U.S. patent application number 15/134133 was filed with the patent office on 2017-10-26 for coiled tubing degradable flow control device.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Robert Bucher, Mohammad Hajjari, Manuel P. Marya.
Application Number | 20170306716 15/134133 |
Document ID | / |
Family ID | 60090077 |
Filed Date | 2017-10-26 |
United States Patent
Application |
20170306716 |
Kind Code |
A1 |
Hajjari; Mohammad ; et
al. |
October 26, 2017 |
Coiled Tubing Degradable Flow Control Device
Abstract
An assembly for inclusion in a tool string conveyed via coiled
tubing within a wellbore. The assembly includes a mandrel having a
passage for receiving fluid via the coiled tubing. The assembly
further includes a packer disposed about the mandrel and expandable
into sealing contact with a wall of the wellbore in response to
receiving the fluid from the passage. The assembly also includes a
flow control device controlling flow of the fluid from the passage
into the packer. The flow control device includes a degradable
material that is reactive to the fluid.
Inventors: |
Hajjari; Mohammad; (Sugar
Land, TX) ; Marya; Manuel P.; (Sugar Land, TX)
; Bucher; Robert; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
60090077 |
Appl. No.: |
15/134133 |
Filed: |
April 20, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/127 20130101;
E21B 34/063 20130101; E21B 17/20 20130101; E21B 23/06 20130101 |
International
Class: |
E21B 33/127 20060101
E21B033/127; E21B 43/16 20060101 E21B043/16; E21B 17/20 20060101
E21B017/20; E21B 34/06 20060101 E21B034/06; E21B 47/00 20120101
E21B047/00; E21B 43/25 20060101 E21B043/25 |
Claims
1. An apparatus comprising: an assembly for inclusion in a tool
string conveyed via coiled tubing within a wellbore, wherein the
assembly comprises: a mandrel comprising a passage for receiving
fluid via the coiled tubing; a packer disposed about the mandrel
and expandable into sealing contact with a wall of the wellbore in
response to receiving the fluid from the passage; and a flow
control device controlling flow of the fluid from the passage into
the packer and comprising a degradable material reactive to the
fluid.
2. The apparatus of claim 1 wherein: the mandrel comprises: a first
mandrel comprising a first passage; and a second mandrel comprising
a second passage; the first and second mandrels are at least
indirectly coupled in a manner permitting fluid communication
between the first and second passages; the packer is disposed about
one of the first and second mandrels; and the flow control device
is disposed in one of the first and second mandrels.
3. The apparatus of claim 1 wherein the degradable material
degrades when exposed to the fluid.
4. The apparatus of claim 1 wherein the flow control device
restricts the fluid flow from the passage into the packer until the
degradable material degrades in reaction to the fluid.
5. The apparatus of claim 1 wherein the flow control device permits
an increasing fluid flow rate as the degradable material degrades
in reaction to the fluid.
6. The apparatus of claim 1 wherein the flow control device
comprises an orifice initially open to fluid flow, and wherein a
flow area of the orifice increases as the degradable material
degrades in reaction to the fluid.
7. The apparatus of claim 1 wherein the degradable material
comprises a plurality of degradable materials reactive to the fluid
at different corresponding rates.
8. The apparatus of claim 1 wherein the degradable material
comprises a plurality of layers each formed of a corresponding one
of a plurality of different degradable materials each reactive to
the fluid at different corresponding rates.
9. The apparatus of claim 8 wherein the plurality of layers
comprises a radially inner layer of a first degradable material and
a radially outer layer of a second degradable material, wherein the
first degradable material is substantially more reactive to the
fluid than the second degradable material, and wherein the radially
inner layer initially defines a passage for communicating the fluid
through the flow control device.
10. The apparatus of claim 1 wherein the degradable material is an
alloy comprising aluminum, magnesium, and gallium.
11. An apparatus comprising: a tool string conveyed via coiled
tubing within a wellbore, wherein the tool string includes an
assembly comprising: a mandrel comprising a passage for receiving
fluid via the coiled tubing; a packer disposed about the mandrel
and expandable into sealing contact with a wall of the wellbore in
response to receiving the fluid from the passage; and a flow
control device controlling flow of the fluid from the passage into
the packer and comprising a degradable material reactive to the
fluid.
12. The apparatus of claim 11 wherein the tool string further
comprises at least one of: an isolation valve operable for fluidly
isolating the passage from the wellbore; a flow restrictor operable
for restricting flow of the fluid from the passage into the
wellbore; and/or a check valve operable for permitting flow of the
fluid from the passage into the wellbore and preventing flow of the
fluid from the wellbore into the passage.
13. The apparatus of claim 11 wherein the tool string further
comprises at least one of: a telemetry tool operable for
facilitating communication between the tool string and surface
equipment; a depth correlation tool operable for determining
location of the tool string within the wellbore; and/or a casing
collar locator operable for determining location of the tool string
within the wellbore.
14. The apparatus of claim 11 wherein the flow control device
permits an increasing fluid flow rate as the degradable material
degrades in reaction to the fluid.
15. The apparatus of claim 11 wherein the flow control device
comprises an orifice initially open to fluid flow through the flow
control device, and wherein a flow area of the orifice increases as
the degradable material degrades in reaction to the fluid.
16. A method comprising: conveying a tool string via coiled tubing
within a wellbore, wherein the tool string comprises: a mandrel
comprising a passage for receiving fluid via the coiled tubing; a
packer disposed about the mandrel and expandable into sealing
contact with a wall of the wellbore in response to receiving the
fluid from the passage; and a flow control device controlling flow
of the fluid from the passage into the packer and comprising a
degradable material reactive to the fluid; and degrading the
degradable material by communicating the fluid through the flow
control device, via the coiled tubing and the passage, such that
the fluid communicated through the flow control device then
inflates the packer into sealing contact with the wall of the
wellbore.
17. The method of claim 16 wherein the flow control device permits
an increasing fluid flow rate from the passage to the packer as the
degradable material degrades in reaction to the fluid.
18. The method of claim 16 wherein an orifice extending through the
degradable material and initially open to fluid flow through the
flow control device increases as the degradable material degrades
in reaction to the fluid.
19. The method of claim 16 further comprising performing a wellbore
operation while the packer is in sealing contact with the wall of
the wellbore.
20. The method of claim 19 wherein the wellbore operation comprises
at least one of: a scale removal operation; a fracturing operation;
a cleanout operation; and/or an acidizing operation.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Inflatable packers may be attached to coiled tubing and
deployed into a wellbore to perform various hydrocarbon wellbore
operations. For example, such operations include setting an
inflatable packer to seal off a section of the wellbore and
stimulating the wellbore formation above or below the packer by
pumping a treatment fluid (e.g., acid) into the formation. Another
example operation includes setting the inflatable packer and
pumping a water shutoff fluid above or below the packer to stop
water flow into the wellbore from a particular zone of the
formation. In such scenarios, among others, the packer is deflated
for retrieval from the wellbore after the wellbore operation. In
other scenarios, the packer is permanently set and then detached
from the coiled tubing, such as for when cement may then be poured
on top of the packer to create a plug in the wellbore.
[0002] To inflate the packer, pressurized fluid communicated
through the coiled tubing may be injected into the packer. However,
the differential pressure between the inside and outside of the
packer may be excessive, causing damage to the inflatable packer.
For example, in sub-hydrostatic wells, the pressure of the fluid
inside the coiled tubing is greater than the bottom hole pressure
in the wellbore, resulting in a large pressure differential that
may damage the packer or cause the packer to inadvertently start
inflating as the coiled tubing is lowered into the wellbore.
SUMMARY OF THE DISCLOSURE
[0003] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify indispensable
features of the claimed subject matter, nor is it intended for use
as an aid in limiting the scope of the claimed subject matter.
[0004] The present disclosure introduces an apparatus that includes
an assembly for inclusion in a tool string conveyed via coiled
tubing within a wellbore. The assembly includes a mandrel, a
packer, and a flow control device. The mandrel includes a passage
for receiving fluid via the coiled tubing. The packer is disposed
about the mandrel and is expandable into sealing contact with a
wall of the wellbore in response to receiving the fluid from the
passage. The flow control device controls flow of the fluid from
the passage into the packer, and includes a degradable material
reactive to the fluid.
[0005] The present disclosure also introduces an apparatus that
includes a tool string conveyed via coiled tubing within a
wellbore. The tool string includes an assembly that includes a
mandrel, a packer, and a flow control device. The mandrel includes
a passage for receiving fluid via the coiled tubing. The packer is
disposed about the mandrel and is expandable into sealing contact
with a wall of the wellbore in response to receiving the fluid from
the passage. The flow control device controls flow of the fluid
from the passage into the packer, and includes a degradable
material reactive to the fluid.
[0006] The present disclosure also introduces a method that
includes conveying a tool string via coiled tubing within a
wellbore. The tool string includes a mandrel, a packer, and a flow
control device. The mandrel includes a passage for receiving fluid
via the coiled tubing. The packer is disposed about the mandrel and
is expandable into sealing contact with a wall of the wellbore in
response to receiving the fluid from the passage. The flow control
device controls flow of the fluid from the passage into the packer,
and includes a degradable material reactive to the fluid. The
method also includes degrading the degradable material by
communicating the fluid through the flow control device, via the
coiled tubing and the passage, such that the fluid communicated
through the flow control device then inflates the packer into
sealing contact with the wall of the wellbore.
[0007] These and additional aspects of the present disclosure are
set forth in the description that follows, and/or may be learned by
a person having ordinary skill in the art by reading the materials
herein and/or practicing the principles described herein. At least
some aspects of the present disclosure may be achieved via means
recited in the attached claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The present disclosure is best understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0009] FIG. 1 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0010] FIG. 2 is a schematic sectional view of a portion of an
example implementation of the apparatus shown in FIG. 1 according
to one or more aspects of the present disclosure.
[0011] FIG. 3 is an axial view of a portion of an example
implementation of the apparatus shown in FIG. 2 according to one or
more aspects of the present disclosure.
[0012] FIG. 4 is an axial view of another example implementation of
the apparatus shown in FIG. 3 according to one or more aspects of
the present disclosure.
[0013] FIG. 5 is a sectional view of a portion of an example
implementation of the apparatus shown in FIG. 2 according to one or
more aspects of the present disclosure.
[0014] FIG. 6 is a sectional view of another example implementation
of the apparatus shown in FIG. 5 according to one or more aspects
of the present disclosure.
[0015] FIG. 7 is a flow-chart diagram of at least a portion of an
example implementation of a method according to one or more aspects
of the present disclosure.
DETAILED DESCRIPTION
[0016] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, merely examples and are
not intended to be limiting. In addition, the present disclosure
may repeat reference numerals and/or letters in the various
examples. This repetition is for simplicity and clarity, and does
not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Moreover, the
formation of a first feature over or on a second feature in the
description that follows may include embodiments in which the first
and second features are formed in direct contact, and may also
include embodiments in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
[0017] FIG. 1 is a schematic view of at least a portion of an
example implementation of a wellsite system 100 according to one or
more aspects of the present disclosure, representing an example
coiled tubing environment in which one or more apparatus described
herein may be implemented, including to perform one or more methods
and/or processes also described herein. However, it is to be
understood that aspects of the present disclosure are also
applicable to implementations in which other tubular or fluid
conveying members, such as drill pipe, are utilized instead of or
in addition to the coiled tubing.
[0018] FIG. 1 depicts a wellsite surface 105 upon which various
wellsite equipment is disposed proximate a wellbore 120. FIG. 1
also depicts a sectional view of the Earth below the wellsite
surface 105 containing the wellbore 120, as well as a tool string
110 positioned within the wellbore 120. The wellbore 120 extends
from the wellsite surface 105 into one or more subterranean
formations 130. When utilized in cased-hole implementations, a
cement sheath 124 may secure a casing 122 within the wellbore 120.
However, one or more aspects of the present disclosure are also
applicable to open-hole implementations, in which the cement sheath
124 and the casing 122 have not yet been installed in the wellbore
120.
[0019] At the wellsite surface 105, the wellsite system 100 may
comprise a control center 180 comprising processing and
communication equipment operable to send, receive, and process
electrical and/or optical signals. The control center 180 is
operable to control at least some aspects of operations of the
wellsite system 100. The control center 180 may comprise an
electrical power source (not shown) operable to supply electrical
power to components of the wellsite system 100, including the tool
string 110. The electrical signals, the optical signals, and the
electrical power may be transmitted between the control center 180
and the tool string 110 via conduits 184, 186 extending between the
control center 180 and the tool string 110. The conduits 184, 186
may each comprise one or more electrical conductors, such as
electrical wires, lines, or cables, which may transmit electrical
power and/or electrical control signals from the control center 180
to the tool string 110, as well as electrical sensor, feedback,
and/or other data signals from the tool string 110 to the control
center 180. The conduits 184, 186 may each further comprise one or
more optical conductors, such as fiber optic cables, which may
transmit light pulses and/or other optical signals between the
control center 180 and the tool string 110. In an embodiment, the
conduits 184, 186 may comprise only fiber optics for transmitting
signals such as between the tool string 110 and the control center
180.
[0020] The conduits 184, 186 may collectively comprise a plurality
of conduits or conduit portions interconnected in series and/or in
parallel and extending between the control center 180 and the tool
string 110. For example, as depicted in the example implementation
of FIG. 1, the conduit 184 extends between the control center 180
and a reel 160 of coiled tubing 162, such that the conduit 184 may
remain substantially stationary with respect to the wellsite
surface 105. The conduit 186 extends between the reel 160 and the
tool string 110 via the coiled tubing 162, including the coiled
tubing 162 spooled on the reel 160. Thus, the conduit 186 may
rotate and otherwise move with respect to the wellsite surface 105.
The reel 160 may be rotatably supported on the wellsite surface 105
by a stationary base 164, such that the reel 160 may be rotated to
advance and retract the coiled tubing 162 within the wellbore 120.
The conduit 186 may be contained within an internal fluid passage
of the coiled tubing 162, secured externally to the coiled tubing
162, or embedded within the structure of the coiled tubing 162. A
rotary joint 150, such as may be known in the art as a collector,
provides an interface between the stationary conduit 184 and the
moving conduit 186.
[0021] The wellsite system 100 further comprises a fluid source 140
from which a fluid may be conveyed by a pump 141 and fluid conduits
142 to the reel 160 of the coiled tubing 162. The fluid conduits
142 extending between the pump 141 and the coiled tubing 162 may be
fluidly connected to the coiled tubing 162 by a swivel or other
rotating coupling (obstructed from view in FIG. 1). The coiled
tubing 162 may be utilized to convey the fluid received from the
fluid source 140 (via the pump 141) to the tool string 110 coupled
at a downhole end of the coiled tubing 162 within the wellbore
120.
[0022] The wellsite system 100 may further comprise a support
structure 170, such as may include or otherwise support a coiled
tubing injector 171 and/or other apparatus for facilitating
movement of the coiled tubing 162 in the wellbore 120. Other
support structures may also be included, such as a derrick, a
crane, a mast, a tripod, and/or other structures. A diverter 172, a
blow-out preventer (BOP) 173, and/or a fluid handling system 174
may also be included as part of the wellsite system 100. For
example, during deployment, the coiled tubing 162 may be passed
from the injector 171, through the diverter 172 and the BOP 173,
and into the wellbore 120. The tool string 110 may be conveyed
along the wellbore 120 via the coiled tubing 162 in conjunction
with the coiled tubing injector 171, such as may apply an
adjustable uphole and downhole force to the coiled tubing 162 to
advance and retract the tool string 110 within the wellbore
120.
[0023] During downhole operations, the fluid from the fluid source
140 may be conveyed through the coiled tubing 162 into the wellbore
120 adjacent the tool string 110. For example, the fluid may be
directed into the wellbore 120 through one or more ports (not
shown) in the tool string 110. Thereafter, the fluid may flow in
the uphole direction and out of the wellbore 120. The diverter 172
may direct the returning fluid to the fluid handling system 174
through one or more conduits 176. The fluid handling system 174 may
clean the fluid and/or prevent the fluid from escaping into the
environment. The fluid may then be returned to the fluid source 140
or otherwise contained for later use, treatment, and/or
disposal.
[0024] The tool string 110 may comprise one or more modules,
sensors, and/or downhole tools 112, 114, hereafter collectively
referred to as the tools 112, 114. For example, one or more of the
tools 112, 114 may be or comprise at least a portion of a
monitoring tool, an acoustic tool, a density tool, a drilling tool,
an electromagnetic (EM) tool, a formation testing tool, a fluid
sampling tool, a formation logging tool, a formation measurement
tool, a gravity tool, a magnetic resonance tool, a neutron tool, a
nuclear tool, a photoelectric factor tool, a porosity tool, a
reservoir characterization tool, a resistivity tool, a seismic
tool, a surveying tool, and/or a tough logging condition (TLC)
tool, among other examples within the scope of the present
disclosure. One or more of the tools 112, 114 may also be or
comprise a perforating gun and/or another perforating or cutting
tool.
[0025] One or more of the tools 112, 114 may also be or comprise a
depth correlation tool, such as a casing collar locator (CCL) for
detecting ends of casing collars by sensing a magnetic irregularity
caused by a relatively high mass of an end of a collar of the
casing 122. One or more of the tools 112, 114 may also or instead
be or comprise a gamma ray (GR) tool that may be utilized for depth
correlation. The CCL and/or GR tools may transmit signals in
real-time to the wellsite surface 105, such as the control center
180, via the conduits 184, 186. The CCL and/or GR tool signals may
be utilized to determine the position of the tool string 110, such
as with respect to known casing collar numbers and/or positions
within the wellbore 120. Therefore, the CCL and/or GR tools may be
utilized to detect and/or log the location of the tool string 110
within the wellbore 120, such as during well service operations
described below.
[0026] One or more of the tools 112, 114 may also be or comprise a
telemetry tool to facilitate communication between the tool string
110 and the control center 180. The telemetry tool may be a wired
electrical telemetry tool and/or an optical telemetry tool, among
other examples.
[0027] One or more of the tools 112, 114 may also comprise one or
more sensors 113, 115, respectively. The sensors 113, 115 may
include inclination and/or other orientation sensors, such as
accelerometers, magnetometers, gyroscopic sensors, and/or other
sensors for utilization in determining the orientation of the tool
string 110 relative to the wellbore 120. The sensors 113, 115 may
also or instead include sensors for utilization in determining
petrophysical and/or geophysical parameters of a portion of the
formation 130 along the wellbore 120, including measuring and/or
detecting one or more of pressure, temperature, strain,
composition, and/or electrical resistivity, among other examples
within the scope of the present disclosure. The sensors 113, 115
may also or instead include fluid sensors for utilization in
detecting the presence of fluid, a certain fluid, or a type of
fluid within the tool string 110 or the wellbore 120. The sensors
113, 115 may also or instead include fluid sensors for utilization
in measuring properties and/or determining composition of the fluid
sampled from the wellbore 120 and/or the formation 130, such as
spectrometers, fluorescence sensors, optical fluid analyzers,
density sensors, viscosity sensors, pressure sensors, and/or
temperature sensors, among other examples within the scope of the
present disclosure. Although FIG. 1 shows the coiled tubing 162
containing the conduit 186 disposed therein and extending between
the reel 160 and the tool string 110, it is to be understood that
the conduit 186 may be omitted from the coiled tubing 162, such as
when performing well service operations or other downhole
operations that do not utilize wired signal communication between
the downhole tools 112, 114 and/or sensors 113, 115 and the control
center 180.
[0028] The tool string 110 may also include a packer assembly 200,
comprising an inflatable packer 202 disposed about a mandrel 204.
The packer 202 may be set (i.e., expanded) into sealing contact
against the wall 126 of the wellbore 120 to form a fluid seal
selectively isolating portions of the wellbore 120 during
performance of various testing, treatment, and/or well service
operations. Although the tool string 110 shown in FIG. 1 comprises
a single packer assembly 200 coupled between the two downhole tools
112, 114, it is to be understood that additional packer assemblies
200 may be included, and in other locations within the tool string
110. For example, two or more packer assemblies 200 may be utilized
to isolate an interval within the wellbore 120 for performing
various testing and/or treatment operations utilizing one or more
of the tools 112, 114. The tool string 110 may also comprise a
different number of tools 112, 114 relative to the example
implementation depicted in FIG. 1, and each tool 112, 114 may be
directly and/or indirectly coupled with the packer assembly
200.
[0029] The packer 202 is inflated by introducing fluid into the
packers through the coiled tubing 162 via the mandrel 204. To
increase the pressure of the fluid in the mandrel 204 to a level
that is sufficient to inflate the packer 202, the tool string 100
may also comprise a fluid control device 117 for blocking the flow
of the fluid from the tool string 110 into the wellbore 120. The
fluid control device 117 is depicted in FIG. 1 as being coupled
between the mandrel 204 and the downhole tool 114. However, the
fluid control device 117 may also be located below the downhole
tool 114, and may form a portion of the downhole tool 114.
[0030] The fluid control device 117 may comprise a fluid barrier
for plugging the flow area of an internal fluid passage 206 (shown
in FIG. 2) extending through the mandrel 204 and other portions of
the tool string 110. For example, the fluid barrier may comprise a
plug, a drop ball, a gate valve, a flapper valve, a ball valve, or
an isolation valve. The fluid control device 117 may also or
instead comprise a flow-restricting device for reducing or
restricting flow of the fluid from the passage 206 into the
wellbore 120. For example, the flow-restricting device may comprise
a flow restrictor, a choke, or a drain valve. The fluid control
device 117 may also or instead comprise a pressure control device,
such as a pressure-responsive opening and closing valve for
preventing fluid from flowing from the passage 206 into the
wellbore 120 until the fluid within the passage 206 achieves a
predetermined pressure. The fluid control device 117 may also or
instead comprise a check valve, such as may prevent wellbore fluid
from flowing from the wellbore 120 into the passage 206 but permit
the fluid to flow from the passage 206 into the wellbore 120 when a
pressure differential across the check valve reaches a
predetermined value. The fluid control device 117 may also or
instead comprise an inline universal valve, such as may be
selectively operable to block fluid flow or freely permit fluid
flow from the passage 206 into the wellbore 120.
[0031] The fluid utilized to inflate the packer 202 may be a
workover fluid, such as may include a mixture of water and diesel
or water and methanol. The fluid utilized to inflate the packer 202
may instead be a brine solution, such as may comprise water and
sodium chloride, calcium chloride, and/or potassium chloride. The
water utilized as part of the workover fluid or the brine solution
may include fresh water or seawater. However, workover fluids and
brine solutions are merely examples, and it is to be understood
that other fluids may be utilized to inflate the packer 202 within
the scope of the present disclosure.
[0032] After the packer 202 is set against the wall 126 of the
wellbore 120, various testing operations may be performed utilizing
one or more of the downhole tools 112, 114 and/or sensors 113, 115.
The packer assembly 200 may also be utilized for well pressure
control, such as when changing surface equipment or tubing. The
packer assembly 200 may also be utilized as a downhole equipment
hanger for attaching other tools downhole from the packer assembly
200.
[0033] The packer assembly 200 may also be utilized for well
service or treatment operations, such as fracturing operations,
well stimulation operations, acid treatment operations, water
shut-off operations, well abandonment operations, well testing
operations, gravel packing operations, cementing operations, and
perforating operations, among other examples. During such well
service operations, a stimulation fluid, a treatment fluid, and/or
other fluids may be communicated through the coiled tubing 162 and
into the tool string 110 for injection into the wellbore 120
adjacent the tool string 110. The fluid may be directed into the
wellbore 120 downhole from the tool string 110 and/or into an
annular area between the wall 126 of the wellbore 120 and the
coiled tubing 162 uphole from the packer 202. Accordingly, the tool
string 110 may comprise an additional fluid control device 116
located uphole from the packer assembly 200. The fluid control
device 116 is depicted in FIG. 1 as being coupled between the
mandrel 204 and the downhole tool 112. However, the fluid control
device 116 may also be located above the downhole tool 112, and may
form a portion of the downhole tool 112. The fluid control device
116 may comprise a fluid barrier, a flow-restricting device, a
pressure control device, a check valve, or an inline universal
valve, as described above with respect to the fluid control device
117. However, the fluid control devices 116, 117 may be different
ones of these examples, and still be utilized to selectively block,
divert, and/or permit fluid flow between the fluid passage 206 and
a selected portion of the wellbore 120.
[0034] For example, if the fluid is intended to be injected into
the wellbore 120 uphole from the packer 202, the fluid control
device 117 may comprise the fluid barrier described above, and may
be utilized to prevent the fluid from flowing into the wellbore
120, while the fluid control device 116 may comprise the inline
universal valve described above, and may be utilized to permit
fluid flow into the wellbore 120 via one or more ports (not shown).
However, if the fluid is intended to be injected into the wellbore
120 downhole from the packer 202, the fluid control device 116 may
be omitted, or may comprise the above-described inline universal
valve being set to prevent fluid flow into the wellbore 120 and
permit fluid flow along the passage 206, while the fluid control
device 117 may also comprise an inline universal valve that is set
to permit fluid flow from the passage 206 into the wellbore 120.
Prior to injecting the fluid into the wellbore 120 downhole from
the packer 202, the fluid barrier may be retrieved or otherwise
removed after the packer 202 is set, thereby clearing the passage
206 through the tool string 110 to allow fluid communication with
the wellbore 120.
[0035] One or both of the fluid control devices 116, 117 may
comprise a mandrel (not shown) having flow ports for fluidly
connecting the fluid passage 206 and the wellbore 120, and a
sliding sleeve (not shown) disposed within the mandrel and movable
to selectively open and close the flow ports. The fluid control
device 116 may also comprise a circulating valve for circulating
the fluid through the coiled tubing 162 and the annular portion of
the wellbore 120 uphole from the packer 202.
[0036] FIG. 2 is a schematic sectional view of a portion of an
example implementation of the packer assembly 200 shown in FIG. 1
according to one or more aspects of the present disclosure. The
following description refers to FIGS. 1 and 2, collectively.
[0037] The packer assembly 200 comprises the mandrel 204, which at
least partially defines the fluid passage 206 extending
longitudinally through the tool string 110 and the mandrel 204 for
receiving the fluid via the coiled tubing 162. The mandrel 204 may
comprise multiple portions collectively forming the mandrel 204
and, thus, collectively defining the fluid passage 206. For
example, in the example implementation depicted in FIG. 2, the
mandrel 204 comprises an upper mandrel 208 defining an upper
passage 209 and a lower mandrel 210 defining a lower passage 211,
such that the upper and lower passages 209, 210 collectively form
at least a portion of the fluid passage 206. Other implementations
within the scope of the present disclosure, however, include
implementations in which the mandrel 204 is a single, discrete
member, as well as implementations in which the mandrel 204
comprises more than the two separate mandrels 208, 210 shown in
FIG. 2.
[0038] In the context of the present disclosure, the terms "upper"
and "lower" refer to location and/or orientation relative to the
wellbore 120. Thus, for example, the upper mandrel 208 is located
further uphole than the lower mandrel 210, and the lower mandrel
210 is located further downhole than the upper mandrel 208.
[0039] The upper mandrel 208 comprises a mechanical interface 212
for mechanically coupling the upper mandrel 208 with a
corresponding mechanical interface 214 of the lower mandrel 210 in
a manner permitting fluid communication between the upper and lower
passages 209, 211. The upper and lower interfaces 212, 214 may each
comprise threaded connectors, fasteners, box-pin couplings, and/or
other mechanical coupling means. Although the upper and lower
mandrels 208, 210 are depicted in FIG. 2 as being coupled directly
together, the upper and lower mandrels 208, 210 may instead be
indirectly coupled via intermediate mandrels, conduits, tools,
and/or other devices in a manner permitting fluid communication
between the upper and lower passages 209, 211.
[0040] The uphole end of the mandrel 204 (e.g., the uphole end of
the upper mandrel 208) comprises a mechanical interface (not shown)
for mechanically coupling the packer assembly 200 with a
corresponding mechanical interface (not shown) of the
uphole-adjacent component of the tool string 110, such as the
downhole tool 112 or the fluid control device 116. A downhole end
of the mandrel 204 (e.g., the downhole end of the lower mandrel
210) comprises a mechanical interface (not shown) for mechanically
coupling the packer assembly 200 with a corresponding mechanical
interface (not shown) of the downhole-adjacent component of the
tool string 110, such as the downhole tool 114 or the fluid control
device 117. Such interfaces of the mandrel 204 may be integrally
formed with the mandrel 204, or may be discrete components coupled
to the mandrel 204 via threaded connection and/or other means. The
interfaces may each comprise threaded connectors, fasteners,
box-pin couplings, and/or other mechanical coupling means for
coupling with the adjacent components of the tool string 110.
[0041] The packer 202 is expandable into sealing contact with the
wall 126 of the wellbore 120 in response to receiving fluid from
the fluid passage 206. That is, the packer 202 comprises or at
least partially defines an expandable volume 216 for receiving the
fluid from the passage 206. For example, upper and lower ends 203
of the packer 202 may each be secured to the mandrel 204 by a
corresponding collar 218. Each collar 218 may comprise an overlay
portion 220 extending longitudinally over the corresponding end 203
of the packer 202. The mandrel 204 comprises one or more fluid
passages 215 extending through a wall 217 of the mandrel 204 to
fluidly connect the fluid passage 206 with the expandable volume
216. For example, at least one of the collars 218 (e.g., the upper
collar 218 in the example implementation depicted in FIG. 2)
comprises a fluid passage 222 fluidly connecting the one or more
fluid passages 215 of the mandrel 204 and the expandable volume 216
of the packer 202. However, while the fluid passage 222 is depicted
in FIG. 2 as extending through the upper collar 218, the passage
222 and/or other means for fluidly connecting the passage 206 and
the expandable volume 216 of the packer 202 may instead be formed
within another portion of the packer assembly 200.
[0042] A check valve 225 may be disposed within and form a portion
of the fluid passage 222. The check valve 225 may permit fluid to
flow from the passage 206 into the expandable volume 216 while
preventing fluid from escaping back into the fluid passage 206
after the packer 202 is set. The check valve 225 may be of typical
design known in the art, such as may comprise a fluid blocking
member 226 contained within a flow-through housing 227. A closure
seat 228 on an inlet side of the housing 227 may cooperate with the
fluid blocking member 226 to fluidly seal against the fluid
blocking member 226. Fluid flow directed through the seat 228
displaces the fluid blocking member 226 from the seat 228 to permit
fluid flow into the expandable volume 216. Attempted flow directed
in an opposite direction against the fluid blocking member 226
imposes a pressure differential force on the fluid blocking member
226 that urges the fluid blocking member 226 against the seat 228
to form the fluid seal and, thus, prevent fluid flow out of the
expandable volume 216. The fluid blocking member 226 may be freely
disposed within the housing 227, or the fluid blocking member 226
may be spring-loaded or otherwise mechanically biased against the
seat 228. The check valve 225 may be set to permit fluid to flow
through the check valve 225 when a pressure differential across the
check valve reaches a predetermined threshold. For example, the
predetermined threshold may range between about 50 pounds per
square inch (PSI) and about 250 PSI, although other values are also
within the scope of the present disclosure.
[0043] As described above, excessive pressure differential between
the packer-setting fluid within the fluid passage 206 and wellbore
fluid within the wellbore 120 surrounding the packer 202 may cause
excessive fluid flow into the packer 202, which may damage and/or
prematurely inflate the packer 202. Such excessive pressure and/or
flow may be the result of the pressure of the packer-setting fluid
discharged from the pump 141 and/or the hydrostatic pressure of the
column of packer-setting fluid within the coiled tubing 162.
However, the packer assembly 200 of the present disclosure also
comprises a flow control device 230 within the passage 206,
interposing the column of packer-setting fluid within the coiled
tubing 162 and the portion of the passage 206 that is in fluid
communication with the expandable volume 216 of the packer 202. The
flow control device 230 reduces or otherwise controls flow and/or
pressure of the fluid flowing from the coiled tubing 162 into the
portion of the passage 206 the fluidly communicates with the
expandable volume 216 of the packer 202, thereby reducing or
preventing damage to the packer 202 during inflation
operations.
[0044] The flow control device 230 is located uphole from the fluid
passages 215 so as to control the flow rate and pressure of the
fluid entering the fluid passages 215. The flow control device 230
may be disposed within the upper passage 209 of the upper mandrel
208, as depicted in FIG. 2, or within the lower passage 211 of the
lower mandrel 210, or elsewhere within the passage 206 of the
mandrel 204 in a manner permitting the flow control device 230 to
reduce or otherwise control the flow and/or pressure of the fluid
introduced into the packer 202 from the coiled tubing 162 via the
fluid passages 206, 215, 222. For example, the flow control device
230 may instead be disposed within the fluid passages 215 and/or
the fluid passages 222.
[0045] At least a portion of the flow control device 230 comprises
a degradable material 232 reactive to the packer-setting fluid
communicated through the coiled tubing 162. The degradable material
232 may be disposed within a flow-through housing 234 in a manner
permitting the degradable material 232 to initially remain within
the housing 234 during the inflation operations. The housing 234
may also permit the flow control device 230 to be installed or
otherwise retained within the mandrel 204 along the fluid passage
206. A passage 236 formed in the degradable material 232 is
initially open to fluid flow through the flow control device 230,
such that the flow control device 230 may act as a choke or similar
flow restrictor to reduce the flow and/or pressure of the fluid
introduced into the packer 202.
[0046] The degradable material 232 may be an alloy or other
combination of elements, compounds, and/or other constituents
formulated such that the degradable material 232 degrades (e.g.,
dissolves, erodes, breaks down) when exposed to the packer-setting
fluid. Accordingly, as the packer-setting fluid flows through the
flow control device 230, the passage 236 enlarges as the degradable
material 232 degrades in reaction to the packer-setting fluid, thus
permitting a gradually increasing fluid flow rate through the flow
control device 230, and a correspondingly decreasing pressure drop
across the flow control device 230. The degradable material 232 may
be selected based on its mechanical strength (i.e., hardness) and
rate of degradation in reaction to the packer-setting fluid. The
mechanical strength and rate of degradation of the degradable
material 232 may depend on the amounts and perhaps relative
orientations of its constituents. The rate of degradation of the
degradable material 232 may also be affected, for example, by
wellbore conditions, including fluid chemistry, temperature, and
pressure. Accordingly, the degradable material 232 may also be
selected based on the anticipated wellbore conditions.
[0047] The degradable material 232 may be a material degradable by
water or a fluid comprising water. For example, the degradable
material 232 may be degradable by fresh water, seawater, or a brine
solution, such as comprising sodium chloride, calcium chloride,
and/or potassium chloride. The degradable material 232 may be
degradable by a workover fluid, which may include a mixture of
water and diesel or water and methanol. However, it is to be
understood that the degradable material 232 may be degradable by
other fluids within the scope of the present disclosure, including
fluids utilized during well service operations.
[0048] The degradable material 232 may be an aluminum alloy
comprising at least aluminum (Al), magnesium (Mg), and gallium
(Ga). In some implementations, the alloy may have a ratio of
magnesium to gallium ranging between about 0.5 and about 3.5. The
alloy may also comprise indium (In), and perhaps silicon (Si). Some
implementations may also comprise zinc (Zn). Example alloys are set
forth below in Table 1, in which the compositions are listed by
weight percentage. Table 1 also lists the Hardness Vickers Number
(HVN) for each example alloy measured directly after casting of
each alloy, and after performing heat treatment (HT) on each alloy.
However, the present disclosure is not limited to the examples
listed in Table 1, and it is to be understood that the degradable
material 232 may comprise other alloys within the scope of the
present disclosure. For example, the degradable material 232 may
comprise a degradable polymer, such as polyactide (PLA) or
polyglycolide (PGA), among other examples. The degradable material
232 may also or instead comprise a degradable ceramic material.
TABLE-US-00001 TABLE 1 HVN HVN Al Mg Ga In Si Mg/Ga (As Cast)
(After HT) Example 1 98.5 0.5 0.5 0.5 0 1.00 42 78 Example 2 97.5
0.5 1.0 1.0 0 0.50 42 78 Example 3 96.0 2.0 1.0 1.0 0 2.00 50 90
Example 4 94.5 3.5 1.0 1.0 0 3.50 60 99 Example 5 85.4 8.0 3.8 1.6
1.2 2.10 88 132 Example 6 86.6 8.0 3.8 1.6 0 2.11 85 136
[0049] FIG. 3 is an axial view of at least a portion of the flow
control device 230 shown in FIG. 2. The following description
refers to FIGS. 2 and 3, collectively. The initial flow passage 236
is a single orifice extending axially through the degradable
material 232 for communicating the fluid through the flow control
device 230. The passage 236 comprises a decreased inner diameter
244, relative to the inner diameter 245 of the housing 234, that
causes a pressure drop across the flow control device 230 and a
decrease in the flow rate through the flow control device 230. The
inner diameter 244 of the passage 236 increases as the degradable
material 232 degrades in reaction to contact with the fluid flowing
through the passage 236, resulting in an increasing flow rate
through the flow control device 230 and a decreasing pressure drop
across the flow control device 230.
[0050] FIG. 4 is an axial view of another example implementation of
the flow control device 230 shown in FIG. 3 according to one or
more aspects of the present disclosure, and designated in FIG. 4 by
reference numeral 250. The flow control device 250 depicted in FIG.
4 is substantially similar in structure and operation to the flow
control device 230 depicted in FIG. 3, including where indicated by
like reference numbers, except as described below. The following
description refers to FIGS. 2-4, collectively.
[0051] The flow control device 250 also comprises the degradable
material 232 disposed within the housing 234. However, whereas the
flow control device 230 shown in FIGS. 2 and 3 comprises a single
initial passage 236, the flow control device 250 comprises multiple
initial passages 252, 254, 256, each formed in and extending
longitudinally through the degradable material 232 for
communicating the fluid through the flow control device 250. Each
passage 252, 254, 256 has a corresponding inner diameter 253, 255,
257 that causes a pressure drop across the flow control device 250
and a decrease in the flow rate through the flow control device
250. The inner diameters 253, 255, 257 increase as the degradable
material 232 degrades in reaction to contact with the fluid flowing
through the passages 252, 254, 256, resulting in an increasing flow
rate through the flow control device 250 and a decreasing pressure
drop across the flow control device 250.
[0052] Although FIG. 4 depicts the flow control device 250 as
comprising three initial passages 252, 254, 256, it is to be
understood that the flow control device 250 may be implemented with
other quantities of initial passages, including two, four, five,
six, or more. Furthermore, although FIG. 4 shows each of the
passages 252, 254, 256 as having a different inner diameter 253,
255, 257, it is to be understood that the passages 252, 254, 256
may have substantially similar inner diameters 253, 255, 257.
[0053] FIG. 5 is a sectional view of another example implementation
of the flow control device 230 shown in FIG. 3 according to one or
more aspects of the present disclosure, and designated in FIG. 5 by
reference numeral 260. The flow control device 260 depicted in FIG.
5 is substantially similar in structure and operation to the flow
control device 230 depicted in FIG. 3, including where indicated by
like reference numbers, except as described below. The following
description refers to FIGS. 2, 3, and 5, collectively.
[0054] The flow control device 260 also comprises the degradable
material 232 disposed within the housing 234. However, the
degradable material 232 is provided as a plurality of concentric
layers 262, 264, 266 of different degradable materials that are
reactive to the packer-setting fluid at different rates. For
example, the degradable material 232 may include a radially outer
layer 262, an intermediate layer 264, and a radially inner layer
266. The degradable material of the inner layer 266 may be
substantially more reactive to the packer-setting fluid than the
degradable material of the intermediate layer 264, and the
degradable material of the intermediate layer 264 may be
substantially more reactive to the packer-setting fluid than the
degradable material of the outer layer 262.
[0055] The initial passage 236 is formed in and extends axially
through the inner layer 266 for initially communicating the
packer-setting fluid through the flow control device 260. The inner
diameter 244 of the initial passage 236 increases as the degradable
material of the inner layer 266 degrades in reaction to contact
with the packer-setting fluid flowing through the passage 236,
resulting in an increasing flow rate through the flow control
device 260 and a decreasing pressure drop across the flow control
device 260. As the inner diameter 244 of the passage 236 increases,
the inner layer 266 substantially degrades, such that the
intermediate layer 264 then substantially defines the passage 236.
Similarly, the intermediate layer 264 will then also substantially
degrade, such that the outer layer 262 substantially defines the
passage 236, until ultimately the degradable material 232 is
substantially removed from the housing 234. Furthermore, if the
degradable material of the inner layer 266 is substantially more
reactive to the packer-setting fluid than the degradable material
of the intermediate layer 264, and the degradable material of the
intermediate layer 264 is substantially more reactive to the
packer-setting fluid than the degradable material of the outer
layer 26, then the inner diameter 244 of the passage 236 will
increase at a slower rate as each of the layers 262, 264, 266
successively degrades in reaction to contact with the
packer-setting fluid flowing through the passage 236, thereby
resulting in a gradually increasing flow rate through the flow
control device 260 and a gradually decreasing pressure drop across
the flow control device 260.
[0056] FIG. 6 is a sectional view of another example implementation
of the flow control device 260 shown in FIG. 5 according to one or
more aspects of the present disclosure, and designated in FIG. 6 by
reference numeral 270. The flow control device 270 depicted in FIG.
6 is substantially similar in structure and operation to the flow
control device 260 depicted in FIG. 5, including where indicated by
like reference numbers, except as described below.
[0057] The flow control device 270 also comprises the degradable
material 232 disposed as concentric layers 262, 264, 266 within the
housing 234, with the initial passage 236 formed in and extending
axially through the inner layer 266. However, each layer 262, 264,
266 is axially offset from the adjacent layer 262, 264, 266.
Consequently, as the packer-setting fluid flows through the flow
control device 270, degradation of the layers 262, 264, 266 will
form an inwardly tapered upper portion 274, while a lower portion
276 may remain substantially cylindrical.
[0058] FIG. 7 is a flow-chart diagram of at least a portion of an
example implementation of a method (300) according to one or more
aspects of the present disclosure. The method (300) may utilize at
least a portion of a wellsite system and valves, such as the
wellsite system 100 shown in FIG. 1 and the flow control devices
230, 250, 260, 270 shown in FIGS. 2-6. The following description
refers to FIGS. 1-6, collectively.
[0059] The method (300) comprises conveying (310) the tool string
110 via the coiled tubing 162 within the wellbore 120. As described
above, the tool string 110 includes the packer assembly 200, which
comprises the mandrel 204 having the passage 206 for receiving
fluid via the coiled tubing 162, the packer 202 disposed about the
mandrel 204 and expandable into sealing contact with the wall of
the wellbore 120 in response to receiving the fluid from the
passage 206, and a flow control device controlling flow of the
fluid from the passage 206 into the packer 202 and comprising
degradable material 232 reactive to the fluid. The flow control
device may be one of the flow control devices 230, 250, 260, 270
shown in FIGS. 2-6 and/or other implementations within the scope of
the present disclosure. The method (300) also comprises degrading
(320) the degradable material 232 by communicating the fluid
through the flow control device, via the coiled tubing 162 and the
passage 206, such that the fluid communicated through the flow
control device then inflates the packer 202 into sealing contact
with the wall of the wellbore 120.
[0060] As described above, the flow control device initially
reduces fluid flow rate from the passage 206 to the packer 202, and
permits an increasing fluid flow rate from the passage 206 to the
packer 202 as the degradable material 232 degrades in reaction to
the fluid. Thus, an area open to fluid flow through the flow
control device (e.g., the passage 236 depicted in FIGS. 2, 3, 5,
and 6 or the passages 252, 254, 256 depicted in FIG. 4) increases
as the degradable material 232 degrades in reaction to the
fluid.
[0061] The method (300) may also comprise performing (330) a
wellbore operation while the packer 202 is in sealing contact with
the wall of the wellbore 120. The wellbore operation may be a scale
removal operation, a fracturing operation, a cleanout operation, or
an acidizing operation, as described in U.S. Pat. No. 7,617,873,
the entire disclosure of which is hereby incorporated herein by
reference.
[0062] In view of the entirety of the present disclosure, including
the figures and the claims, a person having ordinary skill in the
art will readily recognize that the present disclosure introduces
an apparatus comprising: an assembly for inclusion in a tool string
conveyed via coiled tubing within a wellbore, wherein the assembly
comprises: a mandrel comprising a passage for receiving fluid via
the coiled tubing; a packer disposed about the mandrel and
expandable into sealing contact with a wall of the wellbore in
response to receiving the fluid from the passage; and a flow
control device controlling flow of the fluid from the passage into
the packer and comprising a degradable material reactive to the
fluid.
[0063] The mandrel may comprise: a first mandrel comprising a first
passage; and a second mandrel comprising a second passage. The
first and second mandrels may be at least indirectly coupled in a
manner permitting fluid communication between the first and second
passages. The packer may be disposed about one of the first and
second mandrels. The flow control device may be disposed in one of
the first and second mandrels.
[0064] The degradable material may degrade when exposed to the
fluid.
[0065] The flow control device may restrict the fluid flow from the
passage into the packer until the degradable material degrades in
reaction to the fluid.
[0066] The flow control device may permit an increasing fluid flow
rate as the degradable material degrades in reaction to the
fluid.
[0067] The flow control device may comprise an orifice initially
open to fluid flow, and a flow area of the orifice may increase as
the degradable material degrades in reaction to the fluid. The
orifice may be formed in and extend through the degradable
material. An inner diameter of the orifice may increase as the
degradable material degrades in reaction to the fluid.
[0068] The flow control device may comprise a plurality of orifices
initially open to fluid flow the flow control device, and each of
the plurality of orifices may be formed in and extend through the
degradable material. An inner diameter of each of the plurality of
orifices may increase as the degradable material degrades in
reaction to the fluid.
[0069] The degradable material may comprise a plurality of
degradable materials reactive to the fluid at different
corresponding rates.
[0070] The degradable material may comprise a plurality of layers
each formed of a corresponding one of a plurality of different
degradable materials each reactive to the fluid at different
corresponding rates. The plurality of layers may comprise a
radially inner layer of a first degradable material and a radially
outer layer of a second degradable material, wherein the first
degradable material may be substantially more reactive to the fluid
than the second degradable material, and wherein the radially inner
layer may initially define a passage for communicating the fluid
through the flow control device.
[0071] The degradable material may comprise aluminum, an alloy
comprising aluminum and magnesium, an alloy comprising aluminum and
gallium, or an alloy comprising aluminum, magnesium, and gallium.
For example, the degradable material may comprise an alloy
comprising 85.4-98.5% aluminum, 0.5-8.0% magnesium, and 0.5-3.8%
gallium, by weight.
[0072] The present disclosure also introduces an apparatus
comprising: a tool string conveyed via coiled tubing within a
wellbore, wherein the tool string includes an assembly comprising:
a mandrel comprising a passage for receiving fluid via the coiled
tubing; a packer disposed about the mandrel and expandable into
sealing contact with a wall of the wellbore in response to
receiving the fluid from the passage; and a flow control device
controlling flow of the fluid from the passage into the packer and
comprising a degradable material reactive to the fluid.
[0073] The tool string may further comprise one or more of: an
isolation valve operable for fluidly isolating the passage from the
wellbore; a flow restrictor operable for restricting flow of the
fluid from the passage into the wellbore; a check valve operable
for permitting flow of the fluid from the passage into the wellbore
and preventing flow of the fluid from the wellbore into the
passage; a telemetry tool operable for facilitating communication
between the tool string and surface equipment; a depth correlation
tool operable for determining location of the tool string within
the wellbore; and/or a casing collar locator operable for
determining location of the tool string within the wellbore.
[0074] The flow control device may permit an increasing fluid flow
rate as the degradable material degrades in reaction to the
fluid.
[0075] The flow control device may comprise an orifice initially
open to fluid flow through the flow control device, and a flow area
of the orifice may increase as the degradable material degrades in
reaction to the fluid. The orifice may be formed in and extend
through the degradable material. The flow control device may
comprise a plurality of the orifices.
[0076] The present disclosure also introduces a method comprising:
conveying a tool string via coiled tubing within a wellbore,
wherein the tool string comprises: a mandrel comprising a passage
for receiving fluid via the coiled tubing; a packer disposed about
the mandrel and expandable into sealing contact with a wall of the
wellbore in response to receiving the fluid from the passage; and a
flow control device controlling flow of the fluid from the passage
into the packer and comprising a degradable material reactive to
the fluid; and degrading the degradable material by communicating
the fluid through the flow control device, via the coiled tubing
and the passage, such that the fluid communicated through the flow
control device then inflates the packer into sealing contact with
the wall of the wellbore.
[0077] The flow control device may permit an increasing fluid flow
rate from the passage to the packer as the degradable material
degrades in reaction to the fluid.
[0078] An orifice extending through the degradable material and
initially open to fluid flow through the flow control device may
increase as the degradable material degrades in reaction to the
fluid.
[0079] The method may further comprise performing a wellbore
operation while the packer is in sealing contact with the wall of
the wellbore. The wellbore operation may be a scale removal
operation, a fracturing operation, a cleanout operation, or an
acidizing operation, among other example applications also within
the scope of the present disclosure.
[0080] The foregoing outlines features of several embodiments so
that a person having ordinary skill in the art may better
understand the aspects of the present disclosure. A person having
ordinary skill in the art should appreciate that they may readily
use the present disclosure as a basis for designing or modifying
other processes and structures for carrying out the same functions
and/or achieving the same benefits of the embodiments introduced
herein. A person having ordinary skill in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
[0081] The Abstract at the end of this disclosure is provided to
permit the reader to quickly ascertain the nature of the technical
disclosure. It is submitted with the understanding that it will not
be used to interpret or limit the scope or meaning of the
claims.
* * * * *