device
within the SSP to an open state. Unlike the irregular perforations
formed using a perforation gun, the SPPs provide preformed openings
of a controlled shape and may be made of a material that has a
greater erosion-resistance, abrasion-resistance, and/or
corrosion-resistance as compared to the material forming the
majority of the wellbore tubular.
[0090] FIG. 12 is a schematic representation of a hydrocarbon well
10 that may include and/or utilize a downhole device, in particular
a shockwave generation device 190A, according to the present
disclosure, to generate a shockwave 194 within a wellbore fluid 22
that extends within the tubular conduit 42. Wellbore tubular 40 of
hydrocarbon well 10 includes a plurality of SSPs 100. SSPs 100 may
be operatively attached to and/or may form a portion of any
suitable component of wellbore tubular 40. SSPs 100 may be
configured to be operatively attached to and/or formed into a
portion of wellbore tubular 40 prior to the wellbore tubular 40
being located, placed, and/or installed within wellbore 20.
[0091] SSPs 100 may be operatively attached to wellbore tubular 40
in any suitable manner. As examples, 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 quarter
turn latch connection, a welded connection, and/or a brazed
connection.
[0092] Referring to FIGS. 12 and 13, shockwave generation device
190A may be configured to generate a shockwave 194 within a
wellbore fluid 22 that extends within tubular conduit 42. The
shockwave propagates within the wellbore fluid and/or propagates
from the shockwave generation device to the SSP within and/or via
the wellbore fluid. The shockwave may be attenuated by the wellbore
fluid, and this attenuation may include attenuation by at least a
threshold attenuation rate. As an example, the shockwave may have a
peak shockwave intensity proximal the shockwave generation device
and may decay, or decrease in intensity, with distance from the
shockwave generation device. Under these conditions, the threshold
shockwave intensity for an isolation device may be less than a
threshold fraction of the peak shockwave intensity proximal the
shockwave generation device. Examples of the threshold attenuation
rate include attenuation rates of at least 1 megapascal per meter
(MPa/m), at least 2 MPa/m, at least 4 MPa/m, at least 6 MPa/m, at
least 8 MPa/m, at least 10 MPa/m, at least 12 MPa/m, at least 14
MPa/m, at least 16 MPa/m, at least 18 MPa/m, at least 20 MPa/m,
and/or at least 30 MPa/m.
[0093] SSPs 100 are configured to selectively transition from a
closed state, in which fluid flow there through (i.e., between the
tubular conduit and the subterranean formation) is blocked,
restricted, and/or occluded, to an open state, in which fluid flow
there through is permitted, responsive to receipt of, or responsive
to experiencing, a shockwave of greater than a threshold shockwave
intensity for the associated isolation device of the SSP.
[0094] As an example, and as illustrated in FIGS. 12 and 14, SSPs
100 may include an SSP body 110 that defines an SSP conduit 116
forming an opening within the wall of the wellbore tubular. SSP
conduit 116 may extend between tubular conduit 42 and subterranean
formation 34. SSP body 110 has a tubular conduit facing region 112
and an opposed, formation-facing region 114. SSP body 110 also has
a projecting region 113, which projects from SSP body 110 in a
direction that is away from or perpendicular to, a central axis 118
of SSP conduit 116. SSP may include a tool-receiving portion 176,
which may be configured to receive a tool during operative
attachment of the SSP 100 to a wellbore tubular (not shown) and an
attachment region 178, which may be configured to interface with
the wellbore tubular when the SSP 100 is operatively attached to
the wellbore tubular. As an example, attachment region 178 may
include threads (not shown), and SSP 100 may be configured to be
rotated, via receipt of the tool (not shown) within the
tool-receiving portion 176, to permit threading of the SSP 100 into
the wellbore tubular. SSP 100 may further include a sealing
component seat 140, which may be configured to receive a sealing
component 182 when SSP is transitioned to an open state. Sealing
component seat 140 may be shaped to form a fluid seal 144 with
external surface 143 of sealing component 182 when sealing
component 182 is in sealing engagement with sealing component seat
140 and SSP 100 is transitioned to an open state.
[0095] Sealing component seat 140 interfaces with tubular conduit
42 and may be shaped to form a fluid seal 144 with a sealing
component 182, such as a ball sealer, that flows into engagement
with the sealing component seat 140. Formation of the fluid seal
144 may selectively restrict fluid flow from tubular conduit 42 and
into wellbore and/or subterranean formation 34 via SSP conduit 116.
Sealing component seat 140 may be a preformed sealing component
seat that has a predetermined geometry prior to wellbore tubular
being located, placed, and/or installed within wellbore. Sealing
component seat 140 may be selected from a corrosion-resistant
sealing component seat, an erosion-resistant sealing component
seat, an abrasion-resistant sealing component seat, and any
combinations thereof.
[0096] Referring to FIG. 14, SSPs 100 may further include an
isolation device 120 which is illustrated in a closed state 121.
SSP 100 may also include retention device 130. Retention device 130
may be configured to couple, or operatively couple, isolation
device 120 to SSP body 110, such as to retain the isolation device
120 in the closed state 121 prior to receipt of a shockwave having
an intensity greater than a threshold shockwave intensity for the
isolation device 120 transitioning SSP 100 to an open state (not
shown).
[0097] As an example, isolation device 120 may include an isolation
disk that extends across SSP conduit 116 when the SSP 100 is in the
closed state and that separates from SSP body 110 responsive to
receipt of the shockwave with greater than the threshold shockwave
intensity, such as to permit fluid flow through SSP conduit 116
when the SSP 100 is in the open state. As another example,
isolation device 120 may include a frangible isolation disk that
extends across SSP conduit 116 when the SSP 100 is in the closed
state and that breaks apart responsive to receipt of the shockwave
with greater than the threshold shockwave intensity, such as to
permit fluid flow through SSP conduit 116 when the SSP 100 is
transitioned to the open state.
[0098] Since shockwave 194 is attenuated by wellbore fluid 22, the
shockwave may have sufficient energy (i.e., may have greater than
the threshold shockwave intensity for an isolation device) to
transition a first SSP 100, which is less than a threshold distance
from the shockwave generation device 190A when the shockwave
generation device 190A generates the shockwave 194, from the closed
state to the open state. However, the shockwave 194 may have
insufficient energy to transition a second SSP 100, which is
greater than the threshold distance from the shockwave generation
device when the shockwave generation device generates the
shockwave, and remains in the closed state.
[0099] Stated another way, the plurality of explosive charges may
be sized such that the shockwave selectively transitions the first
SSP from the closed state to the open state but does not transition
the second SSP from the closed state to the open state. The
threshold distance also may be referred to herein as a maximum
effective distance of the shockwave and/or of the shockwave
generation device 190A from which the shockwave was generated.
Examples of the threshold distance include threshold distances of
less than 1 meter, less than 2 meters, less than 3 meters, less
than 4 meters, less than 5 meters, less than 6 meters, less than 7
meters, less than 8 meters, less than 10 meters, less than 15
meters, less than 20 meters, or less than 30 meters along an axial
length of the tubular conduit.
[0100] Shockwave generation device 190A may include and/or be any
suitable structure that may, or may be utilized to, generate a
shockwave 194 within wellbore fluid 22. The shockwave generation
device 190A may be an umbilical-attached downhole device or an
autonomous downhole device, as discussed in more detail herein.
[0101] FIG. 13 is a schematic representation of a shockwave
generation device 190A for deployment within hydrocarbon well 10
according to the present disclosure, while FIG. 15 is a more
detailed but still schematic representation of a portion of the
shockwave generation device 190A of FIG. 13. FIG. 16 is a less
detailed schematic side view of a shockwave generation device 190A
according to the present disclosure, while FIG. 17 is a
cross-sectional view of a shockwave generation device 190A
illustrating various relative shapes and orientations for flutes,
explosive charges, and protective barriers that may be utilized in
shockwave generation devices 190A. FIG. 18 is a less detailed
schematic side view of a shockwave generation device 190A according
to the present disclosure, while FIG. 19 is a cross-sectional view
of the shockwave generation device 190A of FIG. 18 taken along line
7-7 of FIG. 18. FIG. 20 illustrates various transverse
cross-sectional shapes for flutes that may be defined by the core
of a shockwave generation device 190A according to the present
disclosure.
[0102] Any of the structures, functions, and/or features that are
discussed herein with reference to shockwave generation devices
190A of FIGS. 13 and 15-20 may be included in and/or utilized with
downhole device 190A and/or hydrocarbon well 10 of FIG. 12 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 downhole device 190 and/or hydrocarbon
well 10 of FIG. 1 may be included in and/or utilized with shockwave
generation devices 190A of FIGS. 13 and 15-20 without departing
from the scope of the present disclosure.
[0103] As illustrated in FIG. 23, shockwave generation device 190A
is configured to generate shockwave 194 within wellbore fluid 22
that extends within tubular conduit 42 of wellbore tubular 40. As
illustrated in FIG. 13, shockwave generation device 190A includes
core 500 and a plurality of explosive charges 520. Shockwave
generation device 190A further includes a plurality of triggering
devices 530.
[0104] Explosive charges 520 are arranged on an external surface
502 of core 500, and each triggering device 530 is configured to
initiate explosion of a selected one of the plurality of explosive
charges 520. Stated another way, shockwave generation device 190A
may be configured such that a selected triggering device 530 may
initiate explosion of a selected explosive charge 520 without
initiating explosion of other explosive charges 520 that may be
associated with other triggering devices 530. As such, shockwave
generation device 190A also may be referred to herein as, or may
be, a select-fire, shockwave generation device 190A, a
selective-fire, downhole shockwave generation device 190A, and/or a
shockwave generation device 190A that is configured to selectively
explode a plurality of explosive charges 520 and to generate a
plurality of shockwaves that are spaced-apart in time.
[0105] It is within the scope of the present disclosure that the
phrase "selected one of the plurality of explosive charges" may
refer to a single explosive charge 520. Alternatively, it is also
within the scope of the present disclosure that the phrase
"selected one of the plurality of explosive charges" may refer to
two or more spaced-apart, separate, and/or distinct explosive
charges 520 and also may be referred to herein as a selected
portion of the plurality of explosive charges. Thus, a given
triggering device 530 may initiate explosion of a single explosive
charge 520 or two or more of the plurality of explosive charges 520
within a selected portion of the plurality of explosive charges
520. Regardless of the exact configuration, each triggering device
530 may initiate explosion of one or more selected and/or
predetermined explosive charges 520 but may not initiate explosion
of each, or every, explosive charge that is included within
shockwave generation device 190A.
[0106] Shockwave generation device 190A may be configured such that
the shockwave emanates symmetrically, at least substantially
symmetrically, isotropically, and/or at least substantially
isotropically, therefrom. Stated another way, the shockwave
generation device may be configured such that the shockwave is
symmetric, at least substantially symmetric, isotropic, and/or at
least substantially isotropic within a given transverse
cross-section of the wellbore tubular in which the shockwave in
generated. This symmetric and/or isotropic behavior of the
shockwave may be accomplished in any suitable manner. As an
example, and as discussed in more detail herein, explosive charges
520 may be circumferentially wrapped around, or at least
substantially around, an external surface 502 of core 500.
[0107] Core 500 of shockwave generation device 190A may be a core
as discussed in more detail herein with respect to a downhole
device and may include any suitable structure and/or material that
may have, form, and/or define external surface 502, which may also
support explosive charges 520, and/or triggering devices 530. It is
also within the scope of the present disclosure that core 500 may
have and/or define one or more pass-through holes 506, as
illustrated in FIG. 13. Pass-through holes 506 may extend along a
longitudinal length of core 500, and communication linkage 508 may
extend therein, as illustrated in FIGS. 13 and 15. Communication
linkage 508 may permit and/or provide communication between one or
more components of shockwave generation device 190A and/or between
umbilical 192 and one or more components of shockwave generation
device 190A and/or between wireless communication network 39 (as
illustrated in FIG. 12) and one or more components of the shockwave
generation device 190A. Although not shown, pass-through holes 506
may also be provided along a longitudinal length of core 500 to
accommodate electrical connections between one or more components
of the shockwave generation device 190A and the source of
electrical power and/or between components of the shockwave
generation device 190A. It is understood that pass-through holes,
communications linkage and electrical connections may also be
included with downhole device 190.
[0108] As illustrated in FIG. 13, core 500 may further have,
include, and/or define one or more flutes 504. Flutes 504 may be
defined by external surface 502. In addition, flutes 504 may be
shaped and/or configured to receive and/or contain one or more
explosive charges 520. As an example, each flute 504 may receive
and/or contain at least a portion, a majority, or even an entirety,
of a respective one of the plurality of explosive charges 520.
[0109] As illustrated in FIGS. 17 and 20, each flute 504 includes a
respective recess 512 and a respective opening 514. Both the
opening and the recess are defined by core 500, and the opening
provides, or is sized to provide, access to the recess by a given
explosive charge 520. Recesses 512 may include and/or be elongate
recesses that may extend along the longitudinal length of core 500,
that may extend about and/or around core 500, that may spiral
around core 500, and/or that may extend circumferentially around a
transverse cross-section of core 500. Similarly, openings 514 may
include and/or be elongate openings that may extend along the
longitudinal length of core 500, that may extend about and/or
around core 500, that may spiral around core 500, and/or that may
extend circumferentially around a transverse cross-section of core
500.
[0110] As an example, and as illustrated in FIGS. 13 and 15 flutes
504 may extend longitudinally along the longitudinal length of core
500. As another example, and as illustrated in FIG. 16, flutes 504
may include a plurality of spiraling flutes that wrap around
external surface 502 and/or that spirals along a longitudinal axis
of core 500. As yet another example, and as illustrated in FIGS. 18
and 19, flutes 504 may include a plurality of circumferential
flutes that extends at least partially, or even completely, around
the transverse cross-section of the core and may include
corresponding circumferential explosive charges 520.
[0111] It is within the scope of the present disclosure that flutes
504 may at least partially, or even completely, house and/or
contain respective explosive charges 520. As an example, and as
illustrated in FIG. 17 at 515, a respective explosive charge 520
may extend within recess 512 and may not extend and/or project
through and/or across opening 514. Stated another way, a given
explosive charge may have and/or define a respective transverse
cross-sectional area, a given flute, which receives the given
explosive charge, may have and/or define a respective transverse
cross-sectional area, and the respective transverse cross-sectional
area of the given explosive charge may be less than the respective
transverse cross-sectional area of the given flute.
[0112] Such a configuration may be utilized to protect the
explosive charge from damage due to motion of the shockwave
generation device within the tubular conduit and/or due to flow of
an abrasive material past the shockwave generation device while the
shockwave generation device is present within the tubular conduit.
Additionally or alternatively, such a configuration may provide a
desired level of focusing, a desired intensity, and/or a desired
directionality of the shockwave that is generated responsive to
explosion of the given explosive charge.
[0113] A given flute 504 additionally or alternatively may be
shaped and/or otherwise configured to protect a given explosive
charge 520 such that initiation of explosion of another, or an
adjacent, explosive charge 520 does not initiate explosion of the
given explosive charge 520. As examples, the given flute 504 may
direct the shockwave that is generated by given explosive charge
520 away from core 500, may direct the shockwave away from the
other flutes 504, and/or may direct the shockwave away from other
explosive charges 520 that are associated with the other flutes
504. As additional examples, the given flute 504 and/or the
adjacent flute(s) may be configured to sufficiently shield and/or
isolate the adjacent explosive charges from the shockwave produced
by the given explosive charge 520 to prevent the shockwave from the
given explosive charge initiating explosion of the adjacent
explosive charges. Such configurations may permit and/or facilitate
each triggering device 520 to initiate explosion of one or more
selected explosive charges 520 without initiating explosion of
each, or every, explosive charge that is included within shockwave
generation device 190A.
[0114] As another example, and as illustrated in FIG. 17 at 516, a
respective explosive charge 520 may extend within recess 512 and
also may extend and/or project through and/or across opening 514.
Stated another way, the respective transverse cross-sectional area
of the given charge may be less than the respective transverse
cross-sectional area of the given flute. Such a configuration may
provide a desired level of focusing, a desired intensity, and/or a
desired directionality of the shockwave that is generated
responsive to explosion of the given explosive charge.
[0115] It is within the scope of the present disclosure that flutes
504 may have and/or define any suitable cross-sectional, or
transverse cross-sectional, shape. As an example, and as
illustrated in FIG. 20 at 590, flutes 504 may have and/or define a
circular, or at least partially circular, transverse
cross-sectional shape. As another example, and as illustrated in
FIG. 20 at 592, flutes 504 may have and/or define an arcuate, or at
least partially arcuate, transverse cross-sectional shape. As yet
another example, and as illustrated in FIG. 20 at 594, flutes 504
may have and/or define a triangular, at least partially triangular,
V-shaped, or at least partially V-shaped, transverse
cross-sectional shape. As another example, and as illustrated in
FIG. 20 at 596, flutes 504 may have and/or define a square, at
least partially square, rectangular, or at least partially
rectangular, transverse cross-sectional shape. Flutes with other
regular and/or irregular geometric transverse cross-sectional
shapes also may be utilized. As illustrated in FIG. 20 at 598, one
or more explosive charges 520 may extend across a portion of
external surface 502 that does not include a flute.
[0116] As discussed in more detail herein, core 500 may be a
single-piece and/or monolithic structure or, alternatively, a
multi-piece core that includes a plurality of core segments 510 as
illustrated in FIG. 18. Each core segment 510 may be operatively
attached to one or more adjacent core segments to form and/or
define core 500. It is understood such arrangements of core 500 may
also be utilized with core 102 of downhole device 190. When
shockwave generation device 190A includes core segments 510, it is
within the scope of the present disclosure that each core segment
510 may have any suitable number of explosive charges 520 and/or
corresponding triggering devices 530 associated therewith and/or
attached thereto. As examples, each core segment may have 1, 2, 3,
4, 5, 6, 7, 8, or more than 8 explosive charges and/or
corresponding triggering devices associated therewith and/or
attached thereto. When shockwave generation device 190A includes
core segments 510, it is within the scope of the present disclosure
that a core segment at the distal end of the core may form the
sealing component holder. Additionally or alternatively, one or
more of the core segments 510 may include an internal void such
that when such core segments 510 are operatively attached, a
sealing component holder 180 may be formed within the interior of
the defined core 500; at least one of the core segments 510 may
include an opening 189 to the so formed sealing component holder
180 with an associated cover (not shown); and at least one of the
core segments 510 includes all or a portion of the metering device
(not shown). If a plurality of sealing component holders are to be
included within core 500, additional sealing component holders may
be similarly formed.
[0117] Explosive charges 520 may include and/or be any suitable
structure that may be adapted, configured, formulated, synthesized,
and/or constructed to selectively explode and/or to selectively
generate the shockwave within the wellbore fluid without causing
substantial damage to the shockwave generation device during
intended operations. Stated another way, at most only insubstantial
damage may be experienced by the shockwave generation device upon
exploding explosive charges 520 during intended operation of the
device.
[0118] An example of explosive charges 520 include a primer cord
(or detonation cord) 522. As an example, shockwave generation
device 190A may include a plurality of lengths of primer cord 522,
with each explosive charge 520 including at least one length of
primer cord as the source of explosive on the shockwave generation
device 190A. Primer cord 522 also may be referred to as detonation
cord or detonating cord and configured to explode and/or detonate.
The primer cord may be any suitable length. As examples, the length
of the primer cord may be at least 0.1 meter (m), at least 0.2 m,
at least 0.3 m, at least 0.4 m, at least 0.5 m, at least 0.6 m, at
least 0.7 m, at least 0.8 m, at least 0.9 m, at least 1 m, at least
1.25 m, at least 1.5 m, at least 1.75 m, or at least 2 m.
Additionally or alternatively, the length of the primer cord may be
less than 5 m, less than 4.5 m, less than 4 m, less than 3.5 m,
less than 3 m, less than 2.5 m, less than 2 m, less than 1.5 m, or
less than 1 m.
[0119] Primer cord 522 also may include any suitable amount of an
explosive, such as research department formula X (RDX), high
melting explosive (HMX), or hexanitrostilbene (HNS). HMX may also
be referred to as octogen, her majesty's explosive, high velocity
military explosive, or high molecular weight RDX. As examples, the
primer cord may include at least 10 grains of explosive per foot of
length (grains/ft) (or 2 grams per meter (g/m)), at least 20
grains/ft (or 4 g/m), at least 25 grains/ft (or 5 grams per meter
(g/m)), at least 40 grains/ft (or 8 grams per meter (g/m)), at
least 80 grains/ft (or 17 g/m), at least 100 grains/ft (or 21 grams
per meter (g/m)), at least 160 grains/ft (or 34 grams per meter
(g/m)), or at least 240 grains/ft (or 51 grams per meter (g/m)).
Additionally or alternatively, the primer cord may include less
than 1000 grains/ft (212 g/m), less than 720 grains/ft (153 g/m),
less than 560 grains/ft (or 119 grams per meter (g/m)), less than
500 grains/ft (or 106 grams per meter (g/m)), less than 450
grains/ft (or 96 grams per meter (g/m)), less than 480 grains/ft
(or 102 grams per meter (g/m)), less than 400 grains/ft (85 g/m),
or less than 320 grains/ft (68 g/m). The amount of explosive may be
in the range of from 20 grains/ft (4 g/m) to 1000 grains/ft (212
g/m), or from 25 grains/ft (5 g/m) to 560 grains/ft (119 g/m) or
from 50 grains/ft (10 g/m) to 480 grains/ft (102 g/m). It is also
understood that isolation devices may be used within the SSPs which
may be made of stronger materials and may require larger explosive
charges to open the SSP and/or Such SSPs may be installed within a
wellbore tubular that has a greater pipe weight and/or is made of a
stronger metal than typical wellbore tubulars in which case
explosive concentrations may be in excess of 1000 grains/ft (212
g/m), of 2000 grains/ft (425 g/m), or of 3000 grains/ft (638
g/m).
[0120] In general, the length of the primer cord and/or the amount
of explosive per unit length of the primer cord may be selected to
provide a desired intensity, or a desired maximum intensity, for
the shockwave when the primer cord explodes within the wellbore
fluid. As an example, the length of the primer cord and/or the
amount of explosive per unit length of the primer cord may be
selected such that the maximum intensity of the shockwave is
greater than the threshold shockwave intensity necessary to
transition an SSP from the closed state to the open state. As
another example, the length of the primer cord and/or the amount of
explosive charge per unit length of the primer cord may be selected
such that maximum intensity of the shockwave is less than an
intensity that would damage, or rupture, a wellbore tubular that
defines a tubular conduit within which the shockwave is generated
and/or such that the shockwave has insufficient energy, or
intensity, to rupture or damage the wellbore tubular.
[0121] Stated another way, each explosive charge 520 may be sized
such that the shockwave has a maximum pressure of at least 100
megapascals (MPa), at least 110 MPa, at least 120 MPa, at least 130
MPa, at least 140 MPa, at least 150 MPa, at least 160 MPa, at least
170 MPa, at least 180 MPa, at least 190 MPa, at least 200 MPa, at
least 250 MPa, at least 300 MPa, at least 400 MPa, or at least 500
MPa. Additionally or alternatively, each explosive charge 520 may
be sized such that the shockwave has a maximum duration of less
than 1 second, less than 0.9 seconds, less than 0.8 seconds, less
than 0.7 seconds, less than 0.6 seconds, less than 0.5 seconds,
less than 0.4 seconds, less than 0.3 seconds, less than 0.2
seconds, less than 0.1 seconds, less than 0.05 seconds, or less
than 0.01 seconds. The maximum duration may be a maximum period of
time during which the shockwave within the wellbore tubular has
greater than the threshold shockwave intensity for the isolation
device. Additionally or alternatively, the maximum duration may be
a maximum period of time during which the shockwave has a shockwave
intensity of greater than 68.9 MPa (10,000 pounds per square inch)
within the portion of the wellbore tubular proximal the SSP to be
transitioned from the closed state to the open state.
[0122] Each explosive charge 520 may be sized such that the
shockwave within the tubular conduit exhibits a shockwave intensity
greater than the threshold shockwave intensity for an isolation
device over a maximum effective distance or length along the
tubular conduit. Examples of the maximum effective distance are as
discussed in more detail herein.
[0123] Shockwave generation device 190A may include any suitable
number of explosive charges 520. As examples, the shockwave
generation device may include at least 2, at least 3, at least 4,
at least 5, at least 6, at least 7, or at least 8 explosive
charges. Additionally or alternatively, the shockwave generation
device may include 20 or fewer, 18 or fewer, 16 or fewer, 14 or
fewer, 12 or fewer, 10 or fewer, 8 or fewer, 6 or fewer, or 4 or
fewer explosive charges.
[0124] Triggering devices 530 may include and/or be any suitable
structure that may be configured to selectively initiate explosion
of a selected portion of the plurality of explosive charges
independent from a remainder of the explosive charges. As an
example, triggering devices 530 may include and/or be electrically
actuated triggering devices, separately addressable switches,
and/or detonators 532, as illustrated in FIG. 15. Detonators may
include blasting caps. As a more specific example, each triggering
device 530 may include a uniquely addressable switch that may be
configured to initiate explosion of a selected one of the plurality
of explosive charges responsive to receipt of a unique code. The
unique code of each triggering device may be different from the
unique code of each of the other triggering devices, thereby
permitting selective actuation of a given triggering device.
[0125] As illustrated in FIGS. 13, 15-16, and 18, triggering
devices 530 may form a portion of a triggering assembly 528.
Triggering assembly 528 may be operatively attached to core 500
and/or may form a portion of core 500. In addition, and when
shockwave generation device 190A is submerged within the wellbore
fluid, triggering assembly 528 may at least partially, or even
completely, isolate at least a portion, or even all, of each
triggering device 530 from the wellbore fluid. As an example, and
as illustrated in FIGS. 13 and 15, triggering assembly 528 may
include and/or define an enclosed volume 529 within the core 500
that is fluidly isolated from the wellbore fluid and/or that
contains and/or houses the triggering devices.
[0126] As illustrated in FIGS. 13, 15, 17, and 19, shockwave
generation device 190A and/or explosive charge 520 thereof may
further include a protective barrier 524. Protective barrier 524
may be configured to at least partially, or even completely,
isolate, or fluidly isolate, explosive charges 520 from the
wellbore fluid when the shockwave generation device is submerged
within the wellbore fluid. Such isolation may prevent contamination
of the explosive charge by the wellbore fluid, may prevent
degradation of the explosive charge by the wellbore fluid, may
resist permeation of the wellbore fluid into the explosive charge,
and/or may resist abrasion of the explosive charge from movement
within the wellbore or by an abrasive material, such as a proppant,
that may be present within the wellbore fluid and/or by wellbore
tubular when the shockwave generation device is present within
tubular conduit.
[0127] As illustrated in FIG. 13, protective barrier 524 may extend
along a length, or even an entire length, of explosive charge 520.
As illustrated in FIG. 17 at 525, protective barrier 524 may extend
completely around a transverse cross-section of a given explosive
charge 520. Additionally or alternatively, and as illustrated in
FIG. 17 at 526, protective barrier 524 may extend at least
partially around a transverse cross-section of core 500 and/or of
external surface 502 thereof and of a given explosive charge
520.
[0128] It is within the scope of the present disclosure that
shockwave generation device 190A may include a plurality of
protective barriers 524 and that each protective barrier 524 may
extend around a corresponding explosive charge 520, may extend
along a length of the corresponding explosive charge, may extend
along an entirety of the length of the corresponding explosive
charge, and/or may extend across a respective portion of external
surface 502 of core 500 to protect the explosive charge 520 from
damage during movement within the wellbore or particle flow around
the shockwave generation device 190A. Additionally or
alternatively, it is also within the scope of the present
disclosure that a single protective barrier 524 may extend at least
partially around two or more of the explosive charges and/or may
extend across a majority, or even all, of external surface 502 of
core 500. Protective barrier 524 may include and/or be formed from
any suitable material. As examples, the protective barrier may
include and/or be a non-metallic protective barrier and/or may be
formed from a polymeric material, an elastomeric material, and/or a
resilient material.
[0129] As illustrated in FIGS. 13 and 15, shockwave generation
device 190A may include a first plurality of explosive charges 520
and a corresponding first plurality of triggering devices 530. In
addition, and as illustrated in FIGS. 13 and 15, shockwave
generation device 190A also may include a second plurality of
explosive charges 520 and a corresponding second plurality of
triggering devices 530. The first plurality of explosive charges
and the first plurality of triggering devices together may define a
first shockwave generation unit 198 (as indicated in solid lines),
and the second plurality of explosive charges and the second
plurality of triggering devices together may define a second
shockwave generation unit 198 (as indicated in dashed lines). An
additional section 199 is included at the distal end of the
shockwave generation device 190A and includes the sealing component
holder and metering device.
[0130] The first shockwave generation unit and the second shockwave
generation unit may be operatively attached to one another, in an
end-to-end fashion, to form and/or define shockwave generation
device 190A. As an example, an end region of the first shockwave
generation unit may be operatively attached to an end region of the
second shockwave generation unit, such as via a coupling structure
562 and/or such that a longitudinal axis of the first shockwave
generation unit is aligned, or at least substantially aligned, with
a longitudinal axis of the second shockwave generation unit.
Shockwave generation device 190A may include any suitable number of
shockwave generation units 198 and each shockwave generation unit
198 may include any suitable number of explosive charges 520 and
corresponding triggering devices 530. As examples, shockwave
generation device 190A may include at least 2, at least 3, at least
4, at least 5, at least 6, at least 8, or at least 10 shockwave
generation units. At least the lowermost (downhole direction)
portion of shockwave generation device 190A may include a sealing
component holder section 199. Section 199 may form a portion of the
lowermost shockwave generation unit 198 or may form a separate unit
such that an end region of the first shockwave generation unit may
be operatively attached to an end region of the sealing component
holder unit, such as via a coupling structure (not shown) and/or
such that a longitudinal axis of the first shockwave generation
unit is aligned, or at least substantially aligned, with a
longitudinal axis of the sealing component holder unit.
[0131] Shockwave generation device 190A may be adapted, configured,
designed, constructed, and/or sized to remain in the tubular
conduit during stimulation of the subterranean formation, during
flow of a stimulant fluid through and/or within the tubular conduit
and past the shockwave generation device 190A, and/or during the
inrush of reservoir fluid into the wellbore tubular. Shockwave
generation device 190A may have any suitable length or overall
length. As examples, the overall length of the shockwave generation
device may be less than 40 meters, less than 35 meters, less than
30 meters, less than 25 meters, or less than 20 meters. The
shockwave generation device 190A also may have any suitable maximum
transverse cross-sectional extent, dimension, and/or diameter
suitable for deployment within a wellbore tubular. As examples, the
maximum transverse cross-sectional extent, dimension, and/or
diameter may be less than 0.2 meters (m), less than 0.15 m, less
than 0.1 m, less than 0.8 m, less than 0.09 m or less than 0.06 m.
It is understood that a downhole device without the shockwave
generation features may have similar dimensions.
[0132] The maximum transverse cross-sectional inner diameter of the
tubular conduit and/or wellbore tubular may be any suitable
diameter capable of accommodating the downhole device and any other
downhole equipment and/or downhole components. As an example, the
maximum transverse cross-sectional inner diameter of the tubular
conduit and/or wellbore tubular may be in the range of from 70 mm
to 178 mm or from 90 mm to 105 mm or from 94 mm to 102 mm. In such
example, opening 189 may be provided proximal the distal end 109 of
the shockwave generation device 190A and/or downhole device 190 and
the sealing components 182 may include oversized ball sealers as
discussed in more detail herein. As an example, the opening 189 may
be provided in a bottom surface of the shockwave generation device
190A and/or downhole device 190. As another example, the opening
189 may be provided in a side surface having a lesser transverse
cross-section dimension or diameter than the average transverse
cross-sectional dimension or diameter of the shockwave generation
device 190A and/or downhole device 190, as determined along its
length, such that the sealing components (e.g., ball sealers) do
not have to pass between the wellbore tubular and the maximum
transverse cross-section extent, dimension and/or diameter of
device 190, 190A. This arrangement provides the ability to locally
release oversized ball sealers at different spaced-apart sections
of the wellbore, oversized ball sealers having a maximum outer
dimension larger than the gap formed between the wellbore tubular
and the maximum outer dimension of the shockwave generation device
or downhole device. Additionally or alternatively, when an opening
189 is positioned at other side surface locations along the length
of the shockwave generation device 190A or downhole device 190, the
maximum transverse cross-sectional dimension of the shockwave
generation device 190A or downhole device 190 may be less than a
cross-sectional diameter of the tubular conduit such that a gap
formed there between may have a sufficient radial dimension to
provide clearance for flow of the sealing components past the
shockwave generation device 190A or downhole device 190.
[0133] As illustrated in FIGS. 13 and 15, shockwave generation
device 190A may further include a detector 540. Detector 540 may be
similar to detector 191 as discussed in more detail herein. Another
example of detector 540 includes a magnetic field detector that is
configured to detect a magnetic field that emanates from a magnetic
material that defines a portion of the wellbore tubular and/or a
SSP of the wellbore tubular. Yet another example of detector 540
includes a radioactivity detector that is configured to detect a
radioactive material that forms and/or defines a portion of the
wellbore tubular and/or a SSP 100 of the wellbore tubular. Yet
another example of detector 540 includes a downhole pressure sensor
that is configured to detect a pressure within the wellbore fluid
that is proximal thereto. Another example of detector 540 includes
a downhole temperature sensor that is configured to detect a
temperature within the wellbore fluid.
[0134] As illustrated in FIGS. 13 and 15, shockwave generation
device 190A may further include a controller 550. Controller 550
may be adapted, configured, designed, constructed, and/or
programmed to control the operation of at least a portion of the
shockwave generation device 190A. Controller 550 may include any
suitable structure, as discussed in more detail herein with respect
to controller 150. As an example, controller 150 may be used to
actuate metering device 186 and controller 550 may be used to
actuate a triggering device 530. Control by controller 550 may be
based, at least in part, on a property and/or parameter detected by
detector 540. Control by controller 150 may be based, at least in
part, on a property and/or parameter detected by detector 191. As
an example, and as illustrated in FIG. 15, shockwave generation
device 190A may include communication linkage 552 between
controller 550 and detector 540.
[0135] As an example, detector 540 may be configured to generate a
location signal that is indicative of the location of the shockwave
generation device 190A within the wellbore tubular 40 and to convey
the location signal to the controller 550 via the communication
linkage 552. In addition, controller 550 may be programmed to
actuate the metering device (instead of using a separate controller
150) and/or a selected one of the plurality of triggering devices
530 based, at least in part, on the location signal and/or
responsive to receipt of the location signal. Metering device 186
may displace an internal volume of the sealing component holder or
triggering device 530 then may initiate explosion of a
corresponding one of the plurality of explosive charges 520.
Detector 540 may be used alternatively or in addition to detector
191.
[0136] As another example, detector 540 may be configured to detect
a pressure pulse within the wellbore fluid, such as may be
deliberately and/or purposefully generated within the wellbore
fluid by an operator of the hydrocarbon well. Under these
conditions, detector 540 may generate a pressure pulse signal
responsive to receipt of the pressure pulse and may provide the
pressure pulse signal, via the communication linkage, to controller
550. Controller 550 then may be programmed to actuate the metering
device and/or the selected one of the plurality of triggering
devices 530 based, at least in part, on the pressure pulse signal
and/or responsive to receipt of the pressure pulse signal.
[0137] Additionally or alternatively, controller 550 may be
configured to actuate the metering device and/or the selected one
of the plurality of triggering devices responsive to receipt of an
actuation signal and/or a triggering signal. The signal may be
provided to the controller in any suitable manner. As an example,
the signal may be provided to controller 550 using downhole
wireless communication network 39, and controller 550 may be
adapted, configured, designed, constructed, and/or programmed to
receive the signal from the downhole wireless communication
network. As another example, the signal may be provided to
controller 550 using umbilical 192. Under these conditions,
controller 550 may be adapted, configured, designed, constructed,
and/or programmed to receive the signal from the umbilical, and it
is within the scope of the present disclosure that the umbilical
may be configured to provide serial communication between the
controller and surface region 30. Alternatively, the devices may be
controlled directly by the surface control system via the umbilical
and communications linkage or wireless communication network.
[0138] The shockwave generation device 190A may further include a
guide structure (not shown). The guide structure may be adapted,
configured, sized, and/or shaped to passively guide and/or direct
the shockwave generation device when the shockwave generation
device moves and/or translates within the tubular conduit. It is
understood that such guide structure may be used with a downhole
device without the shockwave generation features.
[0139] Shockwave generation device 190A may include a bridge plug
setting structure (not shown) in embodiments where the opening to
the sealing component holder is positioned at a surface location
other than the bottom surface of the shockwave generation device. A
bridge plug setting structure may be configured to set, or to
selectively set, a bridge plug within the tubular conduit. It is
understood that such plug setting structure may be used with a
downhole device without the shockwave generation features.
[0140] As also illustrated in FIG. 13, shockwave generation device
190A includes the components of the downhole device 190. Such
components are depicted in the figures with the same reference
numbers as for downhole devices 190. Sealing component holder 180
and metering device 186 may be configured to selectively release at
least one sealing component, such as a ball sealer, for each
explosive charge 520 that is associated with shockwave generation
device 190A and/or for each SSP that is opened by each explosive
charge. This may include releasing the at least one sealing
component 182 responsive to explosion of a corresponding explosive
charge 520, prior to explosion of the corresponding explosive
charge, and/or subsequent to explosion of the corresponding
explosive charge. It is intended that the description contained
herein with respect to sealing component holders, sealing
components, metering devices, and arrangements including such for
downhole device 190 may also be utilized with shockwave generation
device 190A.
[0141] As illustrated in FIG. 13, shockwave generation device 190A
may further include and/or have operatively attached thereto one or
more weights 564. Weights 564 may be configured to increase an
average density of the shockwave generation device, to increase a
weight of the shockwave generation device, and/or to regulate an
orientation of the shockwave generation device when the shockwave
generation device is present within the tubular conduit. As an
example, and as illustrated in FIG. 13, weight 564 may be oriented
off-center with respect to (parallel to) the longitudinal axis of
shockwave generation device 190A and thereby may cause the
shockwave generation device to orient within the tubular conduit in
a predetermined, or desired, manner. It is understood that such
weights may be used with a downhole device without the shockwave
generation features.
[0142] It is within the scope of the present disclosure that,
subsequent to actuation of all the explosive charges 520, shockwave
generation device 190A may be adapted, configured, designed, and/or
constructed to break apart and/or to dissolve within the tubular
conduit. As an example, shockwave generation device 190A may be
formed from a frangible material that breaks apart responsive to
explosion of a last, or final, explosive charge 520. It is
understood that a downhole device without the shockwave generation
features may be similarly constructed.
[0143] As another example, shockwave generation device 190A may be
formed from a degradable material that degrades within the wellbore
fluid. This may include degrading within a timeframe that is
shorter than a timeframe for other components of the hydrocarbon
well, such as wellbore tubular 40. As an example, the shockwave
generation device 190A may be configured to remain intact during
generation of the shockwaves and to partially degrade, completely
degrade, and/or break apart between completion of stimulation
operations that utilize the shockwave generation device and
production of reservoir fluid from the hydrocarbon well. It is
understood that a downhole device without the shockwave generation
features may be similarly constructed.
[0144] As yet another example, shockwave generation device 190A may
be formed from a soluble material that is soluble within the
wellbore fluid. This soluble material may be selected to dissolve
within a timeframe that is shorter than the timeframe for other
components of the hydrocarbon well, such as wellbore tubular 40, to
degrade and/or break apart. As an example, the shockwave generation
device may be configured to remain intact during generation of the
shockwaves and to dissolve, completely dissolve, and/or break apart
between completion of stimulation operations that utilize the
shockwave generation device and production of reservoir fluid from
the hydrocarbon well. It is understood that a downhole device
without the shockwave generation features may be similarly
constructed.
[0145] FIG. 21 is a flowchart depicting method 800, according to
the present disclosure, which includes providing sealing components
within a tubular conduit and optionally also generating a plurality
of shockwaves within a wellbore fluid that extends within the
tubular conduit, while FIGS. 22-26 are schematic cross-sectional
views of a portion of a process flow 340 for providing sealing
components and optionally generating a plurality of shockwaves 194
within a tubular conduit 40. As illustrated in process flow 340 of
FIGS. 22-26, a shockwave generation device 190A may be positioned
within a wellbore tubular 40 that defines a tubular conduit 42 and
extends within subterranean formation 34. The wellbore tubular may
include a plurality of SSPs 100 that initially may be in a closed
state. The plurality of SSPs 100 may be spaced apart along the
wellbore tubular, such as along the longitudinal length of the
wellbore tubular and/or radially around the circumference of the
wellbore tubular.
[0146] Method 800 may include pressurizing the tubular conduit by
introducing a wellbore fluid, such as a stimulant fluid, at 805 and
includes positioning a downhole device, such as a shockwave
generation device, proximal to or within a first region of the
tubular conduit radially interior of a first section of the
wellbore tubular at 810. Method 800 may further include detecting
that the downhole device is within the first region of the tubular
conduit at 815 and include actuating a first triggering device at
820. Method 800 may further include transitioning at least a first
SSP at 825, stimulating a first region of the subterranean
formation at 830, and actuating a metering device to displace a
first internal volume of a sealing component holder to discharge a
first portion of the plurality of sealing components, such as at
least one ball sealer, at 835 to seal SSPs in the open state within
the first section of the wellbore tubular. Method 800 may or may
not include repositioning the downhole device during the
stimulation of the particular region (e.g., the first region or the
second region) of the subterranean formation and/or repositioning
the downhole device for actuating the metering device to displace
an internal volume (e.g., the first internal volume or the second
internal volume) of the sealing component holder. As an example,
the downhole device may be positioned proximal to but outside of
the first region of the tubular conduit for the displacement of the
first internal volume of the sealing component holder. As an
example, the proximal positioning to the first region of the
tubular conduit may include positioning the downhole device within
an adjacent region of the tubular conduit, uphole or downhole from
the first region of the tubular conduit. It is understood the
position downhole may be achieved due to the axial location of the
sealing component holder within the downhole device relative to the
section to be sealed or the movement of the downhole device
downhole occurs with at least one section of the subterranean
formation receiving wellbore fluid.
[0147] Method 800 includes positioning the downhole device proximal
to or within a second region of the tubular conduit radially
interior of a second section of the wellbore at 840, the second
region spaced apart from the first region along the length of the
wellbore tubular. Method 800 may include repressurizing the tubular
conduit at 845 and/or detecting that the downhole device is in the
second region of the tubular conduit at 850. Method 800 may include
actuating a second triggering device at 855. Method 800 may include
transitioning at least a second SSP at 860, stimulating a second
region of the subterranean formation at 865, and actuating the
metering device to displace a second internal volume of a sealing
component holder to discharge a second portion of the plurality of
sealing components, such as at least one ball sealer, at 870 to
seal SSPs in the open state within the second section of the
wellbore tubular. Method 800 may or may not include repositioning
the downhole device during the stimulation of the second region of
the subterranean formation and/or repositioning the downhole device
for the actuation of the metering device and displacement of the
second internal volume of the sealing component holder. It is
understood that the downhole device may be positioned proximal to
but outside of the second region of the tubular conduit for the
displacement of the second internal volume of sealing component
holder. As an example, the proximal positioning to the second
region of the tubular conduit may include positioning the downhole
device within an adjacent region of the tubular conduit, uphole or
downhole from the second region of the tubular conduit. These
processes may be repeated for additional regions within the tubular
conduit and additional sections of the wellbore to seal areas of
interest.
[0148] Pressurizing the tubular conduit at 805 may include
pressurizing the tubular conduit in any suitable manner. As an
example, the pressurizing at 805 may include pressurizing with a
stimulant fluid, such as by flowing the stimulant fluid into the
tubular conduit and/or providing the stimulant fluid to the tubular
conduit. The pressurizing at 805 may be prior to the positioning at
810, concurrently with the positioning at 810, subsequent to the
positioning at 810, prior to the detecting at 815, concurrently
with the detecting at 815, subsequent to the detecting at 815,
and/or prior to the actuating at 820. The pressurizing at 805 is
illustrated in FIG. 22, wherein a stimulant fluid 70 is provided to
tubular conduit 42 of wellbore tubular 40. As also illustrated in
FIG. 22, and during the pressurizing at 805, SSPs 100 associated
with wellbore tubular 40 may be in closed state 121, thereby
permitting pressurization of the tubular conduit.
[0149] Positioning the downhole device may include positioning the
downhole device within the tubular conduit. The positioning of the
downhole device may be accomplished in any suitable manner and/or
in any suitable direction such as in the uphole direction or in the
downhole direction. As an example, the positioning may include
flowing and/or conveying the downhole device in a downhole
direction, such as downhole direction 29 of FIG. 22, within a flow
of the wellbore fluid 22, such as stimulant fluid 70.
Alternatively, the downhole device may be conveyed on jointed pipe
tubing, continuous jointless tubing or other means, such as a
wireline, and/or using a tractor. The wellbore fluid 22 may also
include fracturing fluid with insubstantial amounts of proppant
fluid (clean fracturing fluid). The clean fracturing fluid may
follow a proppant-laden wellbore fluid to displace the
proppant-laden fluid into the subterranean formation. As another
example, the positioning may include positioning with an umbilical,
such as a wireline, as illustrated in FIG. 22 at 192. As yet
another example, the positioning may include autonomously
positioning the downhole device. As another example, the
positioning may include landing, resting, stopping, and/or
receiving the downhole device on and/or with any suitable latch,
catch, receiver, and/or platform that may form a portion of the
wellbore tubular and/or of the SSP, and/or that may extend within
the tubular conduit. FIG. 22 illustrates positioning the downhole
device 190A within a first region 105 of the tubular conduit 42
radially interior of a first section 40A of the wellbore tubular
40.
[0150] Detecting the location of the downhole device may include
detecting in any suitable manner. As an example, the detecting may
include detecting via and/or utilizing a detector, as discussed in
more detail herein. The detecting may include one or more of
detecting a casing collar of the wellbore tubular, detecting a
component associated with the wellbore tubular that has the
potential to disturb magnetic lines of flux, detecting a velocity
of the shockwave generation device within the wellbore tubular,
detecting a residence time of the shockwave generation device
within the wellbore tubular, detecting a distance of flow of the
shockwave generation device along the length of the wellbore
tubular, detecting a depth of the shockwave generation device
within the wellbore tubular, detecting a magnetic material that
forms a portion of the wellbore tubular and/or SSP, and/or
detecting a radioactive material that forms a portion of the
wellbore tubular and/or SSP.
[0151] Actuating at 820 may include actuating the first triggering
device to initiate explosion of a first explosive charge of a
plurality of explosive charges of the downhole device. The
actuating of the first triggering device may include actuating to
generate a first shockwave within the first region of the tubular
conduit. This is illustrated in FIG. 23, where a shockwave 194 is
illustrated within first region 105 of tubular conduit 42.
[0152] The actuating at 820 may include actuating responsive to any
suitable criteria. As an example, the actuating at 820 may be
initiated responsive to the detecting the position of the downhole
device (i.e., responsive to detecting that the downhole device is
within the first region of the tubular conduit). As another
example, the actuating at 820 may include actuating subsequent to
the positioning in a region of the tubular conduit and/or
responsive to completion of the positioning within the tubular
conduit. The actuating at 820 may include electrically actuating,
mechanically actuating, chemically actuating, wirelessly actuating,
and/or actuating responsive to receipt of a pressure pulse.
[0153] Transitioning the first SSP at 825 may include transitioning
one or more first SSPs from respective closed states to respective
open states responsive to receipt of the first shockwave with
greater than the threshold shockwave intensity by the one or more
first SSPs. This is illustrated in FIG. 23, with SSPs 100 that are
present within first region 105 of tubular conduit 42 being
transitioned to open state 122 responsive to receipt of shockwave
194. As also illustrated in FIG. 23, the transitioning at 825 may
further include transitioning the SSPs 100 to open state 122 while
maintaining one or more SSPs 100 that are uphole from the first SSP
in respective closed states 121. The first SSPs and the second SSPs
also may be referred to herein as being spaced-apart, or
longitudinally spaced-apart, along a length of the wellbore
tubular, and this selective transitioning of the SSPs within the
first region 105 of the tubular conduit 42 and not the other SSPs
may be due to the limited, or maximum, effective distance, or
propagation distance, of the shockwave within a wellbore fluid 22
that extends within tubular conduit 42, as is discussed herein.
Examples of the maximum effective distance of the shockwave are
disclosed herein, and the one or more closed SSPs may be
spaced-apart from the downhole device by greater than the maximum
effective distance of the shockwave.
[0154] Stimulating the first region of the subterranean formation
at 830 may include stimulating any suitable first region of the
subterranean formation that may be proximal to and/or associated
with the first region of the tubular conduit. The stimulating at
830 may include stimulating responsive to, or directly responsive
to, the actuating at 820 and/or the transitioning at 825. As an
example, and as illustrated in FIG. 23, transitioning the one or
more first SSPs 100 to open state 122 may permit stimulant fluid 70
to flow from tubular conduit 42 and into subterranean formation 34,
thereby permitting stimulation of the subterranean formation.
[0155] Actuating the metering device at 835 includes actuating the
metering device to displace a first internal volume of a sealing
component holder to discharge a first portion of the plurality of
sealing components, such as at least one ball sealer, to seal SSPs
in the open state within the first region of the tubular conduit.
Actuating at 835 may include releasing the first portion of the
plurality of sealing components from the downhole device and
flowing the first portion of the plurality of sealing components,
via the tubular conduit, to and/or into engagement with the one or
more first SSPs. As illustrated in FIG. 24, sealing components 182
have been released into tubular conduit 42. As illustrated in FIG.
25, engagement between the first portion of the plurality of
sealing components 182 and the one or more first SSPs 100 in the
first region 105 of the tubular conduit 42 within the first section
40A of the wellbore tubular 40 may restrict fluid flow 70 from the
tubular conduit 42 via the one or more first SSPs 100.
[0156] It is within the scope of the present disclosure that the
actuating at 835 may include actuating the metering device in any
suitable manner. As examples, the actuating at 835 may include
electrically actuating, mechanically actuating, and/or wirelessly
actuating.
[0157] This is illustrated in FIGS. 24-25. In FIG. 24, sealing
components 182 in the form of ball sealers are depicted as flowing
within a flow of stimulant fluid 70 in downhole direction 29 within
tubular conduit 42. In FIG. 25, the ball sealers 182 have engaged
with the one or more first SSPs 100 that are present within first
region 105 of the tubular conduit and restrict fluid flow there
through. The actuating at 835 may be performed with any suitable
timing and/or sequence within method 800 to deliver the first
portion of the plurality of sealing components to the one or more
first SSPs 100 in the open state within first region 105 of tubular
conduit 42.
[0158] Positioning the downhole device at 840 may include moving
the downhole device to a second region of the tubular conduit that
is spaced-apart from the first region of the tubular conduit. The
positioning at 840 may be accomplished in any suitable manner and
may be performed similarly, or at least substantially similarly, to
the positioning at 810. As illustrated in the transition from FIG.
23 to FIG. 24, the positioning at 840 may include moving downhole
device 190A in an uphole direction 28 such that the downhole device
is within a second region 107 of tubular conduit 42 radially
interior of second section 40B of wellbore tubular 40.
[0159] Repressurizing the tubular conduit at 845 may include
repressurizing with the stimulant fluid 70. The repressurizing at
845 may be performed at least substantially similar to the
pressurizing at 805. When the pressurizing at 805 includes flowing
and/or providing the stimulant fluid to the tubular conduit, the
flowing and/or providing may be performed continuously, or at least
substantially continuously, during a remainder of method 800. Under
these conditions, the repressurizing at 845 may be responsive to,
or a result of, operative sealing engagement between the first
portion of the plurality of sealing components and the one or more
first SSPs, as accomplished during the actuating at 835.
[0160] The repressurizing at 845 may be performed with any suitable
timing and/or sequence within method 800. As examples, the
repressurizing at 845 may be performed subsequent to the actuating
at 835 and prior to the actuating at 855.
[0161] Detecting that the downhole device is in the second region
of the tubular conduit at 850 may include detecting in any suitable
manner. As an example, the detecting at 850 may be similar, or at
least substantially similar, to the detecting at 815.
[0162] Actuating the second triggering device at 855 may include
actuating to initiate explosion of a second explosive charge and/or
to generate a second shockwave within the second region of the
tubular conduit. The actuating at 855 may be performed in any
suitable manner and may be similar, or at least substantially
similar, to the actuating at 820 and may be responsive, or at least
partially responsive, to the detecting at 850. The actuating at 855
is illustrated in FIG. 26. Therein, downhole device 190A is present
within second region 107 of tubular conduit 42 and has initiated
explosion of a second explosive charge to generate a second
shockwave 194 within wellbore fluid 22 that extends within the
tubular conduit 42.
[0163] Transitioning the second SSP at 860 may include
transitioning one or more second SSPs from respective closed states
to respective open states responsive to receipt of the second
shockwave with greater than the threshold shockwave intensity by
the one or more second SSPs. In general, the transitioning at 860
may be similar, or at least substantially similar, to the
transitioning at 825, which is discussed herein. The transitioning
at 860 is illustrated in FIG. 26. Therein, one or more second SSPs
100 that are present within second portion 107 of tubular conduit
42 are transitioned to respective open states 122 responsive to
receipt of shockwave 194.
[0164] Stimulating the second region of the subterranean formation
at 865 may include stimulating any suitable second region of the
subterranean formation that is proximal to and/or associated with
the second region of the tubular conduit. The stimulating at 865
may be at least substantially similar to the stimulating at 830 and
may be responsive to, or directly responsive to, the actuating at
855 and/or the transitioning at 860. The stimulating at 865
includes flowing stimulant fluid 70 from tubular conduit 42 into
subterranean formation 34 via the one or more second SSPs 100 that
are present within second region 107 of the tubular conduit 42.
[0165] The stimulating at 865 may be performed with any suitable
timing and/or sequence within method 800. As examples, the
stimulating at 865 may be performed subsequent to the actuating at
835, subsequent to the positioning at 840 and may or may not
include repositioning the downhole device uphole or downhole from
the second region prior to stimulating at 865, subsequent to the
repressurizing at 845, subsequent to the detecting at 850, and/or
prior to the actuating at 870.
[0166] Actuating the metering device at 870 may be similar, or at
least substantially similar, to the actuating at 835, which is
discussed herein. The actuating at 870 includes releasing the
second portion of the plurality of sealing components from the
downhole device and flowing the second portion of the plurality of
sealing components, via the tubular conduit, to and/or into
engagement with the one or more second SSPs. Engagement between the
second portion of the plurality of sealing components and the one
or more second SSPs may restrict fluid flow from the tubular
conduit via the one or more second SSPs. This is illustrated in
FIGS. 27-28. In FIG. 27, sealing components 182 in the form of ball
sealers are depicted as flowing within a flow of stimulant fluid 70
in downhole direction 29 within tubular conduit 42 from the
downhole device 190A positioned within a third region 111 of the
tubular conduit 42 within a third section (shown as 40C in FIG. 28)
of the wellbore tubular 40. In FIG. 28, the ball sealers 182 have
engaged with the one or more first SSPs 100 that are present within
second region 107 of the tubular conduit and restrict fluid flow
there through. The actuating at 870 may be performed with any
suitable timing and/or sequence within method 800 to deliver the
second portion of the plurality of sealing components to the one or
more first SSPs 100 in the open state within second region 107 of
tubular conduit 42 within second section 40B of the wellbore
tubular 40.
[0167] The actuating at 870 may be performed with any suitable
timing and/or sequence within method 800. As an example, the
actuating at 870 may be performed subsequent to the positioning at
840 and may or may not include repositioning the downhole device
proximal to or within the second region prior to actuating at 870,
subsequent to the repressurizing at 845, subsequent to the
detecting at 850, subsequent to the actuating at 855, subsequent to
the transitioning at 860, and/or subsequent to the stimulating at
865.
[0168] It is understood that the methods for providing sealing
components within a hydrocarbon well may be used in connection with
fracturing applications and/or re-fracturing applications using a
perforation gun. FIG. 29 is a flowchart depicting method 900,
according to the present disclosure, of providing sealing
components within a hydrocarbon well to be re-fractured. It is
understood that the process with respect to re-fracturing the
wellbore tubular may additionally or alternatively be used in the
original fracturing of the wellbore tubular. Method 900 may include
identifying an area of interest within the hydrocarbon well to be
re-fractured at 910. The hydrocarbon well to be re-fractured may be
a well previously perforated at spaced-apart intervals along the
length of the wellbore tubular within the area of interest for
re-fracturing. It is understood that the refracturing method may
also be used with respect to a wellbore with SSPs in both the
opened and closed state at spaced-apart intervals along the length
of the wellbore tubular within the area of interest for
re-fracturing. The opened SSPs to be sealed with sealing components
and the closed SSPs to be opened for re-fracturing operations.
[0169] Method 900 includes positioning the downhole device proximal
to or within a first region within the tubular conduit radially
interior of a first section of the wellbore tubular at 920. Method
900 includes actuating the metering device at 930 to displace a
first internal volume of the sealing component holder to discharge
a first portion of the plurality of sealing components through the
opening of the sealing component holder into the tubular conduit to
sealing engage with the previous perforations within the first
section of the wellbore tubular. Method 900 includes positioning
the downhole device proximal to or within a second region within
the tubular conduit radially interior of a second section of the
wellbore tubular at 940. Method 900 includes actuating the metering
device at 950 to displace a second internal volume of the sealing
component holder to discharge a second portion of the plurality of
sealing components through the opening of the sealing component
holder into the tubular conduit to sealing engage with the previous
perforations within the second section of the wellbore tubular.
[0170] Method 900 may further include pressurizing the tubular
conduit with a wellbore fluid at 915 and at 935; detecting that the
downhole device is proximal to or within a first region of the
tubular conduit at 925 or a second region of the tubular conduit at
945; repeating the process of sealing the previous perforations
(e.g., 910-950) within additional sections of the wellbore tubular
until the previous perforations within the area of interest for
re-fracturing have been sealed with the sealing components at
955.
[0171] Once the previous perforations within the area of interest
for re-fracturing have been sealed with the sealing components,
method 900 may include positioning a perforation gun within a
region of the tubular conduit radially interior of an unperforated
section of the wellbore tubular within the area of interest for
re-fracturing at 960; positioning the downhole device within the
tubular conduit or removing the downhole device from the tubular
conduit such that detonation of the perforation gun does not
significantly damage the downhole device at 965; detonating the
perforation gun to form new perforations within the wellbore
tubular at 970; positioning the downhole device proximal to or
within the region of the tubular conduit radially interior of the
newly perforated section of the wellbore tubular (a first newly
perforated section) at 975; displacing an additional internal
volume of the sealing component holder of the downhole device to
discharge an additional portion of the plurality of sealing
components from within an additional region of the sealing
component holder through the opening of the sealing component
holder to seal the new perforations within the newly perforated
section of the wellbore tubular (first newly perforated section) at
980; and repeating the perforation process for re-fracturing (e.g.,
960-980) until the re-fracturing of the wellbore tubular within the
area of interest has been completed at 985. FIG. 30 illustrates a
configuration for re-fracturing using the perforation gun 162
(depicted after detonation showing damage) to provide new
perforations 163 within region 161 of the tubular conduit 42
radially interior of the newly perforated section 40D of the
wellbore tubular 40 with the downhole device 190 positioned uphole
of the perforation gun 162. Sealing components 182 are shown within
the previously formed perforations. Although not depicted,
alternatively the downhole device 190 may be integral with the
perforation gun 162 forming a single device having the downhole
device 190 section positioned on top of the perforation gun 162
section. The opening to the sealing component holder may be located
in the side or top of the device. This embodiment allows a single
unit to be utilized with perforation operations.
[0172] As an example, sealing the previous perforations during
re-fracturing a hydrocarbon well may include using a sealing
component holder including at least a first plurality of degradable
sealing components within a first region of the sealing component
holder occupying the first internal volume and a second plurality
of degradable sealing components within a second region of the
sealing component holder occupying the second internal volume. The
sealing component holder may have additional regions occupying
additional internal volumes of the sealing component holder and
including additional pluralities of degradable sealing components.
The first plurality of sealing components, the second plurality of
sealing components, and any additional pluralities of sealing
components may have different degradation rates. As an example, the
first region proximal the opening of the sealing component holder
contains a first plurality of degradable sealing components with
the greatest rate of degradation and the region within the sealing
component holder furtherest from the opening contains a plurality
of degradable sealing components with the lesser rate of
degradation. As an example, the first plurality of degradable
sealing components may have a different rate of degradation than
the second plurality of degradable sealing components.
[0173] It is understood that the methods for providing sealing
components within a well may be used within an injection well used
in connection with hydrocarbon production. An injection well may be
used to assist in sustaining formation pressure within the
reservoir and provide fluid to sweep the subterranean formation and
push hydrocarbons within the reservoir (reservoir fluid) towards a
neighboring hydrocarbon production well. FIG. 31 is a flowchart
depicting method 1100, according to the present disclosure, of
providing sealing components within an injection well to
temporarily seal portions of the subterranean formation to divert
the wellbore fluid within the injection well to other areas within
the well and surrounding subterranean formation. Method 1100 may
include identifying sections of an injection well for which a
wellbore fluid, such as an injection fluid may be diverted to one
or more other sections of such well at 1110. The injection fluid
may be predominantly water, predominantly carbon dioxide, as well
as other suitable fluids. As an example, the identified injection
well may include at least two sections of the wellbore tubular that
are ineffectively providing injection fluid into the subterranean
formation to provide pressure. Each of the at least two sections
are spaced apart from each other along the length of the wellbore
tubular. Such sections may be identified using core samples,
tracers, and/or production logs to determine where the injection
fluid is exiting the wellbore such that the injection fluid is well
swept and ineffective in providing pressure to the reservoir.
Associated with each section of the wellbore tubular is a radially
interior region within the conduit, such as a first region within
the tubular conduit associated with the first section of the
wellbore tubular and a second region within the tubular conduit
associated with the second section of the wellbore tubular. The
injection well also includes at least a third region within the
tubular conduit associated with the third section of the wellbore
tubular. Each section of the wellbore tubular is also associated
with a radially exterior region of the subterranean formation.
[0174] Method 1100 includes positioning the downhole device
proximal to or within a region (e.g., the first region or the
second region) of the tubular conduit at 1105 and providing a first
portion of the plurality of sealing components, such as chemical
diverters or ball sealers, into the tubular conduit of the wellbore
tubular, and sealing the subterranean formation proximate the
section with chemical diverters or openings within the wellbore
tubular with ball sealers at 1120. The sealing includes actuating a
metering device to displace a first internal volume of the sealing
component holder to discharge a first portion of the plurality of
sealing components, such as chemical diverters or ball sealers,
through the opening within the sealing component holder into the
tubular conduit. Method 1100 includes positioning the downhole
device proximal to or within another region of the tubular conduit
at 1125 and sealing another of the sections (e.g., other of the
first region or the second region not yet sealed) of the wellbore
tubular with a second portion or the plurality of sealing
components as 1130. Additional ineffective sections of the
injection well may be identified and provided additional portions
of the plurality of sealing components to divert the injection
fluid into other sections not taking in sufficient injection fluid
to strategically increase the pressure within the reservoir and
maintain production.
[0175] FIG. 32 illustrates an injection well 11. The wellbore
tubular 40 includes a first section 40A of the wellbore tubular 40,
a second section 40B of the wellbore tubular 40, and a third
section 40C of the wellbore tubular 40. A first region 105 within
the tubular conduit 42 is radially interior of the first section
40A of the wellbore tubular 40, a second region 107 within the
tubular conduit 42 is radially interior of the second section 40B
of the wellbore tubular 40, and a third region 111 within the
tubular conduit 42 is radially interior of the third section 40C of
the wellbore tubular 40. The first section 40A, the second section
40B, and the third section 40C of the wellbore tubular 40 contain
perforations 163. Downhole device 190 is positioned within the
tubular conduit 42 proximate the second region 107 of the tubular
conduit 42 proximal the first section 40A of the wellbore tubular
40 and used to seal off the subterranean formation 34 proximate the
first section 40A of the wellbore tubular 40 from the tubular
conduit 42 and the injection fluid.
[0176] 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 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. It is also within the scope of
the present disclosure that the blocks, or steps, may be
implemented as logic, which also may be described as implementing
the blocks, or steps, as logics. In some applications, the blocks,
or steps, may represent expressions and/or actions to be performed
by functionally equivalent circuits or other logic devices. The
illustrated blocks may, but are not required to, represent
executable instructions that cause a computer, processor, and/or
other logic device to respond, to perform an action, to change
states, to generate an output or display, and/or to make
decisions.
[0177] 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 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.
[0178] 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 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.
[0179] In the event that any patents, patent applications, or other
references are incorporated by reference herein and (1) define a
term in a manner that is inconsistent with and/or (2) are otherwise
inconsistent with, either the non-incorporated portion of the
present disclosure or any of the other incorporated references, the
non-incorporated portion of the present disclosure shall control,
and the term or incorporated disclosure therein shall only control
with respect to the reference in which the term is defined and/or
the incorporated disclosure was present originally.
[0180] 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.
[0181] 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
[0182] The downhole devices, wells, and methods disclosed herein
are applicable to the oil and gas industry.
[0183] 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 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.
[0184] 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.
* * * * *