U.S. patent application number 14/041413 was filed with the patent office on 2014-04-17 for controlled swell-rate swellable packer and method.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Pontus GAMSTEDT, Jens HINKE.
Application Number | 20140102726 14/041413 |
Document ID | / |
Family ID | 50474346 |
Filed Date | 2014-04-17 |
United States Patent
Application |
20140102726 |
Kind Code |
A1 |
GAMSTEDT; Pontus ; et
al. |
April 17, 2014 |
Controlled Swell-Rate Swellable Packer and Method
Abstract
A controlled swell-rate swellable packer comprises a mandrel, a
sealing element, and a jacket. The sealing element is disposed
about at least a portion of the mandrel, and the jacket covers at
least a portion of an outer surface of the sealing element. The
jacket comprises a substantially impermeable material with respect
to a swelling agent that is configured to cause the sealing element
to swell.
Inventors: |
GAMSTEDT; Pontus; (Kattarp,
SE) ; HINKE; Jens; (Roskilde, DK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
50474346 |
Appl. No.: |
14/041413 |
Filed: |
September 30, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61714653 |
Oct 16, 2012 |
|
|
|
Current U.S.
Class: |
166/387 ;
166/179; 166/378 |
Current CPC
Class: |
E21B 33/12 20130101;
B05D 7/50 20130101; E21B 33/13 20130101; B05D 1/36 20130101; E21B
33/1208 20130101; E21B 33/02 20130101 |
Class at
Publication: |
166/387 ;
166/179; 166/378 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 33/13 20060101 E21B033/13 |
Claims
1. A controlled swell-rate swellable packer comprising: a mandrel;
a sealing element, wherein the sealing element is disposed about at
least a portion of the mandrel; and a jacket, wherein the jacket
covers at least a portion of an outer surface of the sealing
element, and wherein the jacket comprises a substantially
impermeable material with respect to a swelling agent that is
configured to cause the sealing element to swell.
2. The controlled swell-rate swellable packer of claim 1, wherein
the mandrel comprises a tubular body generally defining a
continuous axial flowbore.
3. The controlled swell-rate swellable packer of claim 1, wherein
the sealing element comprises a swellable material.
4. The controlled swell-rate swellable packer of claim 3, wherein
the swellable material comprises a water-swellable material, an
oil-swellable material, or any combination thereof
5. The controlled swell-rate swellable packer of claim 3, wherein
the swellable material comprises a compound selected from the group
consisting of: a natural rubber, an acrylate butadiene rubber, a
polyacrylate rubber, an isoprene rubber, a choloroprene rubber, a
butyl rubber (IIR), a brominated butyl rubber (BIIR), a chlorinated
butyl rubber (CIIR), a chlorinated polyethylene (CM/CPE), a
neoprene rubber (CR), a styrene butadiene copolymer rubber (SBR), a
sulphonated polyethylene (CSM), ethylene acrylate rubber (EAM/AEM),
an epichlorohydrin ethylene oxide copolymer (CO, ECO), an
ethylene-propylene rubber (EPM and EDPM), an
ethylene-propylene-diene terpolymer rubber (EPT), an ethylene vinyl
acetate copolymer, a fluorosilicone rubber (FVMQ), a silicone
rubber (VMQ), poly 2,2,1-bicyclo heptene (polynorborneane), an
alkylstyrene, a crosslinked substituted vinyl acrylate copolymer,
and any combination thereof.
6. The controlled swell-rate swellable packer of claim 3, wherein
the swellable material comprises a water-swellable material, and
wherein the swellable material comprises a compound selected from
the group consisting of: a nitrile rubber (NBR), a hydrogenated
nitrile rubber (HNBR, HNS), a fluoro rubber (FKM), a perfluoro
rubber (FFKM), tetrafluorethylene/propylene (TFE/P), a
starch-polyacrylate acid graft copolymer, a polyvinyl alcoholcyclic
acid anhydride graft copolymer, isobutylene maleic anhydride, an
acrylic acid type polymer, a vinylacetate-acrylate copolymer, a
polyethylene oxide polymer, a carboxymethyl cellulose type polymer,
a starch-polyacrylonitrile graft copolymer, polymethacrylate,
polyacrylamide, a non-soluble acrylic polymer, sodium bentonite,
and any combination thereof.
7. The controlled swell-rate swellable packer of claim 3, wherein
the swellable material is characterized by a particle size of from
about 0.1 microns to about 2000 microns.
8. The controlled swell-rate swellable packer of claim 1, wherein
the jacket covers at least about 75% of the outer surface of the
sealing element.
9. The controlled swell-rate swellable packer of claim 1, wherein
the jacket comprises a fluoro-elastomer, a plastic, polyethylene,
polypropylene, or combinations thereof.
10. A method of making a controlled swell-rate swellable packer,
comprising: providing a mandrel having at least one sealing element
disposed about at least a portion thereof; masking at least a
portion of any exposed portions of the sealing element with a mask;
applying a jacket to the sealing element; removing the mask; and
providing a controlled swell-rate swellable packer.
11. The method of claim 10, wherein the mask is configured to cover
a portion of the sealing element.
12. The method of claim 10, wherein the mask comprises at least one
of a grid-like pattern, a diamond pattern, or a random pattern.
13. The method of claim 10, wherein the mask is formed from at
least one of paper, plastic, wires, metals, a fibrous material, or
any combination thereof.
14. The method of claim 10, wherein applying the jacket to the
sealing element comprises at least one of spraying a liquideous or
substantially liquideous material onto the sealing element,
painting a liquideous or substantially liquideous material onto the
sealing element, or dipping the sealing element into a liquideous
or substantially liquideous material.
15. The method of claim 10, further comprising drying the jacket
before removing the mask.
16. A method of utilizing a controlled swell-rate swellable packer,
comprising: providing a controlled swell-rate swellable packer,
wherein the controlled swell-rate swellable packer comprises a
sealing element and a jacket, wherein the jacket is disposed on a
first portion of an outer surface of the sealing element, and
wherein a second portion of the outer surface of the sealing
element is uncovered; disposing a tubular string having the
controlled swell-rate swellable packer incorporated therein within
a wellbore; and activating the controlled swell-rate swellable
packer.
17. The method of claim 16, wherein the controlled swell-rate
swellable packer further comprises a mandrel, wherein the sealing
element is disposed circumferentially about at least a portion of
the mandrel.
18. The method of claim 16, wherein the sealing element comprises a
swellable material.
19. The method of claim 16, wherein activating the controlled-rate
swellable packer comprises contacting at least a portion of the
controlled swell-rate packer with a swelling agent.
20. The method of claim 19, wherein the swelling agent comprises a
water-based fluid, an oil-based fluid, or any combination
thereof.
21. The method of claim 19, wherein contacting at least the portion
of the controlled swell-rate packer with the swelling agent
comprises contacting the second portion of the outer surface of the
sealing element with the swelling agent.
22. The method of claim 19, wherein contacting at least the portion
of the controlled swell-rate packer with the swelling agent
comprises contacting the second portion of the outer surface of the
sealing element with the swelling agent for at least 2 days.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and the benefit of U.S.
Provisional Application No. 61/714,653, filed Oct. 16, 2012, to
Gamstedt, et al., and entitled "Controlled Swell-Rate Swellable
Packer and Method," which is incorporated herein by reference in
its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
BACKGROUND
[0004] Hydrocarbons are commonly produced from hydrocarbon-bearing
portions of a subterranean formation via a wellbore penetrating the
formation. A casing or liner is conventionally disposed within the
wellbore and may be secured against the formation with cement which
may be displaced into the annular space between the casing or liner
and the wellbore.
[0005] Packers may also be utilized to secure a casing string
within a wellbore. However, conventionally-available packers do not
allow for such packer to be placed at a desired location within a
wellbore. As such, improved packers are needed.
SUMMARY
[0006] Disclosed herein is a controlled swell-rate swellable
packer.
[0007] Also disclosed herein is a method of making a controlled
swell-rate swellable packer, comprising providing a mandrel having
at least one sealing element disposed about at least a portion
thereof, masking at least a portion of the otherwise exposed
portions of the sealing element, applying a jacket to the sealing
element, and removing the mask, thereby yielding a controlled
swell-rate swellable packer.
[0008] Further disclosed herein is a method of utilizing a
controlled swell-rate swellable packer, as substantially disclosed
herein, comprising providing a controlled swell-rate swellable
packer, disposing a tubular string having the controlled swell-rate
swellable packer incorporated therein within a wellbore, and
activating the controlled swell-rate swellable packer.
[0009] In an embodiment, a controlled swell-rate swellable packer
comprises a mandrel, a sealing element, and a jacket. The sealing
element is disposed about at least a portion of the mandrel, and
the jacket covers at least a portion of an outer surface of the
sealing element. The jacket comprises a substantially impermeable
material with respect to a swelling agent that is configured to
cause the sealing element to swell. The mandrel may comprise a
tubular body generally defining a continuous axial flowbore. The
sealing element may comprises a swellable material, and the
swellable material may comprise a water-swellable material, an
oil-swellable material, or any combination thereof The swellable
material may comprise a compound selected from the group consisting
of: a natural rubber, an acrylate butadiene rubber, a polyacrylate
rubber, an isoprene rubber, a choloroprene rubber, a butyl rubber
(IIR), a brominated butyl rubber (BIIR), a chlorinated butyl rubber
(CIIR), a chlorinated polyethylene (CM/CPE), a neoprene rubber
(CR), a styrene butadiene copolymer rubber (SBR), a sulphonated
polyethylene (CSM), ethylene acrylate rubber (EAM/AEM), an
epichlorohydrin ethylene oxide copolymer (CO, ECO), an
ethylene-propylene rubber (EPM and EDPM), an
ethylene-propylene-diene terpolymer rubber (EPT), an ethylene vinyl
acetate copolymer, a fluorosilicone rubber (FVMQ), a silicone
rubber (VMQ), poly 2,2,1-bicyclo heptene (polynorborneane), an
alkylstyrene, a crosslinked substituted vinyl acrylate copolymer,
and any combination thereof The swellable material may comprise a
water-swellable material, and the swellable material comprises a
compound selected from the group consisting of: a nitrile rubber
(NBR), a hydrogenated nitrile rubber (HNBR, HNS), a fluoro rubber
(FKM), a perfluoro rubber (FFKM), tetrafluorethylene/propylene
(TFE/P), a starch-polyacrylate acid graft copolymer, a polyvinyl
alcoholcyclic acid anhydride graft copolymer, isobutylene maleic
anhydride, an acrylic acid type polymer, a vinylacetate-acrylate
copolymer, a polyethylene oxide polymer, a carboxymethyl cellulose
type polymer, a starch-polyacrylonitrile graft copolymer,
polymethacrylate, polyacrylamide, a non-soluble acrylic polymer,
sodium bentonite, and any combination thereof The swellable
material may be characterized by a particle size of from about 0.1
microns to about 2000 microns. The jacket may cover at least about
75% of the outer surface of the sealing element. The jacket may
comprise a fluoro-elastomer, a plastic, polyethylene,
polypropylene, or combinations thereof.
[0010] In an embodiment, a method of making a controlled swell-rate
swellable packer comprises providing a mandrel having at least one
sealing element disposed about at least a portion thereof, masking
at least a portion of any exposed portions of the sealing element
with a mask, applying a jacket to the sealing element, removing the
mask, and providing a controlled swell-rate swellable packer. The
mask may be configured to cover a portion of the sealing element.
The mask may comprise at least one of a grid-like pattern, a
diamond pattern, or a random pattern. The mask may be formed from
at least one of paper, plastic, wires, metals, a fibrous material,
or any combination thereof Applying the jacket to the sealing
element may comprise at least one of spraying a liquideous or
substantially liquideous material onto the sealing element,
painting a liquideous or substantially liquideous material onto the
sealing element, or dipping the sealing element into a liquideous
or substantially liquideous material. The method may also include
drying the jacket before removing the mask.
[0011] In an embodiment, a method of utilizing a controlled
swell-rate swellable packer comprises providing a controlled
swell-rate swellable packer, disposing a tubular string having the
controlled swell-rate swellable packer incorporated therein within
a wellbore, and activating the controlled swell-rate swellable
packer. The controlled swell-rate swellable packer comprises a
sealing element and a jacket. The jacket is disposed on a first
portion of an outer surface of the sealing element, and a second
portion of the outer surface of the sealing element is uncovered.
The controlled swell-rate swellable packer may further comprise a
mandrel, and the sealing element may be disposed circumferentially
about at least a portion of the mandrel. The sealing element may
comprise a swellable material. Activating the controlled-rate
swellable packer may comprises contacting at least a portion of the
controlled swell-rate packer with a swelling agent. The swelling
agent may comprise a water-based fluid, an oil-based fluid, or any
combination thereof Contacting at least the portion of the
controlled swell-rate packer with the swelling agent may comprise
contacting the second portion of the outer surface of the sealing
element with the swelling agent, and Contacting at least the
portion of the controlled swell-rate packer with the swelling agent
may comprise contacting the second portion of the outer surface of
the sealing element with the swelling agent for at least 2
days.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description:
[0013] FIG. 1 is partial cut-away view of an embodiment of an
environment in which a controlled swell-rate swellable packer may
be employed;
[0014] FIG. 2 is a cutaway view of an embodiment of a controlled
swell-rate swellable packer;
[0015] FIG. 3 is a perspective view of an embodiment of a
controlled swell-rate swellable packer;
[0016] FIG. 4 is a view of an embodiment of a mask which may be
utilized in the manufacture of a controlled swell-rate swellable
packer; and
[0017] FIGS. 5-8 demonstrate examples associated with the
controlled swell-rate swellable packer, as will be disclosed
herein.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0018] In the drawings and description that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals, respectively. In addition, similar
reference numerals may refer to similar components in different
embodiments disclosed herein. The drawing figures are not
necessarily to scale. Certain features of the invention may be
shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in the interest
of clarity and conciseness. The present invention is susceptible to
embodiments of different forms. Specific embodiments are described
in detail and are shown in the drawings, with the understanding
that the present disclosure is not intended to limit the invention
to the embodiments illustrated and described herein. It is to be
fully recognized that the different teachings of the embodiments
discussed herein may be employed separately or in any suitable
combination to produce desired results.
[0019] Unless otherwise specified, use of the terms "connect,"
"engage," "couple," "attach," or any other like term describing an
interaction between elements is not meant to limit the interaction
to direct interaction between the elements and may also include
indirect interaction between the elements described.
[0020] Unless otherwise specified, use of the terms "up," "upper,"
"upward," "up-hole," "upstream," or other like terms shall be
construed as generally from the formation toward the surface or
toward the surface of a body of water; likewise, use of "down,"
"lower," "downward," "down-hole," "downstream," or other like terms
shall be construed as generally into the formation away from the
surface or away from the surface of a body of water, regardless of
the wellbore orientation. Use of any one or more of the foregoing
terms shall not be construed as denoting positions along a
perfectly vertical axis.
[0021] Unless otherwise specified, use of the term "subterranean
formation" shall be construed as encompassing both areas below
exposed earth and areas below earth covered by water such as ocean
or fresh water.
[0022] Disclosed herein are embodiments of wellbore servicing
methods, as well as apparatuses and systems that may be utilized in
performing the same. Particularly, disclosed herein are one or more
embodiments of a wellbore servicing apparatus comprising a
controlled swell-rate swellable packer (CSSP) and systems and
methods of employing the same. In an embodiment, the CSSP, as will
be disclosed herein, may allow an operator to deployed a swellable
packer within a subterranean formation and to control the rate at
which the CSSP will expand so as to isolate two or more portions of
a wellbore and/or two or more zones of a subterranean
formation.
[0023] As depicted in FIG. 1, the operating environment generally
comprises a wellbore 114 that penetrates a subterranean formation
102 for the purpose of recovering hydrocarbons, storing
hydrocarbons, disposing of carbon dioxide, or the like. The
wellbore 114 may be drilled into the subterranean formation 102
using any suitable drilling technique. In an embodiment, a drilling
or servicing rig 106 comprises a derrick 108 with a rig floor 110
through which a tubular string (e.g., a drill string, a tool
string, a segmented tubing string, a jointed tubing string, a
casing string, or any other suitable conveyance, or combinations
thereof) generally defining an axial flowbore may be positioned
within or partially within the wellbore. In an embodiment, the
tubular string may comprise two or more concentrically positioned
strings of pipe or tubing (e.g., a first work string may be
positioned within a second work string). The drilling or servicing
rig 106 may be conventional and may comprise a motor driven winch
and other associated equipment for lowering the tubular string into
the wellbore 114. Alternatively, a mobile workover rig, a wellbore
servicing unit (e.g., coiled tubing units), or the like may be used
to lower the work string into the wellbore 114. While FIG. 1
depicts a stationary drilling rig 106, one of ordinary skill in the
art will readily appreciate that mobile workover rigs, wellbore
servicing units (such as coiled tubing units), and the like may be
employed.
[0024] The wellbore 114 may extend substantially vertically away
from the earth's surface over a vertical wellbore portion, or may
deviate at any angle from the earth's surface 104 over a deviated
or horizontal wellbore portion. In alternative operating
environments, portions or substantially all of the wellbore 114 may
be vertical, deviated, horizontal, and/or curved.
[0025] In the embodiment of FIG. 1, at least a portion of the
wellbore 114 is lined with a casing string and/or liner 120
defining an axial flowbore 121. In the embodiment of FIG. 1, at
least a portion of the casing string 120 is secured into position
against the formation 102 via a plurality of CSSPs 200 (e.g., a
first CSSP 200a, a second CSSP 200b, a third CSSP 200c, and a
fourth CSSP 200d). Additionally, in an embodiment, at least a
portion of the casing string 120 being partially secured into
position against the formation 102 in a conventional manner with
cement. In additional or alternative operating environments, a
CSSP, like CSSP 200 as will be disclosed herein, may be similarly
incorporated within (and similarly utilized to secure) any suitably
tubular string. Examples of such a tubular string include, but are
not limited to, a work string, a jointed pipe string, a coiled
tubing string, a production tubing string, a drill string, the
like, or combinations thereof.
[0026] In an embodiment, the casing string 120 may further have
incorporated therein at least one wellbore servicing tool (WST) 300
(e.g., a first WST 300a, a second WST 300b, a third WST 300c, and a
fourth WST 300d). In an embodiment, one or more of the WSTs 300 may
comprise an actuatable stimulation assembly, which may be
configured for the performance of a wellbore servicing operation,
particularly, a stimulation operation such as a perforating
operation, a fracturing operation, an acidizing operation, or
combinations thereof.
[0027] Referring to FIG. 2, an embodiment of a CSSP 200 is
illustrated. In the embodiment of FIG. 2, the CSSP 200 generally
comprises a mandrel 210, a sealing element 220 disposed
circumferentially about/around at least a portion of the mandrel
210, and a jacket 230 covering at least a portion of the sealing
element 220.
[0028] In an embodiment, the mandrel 210 is a generally cylindrical
or tubular-like structure. In an embodiment, the mandrel 210 may
comprise a unitary structure, alternatively, two or more operably
connected components. Alternatively, a mandrel may comprise any
suitable structure; such suitable structures will be appreciated by
those of skill in the art with the aid of this disclosure.
[0029] In an embodiment the mandrel 210 may be configured for
incorporation into the casing string 120 (alternatively, into any
suitable tubular string). In such an embodiment, the mandrel 210
may comprise a suitable connection to the casing 120 (e.g., to a
casing string member, such as a casing joint). Suitable connections
to a casing string will be known to those of skill in the art. In
such an embodiment, the mandrel 210 is incorporated within the
casing 120 such that an axial flowbore defined by the mandrel 210
is in fluid communication with the axial flowbore of the casing
string 120.
[0030] In an embodiment, the sealing element 220 may generally be
configured to selectively seal and/or isolate two or more portions
of an annular space surrounding the CSSP 200 (e.g., between the
CSSP 200 and one or more walls of the wellbore 114), for example,
by selectively providing a barrier extending circumferentially
around at least a portion of the exterior of the CSSP 200. In an
embodiment, the sealing element 220 may generally comprise a
cylindrical structure having an interior bore (e.g., a tube-like
and/or a ring-like structure). The sealing element 220 may comprise
a suitable interior diameter, a suitable external diameter, and/or
a suitable thickness, for example, as may be selected by one of
skill in the upon viewing this disclosure and in consideration of
factors including, but not limited to, the size/diameter of the
mandrel 210, the against which the sealing element is configured to
engage, the force with which the sealing elements is configured to
engage such surface(s), or other related factors. While the
embodiment of FIG. 1 illustrates a CSSP 200 comprising a single
sealing element 220, one of skill in the art, upon viewing this
disclosure, will appreciate that a similar CSSP may comprise two,
three, four, five, or any other suitable number of sealing elements
like sealing element 220.
[0031] In an embodiment, the sealing element 220 may be configured
to exhibit a radial expansion (e.g., an increase in exterior
diameter) upon being contacted with a selected fluid, that is, a
swelling agent. As used herein, swellable materials generally refer
to any elastomer that swells upon contact with the swelling agent.
For example, the swellable material may be characterized as a
resilient, volume changing material. A variety of swellable
materials may be utilized in accordance with the present
disclosure, including, but not limited to, those that swell upon
contact with an oleaginous fluid and/or an aqueous fluid, such as
water. Swellable materials suitable for use in the present
invention may generally swell by up to approximately 500% of their
original size at the surface. Under downhole conditions, this
swelling may be more or less depending on the conditions present.
In some embodiments, the swelling may be about 400%, alternatively,
up to about 300%, alternatively, up to about 200%, alternatively,
up to about 150% under downhole conditions. In a swelled condition
(partially, substantially, or fully swelled) to at least some
extent, the elastomers may be referred to as swelled materials.
[0032] Examples of suitable such swellable materials that swell
upon contact with an oleaginous fluid and/or an aqueous fluid
include, but are not limited to, natural rubber, acrylate butadiene
rubbers, polyacrylate rubbers, isoprene rubbers, choloroprene
rubbers, butyl rubbers (IIR), brominated butyl rubbers (BIIR),
chlorinated butyl rubbers (CIIR), chlorinated polyethylene
(CM/CPE), neoprene rubbers (CR), styrene butadiene copolymer
rubbers (SBR), sulphonated polyethylene (CSM), ethylene acrylate
rubbers (EAM/AEM), epichlorohydrin ethylene oxide copolymers (CO,
ECO), ethylene-propylene rubbers (EPM and EDPM),
ethylene-propylene-diene terpolymer rubbers (EPT), ethylene vinyl
acetate copolymers, fluorosilicone rubbers (FVMQ), silicone rubbers
(VMQ), poly 2,2,1-bicyclo heptene (polynorborneane), alkylstyrene,
crosslinked substituted vinyl acrylate copolymers and diatomaceous
earth. Examples of suitable elastomers that swell when in contact
with aqueous fluid include, but are not limited to, nitrile rubbers
(NBR), hydrogenated nitrile rubbers (HNBR, HNS), fluoro rubbers
(FKM), perfluoro rubbers (FFKM), tetrafluorethylene/propylene
(TFE/P), starch-polyacrylate acid graft copolymers, polyvinyl
alcoholcyclic acid anhydride graft copolymers, isobutylene maleic
anhydride, acrylic acid type polymers, vinylacetate-acrylate
copolymer, polyethylene oxide polymers, carboxymethyl cellulose
type polymers, starch-polyacrylonitrile graft copolymers and the
like, polymethacrylate, polyacrylamide, non-soluble acrylic
polymers, and highly swelling clay minerals such as sodium
bentonite (having as main ingredient montmorillonite). Other
swellable materials that behave in a similar fashion with respect
to oleaginous fluids or aqueous fluids also may be suitable. Those
of ordinary skill in the art, with the benefit of this disclosure,
will be able to select an appropriate swellable elastomer for use
in the compositions of the present invention based on a variety of
factors, including the application in which the composition will be
used and the desired swelling characteristics. Suitable swellable
materials are commercially available as Swellpackers from
Halliburton Energy Services, Inc. in Houston, Tex.
[0033] The swellable elastomers may be any shape or size,
including, but not limited to, spherical, fiber-like, ovoid,
ribbons, etc. In some embodiments, the swellable elastomers may be
particles ranging in size from about 0.1 .mu.m to about 2000 .mu.m.
Other examples of suitable swellable elastomers that may be used in
the methods of the present invention are disclosed in U.S.
Application Publication No. 2004/0261990, which is incorporated in
its entirety herein by reference.
[0034] In an embodiment, the jacket 230 may be generally configured
to control the rate (and/or duration required) at which the
swellable material will swell upon sufficient contact between the
CSSP and the swelling agent, that is, the "swell-rate." Not
intending to be bound by theory, the jacket 230 may control the
swell-rate by limiting the exposure of the swellable material
(e.g., the sealing member 220) to the swelling agent. For example,
in the embodiment of FIG. 2, the jacket 230 generally covers the
outer surfaces of the sealing member 220. As such, and again, not
intending to be bound by theory, contact between the swelling agent
and the sealing element (and, as such, the swelling of the
swellable material) may be dependent upon the jacket which allows
fluidic access to the sealing element.
[0035] In an embodiment, the jacket 230 may cover a suitable
portion of the otherwise exposed surfaces of the sealing element
220, that is, a portion of the surfaces of the sealing element 220
that would be exposed (e.g., so as to be in contact with a swelling
agent, when such swelling agent is present), were the jacket 230
not present. For example, the jacket may cover about 75%,
alternatively, about 80%, alternatively, about 81%, alternatively,
about 82%, alternatively, about 83%, alternatively, about 84%,
alternatively, about 85%, alternatively, about 86%, alternatively,
about 87%, alternatively, about 88%, alternatively, about 89%,
alternatively, about 90%, alternatively, about 91%, alternatively,
about 92%, alternatively, about 93%, alternatively, about 94%,
alternatively, about 95% of the otherwise exposed surface area of
the sealing element 220 may be covered (e.g., fluidicly sealed) by
the jacket 230.
[0036] In an embodiment, the jacket 230 may comprise an impermeable
material with respect to the swelling agent (e.g., an aqueous
fluid, a hydrocarbon, for example, as may be present within a
downhole, wellbore environment), alternatively, a substantially
impermeable material, alternatively, a low-permeability material.
Examples of suitable materials include, but are not limited to,
fluoro-elastomers and the like, plastics, polymeric materials
(e.g., polyethylene, polypropylene), or combinations thereof
Examples of suitable materials as may be utilized to form the
jacket 230 (e.g., a coating) are commercially available from Accoat
as, inter alia, Accolan, Accoat, and Accoflex, located in
Kvistgaard, Denmark. Persons of skill in the art, upon viewing this
disclosure, may appreciate additional or alternative suitable
materials that may be similarly employed.
[0037] In an embodiment, the jacket 230 (e.g., the material
comprising the jacket 230) may be configured to be applied to the
sealing element by any suitable process. For example, in various
embodiments, the jacket may comprise a liquideous or substantially
liquideous material that may be sprayed onto the sealing element
220, painted onto the sealing element 220, into which the sealing
element 220 may be dipper, or the like. In an embodiment, the
material comprising the jacket 230 may be configured to dry (e.g.,
set, set up, harden, or the like) upon exposure to a predetermined
condition or upon passage of a given duration of time. For example,
the jacket 230 may dry (or the like) upon being heated, cooled,
exposed to a hardening chemical, or combinations thereof.
[0038] As noted above, the jacket 230 may be applied to only a
portion of the sealing element 220, for example, thereby yielding
an exposed portion (e.g., to which the jacket 230 material is not
applied) and an unexposed portion (e.g., to which the jacket 230
material is applied). For example, referring to FIG. 3, a
perspective view of a CSSP is illustrated. In the embodiment of
FIG. 3, a portion of the sealing element 220 is exposed (an exposed
portion 220a) and another portion is covered by the jacket 230 (an
unexposed portion 220b). In an embodiment, the relationship between
the exposed and unexposed portions may comprise any suitable
pattern, design, or the like.
[0039] In an embodiment, as will be disclosed herein, the exposed
and unexposed surfaces of the sealing element 220 may be obtained
by "masking" or otherwise covering a portion of the sealing element
220 (e.g., the portion of the sealing element which will be
exposed) prior to application of the jacket 230 material. In an
embodiment, such a "mask" may be configured to cover any suitable
portion of the sealing element. For example, in an embodiment, the
mask may comprise a grid-like pattern, a diamond pattern, a random
arrangement. The mask may be made from any suitable material,
examples of which include, but are not limited to, paper, plastic,
wires, metals, various fibrous materials, or combinations
thereof.
[0040] One or more embodiments of a CSSP, such as CSSP 200
disclosed herein, having been disclosed, one or more methods
related to making/assembling and utilizing such a CSSP are also
disclosed herein.
[0041] In an embodiment, a method of making a CSSP, such as CSSP
200, generally comprises the steps of providing a mandrel (e.g.,
mandrel 210 disclosed herein) having at least one sealing element
(e.g., sealing element 220) disposed about at least a portion
thereof, masking at least a portion of the otherwise exposed
portions of the sealing element, applying a jacket (e.g., jacket
230 disclosed herein) to the sealing element 220, and removing the
mask.
[0042] In an embodiment, the mandrel 210 having at least one
sealing element 220 disposed about at least a portion thereof may
be obtained. For example, suitable mandrels 210 and sealing
elements 220 may be obtained, alone or in combination, from
Halliburton Energy Services, Inc. in Houston, Tex.
[0043] In an embodiment, once a mandrel 210 having a sealing
element 220 disposed there-around is obtained, at least a portion
of the sealing element 220 (particularly, at least a portion of the
exposed surfaces of the sealing element 220) may be covered with a
mask. In an embodiment, such a mask may be preformed in any
suitable shape. An example of a suitable mask 250 is illustrated in
FIG. 4, although one of skill in the art, upon viewing this
disclosure, will appreciate other suitable configurations. In the
embodiment of FIG. 4, the mask comprises a grid-like pattern having
a plurality of void spaces 250a. In alternative embodiments, a mask
may be any suitable configuration. For example, the mask may
comprise a substantially uniform pattern; alternatively, the mask
may have no pattern at all. The mask may comprise a single sheet
(e.g., as shown in FIG. 4). Alternatively, the mask may comprise
multiple sheets, ribbons, wires, or other suitable forms. The mask
may be wrapped around the sealing element and secured in place.
[0044] In an embodiment, once the mask (e.g., mask 250) has been
secured to/around the sealing element, the jacket 230 may be
applied to the masked sealing element 230. For example, the
material comprising the jacket 230 may be sprayed onto the sealing
element 220, alternatively, the material comprising the jacket 230
may be painted or brushed onto the sealing element 220,
alternatively, the sealing element 220 may be dipped, rolled, or
submerged within the material comprising the jacket 230. As the
sealing element 220 is coated with the material which will form the
jacket 230, the jacket 230 material may adhere to the portions of
the sealing element not covered or shrouded by the mask 250.
[0045] In an embodiment, the jacket 230 material may be allows to
dry or set in place prior to removing the mask. Alternatively, the
mask may be removed at any suitable time after the jacket material
has been applied thereto. As disclosed herein, after the mask is
removed, a portion of the sealing element 220 is exposed (the
exposed portion 220a) and another portion is covered by the jacket
230 (the unexposed portion 220b).
[0046] In an embodiment, a method of utilizing a CSSP, such as CSSP
200 disclosed herein, generally comprises the steps of providing a
CSSP 200, disposing a tubular string having a CSSP 200 incorporated
therein within a wellbore, and activating the CSSP 200.
Additionally, in an embodiment, the method may further comprise
performing a wellbore servicing operation, producing a reservoir
fluid, or combinations thereof.
[0047] In an embodiment, providing a CSSP 200 may comprise one or
more of the steps of the method of making the CSSP 200, as
disclosed herein. In an embodiment, once a CSSP 200 has been
obtained (e.g., either manufactured or obtained from a
manufacturer), the CSSP 200 may be utilized as disclosed
herein.
[0048] In an embodiment, the CSSP 200 may be incorporated within a
tubular string (e.g., a casing string like casing string 120, a
work string, a production string, a drill string, or any other
suitable wellbore tubular) and disposed within a wellbore.
Additionally, for example, as disclosed with regard to FIG. 1, in
an embodiment, a tubular string may comprise two, three, four,
five, six, seven, eight, nine, ten, or more CSSPs incorporated
therein.
[0049] In an embodiment, the CSSP(s) 200 (e.g., the first, second,
third, and fourth CSSPs 200a, 200b, 200c, and 200d, respectively)
may be incorporated as the tubular string is "run into" the
wellbore (e.g., wellbore 114). For example, as will be appreciated
by one of skill in the art upon viewing this disclosure, such
tubular strings are conventionally assembled in "joints" which are
added to the uppermost end of the string as the string is run in.
The tubular string (e.g., casing string 120) may be assembled and
run into the wellbore 114 until the CSSP(s) are located at a
predetermined location, for example, such that a given CSSP (when
expanded) will isolated two adjacent zones of the formation (e.g.,
formation zones 2, 4, 6, and 8) and/or portions of the wellbore
114.
[0050] In an embodiment, once the tubular string comprising one or
more CSSPs is positioned within the wellbore, for examples, such
that the CSSPs will isolated two adjacent zones of the formation
and/or portions of the wellbore 114 when expanded, the CSSPs may be
activated, that is, caused to expand. In an embodiment, activating
the CSSP(s) may comprise contacting the CSSP with swelling agent.
As noted above, the swelling agent may comprise any suitable fluid,
for example, an oleaginous fluid, an aqueous fluid, or combinations
thereof In an embodiment, the swelling agent may comprise a fluid
already present within the wellbore 114, for example, a servicing
fluid, a formation fluid (e.g., a hydrocarbon), or combinations
thereof Alternatively, the swelling agent may be introduced into
the wellbore 114. The swelling agent may be allowed to remain in
contact with the CSSP (e.g., with the exposed surfaces of the
sealing element 220) for a sufficient amount of time for the
sealing element to expand into contact with the formation (e.g.,
with the walls of the wellbore 114), for example, at least 2 days,
alternatively, at least 4 days, alternatively, at least 8 days,
alternatively, at least 12 days, alternatively, at least 2 weeks,
alternatively, at least a month, alternatively, at least 2 months,
alternatively, at least 3 months, alternatively, at least 4 months,
alternatively, any suitable duration.
[0051] In an embodiment, contact with the swelling agent may cause
the sealing element to expand into contact with the formation
(e.g., with the walls of the wellbore 114). In such an embodiment,
the expansion of the sealing element may be effective to isolate
two or more portions of an annular space extending generally
between the tubing string and the walls of the wellbore. In an
embodiment, the expansion of the sealing element 220 may occur at a
controlled rate, as disclosed herein. For example, the expansion of
the sealing element 220 (e.g., where the sealing element continues
to expand) may occur over a predetermined duration, for example,
about 4 days, alternatively, about 6 days, alternatively, about 8
days, alternatively, about 10 days, alternatively, about 12 days,
alternatively, about 14 days, alternatively, about 16 days,
alternatively, about 18 days, alternatively, about 20 days,
alternatively, about 22 days, alternatively, about 24 days.
[0052] In an embodiment, following at least partial expansion of
the CSSP(s), for example, such that two or more portions of the
wellbore and/or two or more zones of the subterranean formation at
substantially isolated, a wellbore servicing operation may be
performed with respect to one or more of such formation zones. In
such an embodiment, the wellbore servicing operation may include
any suitable servicing operation as will be appreciated by one of
skill in the art upon viewing this disclosure. Examples of such
wellbore servicing operations include, but are not limited to, a
fracturing operation, a perforating operation, an acidizing
operation, or combinations thereof.
[0053] In an embodiment, following at least partial expansion of
the CSSP(s), for example, such that two or more portions of the
wellbore and/or two or more zones of the subterranean formation at
substantially isolated and, optionally, following the performance
of a wellbore servicing operation, a formation fluid (e.g., oil,
gas, or both) may be produced from the subterranean formation or
one or more zones thereof.
EXAMPLES
[0054] Also disclosed herein, are one or more examples
demonstrating the concepts disclosed herein with respect to the
CSSP.
[0055] FIG. 5 demonstrates the swell rates of various swellable
materials (swellable barriers/sealing elements), some of which are
uncoated, and some of which are coated with various products and in
various patterns. Generally, as can be seen from FIG. 5, the
uncoated barriers exhibited expansion in the shortest amount of
time, while coated barriers generally exhibited longer times to
expand.
[0056] FIGS. 6A, 6B, and 6C demonstrate a swellable materials
(e.g., barrier) partially coated with Accoflex P572B, as can been
seen from the mesh-like pattern surrounding the barrier, as
disclosed herein.
[0057] FIG. 7 demonstrates a comparison between (moving left to
right) a coated swellable material, a partially coated swellable
material (e.g., as can be seen from the grid-like pattern, as
disclosed herein), and an uncoated swellable material. As can be
seen, the coated swellable material exhibited the greatest
expansion while the uncoated swellable material exhibited the least
expansion, while the partially coated exhibited an intermediate
proportion of expansion.
[0058] FIG. 8 demonstrates the swellrates of various swellable
materials (swellable barriers/sealing elements), some of which are
uncoated, and some of which are coated in various patterns amounts.
Generally, more coating applied to the swellable materials yields
slower rates of expansion (e.g., in terms of percent weight
gain).
Additional Disclosure
[0059] The following are nonlimiting, specific embodiments in
accordance with the present disclosure:
[0060] In a first embodiment, a controlled swell-rate swellable
packer comprises a mandrel; a sealing element, wherein the sealing
element is disposed about at least a portion of the mandrel; and a
jacket, wherein the jacket covers at least a portion of an outer
surface of the sealing element, and wherein the jacket comprises a
substantially impermeable material with respect to a swelling agent
that is configured to cause the sealing element to swell.
[0061] A second embodiment comprises the controlled swell-rate
swellable packer of the first embodiment, wherein the mandrel
comprises a tubular body generally defining a continuous axial
flowbore.
[0062] A third embodiment comprises the controlled swell-rate
swellable packer of the first or second embodiment, wherein the
sealing element comprises a swellable material.
[0063] A fourth embodiment comprises the controlled swell-rate
swellable packer of the third embodiment, wherein the swellable
material comprises a water-swellable material, an oil-swellable
material, or any combination thereof.
[0064] A fifth embodiment comprises the controlled swell-rate
swellable packer of the third embodiment, wherein the swellable
material comprises a compound selected from the group consisting
of: a natural rubber, an acrylate butadiene rubber, a polyacrylate
rubber, an isoprene rubber, a choloroprene rubber, a butyl rubber
(IIR), a brominated butyl rubber (BIIR), a chlorinated butyl rubber
(CIIR), a chlorinated polyethylene (CM/CPE), a neoprene rubber
(CR), a styrene butadiene copolymer rubber (SBR), a sulphonated
polyethylene (CSM), ethylene acrylate rubber (EAM/AEM), an
epichlorohydrin ethylene oxide copolymer (CO, ECO), an
ethylene-propylene rubber (EPM and EDPM), an
ethylene-propylene-diene terpolymer rubber (EPT), an ethylene vinyl
acetate copolymer, a fluorosilicone rubber (FVMQ), a silicone
rubber (VMQ), poly 2,2,1-bicyclo heptene (polynorborneane), an
alkylstyrene, a crosslinked substituted vinyl acrylate copolymer,
and any combination thereof.
[0065] A sixth embodiment comprises the controlled swell-rate
swellable packer of the third embodiment, wherein the swellable
material comprises a water-swellable material, and wherein the
swellable material comprises a compound selected from the group
consisting of: a nitrile rubber (NBR), a hydrogenated nitrile
rubber (HNBR, HNS), a fluoro rubber (FKM), a perfluoro rubber
(FFKM), tetrafluorethylene/propylene (TFE/P), a starch-polyacrylate
acid graft copolymer, a polyvinyl alcoholcyclic acid anhydride
graft copolymer, isobutylene maleic anhydride, an acrylic acid type
polymer, a vinylacetate-acrylate copolymer, a polyethylene oxide
polymer, a carboxymethyl cellulose type polymer, a
starch-polyacrylonitrile graft copolymer, polymethacrylate,
polyacrylamide, a non-soluble acrylic polymer, sodium bentonite,
and any combination thereof.
[0066] A seventh embodiment comprises the controlled swell-rate
swellable packer of any of the third to sixth embodiments, wherein
the swellable material is characterized by a particle size of from
about 0.1 microns to about 2000 microns.
[0067] An eighth embodiment comprises the controlled swell-rate
swellable packer of any of the first to seventh embodiments,
wherein the jacket covers at least about 75% of the outer surface
of the sealing element.
[0068] A ninth embodiment comprises the controlled swell-rate
swellable packer of any of the first to eighth embodiments, wherein
the jacket comprises a fluoro-elastomer, a plastic, polyethylene,
polypropylene, or combinations thereof.
[0069] In a tenth embodiment, a method of making a controlled
swell-rate swellable packer comprises providing a mandrel having at
least one sealing element disposed about at least a portion
thereof; masking at least a portion of any exposed portions of the
sealing element with a mask; applying a jacket to the sealing
element; removing the mask; and providing a controlled swell-rate
swellable packer.
[0070] An eleventh embodiment comprises the method of the tenth
embodiment, wherein the mask is configured to cover a portion of
the sealing element.
[0071] A twelfth embodiment comprises the method of the tenth or
eleventh embodiment, wherein the mask comprises at least one of a
grid-like pattern, a diamond pattern, or a random pattern.
[0072] A thirteenth embodiment comprises the method of any of the
tenth to twelfth embodiments, wherein the mask is formed from at
least one of paper, plastic, wires, metals, a fibrous material, or
any combination thereof.
[0073] A fourteenth embodiment comprises the method of any of the
tenth to thirteenth embodiments, wherein applying the jacket to the
sealing element comprises at least one of spraying a liquideous or
substantially liquideous material onto the sealing element,
painting a liquideous or substantially liquideous material onto the
sealing element, or dipping the sealing element into a liquideous
or substantially liquideous material.
[0074] A fifteenth embodiment comprises the method of any of the
tenth to fourteenth embodiments, further comprising drying the
jacket before removing the mask.
[0075] In a sixteenth embodiment, a method of utilizing a
controlled swell-rate swellable packer comprises providing a
controlled swell-rate swellable packer, wherein the controlled
swell-rate swellable packer comprises a sealing element and a
jacket, wherein the jacket is disposed on a first portion of an
outer surface of the sealing element, and wherein a second portion
of the outer surface of the sealing element is uncovered; disposing
a tubular string having the controlled swell-rate swellable packer
incorporated therein within a wellbore; and activating the
controlled swell-rate swellable packer.
[0076] A seventeenth embodiment comprises the method of the
sixteenth embodiment, wherein the controlled swell-rate swellable
packer further comprises a mandrel, wherein the sealing element is
disposed circumferentially about at least a portion of the
mandrel.
[0077] An eighteenth embodiment comprises the method of the
sixteenth or seventeenth embodiment, wherein the sealing element
comprises a swellable material.
[0078] A nineteenth embodiment comprises the method of any of the
sixteenth to eighteenth embodiments, wherein activating the
controlled-rate swellable packer comprises contacting at least a
portion of the controlled swell-rate packer with a swelling
agent.
[0079] A twentieth embodiment comprises the method of the
nineteenth embodiment, wherein the swelling agent comprises a
water-based fluid, an oil-based fluid, or any combination
thereof.
[0080] A twenty first embodiment comprises the method of the
nineteenth or twentieth embodiment, wherein contacting at least the
portion of the controlled swell-rate packer with the swelling agent
comprises contacting the second portion of the outer surface of the
sealing element with the swelling agent.
[0081] A twenty second embodiment comprises the method of the
nineteenth or twentieth embodiment, wherein contacting at least the
portion of the controlled swell-rate packer with the swelling agent
comprises contacting the second portion of the outer surface of the
sealing element with the swelling agent for at least 2 days.
[0082] While embodiments of the invention have been shown and
described, modifications thereof can be made by one skilled in the
art without departing from the spirit and teachings of the
invention. The embodiments described herein are exemplary only, and
are not intended to be limiting. Many variations and modifications
of the invention disclosed herein are possible and are within the
scope of the invention. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, R.sub.1, and an upper limit,
R.sub.u, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.1+k*(R.sub.u-R.sub.1), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, i.e., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. Use of the term "optionally" with
respect to any element of a claim is intended to mean that the
subject element is required, or alternatively, is not required.
Both alternatives are intended to be within the scope of the claim.
Use of broader terms such as comprises, includes, having, etc.
should be understood to provide support for narrower terms such as
consisting of, consisting essentially of, comprised substantially
of, etc.
[0083] Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
embodiments of the present invention. The discussion of a reference
in the Detailed Description of the Embodiments is not an admission
that it is prior art to the present invention, especially any
reference that may have a publication date after the priority date
of this application. The disclosures of all patents, patent
applications, and publications cited herein are hereby incorporated
by reference, to the extent that they provide exemplary, procedural
or other details supplementary to those set forth herein.
* * * * *