U.S. patent application number 15/111366 was filed with the patent office on 2016-11-17 for well system with degradable plug.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Michael Linley Fripp, John Charles Gano, Jean Marc Lopez.
Application Number | 20160333655 15/111366 |
Document ID | / |
Family ID | 56284837 |
Filed Date | 2016-11-17 |
United States Patent
Application |
20160333655 |
Kind Code |
A1 |
Fripp; Michael Linley ; et
al. |
November 17, 2016 |
WELL SYSTEM WITH DEGRADABLE PLUG
Abstract
A downhole assembly is disclosed. The downhole assembly includes
a tube disposed in a wellbore, and a shroud coupled to and disposed
around the circumference of the tube to form an annulus between an
inner surface of the shroud and an outer surface of the tube. The
downhole assembly further includes a flow control device disposed
in the annulus, and a degradable plug disposed in the annulus and
positioned to prevent fluid flow between the annulus and the
tube.
Inventors: |
Fripp; Michael Linley;
(Carrollton, TX) ; Gano; John Charles; (Lowery
Crossing, TX) ; Lopez; Jean Marc; (Plano,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
56284837 |
Appl. No.: |
15/111366 |
Filed: |
December 31, 2014 |
PCT Filed: |
December 31, 2014 |
PCT NO: |
PCT/US2014/073009 |
371 Date: |
July 13, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/12 20130101;
E21B 29/02 20130101; E21B 43/08 20130101; E21B 43/04 20130101; E21B
33/063 20130101; E21B 33/12 20130101; E21B 43/084 20130101; E21B
34/06 20130101 |
International
Class: |
E21B 29/02 20060101
E21B029/02; E21B 34/06 20060101 E21B034/06; E21B 33/12 20060101
E21B033/12; E21B 43/08 20060101 E21B043/08 |
Claims
1. A downhole assembly, comprising: a tube disposed in a wellbore;
a shroud coupled to and disposed around the circumference of the
tube to form an annulus between an inner surface of the shroud and
an outer surface of the tube; a flow control device disposed in the
annulus; and a degradable plug disposed in the annulus and
positioned to prevent fluid flow between the annulus and the
tube.
2. The downhole assembly of claim 1, further comprising a screen
coupled to and disposed uphole from the shroud and coupled to and
disposed around the circumference of the tube such that an annulus
is formed between an inner surface of the screen and the outer
surface of the tube.
3. The downhole assembly of claim 1, wherein the degradable plug is
positioned in-line with and adjacent to or axially displaced from
the flow control device.
4. (canceled)
5. The downhole assembly of claim 1, wherein the degradable plug is
engaged with the shroud and the tube to form a fluid and pressure
tight seal.
6. The downhole assembly of claim 1, wherein the degradable plug is
positioned in an opening formed in a sidewall of the tube and
engaged with the tube to form a fluid and pressure tight seal to
prevent fluid flow between the annulus and the tube.
7. The downhole assembly of claim 1, wherein the degradable plug is
formed of a composition that degrades within the annulus within a
predetermined time of exposure to a particular fluid.
8. The downhole assembly of claim 7, wherein the degradable plug
comprises a coating formed around the degradable plug that
temporarily protects the degradable plug from exposure to the
particular fluid.
9. The downhole assembly of claim 1, wherein the degradable plug
comprises a first composition imbedded with particles of a second
composition to form a galvanic cell.
10. The downhole assembly of claim 1, wherein the degradable plug
comprises: a shell including a channel extending there through; and
a degradable core disposed within the channel and formed of a
composition that degrades within the annulus within a predetermined
time of exposure to a particular fluid.
11. The downhole assembly of claim 1, wherein the degradable plug
comprises: a shell including a channel extending there through; a
degradable core disposed within the shell and formed of a
composition that degrades within the annulus within a predetermined
time of first exposure to a particular fluid; and a rupture disk
that temporarily protects the degradable plug from exposure to the
particular fluid, the rupture disk formed of a material that
fractures when exposed to a threshold pressure.
12. The downhole assembly of claim 1, wherein the degradable plug
comprises: a shell including: a first channel extending radially
there through; and a second channel extending axially from an outer
surface of the shell to the first channel; and a degradable core
disposed within the second channel and formed of a composition that
degrades within the annulus within a predetermined time of exposure
to a particular fluid.
13. (canceled)
14. A well system comprising: a production string; and a downhole
assembly coupled to and disposed downhole from the production
string, the downhole assembly comprising: a tube; a shroud coupled
to and disposed around the circumference of the tube to form an
annulus between an inner surface of the shroud and an outer surface
of the tube; a flow control device disposed in the annulus; and a
degradable plug disposed in the annulus and positioned to prevent
fluid flow between the annulus and the tube.
15. The well system of claim 14, wherein the downhole assembly
further comprises a screen coupled to and disposed uphole from the
shroud and coupled to and disposed around the circumference of the
tube such that an annulus is formed between an inner surface of the
screen and the outer surface of the tube.
16. The well system of claim 14, wherein the degradable plug is
positioned in-line with and adjacent to or axially displaced from
the flow control device.
17. (canceled)
18. (canceled)
19. The well system of claim 14, wherein the degradable plug is
positioned in an opening formed in a sidewall of the tube and
engaged with the tube to form a fluid and pressure tight seal to
prevent fluid flow between the annulus and the tube.
20. The well system of claim 14, wherein the degradable plug is
formed of a composition that degrades within the annulus within a
predetermined time of exposure to a particular fluid.
21. The well system of claim 20, wherein the degradable plug
comprises a coating formed around the degradable plug that
temporarily protects the degradable plug from exposure to the
particular fluid.
22. (canceled)
23. The well system of claim 14, wherein the degradable plug
comprises: a shell including a channel extending there through; and
a degradable core disposed within the channel and formed of a
composition that degrades within the annulus within a predetermined
time of exposure to a particular fluid.
24. The well system of claim 14, wherein the degradable plug
comprises: a shell including a channel extending there through; a
degradable core disposed within the shell and formed of a
composition that degrades within the annulus within a predetermined
time of first exposure to a particular fluid; and a rupture disk
that temporarily protects the degradable plug from exposure to the
particular fluid, the rupture disk formed of a material that
fractures when exposed to a threshold pressure.
25. The well system of claim 14, wherein the degradable plug
comprises: a shell including: a first channel extending radially
there through; and a second channel extending axially from an outer
surface of the shell to the first channel; and a degradable core
disposed within the second channel and formed of a composition that
degrades within the annulus within a predetermined time of exposure
to a particular fluid.
26. (canceled)
27. A method of temporarily preventing fluid flow between a
production string and a wellbore, comprising: positioning a
degradable plug in a wellbore such that the plug prevents fluid
flow between a production string and a wellbore; and triggering a
chemical reaction that causes the degradable plug to degrade to a
point where fluid flow between the production string and the
wellbore is permitted.
28. The method of claim 27, wherein the degradable plug is
positioned in fluid communication with a flow control device.
29. The method of claim 28, wherein the degradable plug is
positioned in-line with and adjacent to or axially displaced from
the flow control device.
29. (canceled)
30. The method of claim 27, wherein the chemical reaction is
triggered by exposure of the degradable plug to a particular fluid
for an amount of time exceeding a threshold time.
31. The method of claim 27, wherein triggering the chemical
reaction comprises removing a protective coating formed around the
degradable plug to expose the degradable plug to a particular
fluid.
32. The method of claim 31, wherein removing the protective coating
comprises exposing the degradable plug to a threshold temperature
that causes the protective coating to melt or a threshold pressure
that causes the protective coating to fracture.
33. (canceled)
34. The method of claim 27, wherein the degradable plug degrades
into particles small enough such that the particles do not impede
fluid flow.
35. (canceled)
36. The method of claim 27, wherein triggering the chemical
reaction comprises rupturing a rupture disk to expose a core of the
degradable plug to a particular fluid for an amount of time
exceeding a threshold time.
Description
TECHNICAL FIELD
[0001] The present disclosure is related to downhole tools for use
in a wellbore environment and more particularly to degradable plugs
used to temporarily block fluid flow in a well system.
BACKGROUND OF THE DISCLOSURE
[0002] After a wellbore has been formed for the purpose of
exploration or extraction of natural resources such as hydrocarbons
or water, various downhole tools may be inserted into the wellbore
to extract the natural resources from the wellbore and/or to
maintain the wellbore. At various times during production and/or
maintenance operations, it may be necessary to temporarily block
the flow of fluid into or out of various portions of the wellbore
or various portions of the downhole tools used in the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] A more complete and thorough understanding of the various
embodiments and advantages thereof may be acquired by referring to
the following description taken in conjunction with the
accompanying drawings, in which like reference numbers indicate
like features, and wherein:
[0004] FIG. 1 is an elevation view of a well system;
[0005] FIG. 2 is a cross-sectional view of a downhole assembly
including a degradable plug in-line with and adjacent to a flow
control device;
[0006] FIG. 3 is a cross-sectional view of a downhole assembly
including a degradable plug in-line with and axially displaced from
a flow control device;
[0007] FIG. 4 is a cross-sectional view of a downhole assembly
including a degradable plug axially and radially displaced from a
flow control device;
[0008] FIG. 5A is a cross-sectional view of a degradable plug
including an o-ring seal;
[0009] FIG. 5B is a cross-sectional view of a press-fit degradable
plug;
[0010] FIG. 5C is a cross-sectional view of a tapered press-fit
degradable plug;
[0011] FIG. 5D is a cross-sectional view of a threaded degradable
plug;
[0012] FIG. 5E is a cross-sectional view of a swage-fit degradable
plug;
[0013] FIG. 6A is a cross-sectional view of a degradable plug
formed of a degradable composition that is reactive under defined
conditions;
[0014] FIG. 6B is a cross-sectional view of a degradable plug
including a shell and a core disposed within the shell and formed
of a degradable composition that is reactive under defined
conditions;
[0015] FIG. 6C is a cross-sectional view of a degradable plug
including a shell, a core disposed within the shell and formed of a
degradable composition that is reactive under defined conditions,
and a rupture disk;
[0016] FIG. 6D is a cross-sectional view of a degradable plug
including a core formed of a degradable composition that is
reactive under defined conditions and disposed within a shell
including a diffusion channel; and
[0017] FIG. 7 is a flow-chart of a method of temporarily preventing
the flow of production fluids into a production string.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0018] Embodiments of the present disclosure and its advantages may
be understood by referring to FIGS. 1 through 7, where like numbers
are used to indicate like and corresponding parts.
[0019] Production fluids, including hydrocarbons, water, sediment,
and other materials or substances found in a formation may flow
from the formation into a wellbore through the sidewalls of the
open hole portions of the wellbore. The production fluids may
circulate in the wellbore before being extracted via a downhole
assembly. The downhole assembly may include a screen to filter
sediment from the production fluids flowing into the downhole
assembly and a flow control device to regulate the flow of
production fluids into the downhole assembly. Similarly, injection
fluids may flow from a production string into the downhole assembly
before flowing into the wellbore. A plug may be used to temporarily
prevent flow of production or injection fluids between the downhole
assembly and the wellbore. The plug may be positioned axially with
respect to the flow control device. To resume fluid flow between
the downhole assembly and the wellbore, the plug may be removed. To
avoid the cost and time associated with manual removal of the plug,
it may be removed via a chemical reaction that causes the plug to
degrade within the wellbore.
[0020] FIG. 1 is an elevation view of an example embodiment of a
well system. Well system 100 may include well surface or well site
106. Various types of equipment such as a rotary table, drilling
fluid or production fluid pumps, drilling fluid tanks (not
expressly shown), and other drilling or production equipment may be
located at well surface or well site 106. For example, well site
106 may include drilling rig 102 that may have various
characteristics and features associated with a "land drilling rig."
However, downhole drilling tools incorporating teachings of the
present disclosure may be satisfactorily used with drilling
equipment located on offshore platforms, drill ships,
semi-submersibles and drilling barges (not expressly shown).
[0021] Well system 100 may also include production string 103,
which may be used to produce hydrocarbons such as oil and gas and
other natural resources such as water from formation 112 via
wellbore 114. Alternatively, or additionally, production string 103
may be used to inject hydrocarbons such as oil and gas and other
natural resources such as water into formation 112 via wellbore
114. As shown in FIG. 1, wellbore 114 is substantially vertical
(e.g., substantially perpendicular to the surface). In other
embodiments, portions of wellbore 114 may be substantially
horizontal (e.g., substantially parallel to the surface), or at an
angle between vertical and horizontal. Casing string 110 may be
placed in wellbore 114 and held in place by cement, which may be
injected between casing string 110 and the sidewalls of wellbore
114. Casing string 110 may provide radial support to wellbore 114
and may seal against unwanted communication of fluids between
wellbore 114 and surrounding formation 112. Casting string 110 may
extend from well surface 106 to a selected downhole location within
wellbore 114. Portions of wellbore 114 that do not include casing
string 110 may be described as "open hole."
[0022] The terms "uphole" and "downhole" may be used to describe
the location of various components relative to the bottom or end of
wellbore 114 shown in FIG. 1. For example, a first component
described as uphole from a second component may be further away
from the end of wellbore 114 than the second component. Similarly,
a first component described as being downhole from a second
component may be located closer to the end of wellbore 114 than the
second component.
[0023] Well system 100 may also include downhole assembly 120
coupled to production string 103. Downhole assembly 120 may be used
to perform operations relating to the completion of wellbore 114,
the production of hydrocarbons and other natural resources from
formation 112 via wellbore 114, the injection of hydrocarbons and
other natural resources into formation 112 via wellbore 114, and/or
the maintenance of wellbore 114. Downhole assembly 120 may be
located at the end of wellbore 114 or at a point uphole from the
end of wellbore 114. Downhole assembly 120 may be formed from a
wide variety of components configured to perform these operations.
For example, components 122a, 122b and 122c of downhole assembly
120 may include, but are not limited to, screens, flow control
devices, slotted tubing, packers, valves, sensors, and actuators.
The number and types of components 122 included in downhole
assembly 120 may depend on the type of wellbore, the operations
being performed in the wellbore, and anticipated wellbore
conditions.
[0024] Production fluids, including hydrocarbons, water, sediment,
and other materials or substances found in formation 112 may flow
from formation 112 into wellbore 114 through the sidewalls of the
open hole portions of wellbore 114. The production fluids may
circulate in wellbore 114 before being extracted via production
string 103. Alternatively, or additionally, injection fluids,
including hydrocarbons, water, and other materials, may be injected
into wellbore 114 and formation 112 via production string 103 and
downhole assembly 120. Downhole assembly 120 may include a screen
(shown in FIG. 2) to filter sediment from production fluids flowing
into production string 103. Downhole assembly 120 may also include
a flow control device to regulate the flow of production fluids
into production string 103. Downhole assembly 120 may also include
a plug that may be used to temporarily prevent flow of production
fluids into production string 103 or injection fluids out of
production string 103. To avoid the cost and time associated with
manual removal of the plug, it may be removed via a chemical
reaction that causes the plug to degrade within wellbore 114.
[0025] FIG. 2 is a cross-sectional view of a downhole assembly
including a degradable plug in-line with and adjacent to a flow
control device. Production fluids circulating in wellbore 114 may
flow through downhole assembly 200 into production string 103.
Downhole assembly 200 may be located downhole from production
string 103 and may be coupled to production string via tubing 210.
In some embodiments, downhole assembly 200 may be coupled to
production string 103 by a threaded joint. In other embodiments, a
different coupling mechanism may be employed. The coupling of
downhole assembly 200 and production string 103 may also provide a
fluid and pressure tight seal.
[0026] Downhole assembly 200 may include screen 202 and shroud 204,
which may be coupled to and disposed downhole from screen 202. Both
screen 202 and shroud 204 may be coupled to and disposed around the
circumference of tubing 210 such that annulus 212 is formed between
the inner surfaces of screen 202 and shroud 204 and the outer
surface of tubing 210. Production fluids circulating in wellbore
114 may enter downhole assembly 200 by flowing through screen 202
into annulus 212. Screen 202 may be configured to filter sediment
from production fluids as they flow through screen 202. Screen 202
may include, but is not limited to, a sand screen, a gravel filter,
a mesh, or slotted tubing.
[0027] Downhole assembly 200 may also include flow control device
206 disposed within annulus 212 between shroud 204 and tubing 210.
Flow control device 206 may include channel 214 extending there
through to permit the flow of production fluids through flow
control device 206. Flow control device 206 may engage with shroud
204 and tubing 210 to prevent production fluids circulating in
annulus 212 from flowing between flow control device 206 and tubing
210 or shroud 204. For example, flow control device 206 may engage
with the inner surface of shroud 204 to form a fluid and pressure
tight seal and may engage with the outer surface of tubing 210 to
form a fluid and pressure tight seal. Because flow control device
206 engages with tubing 210 and shroud 204 to form a fluid and
pressure tight seal, production fluids circulating in annulus 212
flow through channel 214 rather than between flow control device
206 and tubing 210 or between flow control device 206 and shroud
204.
[0028] The flow of production fluids through channel 214 may be
temporarily blocked by plug 208 disposed in a portion of annulus
212 downhole from flow control device 206. Plug 208 may be
positioned in-line with and adjacent to flow control device 206, as
shown in FIG. 2. Plug 208 may engage with shroud 204 and tubing 210
to form a fluid and pressure tight seal, thereby preventing
production fluids from flowing into the portion of annulus downhole
from flow control device 206. Plug 208 may also be used to
temporarily block the flow of injection fluids from production
string 103 into wellbore 114 and formation 112. For example, the
flow of injection fluids from production string into wellbore 114
and formation 112 may be temporarily blocked by plug 208 positioned
in-line with and adjacent to flow control device 206, as shown in
FIG. 2. Plug 208 may engage with shroud 204 and tubing 210 to form
a fluid and pressure tight seal, thereby preventing injection
fluids from flowing into the portion of annulus uphole from flow
control device 206.
[0029] Plug 208 may be formed of a degradable composition including
a metal or alloy that is reactive under defined conditions. Plug
208 may be removed from annulus 212 using a chemical reaction that
causes plug 208 to degrade, thereby avoiding manual intervention
required to extract plug 208 from annulus 212 using a retrieval
tool. The term "degrade" may be used to describe a process by which
a component breaks down into pieces or dissolves into particles
small enough that they do not impede the flow of fluids. The
features of plug 208, including its degradability, are described in
additional detail with respect to FIGS. 5A-5E and 6A-6D. Once the
chemical reaction causing plug 208 to degrade has been triggered,
the reaction may continue until plug 208 breaks down into pieces or
dissolves into particles small enough that they do not impede the
flow of production fluids through channel 214 of flow control
device 206. When plug 208 has degraded to this point, production
fluids may flow through channel 214 of flow control device 206 and
into the portion of annulus 212 downhole from flow control device
206. From there, the production fluids may flow through opening 216
formed in a sidewall of tubing 210 into tubing 210 and into
production string 103.
[0030] Downhole assembly 200 may also include port 218, which may
be removed to permit access to the portion of annulus 212 downhole
from flow control device 206. Port 218 may be coupled to shroud 204
and tubing 210 via a threaded connection. Port 218 may engage with
shroud 204 and tubing 210 to form a fluid and pressure tight seal.
Port 218 may include a socket or slot into which a tool may be
inserted. With a tool inserted into the socket or slot, port 218
may be rotated in order to disengage the threaded connection
between port 218 and 204. When port 218 has been removed, plug 208
may be replaced (i.e., a new plug may be installed). For example,
after plug 208 has been removed via a chemical reaction causing
plug 208 to degrade, the flow of production fluids through channel
214 of flow control device 206 may again be temporarily blocked by
replacing plug 208.
[0031] FIG. 3 is a cross-sectional view of a downhole assembly
including a degradable plug in-line with and axially displaced from
a flow control device. Production fluids circulating in wellbore
114 may enter downhole assembly 200 by flowing through screen 202
into annulus 212. Production fluids may then flow through channel
214 of flow control device 206 into the portion of annulus 212
downhole from flow control device 206. Production fluids may be
temporarily blocked from flowing through opening 216 into tubing
210 and production string 103 by plug 208 disposed in the portion
of annulus 212 downhole from flow control device 206. Plug 208 may
be positioned in-line with and axially displaced from flow control
device 206, as shown in FIG. 3. Plug 208 may engage with shroud 204
and tubing 210 to form a fluid and pressure tight seal, thereby
preventing production fluids from flowing into the portion of
annulus downhole from plug 208.
[0032] Plug 208 may also be used to temporarily block the flow of
injection fluids from production string 103 into wellbore 114 and
formation 112. For example, the flow of injection fluids from
production string into wellbore 114 and formation 112 may be
temporarily blocked by plug 208 positioned in-line with and axially
displaced from flow control device 206, as shown in FIG. 3. Plug
208 may engage with shroud 204 and tubing 210 to form a fluid and
pressure tight seal, thereby preventing injection fluids from
flowing into the portion of annulus uphole from flow control device
206.
[0033] As explained above with respect to FIG. 2, plug 208 may be
formed of a degradable composition including a metal or alloy that
is reactive under defined conditions. Plug 208 may be removed from
annulus 212 using a chemical reaction that causes plug 208 to
degrade, thereby avoiding manual intervention required to extract
plug 208 from annulus 212 using a retrieval tool. Once the chemical
reaction causing plug 208 to degrade has been triggered, the
reaction may continue until plug 208 breaks down into pieces or
dissolves into particles small enough that they do not impede the
flow of production fluids through annulus 212 or opening 216. When
plug 208 has degraded to this point, production fluids may flow
through opening 216 into tubing 210 and into the production string
103.
[0034] FIG. 4 is a cross-sectional view of a downhole assembly
including a degradable plug axially and radially displaced from a
flow control device. Production fluids circulating in wellbore 114
may enter downhole assembly 200 by flowing through screen 202 into
annulus 212. Production fluids may then flow through channel 214 of
flow control device 206 into the portion of annulus 212 downhole
from flow control device 206. Production fluids may be temporarily
blocked from flowing through opening 216 into tubing 210 and
production string 103 by plug 208. Plug 208 may be positioned
within opening 216 and may engage with opening 216 to form a fluid
and pressure tight seal, thereby preventing production fluids from
flowing between annulus 212 and tubing 210. Plug 208 may also be
used to temporarily block the flow of injection fluids from
production string 103 into wellbore 114 and formation 112. For
example, the flow of injection fluids from production string into
wellbore 114 and formation 112 may be temporarily blocked by plug
208 positioned within opening 216, as shown in FIG. 4. Plug 208 may
engage with opening 216 to form a fluid and pressure tight seal,
thereby preventing injection fluids from flowing between annulus
212 and tubing 210.
[0035] As explained above with respect to FIG. 2, plug 208 may be
formed of a degradable composition including a metal or alloy that
is reactive under defined conditions. Plug 208 may be removed from
opening 216 using a chemical reaction that causes plug 208 to
degrade, thereby avoiding manual intervention required to extract
plug 208 from opening 216 using a retrieval tool. Once the chemical
reaction causing plug 208 to degrade has been triggered, the
reaction may continue until plug 208 breaks down into pieces or
dissolves into particles small enough that they do not impede the
flow of production fluids through opening 216. When plug 208 has
degraded to this point, production fluids may flow through opening
216 into tubing 210 and into the production string 103.
[0036] A variety of mechanisms may be employed to permit plug 208
to form a fluid and pressure tight seal with shroud 204 and tubing
210 (as discussed with respect to FIGS. 2 and 3) or with opening
216 (as discussed with respect to FIG. 4). FIGS. 5A-5E illustrate
exemplary mechanisms that may be used to form a fluid and pressure
tight seal between plug 208 and shroud 204 and tubing 210 (as
discussed with respect to FIGS. 2 and 3) or opening 216 (as
discussed with respect to FIG. 4).
[0037] FIG. 5A is a cross-sectional view of a degradable plug
including an o-ring seal. Plug 208 may include seal 502 disposed
around the circumference of plug 208. Seal 502 may be inset into a
groove on the surface of plug 208 (as shown in FIG. 5A) or may be
disposed on the surface of plug 208. Although one seal 502 is
depicted in FIG. 5A, any number of seals 502 may be used. Seal 502
may be a molded seal made of an elastomeric material. The
elastomeric material may be formed of compounds including, but not
limited to, natural rubber, nitrile rubber, hydrogenated nitrile,
urethane, polyurethane, fluorocarbon, perflurocarbon, propylene,
neoprene, hydrin, etc. The elastomeric material may also be a
degradable elastomeric material. Examples of degradable elastomeric
material include but are not limited to EPDM rubber, natural
rubber, elastomers containing polyglocolic acid, elastomers
containing polylactic acid, or elastomers containing thiol. Seal
502 may engage with shroud 204 and tubing 210 form a fluid and
pressure tight seal.
[0038] Although plug 208 is shown in FIG. 5A positioned in-line
with and adjacent to flow control device 206, plug 208 may also be
positioned in-line with and axially displaced from flow control
device 206 (as shown in FIG. 3) or within opening 216 (as shown in
FIG. 4). Where plug 208 is positioned as shown in FIG. 3, seal 502
may engage with shroud 204 and tubing 210 to form a fluid and
pressure tight seal. Where plug 208 is positioned as shown in FIG.
4, seal 502 may engage with opening 216 to form a fluid and
pressure tight seal.
[0039] FIG. 5B is a cross-sectional view of a press-fit degradable
plug. Plug 208 may include protrusions 504 extending radially from
the surface of plug 208. The distance that protrusions 504 extend
from the surface of plug 208 may be chosen to provide an
interference fit between protrusions 504 and the surface with which
they are sealing. For example, protrusions 504 may extend radially
from the surface of plug 208 to provide an interference fit with
shroud 504 and tubing 210. The interference fit between protrusions
504 and shroud 204 and between protrusions 504 and tubing 210 may
provide a fluid and pressure tight seal.
[0040] Although plug 208 is shown in FIG. 5B positioned in-line
with and adjacent to flow control device 206, plug 208 may also be
positioned in-line with and axially displaced from flow control
device 206 (as shown in FIG. 3) or within opening 216 (as shown in
FIG. 4). Where plug 208 is positioned as shown in FIG. 3, the
interference fit between protrusions 504 and shroud 204 and between
protrusions 504 and tubing 210 may provide a fluid and pressure
tight seal. Where plug 208 is positioned as shown in FIG. 4,
protrusions 504 may extend radially from the surface of plug 208 to
provide an interference fit with opening 216. The interference fit
between protrusions 504 and opening 216 may provide a fluid and
pressure tight seal.
[0041] FIG. 5C is a cross-sectional view of a press-fit degradable
plug. Plug 208 may include tapered end 506. Tapered end 506 of plug
208 may extend partially into channel 214 of flow control device
206. Tapered end 506 may be configured to provide an interference
fit between plug 208 and flow control device 206. The interference
fit between tapered end 506 and flow control device 206 may provide
a fluid and pressure tight seal. Although plug 208 is depicted in
FIG. 5C positioned in-line with and adjacent flow control device
206, plug 208 may also be positioned within opening 216 (as shown
in FIG. 4). Where plug 208 is positioned as shown in FIG. 4,
tapered end 506 may extend partially into opening 216. Tapered end
506 may be configured to provide an interference fit between plug
208 and opening 216. The interference fit between plug 208 and
opening 216 may provide a fluid and pressure tight seal.
[0042] FIG. 5D is a cross-sectional view of a threaded degradable
plug. Plug 208 may include threads 508 configured to engage with
threads 510 of shroud 204 and threads 512 of tubing 210. The
engagement of threads 508 with threads 510 and threads 512 may
provide a fluid and pressure tight seal. Although plug 208 is
depicted in FIG. 5D positioned in-line with and adjacent flow
control device 206, plug 208 may also be positioned in-line with
and axially displaced from flow control device 206 (as shown in
FIG. 3) or within opening 216 (as shown in FIG. 4). Where plug 208
is positioned as shown in FIG. 3, the engagement of threads 508
with threads 510 and threads 512 may provide a fluid and pressure
tight seal. Where plug 208 is positioned as shown in FIG. 4,
threads 508 may be configured to engage with threads formed on the
surface of opening 216. The engagement of threads 508 with threads
formed on the surface of opening 216 may provide a fluid and
pressure tight seal. A sealant may be applied to or disposed within
the threads to enhance the seal.
[0043] FIG. 5E is a cross-sectional view of a swage-fit degradable
plug. Plug 208 may be configured to engage with swage fitting 514
to provide an interference fit between plug 208 and swage fitting
514. Plug 208 may be shrink-fit into swage fitting 514. The
interference fit between plug 208 and swage fitting 514 may provide
a fluid and pressure tight seal. Although plug 208 and swage
fitting 514 are depicted in FIG. 5D positioned adjacent flow
control device 206, plug 208 and swage fitting 514 may also be
positioned in-line with and axially displaced from flow control
device 206 (as shown in FIG. 3). Additionally, plug 208 and swage
fitting 514 may be positioned within opening 216 (as shown in FIG.
4).
[0044] FIGS. 6A-6D illustrate exemplary embodiments of a degradable
plug. FIG. 6A is a cross-sectional view of a degradable plug formed
of degradable composition that is reactive under defined
conditions. Plug 208 may include socket 602 which may be configured
to engage with a tool to permit plug 208 to be positioned within or
extracted from downhole assembly 200 (shown in FIG. 2). As
discussed above with respect to FIG. 2, plug 208 may be formed of a
degradable composition including a metal or alloy that is reactive
under defined conditions. The composition of plug 208 may be
selected such that plug 208 begins to degrade within a
predetermined time of first exposure to a corrosive or acidic fluid
due to reaction of the metal or alloy from which plug 208 is formed
with the corrosive or acidic fluid. Additionally, the composition
of plug 208 may be selected such that the degradation of plug 208
accelerates with increasing salinity or with decreasing pH of the
corrosive or acidic fluid. The composition of plug 208 may further
be selected such that plug 208 degrades sufficiently to form pieces
or particles small enough that they do not impede the flow of
production fluids through channel 214 of flow control device 206
(shown in FIG. 2) or opening 216 (shown in FIG. 2). The corrosive
or acidic fluid may already be present within annulus 212 (shown in
FIG. 2) during operation of wellbore 114 (shown in FIG. 1) or may
be injected into annulus 212 to trigger a chemical reaction that
causes plug 208 to degrade. Additionally, the fluid may be
introduced as part of the wellbore cleanup procedures. Examples of
corrosive or acidic fluids include organic acids and inorganic
acids, such as hydrochloric acid, acetic acid, citric acid,
carbonic acid, lactic acid, glycolic acid, and hydrofluoric acid.
Exemplary compositions from which plug 208 may be formed include
compositions in which the metal or alloy is selected from one of
calcium, magnesium, aluminum, and combinations thereof. The
composition of plug 208 may be formed from a solution process, from
a powder metallurgy process, or from a nanomatrix composite.
Additionally or alternatively, the composition of plug 208 may be
cast, extruded, or forged. The composition of plug 208 may also be
heat treated or annealed.
[0045] Plug 208 may also be formed from the metal or alloy imbedded
with small particles (e.g., particulates, powders, flakes, fibers,
and the like) of a non-reactive material. The non-reactive material
may be selected such that it remains structurally intact even when
exposed to the corrosive or acidic fluid for a duration of time
sufficient to degrade the metal or alloy into pieces or particles
small enough that they do not impede the flow of production fluids
through channel 214 of flow control device 206 (shown in FIG. 2) or
opening 216 (shown in FIG. 2). When the metal or alloy degrades,
the small particles of the non-reactive material may remain. The
particle size of the non-reactive material may be selected such
that the particles are small enough that they do not impede the
flow of production fluids through channel 214 of flow control
device 206 (shown in FIG. 2) or opening 216 (shown in FIG. 2). The
non-reactive material may be selected from one of lithium, bismuth,
calcium, magnesium, and aluminum (including aluminum alloys) if not
already selected as the reactive metal or alloy, and combinations
thereof.
[0046] Plug 208 may also be formed from the metal or alloy imbedded
with small particles (e.g., particulates, powders, flakes, fibers,
and the like) to form a galvanic cell. The composition of the
particles may be selected such that the metal from which the
particles are formed has a different galvanic potential than the
metal or alloy in which the particles are imbedded. Contact between
the particles and the metal or alloy in which they are imbedded may
trigger microgalvanic corrosion that causes plug 208 to degrade.
Exemplary compositions from which the particles may be formed
include iron, steel, aluminum alloy, zinc, magnesium, graphite,
nickel, copper, carbon, tungsten, and combinations thereof.
[0047] Plug 208 may also be formed from an anodic material imbedded
with small particles of cathodic material. The anodic and cathodic
materials may be selected such that plug 208 begins to degrade upon
exposure to a brine fluid, which may also be referred to as an
electrolytic fluid, due to an electrochemical reaction that causes
the plug to corrode. A brine fluid or electrolytic fluid may
include fluids containing NaCL, KCL, and other salts. Exemplary
compositions from which the anodic material may be formed include
one of magnesium, aluminum, and combinations thereof. Exemplary
compositions from which the cathodic material may be formed include
one of iron, nickel, copper, graphite, tungsten, and combinations
thereof. The anodic and cathodic materials may be selected such
that plug 208 is degraded sufficiently within a predetermined time
of first exposure to the electrolytic fluid to form pieces or
particles small enough that they do not impede the flow of
production fluids through channel 214 of flow control device 206
(shown in FIG. 2) or opening 216 (shown in FIG. 2). The
electrolytic fluid may already be present within annulus 212 (shown
in FIG. 2) during operation of wellbore 114 (shown in FIG. 1) or
may be injected into annulus 212 to trigger a electrochemical
reaction that causes plug 208 to degrade. As another example, plug
208 may be coated with a material that degrades when exposed to a
wellbore fluid. A wellbore fluid may be circulated around the plug
208 in order to degrade the coating. Examples of degradable
coatings include EPDM that degrades in crude oil, paint or plastics
that degrades in xylene, or PGA or PLA that degrades in water.
[0048] Plug 208 may include a coating to temporarily protect the
metal or alloy from exposure to the corrosive, acidic, or
electrolytic fluid. As an example, plug 208 may be coated with a
material that softens or melts when a threshold temperature is
reached in annulus 212 (shown in FIG. 2). After the coating softens
or melts, the surface of plug 208 may be exposed to the corrosive,
acidic, or electrolytic fluid circulating in annulus 212 (shown in
FIG. 2). As another example, plug 208 may be coated with a material
that fractures when exposed to a threshold pressure. The threshold
pressure may be a pressure greater than a pressure that occurs
during operation of wellbore 114 (shown in FIG. 1). The pressure in
wellbore 114 (shown in FIG. 1) or annulus 212 (shown in FIG. 2) may
be manipulated such that it exceeds the threshold pressure, causing
the coating to fracture. When the coating fractures, the surface of
plug 208 may be exposed to the corrosive, acidic, or electrolytic
fluid circulating in annulus 212 (shown in FIG. 2). As yet another
example, plug 208 may be coated with a material that erodes when
exposed to a particle laden fluid. When the coating erodes, the
surface of plug 208 may be exposed to the corrosive, acidic, or
electrolytic fluid circulating in annulus 212 (shown in FIG. 2).
Exemplary coatings may be selected from a metallic, ceramic, or
polymeric material, and combinations thereof. The coating may have
low reactivity with the corrosive, acidic, or electrolytic fluid
present in annulus 212 (shown in FIG. 2), such that it protects
plug 208 from degradation until the coating is compromised allowing
the corrosive, acidic, or electrolytic fluid to contact the metal
or alloy.
[0049] FIG. 6B is a cross-sectional view of a degradable plug
including a shell and a core disposed within the shell and formed
of a degradable composition that is reactive under defined
conditions. Plug 208 may include core 604 disposed within channel
606 extending through shell 608. Core 604 may be removed from shell
606 using a chemical reaction that causes core 604 to degrade. Plug
208 also may include socket 602 which may be configured to engage
with a tool to permit plug 208 to be positioned within or extracted
from downhole assembly 200 (shown in FIG. 2). Socket 602 may be
open to channel 606 such that, when core 604 is removed from shell
608, fluid may flow through plug 208 via socket 602 and channel
606.
[0050] Core 604 may be formed of a degradable composition including
a metal or alloy that is reactive under defined conditions. The
composition of core 604 may be selected such that core 604 begins
to degrade within a predetermined time of first exposure to a
corrosive or acidic fluid due to reaction of the metal or alloy
from which core 604 is formed with the corrosive or acidic fluid.
Additionally, the composition of plug 208 may be selected such that
the degradation of plug 208 accelerates with increasing salinity or
with decreasing pH of the corrosive or acidic fluid. The
composition of core 604 may be selected such that core 604 degrades
sufficiently to form pieces or particles small enough that they do
not impede the flow of production fluids through shell 608. The
corrosive or acidic fluid may already be present within annulus 212
(shown in FIG. 2) during operation of wellbore 114 (shown in FIG.
1) or may be injected into annulus 212 to trigger a chemical
reaction that causes core 604 to degrade. Additionally, the fluid
may be introduced as part of the wellbore cleanup procedures.
Examples of corrosive or acidic fluids include organic acids and
inorganic acids, such as hydrochloric acid, acetic acid, citric
acid, carbonic acid, lactic acid, glycolic acid, and hydrofluoric
acid. Exemplary compositions from which core 604 may be formed
include compositions in which the metal or alloy is selected from
one of calcium, magnesium, aluminum, and combinations thereof. The
composition of core 604 may be formed from a solution process, from
a powder metallurgy process, or from a nanomatrix composite.
Additionally or alternatively, the composition of core 604 may be
cast, extruded, or forged. The composition of core 604 may also be
heat treated or annealed.
[0051] Core 604 may also be formed from the metal or alloy imbedded
with small particles (e.g., particulates, powders, flakes, fibers,
and the like) of a non-reactive material. The non-reactive material
may be selected such that it remains structurally intact even when
exposed to the corrosive or acidic fluid for a duration of time
sufficient to degrade the metal or alloy into pieces or particles
small enough that they do not impede the flow of production fluids
through plug 208. When the metal or alloy degrades, the small
particles of the non-reactive material may remain. The particle
size of the non-reactive material may be selected such that the
particles are small enough that they do not impede the flow of
production fluids through plug 208. The non-reactive material may
be selected from one of lithium, bismuth, calcium, magnesium, and
aluminum (including aluminum alloys) if not already selected as the
reactive metal or alloy, and combinations thereof.
[0052] Core 604 may also be formed from the metal or alloy imbedded
with small particles (e.g., particulates, powders, flakes, fibers,
and the like) to form a galvanic cell. The composition of the
particles may be selected such that the metal from which the
particles are formed has a different galvanic potential than the
metal or alloy in which the particles are imbedded. Contact between
the particles and the metal or alloy in which they are imbedded may
trigger microgalvanic corrosion that causes core 604 to degrade.
Exemplary compositions from which the particles may be formed
include iron, steel, aluminum alloy, zinc, magnesium, graphite,
nickel, copper, carbon, tungsten, and combinations thereof.
[0053] Core 604 may also be formed from an anodic material imbedded
with small particles of cathodic material. The anodic and cathodic
materials may be selected such that core 604 begins to degrade upon
exposure to a brine fluid, which may also be referred to as an
electrolytic fluid, due to an electrochemical reaction that causes
the plug to corrode. Brine fluids may include fluids containing
NaCl, KCl, and other salts. Exemplary compositions from which the
anodic material may be formed include one of magnesium, aluminum,
and combinations thereof. Exemplary compositions from which the
cathodic material may be formed include one of iron, nickel,
copper, graphite, tungsten, and combinations thereof. The anodic
and cathodic materials may be selected such that core 604 is
degraded sufficiently within a predetermined time of first exposure
to the electrolytic fluid to form pieces or particles small enough
that they do not impede the flow of production fluids through plug
208. The electrolytic fluid may already be present within annulus
212 (shown in FIG. 2) during operation of wellbore 114 (shown in
FIG. 1) or may be injected into annulus 212 to trigger a
electrochemical reaction that causes core 604 to degrade.
[0054] Core 604 may include a coating to temporarily protect the
metal or alloy from exposure to the corrosive, acidic, or
electrolytic fluid. As an example, core 604 may be coated with a
material that softens or melts when a threshold temperature is
reached in annulus 212 (shown in FIG. 2). After the coating softens
or melts, the surface of core 604 may be exposed to the corrosive,
acidic, or electrolytic fluid circulating in annulus 212 (shown in
FIG. 2). As another example, core 604 may be coated with a material
that fractures when exposed to a threshold pressure. The threshold
pressure may be a pressure greater than a pressure that occurs
during operation of wellbore 114 (shown in FIG. 1). The pressure in
wellbore 114 (shown in FIG. 1) or annulus 212 (shown in FIG. 2) may
be manipulated such that it exceeds the threshold pressure, causing
the coating to fracture. When the coating fractures, the surface of
core 604 may be exposed to the corrosive, acidic, or electrolytic
fluid circulating in annulus 212 (shown in FIG. 2). As yet another
example, core 604 may be coated with a material that erodes when
exposed to a particle laden fluid. When the coating erodes, the
surface of core 604 may be exposed to the corrosive, acidic, or
electrolytic fluid circulating in annulus 212 (shown in FIG. 2).
Exemplary coatings may be selected from a metallic, ceramic, or
polymeric material, and combinations thereof. The coating may have
low reactivity with the corrosive or acidic fluid present in
annulus 212 (shown in FIG. 2), such that it protects core 604 from
degradation until the coating is compromised allowing the
corrosive, acidic, or electrolytic to contact the metal or alloy.
As another example, core 604 may be coated with a material that
degrades when exposed to a wellbore fluid. A wellbore fluid may be
circulated around core 604 in order to degrade the coating.
Examples of degradable coatings include EPDM that degrades in crude
oil, paint or plastics that degrades in xylene, or PGA or PLA that
degrades in water.
[0055] Shell 608 may be formed of a non-reactive material. The
non-reactive material may be selected such that it remains
structurally intact even when exposed to the corrosive or acidic
fluid for a duration of time sufficient to degrade the metal or
alloy from which core 604 is formed into pieces or particles small
enough that they do not impede the flow of production fluids
through plug 208.
[0056] FIG. 6C is a cross-sectional view of a degradable plug
including a shell, a core disposed within the shell and formed of a
degradable composition that is reactive under defined conditions,
and a rupture disk. Plug 208 may include socket 602 which may be
configured to engage with a tool to permit plug 208 to be
positioned within or extracted from downhole assembly 200 (shown in
FIG. 2). Plug 208 may also include core 604 disposed within channel
606 extending through shell 608. As discussed above with respect to
FIG. 6B, core 604 may be removed from shell 610 using a chemical
reaction that causes core 604 to degrade. Socket 602 may be open to
channel 606 such that, when core 604 is removed from shell 608,
fluid may flow through plug 208 via socket 602 and channel 606.
[0057] Plug 208 may further include rupture disk 618 that
temporarily protects core 604 from degradation until the rupture
disk is compromised allowing the corrosive or acidic fluid to
contact the metal or alloy. Rupture disk 618 may be formed of a
material that fractures when exposed to a threshold pressure. The
threshold pressure may be a pressure greater than a pressure that
occurs during operation of wellbore 114 (shown in FIG. 1). The
pressure in wellbore 114 (shown in FIG. 1) or annulus 212 (shown in
FIG. 2) may be manipulated such that it exceeds the threshold
pressure, causing rupture disk 618 to fracture. When rupture disk
618 fractures, the surface of core 604 may be exposed to the brine
fluid, corrosive fluid, or acidic fluid circulating in annulus 212
(shown in FIG. 2). As discussed above with respect to FIG. 6B,
exposure to the brine fluid, corrosive fluid, or acidic fluid may
trigger a chemical reaction or galvanic reaction that causes core
604 to degrade.
[0058] As discussed above with respect to FIG. 6B, shell 608 may be
formed of a non-reactive material that remains structurally intact
even when exposed to the corrosive or acidic fluid for a duration
of time sufficient to degrade core 604 is formed into pieces or
particles small enough that they do not impede the flow of
production fluids through plug 208.
[0059] FIG. 6D is a cross-sectional view of a degradable plug
including a core formed of a degradable composition that is
reactive under defined conditions and disposed within a shell
including a diffusion channel. Plug 208 also may include socket 602
which may be configured to engage with a tool to permit plug 208 to
be positioned within or extracted from downhole assembly 200 (shown
in FIG. 2). Plug 208 may also include core 604 disposed within
channel 614 extending axially through a portion of shell 610. As
discussed above with respect to FIG. 6B, core 604 may be removed
from shell 610 using a chemical reaction that causes core 604 to
degrade.
[0060] Shell 610 may include diffusion channel 612 extending
radially through shell 610. When core 604 is removed from shell
610, fluid may flow through plug 208 via channel 614 and diffusion
channel 612. Surface 616 of shell 610 may act as a diffuser,
deflecting fluids flowing through channel 614 into diffusion
channel 612. Shell 610 may be formed of a non-reactive material.
The non-reactive material may be selected such that it remains
structurally intact even when exposed to the corrosive or acidic
fluid for a duration of time sufficient to degrade core 604 into
pieces or particles small enough that they do not impede the flow
of production fluids through plug 208.
[0061] Although not illustrated in FIG. 6D, shell 610 may also
include rupture disk 618 (shown in FIG. 6C). As discussed with
respect to FIG. 6C, rupture disk 618 may temporarily protect core
604 from degradation until the rupture disk is compromised allowing
the corrosive or acidic fluid to contact the metal or alloy.
[0062] FIG. 7 illustrates a method of temporarily preventing the
flow of fluids into or out of a production string. Method 700 may
begin, and at step 710, a plug may be positioned within a downhole
assembly to temporarily block the flow of production fluids into a
production string or injection fluids out of the production string.
As discussed above with respect to FIG. 2, the downhole assembly
may include a screen and a shroud, which may be coupled to and
disposed downhole from the screen. Both the screen and the shroud
may be coupled to and disposed around the circumference of tubing
coupled to the production string such that an annulus is formed
between the inner surfaces of the screen and shroud and the outer
surface of the tubing. The downhole assembly may also include a
flow control device disposed within the annulus. The plug may be
positioned in the portion of the annulus downhole from the flow
control device.
[0063] In some embodiments, the plug may be positioned in-line with
and adjacent to the flow control device, as shown in FIG. 2. In
other embodiments, the plug may be positioned in-line with and
axially displaced from the flow control device, as shown in FIG. 3.
In still other embodiments, the plug may positioned in an opening
in the tubing, as shown in FIG. 4. As discussed above with respect
to FIGS. 5A-5E, the plug may engage shroud and the tubing or the
opening to form a fluid and pressure tight seal. Production fluids
circulating in the wellbore may enter the downhole assembly by
flowing through the screen and into the annulus, but as discussed
above with respect to FIGS. 2-4, the flow of production fluids from
the annulus into the tubing and the production string may be
temporarily blocked by the plug. Similarly, injection fluids
circulating in the production string may be temporarily blocked
from flowing into the formation by the plug.
[0064] The plug may be positioned within the downhole assembly
before the downhole assembly is positioned in the wellbore.
Alternatively, the plug may be positioned within the downhole
assembly after the downhole assembly is positioned in the wellbore.
As discussed above with respect to FIG. 2, the downhole assembly
may include a port, which may be removed to permit access to the
portion of the annulus downhole from the flow control device. When
the port has been removed, the plug may be positioned within the
downhole assembly.
[0065] At step 720, the plug (or the core of the plug) may be
removed in order to permit the flow of fluids into or out of the
production string. As discussed above with respect to FIGS. 6A-6D,
the plug (or the core of the plug) may be removed by a chemical or
electro-chemical reaction that causes the plug (or the core) to
degrade. Once the chemical reaction has been triggered, the
reaction may continue until the plug (or the core) breaks down into
pieces or dissolves into particles small enough that they do not
impede the flow of production fluids. For example, where the entire
plug degrades, the reaction may continue until the plug breaks down
into pieces or dissolves into particles small enough that they do
not impede the flow of production fluids through the flow control
device or the opening. Where only the core of the plug degrades,
the reaction may continue until the core breaks down into pieces or
dissolves into particles small enough that they do not impede the
flow of production fluids through the flow control device, the
opening, or the plug. When the plug (or the core) has degraded to
this point, fluids may flow into and out of the production
string.
[0066] At step 730, the flow of fluids into and out of the
production string may be permitted. As discussed above with respect
to step 710, production fluids circulating in the wellbore may
enter the downhole assembly by flowing through a screen and into
the annulus. Production fluids circulating in the annulus may flow
through a flow control device disposed in the annulus and into the
portion of the annulus downhole from flow the control device. From
there, the production fluids may flow through an opening=formed in
a sidewall of tubing coupled to the production string and into the
production string. Similarly, injection fluids circulating in the
production string may flow into the annulus through the opening
formed in the sidewall of the tubing. From there, the injection
fluids may flow through the flow control device disposed in the
annulus and into the formation.
[0067] At step 740, a determination may be made regarding whether
to temporarily prevent the flow of fluids into or out of the
production string. If it is determined to temporarily prevent the
flow of fluids into the production string, the method may return to
step 710. If it is determined not to temporarily prevent the flow
of fluids into the production string, the method may end.
[0068] Modifications, additions, or omissions may be made to method
700 without departing from the scope of the present disclosure. For
example, the order of the steps may be performed in a different
manner than that described and some steps may be performed at the
same time. Additionally, each individual step may include
additional steps without departing from the scope of the present
disclosure.
[0069] Embodiments disclosed herein include:
[0070] A. A downhole assembly that includes a tube disposed in a
wellbore, a shroud coupled to and disposed around the circumference
of the tube to form an annulus between an inner surface of the
shroud and an outer surface of the tube, a flow control device
disposed in the annulus, and a degradable plug disposed in the
annulus and positioned to prevent fluid flow between the annulus
and the tube.
[0071] B. A well system that includes a production string, and a
downhole assembly coupled to and disposed downhole from the
production string. The downhole assembly includes a tube, a shroud
coupled to and disposed around the circumference of the tube to
form an annulus between an inner surface of the shroud and an outer
surface of the tube, a flow control device disposed in the annulus,
and a degradable plug disposed in the annulus and positioned to
prevent fluid flow between the annulus and the tube.
[0072] C. A method of temporarily preventing fluid flow between a
production string and a wellbore that includes positioning a
degradable plug in a wellbore such that the plug prevents fluid
flow between a production string and a wellbore, and triggering a
chemical reaction that causes the degradable plug to degrade to a
point where fluid flow between the production string and the
wellbore is permitted.
[0073] Each of embodiments A, B, and C may have one or more of the
following additional elements in any combination: Element 1: the
downhole assembly further includes a screen coupled to and disposed
uphole from the shroud and coupled to and disposed around the
circumference of the tube such that an annulus is formed between an
inner surface of the screen and the outer surface of the tube.
Element 2: wherein the degradable plug is positioned in-line with
and adjacent to the flow control device. Element 3: wherein the
degradable plug is positioned in-line with and axially displaced
from the flow control device. Element 4: wherein the degradable
plug is engaged with the shroud and the tube to form a fluid and
pressure tight seal. Element 5: wherein the degradable plug is
positioned in an opening formed in a sidewall of the tube, and
engaged with the tube to form a fluid and pressure tight seal and
prevent fluid flow between the annulus and the tube. Element 6:
wherein the degradable plug is formed of a composition that
degrades within the annulus within a predetermined time of exposure
to a particular fluid. Element 7: wherein the degradable plug
includes a degradable plug formed of a composition that degrades
within the annulus within a predetermined time of exposure to a
particular fluid, and a coating formed around the degradable plug
that temporarily protects the degradable plug from exposure to the
particular fluid. Element 8: wherein the degradable plug comprises
a first composition imbedded with particles of a second composition
to form a galvanic cell. Element 9: wherein the degradable plug
includes a shell including a channel extending there through, and a
degradable core disposed within the channel and formed of a
composition that degrades within the annulus within a predetermined
time of exposure to a particular fluid. Element 10: wherein the
degradable plug includes a shell including a channel extending
there through, a degradable core disposed within the shell and
formed of a composition that degrades within the annulus within a
predetermined time of first exposure to a particular fluid, and a
rupture disk that temporarily protects the degradable plug from
exposure to the particular fluid, the rupture disk formed of a
material that fractures when exposed to a threshold pressure.
Element 11: wherein the degradable plug includes a shell including
a first channel extending radially there through, and a second
channel extending axially from an outer surface of the shell to the
first channel, and a degradable core disposed within the second
channel and formed of a composition that degrades within the
annulus within a predetermined time of exposure to a particular
fluid. Element 12: wherein the degradable plug includes a rupture
disk that temporarily protects the degradable core from exposure to
the particular fluid, the rupture disk formed of a material that
fractures when exposed to a threshold pressure.
[0074] Element 13: wherein the degradable plug is positioned in
fluid communication with a flow control device. Element 14: wherein
the chemical reaction is triggered by exposure of the degradable
plug to a particular fluid for an amount of time exceeding a
threshold time. Element 15: wherein triggering the chemical
reaction comprises removing a protective coating formed around the
degradable plug to expose the degradable plug to a particular
fluid. Element 16: wherein removing the protective coating
comprises exposing the degradable plug to a threshold temperature
that causes the protective coating to melt. Element 17: wherein
removing the protective coating comprises exposing the degradable
plug to a threshold pressure that causes the protective coating to
fracture. Element 18: wherein the degradable plug degrades into
particles small enough that they do not impede fluid flow. Element
19: wherein the chemical reaction causes a core of the degradable
plug to degrade to a point where flow of fluids through the
degradable plug is permitted. Element 20: wherein triggering the
chemical reaction comprises rupturing a rupture disk to expose a
core of the degradable plug to a particular fluid for an amount of
time exceeding a threshold time.
[0075] Therefore, the disclosed systems and methods are well
adapted to attain the ends and advantages mentioned as well as
those that are inherent therein. The particular embodiments
disclosed above are illustrative only, as the teachings of the
present disclosure may be modified and practiced in different but
equivalent manners apparent to those skilled in the art having the
benefit of the teachings herein. Furthermore, no limitations are
intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed
above may be altered, combined, or modified and all such variations
are considered within the scope of the present disclosure. The
systems and methods illustratively disclosed herein may suitably be
practiced in the absence of any element that is not specifically
disclosed herein and/or any optional element disclosed herein.
[0076] Although the present disclosure and its advantages have been
described in detail, it should be understood that various changes,
substitutions and alterations can be made herein without departing
from the spirit and scope of the disclosure as defined by the
following claims.
* * * * *