Note: Descriptions are shown in the official language in which they were submitted.
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PLUGGING DEVICES AND DEPLOYMENT
IN SUBTERRANEAN WELLS
TECHNICAL FIELD
This disclosure relates generally to equipment utilized
and operations performed in conjunction with a subterranean
well and, in one example described below, more particularly
provides for plugging devices and their deployment in wells.
BACKGROUND
It can be beneficial to be able to control how and
where fluid flows in a well. For example, it may be
desirable in some circumstances to be able to prevent fluid
from flowing into a particular formation zone. As another
example, it may be desirable in some circumstances to cause
fluid to flow into a particular formation zone, instead of
into another formation zone. As yet another example, it may
be desirable to temporarily prevent fluid from flowing
through a passage of a well tool. Therefore, it will be
readily appreciated that improvements are continually needed
in the art of controlling fluid flow in wells.
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SUMMARY
In one embodiment, there is described a method of
plugging an opening in a subterranean well, the method
comprising: deploying a plugging device into the well, the
plugging device including at least two bodies, and a washer
element connected between the bodies, the washer element being
generally disk-shaped and comprising a hole, a line extending
through the hole and connected to the bodies on respective
opposite sides of the washer element; and conveying the
plugging device by fluid flow into engagement with the
opening, the washer element preventing the plugging device
from being conveyed through the opening, and the washer
element blocking the fluid flow through the opening.
In another embodiment, there is described a method of
plugging an opening in a subterranean well, the method
comprising: deploying a plugging device into the well, the
plugging device including a body, and an outer material
enveloping the body, wherein the outer material comprises one
of the group consisting of a wrapper and a bag, and wherein
the one of the group consisting of the wrapper and the bag is
formed of one of the group consisting of a fabric, a mesh, a
net and a gauze; and conveying the plugging device by fluid
flow into engagement with the opening, the body preventing the
plugging device from extruding through the opening, and the
outer material blocking the fluid flow between the body and
the opening.
Date Recue/Date Received 2021-02-24
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In another embodiment, there is described a method of
completing a well, the method comprising: conveying a bottom
hole assembly into the well on a conveyance, the bottom hole
assembly comprising at least one perforator; forming first
perforations in the well with the perforator; then displacing
the bottom hole assembly further into the well, thereby
extending the conveyance longitudinally across the first
perforations; then flowing a stimulation fluid into the first
perforations; plugging the first perforations; then displacing
the bottom hole assembly to a desired position in the well;
then forming second perforations at the desired position; and
flowing the stimulation fluid into the second perforations
without positioning a packer between the first and second
perforations.
In another embodiment, there is described a method of
completing a well, the method comprising: conveying the bottom
hole assembly into the well with a conveyance, wherein the
conveying comprises displacing the bottom hole assembly by
fluid flow through the well; perforating a first zone with a
perforator of a bottom hole assembly in the well; fracturing
the first zone; perforating a second zone; and fracturing the
second zone, wherein the first zone perforating, the first
zone fracturing, the second zone perforating and the second
zone fracturing are performed without withdrawing the bottom
hole assembly from the well.
Date Recue/Date Received 2021-02-24
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BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a representative partially cross-sectional
view of an example of a well system and associated method
which can embody principles of this disclosure.
FIGS. 2A-D are enlarged scale representative partially
cross-sectional views of steps in an example of a re-
completion method that may be practiced with the system of
FIG. 1.
FIGS. 3A-D are representative partially cross-sectional
views of steps in another example of a method that may be
practiced with the system of FIG. 1.
FIGS. 4A & B are enlarged scale representative
elevational views of examples of a flow conveyed device that
may be used in the system and methods of FIGS. 1-3D, and
which can embody the principles of this disclosure.
FIG. 5 is a representative elevational view of another
example of the flow conveyed device.
FIGS. 6A & B are representative partially cross-
sectional views of the flow conveyed device in a well, the
device being conveyed by flow in FIG. 6A, and engaging a
casing opening in FIG. 6B.
FIGS. 7-9 are representative elevational views of
examples of the flow conveyed device with a retainer.
FIG. 10 is a representative cross-sectional view of an
example of a deployment apparatus and method that can embody
the principles of this disclosure.
FIG. 11 is a representative schematic view of another
example of a deployment apparatus and method that can embody
the principles of this disclosure.
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FIGS. 12 & 13 are representative cross-sectional views
of additional examples of the flow conveyed device.
FIG. 14 is a representative cross-sectional view of a
well tool that may be operated using the flow conveyed
device.
FIG. 15 is a representative partially cross-sectional
view of a plugging device dispensing system that can embody
the principles of this disclosure.
FIGS. 16A-42B are representative views of examples of
dispensing tools that may be used with the dispensing system
of FIG. 15.
FIGS. 43 & 44 are representative views of additional
plugging device embodiments having a relatively strong
central member surrounded by a relatively low density
material.
FIG. 45 is a representative view of another plugging
device embodiment.
FIG. 46 is a representative view of yet another
plugging device embodiment.
FIGS. 47-49 are representative partially cross-
sectional views of another example of the system and method
that can embody the principles of this disclosure.
DETAILED DESCRIPTION
Representatively illustrated in FIG. 1 is a system 10
for use with a well, and an associated method, which can
embody principles of this disclosure. However, it should be
clearly understood that the system 10 and method are merely
one example of an application of the principles of this
disclosure in practice, and a wide variety of other examples
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are possible. Therefore, the scope of this disclosure is not
limited at all to the details of the system 10 and method
described herein and/or depicted in the drawings.
In the FIG. 1 example, a tubular string 12 is conveyed
into a wellbore 14 lined with casing 16 and cement 18.
Although multiple casing strings would typically be used in
actual practice, for clarity of illustration only one casing
string 16 is depicted in the drawings.
Although the wellbore 14 is illustrated as being
vertical, sections of the wellbore could instead be
horizontal or otherwise inclined relative to vertical.
Although the wellbore 14 is completely cased and cemented as
depicted in FIG. 1, any sections of the wellbore in which
operations described in more detail below are performed
could be uncased or open hole. Thus, the scope of this
disclosure is not limited to any particular details of the
system 10 and method.
The tubular string 12 of FIG. 1 comprises coiled tubing
and a bottom hole assembly 22. As used herein, the term
20 "coiled tubing" refers to a substantially continuous tubing
that is stored on a spool or reel 24. The reel 24 could be
mounted, for example, on a skid, a trailer, a floating
vessel, a vehicle, etc., for transport to a wellsite.
Although not shown in FIG. 1, a control room or cab would
typically be provided with instrumentation, computers,
controllers, recorders, etc., for controlling equipment such
as an injector 26 and a blowout preventer stack 28.
As used herein, the term "bottom hole assembly" refers
to an assembly connected at a distal end of a tubular string
in a well. It is not necessary for a bottom hole assembly to
be positioned or used at a "bottom" of a hole or well.
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When the tubular string 12 is positioned in the
wellbore 14, an annulus 30 is formed radially between them.
Fluid, slurries, etc., can be flowed from surface into the
annulus 30 via, for example, a casing valve 32. One or more
pumps 34 may be used for this purpose. Fluid can also be
flowed to surface from the wellbore 14 via the annulus 30
and valve 32.
Fluid, slurries, etc., can also be flowed from surface
into the wellbore 14 via the tubing 20, for example, using
one or more pumps 36. Fluid can also be flowed to surface
from the wellbore 14 via the tubing 20.
In the further description below of the examples of
FIGS. 2A-14, one or more flow conveyed devices are used to
block or plug openings in the system 10 of FIG. 1. However,
it should be clearly understood that these methods and the
flow conveyed device may be used with other systems, and the
flow conveyed device may be used in other methods in keeping
with the principles of this disclosure.
The example methods described below allow existing
fluid passageways to be blocked permanently or temporarily
in a variety of different applications. Certain flow
conveyed device examples described below are made of a
fibrous material and may comprise a central body, a "knot"
or other enlarged geometry.
The devices may be conveyed into the passageways or
leak paths using pumped fluid. Fibrous material extending
outwardly from a body of a device can "find" and follow the
fluid flow, pulling the enlarged geometry or fibers into a
restricted portion of a flow path, causing the enlarged
geometry and additional strands to become tightly wedged
into the flow path, thereby sealing off fluid communication.
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The devices can be made of degradable or non-degradable
materials. The degradable materials can be either self-
degrading, or can require degrading treatments, such as, by
exposing the materials to certain acids, certain base
compositions, certain chemicals, certain types of radiation
(e.g., electromagnetic or "nuclear"), or elevated
temperature. The exposure can be performed at a desired time
using a form of well intervention, such as, by spotting or
circulating a fluid in the well so that the material is
exposed to the fluid.
In some examples, the material can be an acid
degradable material (e.g., nylon, etc.), a mix of acid
degradable material (for example, nylon fibers mixed with
particulate such as calcium carbonate), self-degrading
material (e.g., poly-lactic acid (PLA), poly-glycolic acid
(PGA), etc.), material that degrades by galvanic action
(such as, magnesium alloys, aluminum alloys, etc.), a
combination of different self-degrading materials, or a
combination of self-degrading and non-self-degrading
materials.
Multiple materials can be pumped together or
separately. For example, nylon and calcium carbonate could
be pumped as a mixture, or the nylon could be pumped first
to initiate a seal, followed by calcium carbonate to enhance
the seal.
In certain examples described below, the device can be
made of knotted fibrous materials. Multiple knots can be
used with any number of loose ends. The ends can be frayed
or un-frayed. The fibrous material can be rope, fabric,
metal wool, cloth or another woven or braided structure.
The device can be used to block open sleeve valves,
perforations or any leak paths in a well (such as, leaking
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connections in casing, corrosion holes, etc . ) . Any opening
or passageway through which fluid flows can be blocked with
a suitably configured device. For example, an intentionally
or inadvertently opened rupture disk, or another opening in
a well tool, could be plugged using the device.
In one example method described below, a well with an
existing perforated zone can be re-completed. Devices
(either degradable or non-degradable) are conveyed by flow
to plug all existing perforations.
The well can then be re-completed using any desired
completion technique. If the devices are degradable, a
degrading treatment can then be placed in the well to open
up the plugged perforations (if desired).
In another example method described below, multiple
formation zones can be perforated and fractured (or
otherwise stimulated, such as, by acidizing) in a single
trip of the bottom hole assembly 22 into the well. In the
method, one zone is perforated, the zone is stimulated, and
then the perforated zone is plugged using one or more
devices.
These steps are repeated for each additional zone,
except that a last zone may not be plugged. All of the
plugged zones are eventually unplugged by waiting a certain
period of time (if the devices are self-degrading), by
applying an appropriate degrading treatment, or by
mechanically removing the devices.
Referring specifically now to FIGS. 2A-D, steps in an
example of a method in which the bottom hole assembly 22 of
FIG. 1 can be used in re-completing a well are
representatively illustrated. In this method (see FIG. 2A),
the well has existing perforations 38 that provide for fluid
communication between an earth formation zone 40 and an
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interior of the casing 16. However, it is desired to re-
complete the zone 40, in order to enhance the fluid
communication.
Referring additionally now to FIG. 2B, the perforations
38 are plugged, thereby preventing flow through the
perforations into the zone 40. Plugs 42 in the perforations
can be flow conveyed devices, as described more fully below.
In that case, the plugs 42 can be conveyed through the
casing 16 and into engagement with the perforations 38 by
fluid flow 44.
Referring additionally now to FIG. 2C, new perforations
46 are formed through the casing 16 and cement 18 by use of
an abrasive jet perforator 48. In this example, the bottom
hole assembly 22 includes the perforator 48 and a
circulating valve assembly 50. Although the new perforations
46 are depicted as being formed above the existing
perforations 38, the new perforations could be formed in any
location in keeping with the principles of this disclosure.
Note that other means of providing perforations 46 may
be used in other examples. Explosive perforators, drills,
etc., may be used if desired. The scope of this disclosure
is not limited to any particular perforating means, or to
use with perforating at all.
The circulating valve assembly 50 controls flow between
the coiled tubing 20 and the perforator 48, and controls
flow between the annulus 30 and an interior of the tubular
string 12. Instead of conveying the plugs 42 into the well
via flow 44 through the interior of the casing 16 (see FIG.
2B), in other examples the plugs could be deployed into the
tubular string 12 and conveyed by fluid flow 52 through the
tubular string prior to the perforating operation. In that
case, a valve 54 of the circulating valve assembly 50 could
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be opened to allow the plugs 42 to exit the tubular string
12 and flow into the interior of the casing 16 external to
the tubular string.
Referring additionally now to FIG. 2D, the zone 40 has
been fractured by applying increased pressure to the zone
after the perforating operation. Enhanced fluid
communication is now permitted between the zone 40 and the
interior of the casing 16.
Note that fracturing is not necessary in keeping with
the principles of this disclosure. A zone could be
stimulated (for example, by acidizing) with or without
fracturing. Thus, although fracturing is described for
certain examples, it should be understood that other types
of stimulation treatments, in addition to or instead of
fracturing, could be performed.
In the FIG. 2D example, the plugs 42 prevent the
pressure applied to fracture the zone 40 via the
perforations 46 from leaking into the zone via the
perforations 38. The plugs 42 may remain in the perforations
38 and continue to prevent flow through the perforations, or
the plugs may degrade, if desired, so that flow is
eventually permitted through the perforations.
In other examples, fractures may be formed via the
existing perforations 38, and no new perforations may be
formed. In one technique, pressure may be applied in the
casing 16 (e.g., using the pump 34), thereby initially
fracturing the zone 40 via some of the perforations 38 that
receive most of the fluid flow 44. After the initial
fracturing of the zone 40, and while the fluid is flowed
through the casing 16, plugs 42 can be released into the
casing, so that the plugs seal off those perforations 38
that are receiving most of the fluid flow.
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In this way, the fluid 44 will be diverted to other
perforations 38, so that the zone 40 will also be fractured
via those other perforations 38. The plugs 42 can be
released into the casing 16 continuously or periodically as
the fracturing operation progresses, so that the plugs
gradually seal off all, or most, of the perforations 38 as
the zone 40 is fractured via the perforations. That is, at
each point in the fracturing operation, the plugs 42 will
seal off those perforations 38 through which most of the
fluid flow 44 passes, which are the perforations via which
the zone 40 has been fractured.
Referring additionally now to FIGS. 3A-D, steps in
another example of a method in which the bottom hole
assembly 22 of FIG. 1 can be used in completing multiple
zones 40a-c of a well are representatively illustrated. The
multiple zones 40a-c are each perforated and fractured
during a single trip of the tubular string 12 into the well.
In FIG. 3A, the tubular string 12 has been deployed
into the casing 16, and has been positioned so that the
perforator 48 is at the first zone 40a to be completed. The
perforator 48 is then used to form perforations 46a through
the casing 16 and cement 18, and into the zone 40a.
In FIG. 3B, the zone 40a has been fractured by applying
increased pressure to the zone via the perforations 46a. The
fracturing pressure may be applied, for example, via the
annulus 30 from the surface (e.g., using the pump 34 of FIG.
1), or via the tubular string 12 (e.g., using the pump 36 of
FIG. 1). The scope of this disclosure is not limited to any
particular fracturing means or technique, or to the use of
fracturing at all.
After fracturing of the zone 40a, the perforations 46a
are plugged by deploying plugs 42a into the well and
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conveying them by fluid flow into sealing engagement with
the perforations. The plugs 42a may be conveyed by flow 44
through the casing 16 (e.g., as in FIG. 2B), or by flow 52
through the tubular string 12 (e.g., as in FIG. 2C).
The tubular string 12 is repositioned in the casing 16,
so that the perforator 48 is now located at the next zone
40b to be completed. The perforator 48 is then used to form
perforations 46b through the casing 16 and cement 18, and
into the zone 40b. The tubular string 12 may be repositioned
before or after the plugs 42a are deployed into the well.
In FIG. 3C, the zone 40b has been fractured by applying
increased pressure to the zone via the perforations 46b. The
fracturing pressure may be applied, for example, via the
annulus 30 from the surface (e.g., using the pump 34 of FIG.
1), or via the tubular string 12 (e.g., using the pump 36 of
FIG. 1).
After fracturing of the zone 40b, the perforations 46b
are plugged by deploying plugs 42b into the well and
conveying them by fluid flow into sealing engagement with
the perforations. The plugs 42b may be conveyed by flow 44
through the casing 16, or by flow 52 through the tubular
string 12.
The tubular string 12 is repositioned in the casing 16,
so that the perforator 48 is now located at the next zone
40c to be completed. The perforator 48 is then used to form
perforations 46c through the casing 16 and cement 18, and
into the zone 40c. The tubular string 12 may be repositioned
before or after the plugs 42b are deployed into the well.
In FIG. 3D, the zone 40c has been fractured by applying
increased pressure to the zone via the perforations 46c. The
fracturing pressure may be applied, for example, via the
annulus 30 from the surface (e.g., using the pump 34 of FIG.
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1), or via the tubular string 12 (e.g., using the pump 36 of
FIG. 1).
The plugs 42a,b are then degraded and no longer prevent
flow through the perforations 46a,b. Thus, as depicted in
FIG. 3D, flow is permitted between the interior of the
casing 16 and each of the zones 40a-c.
The plugs 42a,b may be degraded in any manner. The
plugs 42a,b may degrade in response to application of a
degrading treatment, in response to passage of a certain
period of time, or in response to exposure to elevated
downhole temperature. The degrading treatment could include
exposing the plugs 42a,b to a particular type of radiation,
such as electromagnetic radiation (e.g., light having a
certain wavelength or range of wavelengths, gamma rays,
etc.) or "nuclear" particles (e.g., gamma, beta, alpha or
neutron).
The plugs 42a,b may degrade by galvanic action or by
dissolving. The plugs 42a,b may degrade in response to
exposure to a particular fluid, either naturally occurring
in the well (such as water or hydrocarbon fluid), or
introduced therein (such as a fluid having a particular pH).
Note that any number of zones may be completed in any
order in keeping with the principles of this disclosure. The
zones 40a-c may be sections of a single earth formation, or
they may be sections of separate formations. Although the
perforations 46c are not described above as being plugged in
the method, the perforations 46c could be plugged after the
zone 40c is fractured or otherwise stimulated (e.g., to
verify that the plugs are indeed preventing flow from the
casing 16 to the zones 40a-c).
In other examples, the plugs 42 may not be degraded.
The plugs 42 could instead be mechanically removed, for
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example, by milling or otherwise cutting the plugs 42 away
from the perforations. In any of the method examples
described above, after the fracturing operation(s) are
completed, the plugs 42 can be milled off or otherwise
removed from the perforations 38, 46, 46a,b without
dissolving, melting, dispersing or otherwise degrading a
material of the plugs.
In some examples, the plugs 42 can be mechanically
removed, without necessarily cutting the plugs. A tool with
appropriate gripping structures (such as a mill or another
cutting or grabbing device) could grab the plugs 42 and pull
them from the perforations.
Referring additionally now to FIG. 4A, an example of a
flow conveyed device 60 that can incorporate the principles
of this disclosure is representatively illustrated. The
device 60 may be used for any of the plugs 42, 42a,b in the
method examples described above, or the device may be used
in other methods.
The device 60 example of FIG. 4A includes multiple
fibers 62 extending outwardly from an enlarged body 64. As
depicted in FIG. 4A, each of the fibers 62 has a lateral
dimension (e.g., a thickness or diameter) that is
substantially smaller than a size (e.g., a thickness or
diameter) of the body 64.
The body 64 can be dimensioned so that it will
effectively engage and seal off a particular opening in a
well. For example, if it is desired for the device 60 to
seal off a perforation in a well, the body 64 can be formed
so that it is somewhat larger than a diameter of the
perforation. If it is desired for multiple devices 60 to
seal off multiple openings having a variety of dimensions
(such as holes caused by corrosion of the casing 16), then
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the bodies 64 of the devices can be formed with a
corresponding variety of sizes.
In the FIG. 4A example, the fibers 62 are joined
together (e.g., by braiding, weaving, cabling, etc.) to form
lines 66 that extend outwardly from the body 64. In this
example, there are two such lines 66, but any number of
lines (including one) may be used in other examples.
The lines 66 may be in the form of one or more ropes,
in which case the fibers 62 could comprise frayed ends of
the rope(s). In addition, the body 64 could be formed by one
or more knots in the rope(s). In some examples, the body 64
can comprise a fabric or cloth, the body could be formed by
one or more knots in the fabric or cloth, and the fibers 62
could extend from the fabric or cloth.
In other examples, the device 60 could comprise a
single sheet of material, or multiple strips of sheet
material. The device 60 could comprise one or more films.
The body 64 and lines 66 may not be made of the same
material, and the body and/or lines may not be made of a
fibrous material.
In the FIG. 4A example, the body 64 is formed by a
double overhand knot in a rope, and ends of the rope are
frayed, so that the fibers 62 are splayed outward. In this
manner, the fibers 62 will cause significant fluid drag when
the device 60 is deployed into a flow stream, so that the
device will be effectively "carried" by, and "follow," the
flow.
However, it should be clearly understood that other
types of bodies and other types of fibers may be used in
other examples. The body 64 could have other shapes, the
body could be hollow or solid, and the body could be made up
of one or multiple materials. The fibers 62 are not
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necessarily joined by lines 66, and the fibers are not
necessarily formed by fraying ends of ropes or other lines.
The body 64 is not necessarily centrally located in the
device 60 (for example, the body could be at one end of the
lines 66). Thus, the scope of this disclosure is not limited
to the construction, configuration or other details of the
device 60 as described herein or depicted in the drawings.
Referring additionally now to FIG. 4B, another example
of the device 60 is representatively illustrated. In this
example, the device 60 is formed using multiple braided
lines 66 of the type known as "mason twine." The multiple
lines 66 are knotted (such as, with a double or triple
overhand knot or other type of knot) to form the body 64.
Ends of the lines 66 are not necessarily frayed in these
examples, although the lines do comprise fibers (such as the
fibers 62 described above).
Referring additionally now to FIG. 5, another example
of the device 60 is representatively illustrated. In this
example, four sets of the fibers 62 are joined by a
corresponding number of lines 66 to the body 64. The body 64
is formed by one or more knots in the lines 66.
FIG. 5 demonstrates that a variety of different
configurations are possible for the device 60. Accordingly,
the principles of this disclosure can be incorporated into
other configurations not specifically described herein or
depicted in the drawings. Such other configurations may
include fibers joined to bodies without use of lines, bodies
formed by techniques other than knotting, etc.
Referring additionally now to FIGS. 6A & B, an example
of a use of the device 60 of FIG. 4 to seal off an opening
68 in a well is representatively illustrated. In this
example, the opening 68 is a perforation formed through a
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sidewall 70 of a tubular string 72 (such as, a casing,
liner, tubing, etc.). However, in other examples the opening
68 could be another type of opening, and may be formed in
another type of structure.
The device 60 is deployed into the tubular string 72
and is conveyed through the tubular string by fluid flow 74.
The fibers 62 of the device 60 enhance fluid drag on the
device, so that the device is influenced to displace with
the flow 74.
Since the flow 74 (or a portion thereof) exits the
tubular string 72 via the opening 68, the device 60 will be
influenced by the fluid drag to also exit the tubular string
via the opening 68. As depicted in FIG. 6B, one set of the
fibers 62 first enters the opening 68, and the body 64
follows. However, the body 64 is appropriately dimensioned,
so that it does not pass through the opening 68, but instead
is lodged or wedged into the opening. In some examples, the
body 64 may be received only partially in the opening 68,
and in other examples the body may be entirely received in
the opening.
The body 64 may completely or only partially block the
flow 74 through the opening 68. If the body 64 only
partially blocks the flow 74, any remaining fibers 62
exposed to the flow in the tubular string 72 can be carried
by that flow into any gaps between the body and the opening
68, so that a combination of the body and the fibers
completely blocks flow through the opening.
In another example, the device 60 may partially block
flow through the opening 68, and another material (such as,
calcium carbonate, PLA or PGA particles) may be deployed and
conveyed by the flow 74 into any gaps between the device and
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the opening, so that a combination of the device and the
material completely blocks flow through the opening.
The device 60 may permanently prevent flow through the
opening 68, or the device may degrade to eventually permit
flow through the opening. If the device 60 degrades, it may
be self-degrading, or it may be degraded in response to any
of a variety of different stimuli. Any technique or means
for degrading the device 60 (and any other material used in
conjunction with the device to block flow through the
opening 68) may be used in keeping with the scope of this
disclosure.
In other examples, the device 60 may be mechanically
removed from the opening 68. For example, if the body 64
only partially enters the opening 68, a mill or other
cutting device may be used to cut the body from the opening.
Referring additionally now to FIGS. 7-9, additional
examples of the device 60 are representatively illustrated.
In these examples, the device 60 is surrounded by,
encapsulated in, molded in, or otherwise retained by, a
retainer 80.
The retainer 80 aids in deployment of the device 60,
particularly in situations where multiple devices are to be
deployed simultaneously. In such situations, the retainer 80
for each device 60 prevents the fibers 62 and/or lines 66
from becoming entangled with the fibers and/or lines of
other devices.
The retainer 80 could in some examples completely
enclose the device 60. In other examples, the retainer 80
could be in the form of a binder that holds the fibers 62
and/or lines 66 together, so that they do not become
entangled with those of other devices.
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In some examples, the retainer 80 could have a cavity
therein, with the device 60 (or only the fibers 62 and/or
lines 66) being contained in the cavity. In other examples,
the retainer 80 could be molded about the device 60 (or only
the fibers 62 and/or lines 66).
During or after deployment of the device 60 into the
well, the retainer 80 dissolves, melts, disperses or
otherwise degrades, so that the device is capable of sealing
off an opening 68 in the well, as described above. For
example, the retainer 80 can be made of a material 82 that
degrades in a wellbore environment.
The retainer material 82 may degrade after deployment
into the well, but before arrival of the device 60 at the
opening 68 to be plugged. In other examples, the retainer
material 82 may degrade at or after arrival of the device 60
at the opening 68 to be plugged. If the device 60 also
comprises a degradable material, then preferably the
retainer material 82 degrades prior to the device material.
The material 82 could, in some examples, melt at
elevated wellbore temperatures. The material 82 could be
chosen to have a melting point that is between a temperature
at the earth's surface and a temperature at the opening 68,
so that the material melts during transport from the surface
to the downhole location of the opening.
The material 82 could, in some examples, dissolve when
exposed to wellbore fluid. The material 82 could be chosen
so that the material begins dissolving as soon as it is
deployed into the wellbore 14 and contacts a certain fluid
(such as, water, brine, hydrocarbon fluid, etc.) therein. In
other examples, the fluid that initiates dissolving of the
material 82 could have a certain pH range that causes the
material to dissolve.
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Note that it is not necessary for the material 82 to
melt or dissolve in the well. Various other stimuli (such
as, passage of time, elevated pressure, flow, turbulence,
etc.) could cause the material 82 to disperse, degrade or
otherwise cease to retain the device 60. The material 82
could degrade in response to any one, or a combination, of:
passage of a predetermined period of time in the well,
exposure to a predetermined temperature in the well,
exposure to a predetermined fluid in the well, exposure to
radiation in the well and exposure to a predetermined
chemical composition in the well. Thus, the scope of this
disclosure is not limited to any particular stimulus or
technique for dispersing or degrading the material 82, or to
any particular type of material.
In some examples, the material 82 can remain on the
device 60, at least partially, when the device engages the
opening 68. For example, the material 82 could continue to
cover the body 64 (at least partially) when the body engages
and seals off the opening 68. In such examples, the material
82 could advantageously comprise a relatively soft, viscous
and/or resilient material, so that sealing between the
device 60 and the opening 68 is enhanced.
Suitable relatively low melting point substances that
may be used for the material 82 can include wax (e.g.,
paraffin wax, vegetable wax), ethylene-vinyl acetate
copolymer (e.g., ELVAX(TM) available from DuPont), atactic
polypropylene, and eutectic alloys. Suitable relatively soft
substances that may be used for the material 82 can include
a soft silicone composition or a viscous liquid or gel.
Suitable dissolvable materials can include PLA, PGA,
anhydrous boron compounds (such as anhydrous boric oxide and
anhydrous sodium borate), polyvinyl alcohol, polyethylene
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oxide, salts and carbonates. The dissolution rate of a
water-soluble polymer (e.g., polyvinyl alcohol, polyethylene
oxide) can be increased by incorporating a water-soluble
plasticizer (e.g., glycerin), or a rapidly-dissolving salt
(e.g., sodium chloride, potassium chloride), or both a
plasticizer and a salt.
In FIG. 7, the retainer 80 is in a cylindrical form.
The device 60 is encapsulated in, or molded in, the retainer
material 82. The fibers 62 and lines 66 are, thus, prevented
from becoming entwined with the fibers and lines of any
other devices 60.
In FIG. 8, the retainer 80 is in a spherical form. In
addition, the device 60 is compacted, and its compacted
shape is retained by the retainer material 82. A shape of
the retainer 80 can be chosen as appropriate for a
particular device 60 shape, in compacted or un-compacted
form.
In FIG. 9, the retainer 80 is in a cubic form. Thus,
any type of shape (polyhedron, spherical, cylindrical, etc.)
may be used for the retainer 80, in keeping with the
principles of this disclosure.
Referring additionally now to FIG. 10, an example of a
deployment apparatus 90 and an associated method are
representatively illustrated. The apparatus 90 and method
may be used with the system 10 and method described above,
or they may be used with other systems and methods.
When used with the system 10, the apparatus 90 can be
connected between the pump 34 and the casing valve 32 (see
FIG. 1). Alternatively, the apparatus 90 can be "teed" into
a pipe associated with the pump 34 and casing valve 32, or
into a pipe associated with the pump 36 (for example, if the
devices 60 are to be deployed via the tubular string 12).
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However configured, an output of the apparatus 90 is
connected to the well, although the apparatus itself may be
positioned a distance away from the well.
The apparatus 90 is used in this example to deploy the
devices 60 into the well. The devices 60 may or may not be
retained by the retainer 80 when they are deployed. However,
in the FIG. 10 example, the devices 60 are depicted with the
retainers 80 in the spherical shape of FIG. 8, for
convenience of deployment. The retainer material 82 can be
at least partially dispersed during the deployment, so that
the devices 60 are more readily conveyed by the flow 74.
In certain situations, it can be advantageous to
provide a certain spacing between the devices 60 during
deployment, for example, in order to efficiently plug casing
perforations. One reason for this is that the devices 60
will tend to first plug perforations that are receiving
highest rates of flow.
In addition, if the devices 60 are deployed downhole
too close together, some of them can become trapped between
perforations, thereby wasting some of the devices. The
excess "wasted" devices 60 might later interfere with other
well operations.
To mitigate such problems, the devices 60 can be
deployed with a selected spacing. The spacing may be, for
example, on the order of the length of the perforation
interval. The apparatus 90 is desirably capable of deploying
the devices 60 with any selected spacing between the
devices.
Each device 60 in this example has the retainer 80 in
the form of a dissolvable coating material with a frangible
coating 88 thereon, to impart a desired geometric shape
(spherical in this example), and to allow for convenient
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deployment. The dissolvable retainer material 82 could be
detrimental to the operation of the device 60 if it
increases a drag coefficient of the device. A high
coefficient of drag can cause the devices 60 to be swept to
a lower end of the perforation interval, instead of sealing
uppermost perforations.
The frangible coating 88 is used to prevent the
dissolvable coating from dissolving during a queue time
prior to deployment. Using the apparatus 90, the frangible
coating 88 can be desirably broken, opened or otherwise
damaged during the deployment process, so that the
dissolvable coating is then exposed to fluids that can cause
the coating to dissolve.
Examples of suitable frangible coatings include
cementitious materials (e.g., plaster of Paris) and various
waxes (e.g., paraffin wax, carnauba wax, vegetable wax,
machinable wax). The frangible nature of a wax coating can
be optimized for particular conditions by blending a less
brittle wax (e.g., paraffin wax) with a more brittle wax
(e.g., carnauba wax) in a certain ratio selected for the
particular conditions.
As depicted in FIG. 10, the apparatus 90 includes a
rotary actuator 92 (such as, a hydraulic or electric servo
motor, with or without a rotary encoder). The actuator 92
rotates a sequential release structure 94 that receives each
device 60 in turn from a queue of the devices, and then
releases each device one at a time into a conduit 86 that is
connected to the tubular string 72 (or the casing 16 or
tubing 20 of FIG. 1).
Note that it is not necessary for the actuator 92 to be
a rotary actuator, since other types of actuators (such as,
a linear actuator) may be used in other examples. In
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addition, it is not necessary for only a single device 60 to
be deployed at a time. In other examples, the release
structure 94 could be configured to release multiple devices
at a time. Thus, the scope of this disclosure is not limited
to any particular details of the apparatus 90 or the
associated method as described herein or depicted in the
drawings.
In the FIG. 10 example, a rate of deployment of the
devices 60 is determined by an actuation speed of the
actuator 92. As a speed of rotation of the structure 94
increases, a rate of release of the devices 60 from the
structure accordingly increases. Thus, the deployment rate
can be conveniently adjusted by adjusting an operational
speed of the actuator 92. This adjustment could be
automatic, in response to well conditions, stimulation
treatment parameters, flow rate variations, etc.
As depicted in FIG. 10, a liquid flow 96 enters the
apparatus 90 from the left and exits on the right (for
example, at about 1 barrel per minute). Note that the flow
96 is allowed to pass through the apparatus 90 at any
position of the release structure 94 (the release structure
is configured to permit flow through the structure at any of
its positions).
When the release structure 94 rotates, one or more of
the devices 60 received in the structure rotates with the
structure. When a device 60 is on a downstream side of the
release structure 94, the flow 96 though the apparatus 90
carries the device to the right (as depicted in FIG. 10) and
into a restriction 98.
The restriction 98 in this example is smaller than the
diameter of the device 60. The flow 96 causes the device 60
to be forced through the restriction 98, and the frangible
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coating 88 is thereby damaged, opened or fractured to allow
the inner dissolvable material 82 of the retainer 80 to
dissolve.
Other ways of opening, breaking or damaging a frangible
coating may be used in keeping with the principles of this
disclosure. For example, cutters or abrasive structures
could contact an outside surface of a device 60 to
penetrate, break, abrade or otherwise damage the frangible
coating 88. Thus, this disclosure is not limited to any
particular technique for damaging, breaking, penetrating or
otherwise compromising a frangible coating.
Referring additionally now to FIG. 11, another example
of a deployment apparatus 100 and an associated method are
representatively illustrated. The apparatus 100 and method
may be used with the system 10 and method described above,
or they may be used with other systems and methods.
In the FIG. 11 example, the devices 60 are deployed
using two flow rates. Flow rate A through two valves (valves
A & B) is combined with Flow rate B through a pipe 102
depicted as being vertical in FIG. 11 (the pipe may be
horizontal or have any other orientation in actual
practice).
The pipe 102 may be associated with the pump 34 and
casing valve 32, or the pipe may be associated with the pump
36 if the devices 60 are to be deployed via the tubular
string 12. In some examples, a separate pump (not shown) may
be used to supply the flow 96 through the valves A & B.
Valve A is not absolutely necessary, but may be used to
control a queue of the devices 60. When valve B is open the
flow 96 causes the devices 60 to enter the vertical pipe
102. Flow 104 through the vertical pipe 102 in this example
is substantially greater than the flow 96 through the valves
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A & B (that is, flow rate B >> flow rate A), although in
other examples the flows may be substantially equal or
otherwise related.
A spacing (dist. B) between the devices 60 when they
are deployed into the well can be calculated as follows:
dist. B = dist. A * (IDA2/IDA2) * (flow rate B/flow rate A),
where dist. A is a spacing between the devices 60 prior to
entering the pipe 102, IDA is an inner diameter of a pipe
106 connected to the pipe 102, and IDB is an inner diameter
of the pipe 102. This assumes circular pipes 102, 104. Where
corresponding passages are non-circular, the term IDA2/IDB2
can be replaced by an appropriate ratio of passage areas.
The spacing between the plugging devices 60 in the well
(dist. B) can be automatically controlled by varying one or
both of the flow rates A,B. For example, the spacing can be
increased by increasing the flow rate B or decreasing the
flow rate A. The flow rate(s) A,B can be automatically
adjusted in response to changes in well conditions,
stimulation treatment parameters, flow rate variations, etc.
In some examples, flow rate A can have a practical
minimum of about 1/2 barrel per minute. In some
circumstances, the desired deployment spacing (dist. B) may
be greater than what can be produced using a convenient
spacing dist. A of the devices 60 and the flow rate A in the
pipe 106.
The deployment spacing B may be increased by adding
spacers 108 between the devices 60 in the pipe 106. The
spacers 108 effectively increase the distance A between the
devices 60 in the pipe 106 (and, thus, increase the value of
dist. A in the equation above).
The spacers 108 may be dissolvable or otherwise
dispersible, so that they dissolve or degrade when they are
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in the pipe 102 or thereafter. In some examples, the spacers
108 may be geometrically the same as, or similar to, the
devices 60.
Note that the apparatus 100 may be used in combination
with the restriction 98 of FIG. 10 (for example, with the
restriction 98 connected downstream of the valve B but
upstream of the pipe 102). In this manner, a frangible or
other protective coating on the devices 60 and/or spacers
108 can be opened, broken or otherwise damaged prior to the
devices and spacers entering the pipe 102.
Referring additionally now to FIG. 12, a cross-
sectional view of another example of the device 60 is
representatively illustrated. The device 60 may be used in
any of the systems and methods described herein, or may be
used in other systems and methods.
In this example, the body of the device 60 is made up
of filaments or fibers 62 formed in the shape of a ball or
sphere. Of course, other shapes may be used, if desired.
The filaments or fibers 62 may make up all, or
substantially all, of the device 60. The fibers 62 may be
randomly oriented, or they may be arranged in various
orientations as desired.
In the FIG. 12 example, the fibers 62 are retained by
the dissolvable, degradable or dispersible material 82. In
addition, a frangible coating may be provided on the device
60, for example, in order to delay dissolving of the
material 82 until the device has been deployed into a well
(as in the example of FIG. 10).
The device 60 of FIG. 12 can be used in a diversion
fracturing operation (in which perforations receiving the
most fluid are plugged to divert fluid flow to other
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perforations), in a re-completion operation (e.g., as in the
FIGS. 2A-D example), or in a multiple zone perforate and
fracture operation (e.g., as in the FIGS. 3A-D example).
One advantage of the FIG. 12 device 60 is that it is
capable of sealing on irregularly shaped openings,
perforations, leak paths or other passageways. The device 60
can also tend to "stick" or adhere to an opening, for
example, due to engagement between the fibers 62 and
structure surrounding (and in) the opening. In addition,
there is an ability to selectively seal openings.
The fibers 62 could, in some examples, comprise wool
fibers. The device 60 may be reinforced (e.g., using the
material 82 or another material) or may be made entirely of
fibrous material with a substantial portion of the fibers 62
randomly oriented.
The fibers 62 could, in some examples, comprise metal
wool, or crumpled and/or compressed wire. Wool may be
retained with wax or other material (such as the material
82) to form a ball, sphere, cylinder or other shape.
In the FIG. 12 example, the material 82 can comprise a
wax (or eutectic metal or other material) that melts at a
selected predetermined temperature. A wax device 60 may be
reinforced with fibers 62, so that the fibers and the wax
(material 82) act together to block a perforation or other
passageway.
The selected melting point can be slightly less than a
static wellbore temperature. The wellbore temperature during
fracturing is typically depressed due to relatively low
temperature fluids entering wellbore. After fracturing,
wellbore temperature will typically increase, thereby
melting the wax and releasing the reinforcement fibers 62.
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This type of device 60 in the shape of a ball or other
shapes may be used to operate downhole tools in a similar
fashion. In FIG. 14, a well tool 110 is depicted with a
passageway 112 extending longitudinally through the well
tool. The well tool 110 could, for example, be connected in
the casing 16 of FIG. 1, or it could be connected in another
tubular string (such as a production tubing string, the
tubular string 12, etc.).
The device 60 is depicted in FIG. 14 as being sealingly
engaged with a seat 114 formed in a sliding sleeve 116 of
the well tool 110. When the device 60 is so engaged in the
well tool 110 (for example, after the well tool is deployed
into a well and appropriately positioned), a pressure
differential may be produced across the device and the
sliding sleeve 116, in order to shear frangible members 118
and displace the sleeve downward (as viewed in FIG. 14),
thereby allowing flow between the passageway 112 and an
exterior of the well tool 110 via openings 120 formed
through an outer housing 122.
The material 82 of the device 60 can then dissolve,
disperse or otherwise degrade to thereby permit flow through
the passageway 112. Of course, other types of well tools
(such as, packer setting tools, frac plugs, testing tools,
etc.) may be operated or actuated using the device 60 in
keeping with the scope of this disclosure.
A drag coefficient of the device 60 in any of the
examples described herein may be modified appropriately to
produce a desired result. For example, in a diversion
fracturing operation, it is typically desirable to block
perforations at a certain location in a wellbore. The
location is usually at the perforations taking the most
fluid.
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Natural fractures in an earth formation penetrated by
the wellbore make it so that certain perforations receive a
larger portion of fracturing fluids. For these situations
and others, the device 60 shape, size, density and other
characteristics can be selected, so that the device tends to
be conveyed by flow to a certain corresponding section of
the wellbore.
For example, devices 60 with a larger coefficient of
drag (Cd) may tend to seat more toward a toe of a generally
horizontal or lateral wellbore. Devices 60 with a smaller Cd
may tend to seat more toward a heel of the wellbore. For
example, if the wellbore 14 depicted in FIG. 2B is
horizontal or highly deviated, the heel would be at an upper
end of the illustrated wellbore, and the toe would be at the
lower end of the illustrated wellbore (e.g., the direction
of the fluid flow 44 is from the heel to the toe).
Smaller devices 60 with long fibers 62 floating freely
(see the example of FIG. 13) may have a strong tendency to
seat at or near the heel. A diameter of the device 60 and
the free fiber 62 length can be appropriately selected, so
that the device is more suited to stopping and sealingly
engaging perforations anywhere along the length of the
wellbore.
Acid treating operations can benefit from use of the
device 60 examples described herein. Pumping friction causes
hydraulic pressure at the heel to be considerably higher
than at the toe. This means that the fluid volume pumped
into a formation at the heel will be considerably higher
than at the toe. Turbulent fluid flow increases this effect.
Gelling additives might reduce an onset of turbulence and
decrease the magnitude of the pressure drop along the length
of the wellbore.
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Higher initial pressure at the heel allows zones to be
acidized and then plugged starting at the heel, and then
progressively down along the wellbore. This mitigates waste
of acid from attempting to acidize all of the zones at the
same time.
The free fibers 62 of the FIGS. 4-6B & 13 examples
greatly increase the ability of the device 60 to engage the
first open perforation (or other leak path) it encounters.
Thus, the devices 60 with low Cd and long fibers 62 can be
used to plug from upper perforations to lower perforations,
while turbulent acid with high frictional pressure drop is
used so that the acid treats the unplugged perforations
nearest the top of the wellbore with acid first.
In examples of the device 60 where a wax material (such
as the material 82) is used, the fibers 62 (including the
body 64, lines 66, knots, etc.) may be treated with a
treatment fluid that repels wax (e.g., during a molding
process). This may be useful for releasing the wax from the
fibrous material after fracturing or otherwise compromising
the retainer 80 and/or a frangible coating thereon.
Suitable release agents are water-wetting surfactants
(e.g., alkyl ether sulfates, high hydrophilic-lipophilic
balance (HLB) nonionic surfactants, betaines,
alkyarylsulfonates, alkyldiphenyl ether sultanates, alkyl
sulfates). The release fluid may also comprise a binder to
maintain the knot or body 64 in a shape suitable for
molding. One example of a binder is a polyvinyl acetate
emulsion.
Broken-up or fractured devices 60 can have lower Cd.
Broken-up or fractured devices 60 can have smaller cross-
sections and can pass through the annulus 30 between tubing
20 and casing 16 more readily.
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The restriction 98 (see FIG. 10) may be connected in
any line or pipe that the devices 60 are pumped through, in
order to cause the devices to fracture as they pass through
the restriction. This may be used to break up and separate
devices 60 into wax and non-wax parts. The restriction 98
may also be used for rupturing a frangible coating covering
a soluble wax material 82 to allow water or other well
fluids to dissolve the wax.
Fibers 62 may extend outwardly from the device 60,
whether or not the body 64 or other main structure of the
device also comprises fibers. For example, a ball (or other
shape) made of any material could have fibers 62 attached to
and extending outwardly therefrom. Such a device 60 will be
better able to find and cling to openings, holes,
perforations or other leak paths near the heel of the
wellbore, as compared to the ball (or other shape) without
the fibers 62.
For any of the device 60 examples described herein, the
fibers 62 may not dissolve, disperse or otherwise degrade in
the well. In such situations, the devices 60 (or at least
the fibers 62) may be removed from the well by swabbing,
scraping, circulating, milling or other mechanical methods.
In situations where it is desired for the fibers 62 to
dissolve, disperse or otherwise degrade in the well, nylon
is a suitable acid soluble material for the fibers. Nylon 6
and nylon 66 are acid soluble and suitable for use in the
device 60. At relatively low well temperatures, nylon 6 may
be preferred over nylon 66, because nylon 6 dissolves faster
or more readily.
Self-degrading fiber devices 60 can be prepared from
poly-lactic acid (PLA), poly-glycolic acid (PGA), or a
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combination of PLA and PGA fibers 62. Such fibers 62 may be
used in any of the device 60 examples described herein.
Fibers 62 can be continuous monofilament or
multifilament, or chopped fiber. Chopped fibers 62 can be
carded and twisted into yarn that can be used to prepare
fibrous flow conveyed devices 60.
The PLA and/or PGA fibers 62 may be coated with a
protective material, such as calcium stearate, to slow its
reaction with water and thereby delay degradation of the
device 60. Different combinations of PLA and PGA materials
may be used to achieve corresponding different degradation
times or other characteristics.
PLA resin can be spun into fiber of 1-15 denier, for
example. Smaller diameter fibers 62 will degrade faster.
Fiber denier of less than 5 may be most desirable. PLA resin
is commercially available with a range of melting points
(e.g., 60 to 185 C). Fibers 62 spun from lower melting point
PLA resin can degrade faster.
PLA bi-component fiber has a core of high-melting point
PLA resin and a sheath of low-melting point PLA resin (e.g.,
60 C melting point sheath on a 130 C melting point core).
The low-melting point resin can hydrolyze more rapidly and
generate acid that will accelerate degradation of the high-
melting point core. This may enable the preparation of a
plugging device 60 that will have higher strength in a
wellbore environment, yet still degrade in a reasonable
time. In various examples, a melting point of the resin can
decrease in a radially outward direction in the fiber.
Referring additionally now to FIG. 15, a system 200 and
associated method for dispensing the plugging devices 60
into the wellbore 14 is representatively illustrated. In
this system 200, the plugging devices 60 are not discharged
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into the wellbore 14 at the surface and conveyed to a
desired plugging location (such as perforations 38, 46a-c,
46 in the examples of FIGS. 2A-3D or the opening 68 in the
example of FIGS. 6A & B) by fluid flow 44, 74, 96, 104.
Instead, the plugging devices 60 are contained in a
container 202, the container is conveyed by a conveyance 204
to a desired downhole location, and the plugging devices are
released from the container at the downhole location.
A variety of different containers 202 for the plugging
devices 60 are described below and depicted in FIGS. 16A-
42B. However, it should be clearly understood that the scope
of this disclosure is not limited to any particular type or
configuration of the container 202.
An actuator 206 may be provided for releasing or
forcibly discharging the plugging devices 60 from the
container 202 when desired. The container 202 and the
actuator 206 may be combined into a dispenser tool 300 for
dispensing the plugging devices 60 in the well at a downhole
location. A variety of different actuators 206 are described
below and depicted in the drawings, however, it is not
necessary for an actuator to be provided, or for any
particular type or configuration of actuator to be provided.
The conveyance 204 could be any type suitable for
transporting the container 202 to the desired downhole
location. Examples of conveyances include wireline,
slickline, coiled tubing, jointed tubing, autonomous or
wired tractor, etc.
In some examples, the container 202 could be displaced
by fluid flow 208 through the wellbore 14. The fluid flow
208 could be any of the fluid flows 44, 74, 96, 104
described above. The fluid flow 208 could comprise a
treatment fluid, such as a stimulation fluid (for example, a
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fracturing and/or acidizing fluid), an inhibitor (for
example, to inhibit formation of paraffins, asphaltenes,
scale, etc.) and/or a remediation treatment (for example, to
remediate damage due to scale, clays, polymer, etc., buildup
in the well).
In the FIG. 15 example, the plugging devices 60 are
released from the container 202 above a packer, bridge plug,
wiper plug or other type of plug 210 previously set in the
wellbore 14. In other examples, the plugging devices 60
could be released above a previously plugged valve, such as
the valve 110 example of FIG. 14.
Note that it is not necessary in keeping with the scope
of this disclosure for the plugging devices 60 to be
released into the wellbore 14 above any packer, plug 210 or
other flow blockage in the wellbore.
As depicted in FIG. 15, the plugging devices 60 will be
conveyed by the flow 208 into sealing engagement with the
perforations 46 above the plug 210. In other examples, the
plugging devices 60 could block flow through other types of
openings (e.g., openings in tubulars other than casing 16,
flow passages in well tools such as the valve 110, etc.).
Thus, the scope of this disclosure is not limited to use of
the container 202 to release the plugging devices 60 for
plugging the perforations 46.
The plugging devices 60 depicted in FIG. 15 are similar
to those of the FIG. 12 example, and are spherically shaped.
These plugging devices 60 are also depicted in the other
examples of the system 200 and container 202 of FIGS. 16A-
42B for convenience. However, any of the plugging devices 60
described herein may be used with any of the system 200 and
container 202 examples, and the scope of this disclosure is
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not limited to use of any particular configuration, type or
shape of the plugging devices.
Although only release of the plugging devices 60 from
the container 202 is described herein and depicted in the
drawings, other plugging substances, devices or materials
may also be released downhole from the container 208 (or
another container) into the wellbore 14 in other examples. A
material (such as, calcium carbonate, PLA or PGA particles)
may be released from the container 208 and conveyed by the
flow 208 into any gaps between the devices 60 and the
openings to be plugged, so that a combination of the devices
and the materials completely blocks flow through the
openings.
Referring additionally now to FIGS. 16A-18B, an example
of the dispensing tool 300 is representatively illustrated
in various stages of actuation. The dispensing tool 300 may
be used in the system 200 and method of FIG. 15, or it may
be used with other systems or methods in keeping with the
scope of this disclosure.
In this example, the tool 300 is actuated using a
linear actuator 206 connected at an upper end of the
container 202. A portion of the actuator 206 is depicted in
FIGS. 16A & B, but is not depicted in FIGS. 17A-18B for
convenience.
Any linear actuator 206 having sufficient force and
stroke length can be used. Suitable examples include
standard wireline plug setting tools (such as, those
operated using an ignited propellant (e.g., the common
setting tool marketed by Baker Oil Tools of Houston, Texas
USA), an electric actuator, or an electro-hydraulic
actuator, etc.), hydraulic coiled tubing plug setting tools,
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or any hydraulic actuator (for example, using differential
pressure or hydrostatic pressure to generate a force, etc.).
The plugging devices 60 are contained inside a chamber
212 of the container 202. A rod 214 is retained by a shear
pin 216. The rod 214 connects an end closure 218 to a
mandrel 220. The mandrel 220 is connected to the linear
actuator 206.
When the actuator 206 is operated as depicted in FIGS.
17A & B, the shear pin 216 is sheared, and the rod 214
experiences a tensile load. When sufficient tensile load is
exerted on the rod 214 by the actuator 206, a reduced cross-
section portion 214a of the rod is parted, thereby releasing
the end closure 218 from the chamber 212.
As depicted in FIGS. 18A & B, the end closure 218 can
separate from the container 202 and thereby allow the
plugging devices 60 to be released from the chamber 212. The
end closure 218 can be made of a frangible or dissolvable
material, so that it does not interfere with subsequent well
operations.
Additionally, when the mandrel 220 is displaced upward
by the actuator 206, a flow path 222 at a top of the
container 202 is opened. The fluid flow 208 can enter the
flow path 222, and assist in separating the end closure 218
from the container 202 and displacing the plugging devices
60 from the chamber 212. Alternatively, the tool 300 can be
displaced upward in the wellbore 14, to thereby create a
differential pressure from the top of the chamber 212 to the
bottom of the chamber.
The plugging devices 60 and any fluid and/or other
material in the chamber 212 will be ejected from the
container 202. A rate at which the chamber 212 contents are
ejected is dependent on the flow rate and other properties
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of the fluid flow 208, or on the rate of displacement of the
tool 30 through the wellbore 14. Thus, these rates can be
conveniently varied to thereby achieve a desired spacing of
the plugging devices 60 along the wellbore 14.
Referring additionally now to FIGS. 19A-21B, another
example of the dispensing tool 300 is representatively
illustrated in various stages of actuation. This example is
similar in many respects to the FIGS. 16A-18B example.
However, instead of the rod 214 parting in response to
tension applied by the actuator 206, the end closure 218
breaks and thereby allows the plugging devices 60 to be
released from the chamber 212.
In FIGS. 19A & B, the tool 300 is in a run-in
configuration. The end closure 218, which is made of a
frangible material, closes off a lower end of the chamber
212.
In FIGS. 20A & B, the actuator 206 has displaced the
mandrel 220 and rod 214 upward. This upward displacement of
the rod 214 causes the end closure 218 to break.
In FIGS. 21A & B, fluid flow 208 into the open flow
path 222 (or upward displacement of the tool 300 in the
wellbore 14) acts to discharge the plugging devices 60, and
any fluid or other material, from the container 202.
Referring additionally now to FIGS. 22A-23B, another
example of the tool 30 is representatively illustrated. In
this example, the plugging devices 60 are initially
contained in a separate cartridge 224 that is reciprocably
received in the container 202. The cartridge 224 can be
"pre-loaded" with the plugging devices 60, thereby making it
convenient to prepare the tool 300 for use in a well.
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The rod 214 is connected to an upper end of the
cartridge 224, and the end closure 218 closes off a lower
end of the cartridge. In FIGS. 22A & B, the tool 300 is in a
run-in configuration. The end closure 218 is secured to the
cartridge 224 and is shouldered up against a lower end of
the container 202.
In FIGS. 23A & B, the actuator 206 has displaced the
mandrel 220, rod 214 and cartridge 224 upward. The tensile
force exerted by the actuator 206 has sheared the end
closure 218 from the cartridge 224, thereby opening the
lower end of the cartridge and container 202. The flow path
22 is also opened, so the fluid flow 208 (or upward
displacement of the tool 300 in the wellbore 14) can
displace the plugging devices 60, and any associated fluid
and material, out of the container 202 and into the wellbore
14.
Referring additionally now to FIGS. 24A-25B, another
example of the tool 300 is representatively illustrated. In
this example, the end closure 218 is not necessarily
frangible, but is instead flexible in a manner allowing the
lower end of the container 202 to be opened in response to
upward displacement of the rod 214 by the actuator 206.
In FIGS. 24A & B, the tool 300 is in a run-in
configuration. A radially enlarged recess 226 at a lower end
of the rod 214 receives inwardly extending projections 218a
of the end closure 218, which is separated into multiple
elongated, resilient collets 218b. Thus, the collets 218b
are maintained in an inwardly flexed condition by the rod
214.
In FIGS. 25A & B, the rod 214 has been displaced upward
by the actuator 206, thereby releasing the projections 218a
from the recess 226, and allowing the collets 218b to flex
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outward. This opens the lower end of the container 202 and
permits the fluid flow 208 via the now open flow path 222
(or upward displacement of the tool 300 in the wellbore 14)
to displace the plugging devices 60, and any associated
fluid and material, from the chamber 212 into the wellbore
14.
Referring additionally now to FIGS. 26A-27B, another
example of the tool 300 is representatively illustrated. In
this example, the actuator 206 is not a linear actuator, but
instead is a rotary actuator including a motor 228.
The motor 228 rotates an auger 230 in the container
202. The plugging devices 60 are contained in the chamber
212, which extends helically between blades of the auger
230. The auger 230 is separately depicted in FIGS. 27A & B.
When the auger 230 is rotated by the motor 228, the
plugging devices 60 are gradually discharged from the lower
end of the container 202. A rate of discharge of the
plugging devices 60 can be controlled by varying a
rotational speed of the motor 228 and auger 230. The tool
300 can be displaced in the wellbore 14 at a selected
velocity while rotating the auger 230 at a specific speed to
thereby achieve a desired plugging device 60 spacing in the
wellbore 14.
Suitable examples of motors or rotary actuators for use
as the motor 228 include: a) a wireline or slickline
operated electric motor or motor and drivetrain, b) a
wireline or slickline operated electric or hydraulic rotary
actuator, c) a mud motor (a turbine or positive displacement
fluid motor) operated on coiled tubing or jointed pipe, d) a
battery operated rotary source conveyed by any suitable
means, and e) pipe rotation from surface with a drag block
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or other friction element downhole to provide relative
rotary motion at the tool 300.
Referring additionally now to FIGS. 28A-30B, another
example of the tool 300 is representatively illustrated.
This example is similar in many respects to the FIGS. 26A-
27B example, in that rotation of the auger 230 is used to
discharge the plugging devices 60 from the container 202.
However, the FIGS. 28A-30B example also includes a barrier
232 displaceable by the auger 230 rotation, to thereby
positively discharge the plugging devices 60 from the
chamber 212.
In FIGS. 28A & B, the tool 300 is in a run-in
configuration. The barrier 232 is positioned at an upper end
of the chamber 212, which is loaded with the plugging
devices 60. The barrier 232 has a helical slot 232a formed
therein for engagement with the blades of the auger 230.
Top and side views of the barrier 232 are
representatively illustrated in respective FIGS. 29A & B. In
these views it may be seen that the barrier 232 also has
splines 232b formed longitudinally thereon for sliding
engagement with longitudinal grooves 212a formed in the
chamber 212.
The engagement between the splines 232b and the grooves
212a prevents the barrier 232 from rotating with the auger
230, while also permitting the barrier to displace
longitudinally in the chamber 212 due to rotation of the
auger 230 and engagement between the auger blades and the
helical slot 232a.
In FIGS. 30A & B, the auger 230 has been rotated by the
motor 228 of the actuator 206, thereby displacing the
barrier 232 longitudinally through the container 202 and
discharging the plugging devices 60 from the chamber 212.
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Referring additionally now to FIGS. 31A-32B, another
example of the tool 300 is representatively illustrated. In
this example, multiple barriers 232 are spaced
longitudinally along the rod 214, which is externally
threaded (see FIGS. 32A & B).
The externally threaded rod 214 is similar in some
respects to the auger 230 of the FIGS. 26A-30B examples, in
that rotation of the rod by the motor 228 causes
longitudinal displacement of the barriers 232 through the
chamber 212. The barriers 232 of the FIGS. 31A-32B example
include the helical slot 232a, in that they are internally
threaded. External splines 232b could be provided on the
barriers 232 for engagement with longitudinal slots 212a in
the chamber 212 (as in the FIGS. 28A-30B example), if
desired, to prevent rotation of the barriers 232 with the
threaded rod 214.
In FIGS. 31A & B, the tool 300 is depicted in a run-in
configuration. When the motor 228 is operated to rotate the
rod 214, the barriers 232 will gradually displace
downwardly, thereby releasing the plugging devices 60 from
the lower end of the container 202. The barriers 232 can
also displace out of the chamber 212 and into the wellbore
14, and so the barriers can be made of a frangible or
dissolvable material, so that they will not interfere with
subsequent well operations.
Referring additionally now to FIGS. 33A-34B, another
example of the tool 300 is representatively illustrated. In
this example, the tool 300 includes the cartridge 224,
similar to the FIGS. 22A-23B example, but the cartridge is
rotated to release the plugging devices 60, instead of being
displaced longitudinally.
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In FIGS. 33A & B, the tool 300 is depicted in a run-in
configuration. The plugging devices 60 are received in the
cartridge 224, which is rotatably received in the container
202, and is connected to the motor 228. A passage 234
extending longitudinally through the end closure 218 is
blocked by an end closure 238 of the cartridge 224.
In FIGS. 34A & B, the tool 300 is depicted in an
actuated configuration, in which the cartridge 224 has been
rotated by the motor 228. As a result, a passage 236 in the
cartridge end closure 238 is now aligned with the passage
234 in the container end closure 218.
Another passage 240 in an upper end closure of the
cartridge 224 is now aligned with the flow path 222. The
plugging devices 60 can now be released into the wellbore 14
by the fluid flow 208 (or by upward displacement of the tool
300 through the wellbore).
Referring additionally now to FIGS. 35A-C, the FIGS.
26A-27B example of the tool 300 is representatively
illustrated as combined with a perforator 48. The perforator
48 is connected above the tool 300, with a line 242 for
operating the motor 228 extending through the perforator.
The line 242 may be an electrical, hydraulic, fiber optic or
other type of line for transmitting power and/or control
signals to the actuator 206 and motor 228.
The perforator 48 in this example is an explosive
perforator of the type including shaped charges 48a within
an outer tubular housing 48b. However, other types of
perforators (such as, fluid jet perforators, etc.) may be
used in other examples.
The perforator 48 is connected above the tool 300, in
that the perforator is connected between the conveyance 204
(see FIG. 15) and the dispensing tool. However, other
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relative positions of the perforator 48, conveyance 204 and
tool 300 may be used, in keeping with the scope of this
disclosure.
Referring additionally now to FIGS. 36A-C, another
example of the combined perforator 48 and dispensing tool
300 is representatively illustrated. In this example, the
tool 300 is connected above the perforator 48, so that the
tool 300 will be connected between the conveyance 204 (see
FIG. 15) and the perforator.
The line 242 in this example can include multiple
lines, and different types of lines may be included (such
as, electrical, hydraulic, fiber optic, detonating cord,
etc.). At least one of the lines 242 can be used to operate
the actuator 206, and another of the lines can be used to
operate the perforator 48 (such as, to detonate a detonator
or blasting cap of the perforator to set off the shaped
charges 48a, etc.). For operation of the perforator 48, at
least one of the lines 242 extends longitudinally through
the dispensing tool 300, from the conveyance 204 to the
perforator.
In this configuration, the dispensing tool 300 can
dispense the plugging devices 60 into the wellbore 14 above
perforations formed by the perforator 48, so that the fluid
flow 208 can conveniently convey the plugging devices into
sealing engagement with the perforations, such as, after a
treatment operation has been performed. In other
configurations in which the dispensing tool 300 is
positioned below the perforator 48, the conveyance 204 can
be used to raise the dispensing tool relative to
perforations formed by the perforator (such as, after a
treatment operation has been performed), in order to
dispense the plugging devices 60 above the perforations.
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However, it is not necessary in keeping with the scope of
this disclosure for the plugging devices 60 to be dispensed
above, below, or in any other particular position relative
to perforations.
Note that, since the dispensing tool 300 is positioned
above the perforator 48, the dispensing tool is configured
to discharge the plugging devices 60 laterally from the tool
into the wellbore 14. Specifically, the tool 300 includes a
side discharge port 244 that is initially blocked by a
barrier 246, as depicted in FIG. 36B.
The barrier 246 is internally threaded and disposed on
an externally threaded lower portion of the rod 214. When
the rod 214 is rotated by the motor 228, the barrier 246
displaces downward in the container 202, until the port 244
is fully opened. Rotation of the rod 214 also operates the
auger 230, so that the plugging devices 60 are discharged
from the side port 244 after it is opened.
Referring additionally now to FIGS. 37A-38C, another
example of the combined perforator 48 and dispensing tool
300 is representatively illustrated. In this example, the
dispensing tool 300 is connected between two perforators 48.
Accordingly, the tool 300 includes the side port 244 and
barrier 246 for controlling release of the plugging devices
60 laterally from the chamber 212 into the wellbore 14.
In FIGS. 37A-C, the dispensing tool 300 is depicted in
a run-in configuration. In FIGS. 38A-C, the dispensing tool
300 is depicted in an actuated configuration, with the side
port 244 open, so that the plugging devices 60 are released
from the container 202.
Referring additionally now to FIGS. 39A & B, another
example of the dispensing tool 300 is representatively
illustrated. In this example, the actuator for releasing the
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plugging devices 60 is in the form of detonators 248 and
frangible disks 250 that initially block the flow path 222
and passage 244 at opposite ends of the chamber 212.
When an appropriate electrical signal is transmitted to
the detonators 248 via the lines 242, the detonators
detonate, thereby breaking the frangible disks 250. Fluid
flow 208 can then pass into the chamber 212 via the flow
path 222, and the plugging devices 60 can displace out of
the chamber via the open passage 244.
In the FIGS. 39A & B example, the dispensing tool 300
is connected above a perforator 48, that is, between the
conveyance 204 and the perforator. Thus, the passage 244
discharges the plugging devices 60 laterally into the
wellbore 14. At least one of the lines 242 extends
longitudinally through the dispensing tool 300 to the
perforator 48 for actuation of the perforator.
Referring additionally now to FIGS. 40A & B, another
example of the dispensing tool 300 is representatively
illustrated. This example is similar in some respects to the
example of FIGS. 39A & B, in that detonators 248 are used to
open opposite ends of the chamber 212 and release the
plugging devices 60.
However, in the FIGS. 40A & B example, the lower
detonator 248 is received in the frangible end closure 218.
When the detonators 248 are detonated, the end closure 218
will break, thereby opening the lower end of the chamber
212, and the frangible disk 250 initially blocking the flow
path 222 will break, thereby opening the flow path. The
fluid flow 208 (or upward displacement of the tool 300 in
the wellbore 14) can then displace the plugging devices 60,
and any associated fluid and material in the chamber 212,
into the wellbore via the open lower end of the chamber.
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A sealed bulkhead 252 with electrical feed-throughs can
be used to isolate the chamber 212 from the conveyance 204
or a perforator 48 connected above the dispensing tool 300.
In various example configurations, the FIGS. 40A & B tool
300 could be positioned above, below or between one or more
perforators 48.
Referring additionally now to FIGS. 41A-C, another
example of the dispensing tool 300 is representatively
illustrated, connected between two perforators 48. The
dispensing tool 300 in this example is similar, and operates
similar to, the FIGS. 39A & B example.
Referring additionally now to FIGS. 42A & B, yet
another example of the dispensing tool 300 is
representatively illustrated. In this example, a gas
generation charge or propellant 254 is used to release and
eject the plugging devices 60 into the wellbore 14.
To operate the tool 300, the propellant 254 is ignited
via the lines 242, causing a buildup of pressure. When the
pressure reaches a predetermined level, a rupture disk 256
ruptures, suddenly introducing relatively high pressure gas
into the chamber 212. The sudden pressure increase in the
chamber 212 causes the end closure 218 to break, thereby
releasing the plugging devices 60 from the chamber into the
wellbore 14.
The FIGS. 42A & B dispensing tool 300 example could be
configured for connection above a perforator, or between
perforators, by providing a laterally directed passage (such
as the passage 244 described above) with a frangible
closure. Any of the dispensing tool 300 examples described
above could be positioned above or between perforators 48,
or otherwise positioned relative to other well tools, in
keeping with the scope of this disclosure.
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Some advantages of the dispensing tool 300 and method
examples described above can include (but are not limited
to): a) the plugging devices 60 can be precisely placed at a
desired location within the wellbore 14 for selective
plugging of specific perforations 46, b) the plugging
devices 60 do not have to be compatible with surface pumping
equipment, c) a possibility of accidentally plugging surface
pumping equipment is eliminated, d) very large plugging
devices 60 can be deployed, making it possible to plug very
large openings in the well, e) plugging devices 60 can be
distributed in a specific desired spacing or density within
the wellbore 14, f) no special or additional surface
equipment is needed beyond that required for standard
plugging and perforating operations, and g) there is no
possibility of presetting a plug.
One use of the plugging devices 60 described herein is
to block flow into or out of a perforation 46 during a
fracturing operation. FIG. 43 depicts a plugging device 60
which is comprised of a central body 64 or member (such as a
ball) which has enough strength to prevent extrusion through
an opening 46 or 68 which is being blocked, and of an outer
flexible, fluffy, or sponge-like material 306 which aids in
directing the device 60 to a flow passage (such as
perforation 46 or opening 68) and enhancing the ability of
the device to seal an arbitrary shaped opening. FIG. 43
depicts a rectangular embodiment, and FIG. 44 depicts a
spherical embodiment.
The central member or body 64 can be made of any
degradable, self-degrading or non-degrading material (such
as, any of the materials described herein) which has
sufficient strength to prevent extrusion. The outer material
306 can comprise any suitable material (such as, open cell
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foam, fiber, fabric, sponge, etc.), whether degradable,
self-degrading or non-degrading.
This device 60 can also be enclosed in a degradable
retainer 80 or shell (such as, any of the retainers
described herein), with or without a frangible coating 88
thereon. In one example, the device 60 can comprise a
sponge-like, relatively low density outer material 306
compressed around a central, relatively high strength
spherical body 64, until the retainer 80 dissolves, thereby
allowing the foam-type or sponge-like material 306 to expand
in a well.
FIG. 45 depicts another embodiment in which a strong
center member or body 64 is enclosed in a wrapper or bag of
mesh, net, gauze or other fluffy or relatively low density
outer material 306 that helps the device 60 find an opening
46, 68 through which fluid 74, 208 is flowing and assists in
sealing the opening.
FIG. 46 depicts another embodiment of the device 60,
which is comprised of a relatively strong disk-type or
washer element 308 with a length of fibrous material (such
as the line 66) extending through a hole 310 in the disk-
type or washer element 308. Near one or more ends of the
fibrous material line 66, a body 64 comprising a knot or
other enlarged portion is present, which cannot pass through
the hole 310 in the washer element 308.
The washer element 308 can comprise almost any shape or
suitable material and the fibrous material line 66 can
comprise any pliable or otherwise suitable material. In this
example, the fibers 62 extending outwardly from each of the
bodies 64 are very effective at "finding" an opening 46, 68
to be plugged and the body 64 "knots" are sized such that
they can pass into or through the opening to be plugged.
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One end of the knotted line 66 will follow flow and
pass through the opening, causing the washer element 308 to
be drawn up against the wall surrounding the opening 46, 68.
The body 64 knot at the other end of the line 66 will plug
the center hole 310 in the washer element 308 causing it to
be tightly sealed by pressure against the wall surrounding
the opening 46, 68.
The washer element 308 can be coated with elastomer or
other suitable material to aid in sealing. Any or all
portions of this device 60 can be made of degradable or
self-degrading material, if desired. Any of these plugging
devices 60 can be packaged as described above in a frangible
outer shell, coating 88 and/or retainer 80.
Referring additionally now to FIGS. 47-49, another
example of the system 10 and method is representatively
illustrated. In this example, multiple zones 40a,b are
perforated, fractured and plugged (e.g., perforations 46a,b
are plugged by plugging devices 60). Although only two zones
40a,b are depicted in FIGS. 47-49, any number of zones may
be perforated, fractured and plugged in keeping with the
principles of this disclosure, although a last zone
perforated and fractured may not also be plugged.
In the FIGS. 47-49 example, the conveyance 204 may
specifically comprise a wireline. A connector 302 is used to
connect one or more perforators 48 to the wireline
(conveyance 204). A firing head 304 may be provided, if
desired, for controlling operation of the perforators 48.
Note that, in this example, the bottom hole assembly 22
remains in the wellbore 14 while one or more zones 40a,b are
perforated and fractured.
The following steps may be included in the method:
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1. Run wireline-conveyed perforating bottom hole assembly
22 (which is capable of perforating multiple zones
40a,b at respective different times) into the wellbore
14.
2. Perforate the zone 40a.
3. Move bottom hole assembly 22 in wellbore 14 (see step 3
alternatives below).
4. Fracture the zone 40a with fluid and/or proppant
slurry.
5. Pump plugging devices 60 from surface to seal off
perforations 46a
6. Move bottom hole assembly 22 to next zone 40b.
7. Repeat steps 2 ¨ 6 until the desired number of zones is
completed (although steps 5 & 6 may not be performed
for the last zone).
Alternatives for step 3:
a. Move bottom hole assembly 22 up above new
perforations (devices 60 will be pumped past
perforating bottom hole assembly 22 during
fracturing).
b. Pull bottom hole assembly 22 up past a top of a
liner 16 into a larger ID liner or casing, in order
to reduce flow velocity around assembly 22 during
fracturing (devices 60 will be pumped past
perforating BHA 22 during fracturing).
c.Lower/pump assembly 22 below new perforations
(devices 60 will land on perforations 46a above
perforating BHA 22).
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The following steps may be included in another example
of the method:
1. Run BHA 22 (which includes at least two individually
operable perforators 48, or the ability to individually
perforate separate zones) in wellbore 14. The BHA 22
may also include means (such as, dispenser tool 300) of
releasing devices 60 at different times (e.g., two
individually operable dispenser tools 300, or one tool
which can be used to dispense devices 60 at least two
separate times.)
2. Perforate a zone 40a.
3. Move assembly 22 in wellbore 14 (see alternatives for
step 3 below).
4. Fracture the zone 40a with fluid and/or proppant
slurry.
5. Release devices 60 to seal off perforations 46a when
fluid 208 is pumped into the wellbore 14.
6. Move assembly 22 to next zone 40b.
7. Repeat steps 2 ¨ 6 until the desired number of zones is
completed (although steps 5 & 6 may not be performed
for the last zone).
Alternatives for step 3:
a. Move assembly 22 up above new perforations 46a
(devices 60 will be released from a dispenser 300
above or below the perforators 48 of the BHA 22
during fracturing).
b. Pull assembly 22 up past a top of a liner 16 and
into a larger ID liner or casing, in order to reduce
flow velocity around assembly 22 during fracturing
(devices 60 will be released from a dispenser 300
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above or below the perforators 48 of the BHA 22
during fracturing).
c. Lower or pump assembly 22 below new perforations 46a
(devices 60 will be released from a dispenser 300
above or below the perforators 48 of the BHA 22
during fracturing).
For the methods described above, measures may be taken
to mitigate or prevent fracturing fluid from damaging the
wireline 204 when it is positioned across open perforations
during a fracturing operation. Such measures can include:
1. Use erosion resistant cable.
2. Use armored cable.
3. Centralize the cable in the wellbore 14 or casing 16 so
it is not near the high velocity flow going into the
perforations.
4. Use rubber coated cable.
5. Use cable designed to seal on perforations during
fracturing operation.
6. Use hollow weight bars on the cable to protect the
cable from fracturing fluid erosion.
It may now be fully appreciated that the above
disclosure provides significant advancements to the art of
controlling flow in subterranean wells. In some examples
described above, the plugging device 60 may be used to block
flow through openings in a well, with the device being
uniquely configured so that its conveyance with the flow is
enhanced and/or its sealing engagement with an opening is
enhanced. A dispensing tool 300 can be used to deploy the
devices 60 downhole, so that a desired location and spacing
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between the devices is achieved. Dispensing apparatus 90,
100 may be used at surface.
The above disclosure provides to the art a method of
plugging an opening 46, 68 in a subterranean well. In one
example, the method can comprise deploying a plugging device
60 into the well, the plugging device 60 including a body
64, and an outer material 306 enveloping the body 64 (e.g.,
completely surrounding the body 64 on all sides, as in the
examples of FIGS. 43-45), the outer material 306 having a
greater flexibility than a material of the body 64; and
conveying the plugging device 60 by fluid flow 74, 208 into
engagement with the opening 46, 68, the body 64 preventing
the plugging device 60 from extruding through the opening
46, 68, and the outer material 306 blocking the fluid flow
74, 208 between the body 64 and the opening 46, 68.
The method may include forming the outer material 306
with a relatively low density material, or at least one of a
foam material and a sponge material. The method may include
forming the outer material with at least one of a wrapper, a
bag, a fabric, a mesh material, a net material and a gauze
material.
Another method of plugging an opening 46, 68 in a
subterranean well is described above. In this example, the
method comprises: deploying a plugging device 60 into the
well, the plugging device 60 including at least two bodies
64, and a washer element 308 connected between the bodies
64, the washer element 308 being generally disk-shaped and
comprising a hole 310, a line 66 extending through the hole
310 and connected to the bodies 64 on respective opposite
sides of the washer element 308; and conveying the plugging
device 60 by fluid flow 74, 208 into engagement with the
opening 46, 68, the washer element 308 preventing the
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plugging device 60 from being conveyed through the opening
46, 68, and the washer element 308 blocking the fluid flow
74, 208 through the opening 46, 68.
The conveying step may include at least one of the
bodies 64 being conveyed into the opening 46, 68. The
conveying step may include at least one of the bodies 64
being conveyed through the opening 46, 68.
The line 66 may comprise joined together fibers 62. The
line 66 may comprise a rope.
The method may include forming the bodies 64 as knots
in the line 66. The method may include forming the bodies 64
with fibers 62 extending outwardly from the bodies 64.
A method of completing a well is also provided to the
art by the above disclosure. In one example, the method can
comprise: conveying a bottom hole assembly 22 into the well
on a conveyance 204, the bottom hole assembly 22 comprising
at least one perforator 48; forming perforations 46a in the
well with the perforator 48; then displacing the bottom hole
assembly 22 further into the well, thereby extending the
conveyance 204 longitudinally across the first perforations
46a; and then flowing a stimulation fluid 208 into the first
perforations 46a.
The conveyance 204 may extend longitudinally across the
first perforations 46a during the stimulation fluid 208
flowing step. The conveyance 204 may comprise a wireline,
and the wireline may extend longitudinally across the first
perforations 46a during the stimulation fluid 208 flowing
step.
The method may include plugging the first perforations
46a, displacing the bottom hole assembly 22 to a desired
position in the well, forming second perforations 46b at the
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desired position, and flowing the stimulation fluid 208 into
the second perforations 46b.
The plugging step and the second perforations 46b
forming step may be performed without withdrawing the bottom
hole assembly 22 from the well. These steps can be performed
in a single trip of the bottom hole assembly 22 into the
wellbore 14.
The first perforations 46a forming step, the second
perforations 46b forming step, the stimulation fluid 208
flowing into the first perforations 46a step and the
stimulation fluid 208 flowing into the second perforations
46b step may be performed without withdrawing the bottom
hole assembly 22 from the well. These steps can be performed
in a single trip of the bottom hole assembly 22 into the
wellbore 14.
Another method of completing a well is described above.
In this example, the method comprises: perforating a first
zone 40a with a perforator 48 of a bottom hole assembly 22
in the well; fracturing the first zone 40a; perforating a
second zone 40b; and fracturing the second zone 40b. The
first zone 40a perforating step, the first zone 40a
fracturing step, the second zone 40b perforating step and
the second zone 40b fracturing step can be performed without
withdrawing the bottom hole assembly 22 from the well.
These steps can be performed in a single trip of the bottom
hole assembly 22 into the wellbore 14.
At least one of the first zone 40a fracturing step and
the second zone 40b fracturing step may be performed while
the bottom hole assembly 22 is positioned in the well.
The method may comprise conveying the bottom hole
assembly 22 into the well with a conveyance 204. The
conveyance 204 may extend longitudinally across the first
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zone 40a after the first zone 40a perforating step and
during the second zone 40b fracturing step. The conveyance
204 may comprise a wireline.
The conveying step may include displacing the bottom
hole assembly 22 by fluid flow 74, 208 through the well.
The method may include displacing the bottom hole
assembly 22 to an increased diameter section of the well
prior to the first zone 40a fracturing.
The method may include, after the first zone 40a
perforating step, displacing the bottom hole assembly 22 to
a position downhole from the first zone 40a, and the bottom
hole assembly 22 remaining at the position during the first
zone 40a fracturing step.
Although various examples have been described above,
with each example having certain features, it should be
understood that it is not necessary for a particular feature
of one example to be used exclusively with that example.
Instead, any of the features described above and/or depicted
in the drawings can be combined with any of the examples, in
addition to or in substitution for any of the other features
of those examples. One example's features are not mutually
exclusive to another example's features. Instead, the scope
of this disclosure encompasses any combination of any of the
features.
Although each example described above includes a
certain combination of features, it should be understood
that it is not necessary for all features of an example to
be used. Instead, any of the features described above can be
used, without any other particular feature or features also
being used.
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It should be understood that the various embodiments
described herein may be utilized in various orientations,
such as inclined, inverted, horizontal, vertical, etc., and
in various configurations, without departing from the
principles of this disclosure. The embodiments are described
merely as examples of useful applications of the principles
of the disclosure, which is not limited to any specific
details of these embodiments.
In the above description of the representative
examples, directional terms (such as "above," "below,"
"upper," "lower," etc.) are used for convenience in
referring to the accompanying drawings. However, it should
be clearly understood that the scope of this disclosure is
not limited to any particular directions described herein.
The terms "including," "includes," "comprising,"
"comprises," and similar terms are used in a non-limiting
sense in this specification. For example, if a system,
method, apparatus, device, etc., is described as "including"
a certain feature or element, the system, method, apparatus,
device, etc., can include that feature or element, and can
also include other features or elements. Similarly, the term
"comprises" is considered to mean "comprises, but is not
limited to."
Of course, a person skilled in the art would, upon a
careful consideration of the above description of
representative embodiments of the disclosure, readily
appreciate that many modifications, additions,
substitutions, deletions, and other changes may be made to
the specific embodiments, and such changes are contemplated
by the principles of this disclosure. For example,
structures disclosed as being separately formed can, in
other examples, be integrally formed and vice versa.
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Accordingly, the foregoing detailed description is to be
clearly understood as being given by way of illustration and
example only, the spirit and scope of the invention being
limited solely by the appended claims and their equivalents.
