U.S. patent application number 15/753400 was filed with the patent office on 2018-08-30 for packer element protection from incompatible fluids.
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 Paul David Ringgenberg.
Application Number | 20180245420 15/753400 |
Document ID | / |
Family ID | 58386915 |
Filed Date | 2018-08-30 |
United States Patent
Application |
20180245420 |
Kind Code |
A1 |
Ringgenberg; Paul David |
August 30, 2018 |
PACKER ELEMENT PROTECTION FROM INCOMPATIBLE FLUIDS
Abstract
Protective elements are placed over packer seal elements to
provide insulation from incompatible wellbore fluids and its
degrading effects. The protective element may take the form of an
insulating tape, a protective coating, a sleeve, or a tube fitted
over the packer seal element.
Inventors: |
Ringgenberg; Paul David;
(Frisco, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
58386915 |
Appl. No.: |
15/753400 |
Filed: |
September 22, 2015 |
PCT Filed: |
September 22, 2015 |
PCT NO: |
PCT/US15/51341 |
371 Date: |
February 19, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/127 20130101;
E21B 33/12 20130101 |
International
Class: |
E21B 33/12 20060101
E21B033/12; E21B 33/127 20060101 E21B033/127 |
Claims
1. A packer element protection method, comprising: deploying a
workstring along a wellbore, the workstring having a packer element
thereon, wherein a protective element is positioned over the packer
element; insulating the packer element from wellbore fluids using
the protective element; and setting the packer element.
2. A method as defined in claim 1, wherein: the packer element is
insulated using a protective tape wrapped around the packer
element; the packer element is insulated using a layer of fluid
compatible rubber placed over the packer element; the packer
element is insulated using a protective coating painted on the
packer element; or the packer element is insulated using a
selectively actuatable sleeve positioned over the packer
element.
3. (canceled)
4. (canceled)
5. (canceled)
6. A method as defined in claim 2, wherein setting the packer
element comprises: actuating the sleeve to uncover the packer
element; and setting the packer element.
7. A method as defined in claim 1, wherein the packer element is
insulated using a tube positioned over the packer element.
8. A method as defined in claim 7, wherein setting the packer
element comprises: expanding the tube along with the packer
element; or breaking the tube when the packer element is set.
9. A method as defined in claim 1, wherein the packer element is
insulated using a bag positioned over the packer element.
10. A method as defined in claim 1, further comprising exposing the
packer element to the wellbore fluids after the packer element is
set.
11. A method of constructing a protected packer element,
comprising: applying a protective element over a packer element;
and positioning the packer element on a workstring.
12. A method as defined in claim 11, wherein applying the
protective element comprises: wrapping the packer element with a
protective tape; applying a layer of fluid compatible rubber to the
packer element; painting a protective coating on the packer
element; positioning a selectively actuatable sleeve over the
packer element; or placing a tube over the packer element.
13. (canceled)
14. (canceled)
15. (canceled)
16. (canceled)
17. A method as defined in claim 11, wherein applying the
protective element comprises applying an expandable tube over the
packer element.
18. A method as defined in claim 11, wherein applying the
protective element comprises placing a bag over the packer
element.
19. A protected packer element, comprising: a packer element; and a
protective element placed over the packer element, wherein the
protective element insulates the packer element from wellbore
fluids.
20. A packer element as defined in claim 19, wherein the protective
element is a protective tape wrapped around the packer element.
21. A packer element as defined in claim 19, wherein the protective
element is a layer of fluid compatible rubber applied to the packer
element.
22. A packer element as defined in claim 19, wherein the protective
element is a protective coating painted on the packer element.
23. A packer element as defined in claim 19, wherein the protective
element is a selectively actuatable sleeve positioned over the
packer element.
24. A packer element as defined in claim 19, wherein the protective
element is a tube placed around the packer element.
25. A packer element as defined in claim 24, wherein the tube is an
expandable tube.
26. A packer element as defined in claim 19, wherein the protective
element is a bag placed over the packer element.
27. A packer element as defined in claim 19, wherein the protective
element is no longer insulates the packer element from the wellbore
fluids after the packer element is set.
Description
FIELD OF THE INVENTION
[0001] The present invention relates generally to downhole
equipment and, more specifically, to a packer element protected
from incompatible fluids.
BACKGROUND
[0002] Downhole packers are commonly used in many oilfield
applications for the purpose of sealing against the flow of fluid
to isolate one or more portions of a wellbore for the purposes of
testing, treating, or producing the well. Non-limiting examples of
fluid include: liquids such as oil and water, gases such as natural
gas, and three-phase flow. The packers are suspended in the
wellbore, or in a casing in the wellbore, from a tubing string, or
the like, and are activated, or set, so that one or more packer
elements engage the inner surface of the wellbore or casing, thus
preventing fluid flow through the annulus.
[0003] Retrievable packer elements are compounded from a very
limited number of different rubber compounds. This is primarily due
to the fact that elastomers capable of handling a wide variety of
oil field fluids normally have low tensile strength and low
extrusion resistance. Such strength qualities are needed for
retrievable packer elements. Therefore, most packer elements are
made from tough Nitrile (e.g., NBR and HNBR) materials as they have
good extrusion resistance. However, the Nitrile does not have good
chemical compatibility resistance with many common oil field
completion fluids, such as Zinc Bromide, also referred to as
incompatible fluids. As a result, when Nitrile is used in these
environments, the packer element begins degrading as soon as it
comes into contact with the incompatible fluid. For example, in
some fluid environments, the packers only last 24 hours. However,
the time required to perform certain operations (such as tripping
and setting a packer for a drill string test) can far exceed 24
hours. As a result, costly retrieval and resetting operations are
regularly required.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 is a well system having two packer elements
positioned therein, which may embody principles of the present
disclosure;
[0005] FIG. 2 is an exploded view of packer element 18,20 of FIG.
1, according to certain illustrative embodiments of the present
disclosure;
[0006] FIG. 3 is an illustration of a packer element wrapped with
protective tape; and
[0007] FIG. 4 is a cross-sectional view of a packer assembly having
a protective sleeve, according to certain illustrative embodiments
of the present disclosure.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0008] Illustrative embodiments and related methods of the present
invention are described below as they might be employed in a packer
element protected from incompatible fluids. In the interest of
clarity, not all features of an actual implementation or method are
described in this specification. It will of course be appreciated
that in the development of any such actual embodiment, numerous
implementation-specific decisions must be made to achieve the
developers' specific goals, such as compliance with system-related
and business-related constraints, which will vary from one
implementation to another. Moreover, it will be appreciated that
such a development effort might be complex and time-consuming, but
would nevertheless be a routine undertaking for those of ordinary
skill in the art having the benefit of this disclosure. Further
aspects and advantages of the various embodiments and related
methods of the disclosure will become apparent from consideration
of the following description and drawings.
[0009] As described herein, illustrative embodiments of the present
disclosure are directed to packer elements having a protective
element positioned thereon which protects the packer's rubber
compound from incompatible wellbore fluids. In general, the
protective element protects the packer element from the
incompatible fluid until the packer is set. The protective element
may take a variety of forms. In a first embodiment, protective tape
is wrapped around the packer element. In a second embodiment, a
layer of fluid compatible rubber is applied in the packer element.
In a third embodiment, a protective coating is painted on the
packer element. In a fourth embodiment, a selectively actuatable
sleeve is applied to the workstring over the packer element. In a
fifth embodiment, a tub is placed over the packer element. In a
sixth embodiment, a bag is placed over the packer element.
Accordingly, through use of the protective elements, the life of
the packer element in the incompatible fluid is extended since the
packer element is not exposed to the fluids until after
setting.
[0010] FIG. 1 is a well system having two packer elements
positioned therein, which may embody principles of the present
disclosure. In well system 10, a tubular string 12 (e.g., a
production tubing string, liner string, etc.) has been installed in
wellbore 14. Wellbore 14 may be fully or partially cased (as
depicted with casing string 16 in an upper portion of FIG. 1),
and/or wellbore 14 may be fully or partially uncased (as depicted
in a lower portion of FIG. 1). An annular barrier is formed between
tubular string 12 and casing string 16 by means of a packer element
18. Another annular barrier is formed between tubular string 12 and
uncased wellbore 14 by means of another packer element 20.
[0011] It should be clearly understood that packer elements 18,20
are merely two examples of practical uses of the principles of the
present disclosure. Other types of packer elements may be
constructed, and other types of annular barriers may be formed,
without departing from the principles of the invention. For
example, an annular barrier could be formed in conjunction with a
tubing, liner or casing hanger, a packer may or may not include an
anchoring device for securing a tubular string, a bridge plug or
other type of plug may include an annular barrier, etc. Thus, the
embodiments described herein are not limited in any manner to the
details of well system 10.
[0012] Each of the packer elements 18, 20 includes a seal assembly
which engages the corresponding wall; however, for simplicity the
complete packer assembly will be represented herein as packer
elements 18,20. The seal assembly of the packer element may be, for
example, an inflatable packer assembly. Various techniques may be
employed for expanding the packer element into contact with the
corresponding wall, as will be understood by those ordinarily
skilled in the art having the benefit of this disclosure.
[0013] As previously mentioned, the illustrative embodiments
described herein apply protective elements to insulate the packer
elements from degrading downhole fluids. FIG. 2 is an exploded view
of packer element 18,20 of FIG. 1, according to certain
illustrative embodiments of the present disclosure. As shown in
FIG. 2, packer element 18,20 is a seal assembly 22 having a
protective element 24 placed over it. Protective element 24
insulates packer element 18,20/seal assembly 22 from wellbore
fluids during deployment of the workstring 12 into the wellbore. In
certain embodiments, after packer element 18,20 is set along casing
string 16, protective element 24 is damaged such that seal assembly
22 is then exposed to wellbore fluids and degradation begins. In
other embodiments, however, even after setting of packer element
18,20, protective element 24 remains intact such seal assembly 22
continues to be insulated from the wellbore fluids.
[0014] Protective element 24 may take a variety of embodiments. In
a first embodiment, protective element 24 is protective tape
wrapped around seal assembly 22. The tape may be, for example, a
self-amalgamating tape, which may take the form of a non-tacky
silicone-rubber tape which, when stretched and wrapped around seal
assembly 22 in a continuous fashion, combines or unites itself into
a strong, seamless, rubbery, waterproof, and electrically
insulating layer. As packer element 18,20 is run into the wellbore,
seal assembly 22 is not exposed to the incompatible wellbore fluid.
The silicone rubber in the protective tape is compatible with most
oil field completion fluids and, thus, insulates/protects the
Nitrile seal assembly 22 from exposure. When packer element 18,20
is set in certain embodiments, the silicone rubber tape 24 would no
longer fully protect the Nitrile seal 22 from the fluid, and the
degrading of packer element 18,20 would finally start. One
advantage of this embodiment is that the silicone rubber tape 24
may be applied to the packer element in the field whenever it is
determined the well bore fluid is incompatible with the seal
assembly 22. FIG. 3 is an illustration of an illustrative packer
element 18,20 wrapped with protective tape 24.
[0015] Still referencing FIG. 2, in a second embodiment, protective
element 24 may take the form of a layer of wellbore fluid
compatible rubber applied to seal assembly 22. In this embodiment,
seal assembly 22 would be manufactured, then the protective
wellbore fluid-compatible rubber layer 24 would be overlaid atop
the entire seal assembly 22. The inner core/seal assembly 22 would
still be the tough Nitrile, but the outer layer would be the
protective wellbore fluid compatible rubber.
[0016] In a third embodiment, the protective element 24 is a
protective coating painted on packer element 18,20. Here, a
protective coating is painted all exterior surfaces of seal
assembly 22. Examples of such paint include, for example, flexible
paints used to coat inflatable boats and other formulations that
have different compatibility in different fluids. Other examples
include car bumper paint, truck bed liner paints, Plastidip.RTM.
and Flexseal.RTM..
[0017] In a fourth embodiment, protective element 24 takes the form
of a selectively actuatable sleeve positioned over packer element
18,20. FIG. 4 is a cross-sectional view of a packer assembly having
a protective sleeve, according to certain illustrative embodiments
of the present disclosure. In FIG. 4, a spring loaded sleeve 26 is
installed over packer elements 18,20 and compatible fluid is placed
inside cavity 30 formed between packer elements 18,20 and sleeve
26. In this illustrative embodiment, sleeve 26 is deactivated by
the initial packer setting process, which would shear pins 32, thus
allowing spring 28 to fully uncover the packer elements.
[0018] To provide a more detailed description, FIG. 4 is provided.
In this example, a complete packer assembly 19 is illustrated.
Packer assembly 19 may be any variety of packer assembly, such as,
for example, the RTTS.TM. packer commercially available from
Halliburton Energy Services, Inc. of Houston, Tex. USA. However,
other types of packers may be used along the workstring, in keeping
with the spirit of this disclosure. Examples of other packers which
may be used include the CHAMP IV.TM. and CHAMP V.TM. packers, also
marketed by Halliburton Energy Services, Inc.
[0019] Nevertheless, packer assembly 19 is representative of a
retrievable packer, operation of which can benefit from the
principles of this disclosure. Packer assembly 19 includes a
generally tubular mandrel 34, a set of hydraulically actuated slips
36, a set of seal assemblies 22, a set of mechanically actuated
slips 40 and a drag block 42. A J-slot mechanism (not shown)
controls whether mandrel 34 can be lowered (as viewed in FIG. 4)
relative to the seal assemblies 22, slips 40 and drag block 42.
Drag block 42 is biased into contact with an inner wall of the
casing 16 (FIG. 1) (or the formation wall 14 in an uncased
wellbore) and thereby provides a frictional force, so that mandrel
34 will displace downward relative to the seal assemblies 22, slips
40 and drag block when the J-slot mechanism is operated to its
"set" position.
[0020] As stated above, a selectively actuatable sleeve 26 is
positioned over seal assemblies 22 and biased using spring 28.
Fluid compatible with seal assemblies 22 is pumped into cavity 30
(formed between packer elements 18,20 and sleeve 26) just before
the workstring is deployed downhole. Since wellbore fluid is
already in the wellbore, once packer assembly 19 comes into contact
with the wellbore fluid, the compatible fluid in cavity 30 will
remain in place due to hydrostatic pressure present in the
wellbore. As the compatible fluid is held in place, it insulates
seal assemblies 22 from the wellbore fluid.
[0021] To set the packer assembly 19 in one illustrative method,
the packer assembly is positioned lower in the wellbore than its
intended setting location. Packer assembly 19 is then raised and
rotated to select the J-slot mechanism "set" position, and the
tubular string 12/mandrel 34 is then lowered to set seal assemblies
22. The frictional force provided by drag block 42 urges slips 40
upward along ramps 44, so that slips 40 displace radially outward
and obtain an initial "bite" into casing 16 (or the formation wall
if the wellbore is uncased). However, in doing so, slips 40 first
shear the pins 32, thus releasing sleeve 26 to move in the
direction of spring 28 until sleeve 26 abuts shoulder 29. As a
result, seal assemblies 22 are no longer insulated from the
wellbore fluids. Thereafter, further lowering of the tubular string
12 and mandrel 34 compresses the seal assemblies 22, thereby
radially outwardly extending the seal elements and sealing off the
annulus. After being set, packer assembly 19 can be unset by
raising the mandrel 34, thereby decompressing the seal assemblies
22 and allowing slips 40 to retract inward.
[0022] In a fifth embodiment, the protective element is a tube
placed around seal assembly 22. For example, a thin metal tube
could be installed over the seal assemblies, thus keeping them
isolated from the incompatible wellbore fluid. When the packer
element 18,20 is set, the tube would be forced out into the casing,
as previously described. In such an embodiment, the metallic nature
of the tube may enable it to remain intact after setting, thus
continuing to insulate the seal assembly.
[0023] In a sixth embodiment, the protective element is an
expandable tube placed around the seal assembly 22. Here, for
example, a thin Teflon.RTM. or plastic tube could be installed over
the seal elements 22. Depending on the material selected, the tube
would either expand with the seals 22 (thus, continuing to insulate
from incompatible fluids) or may break up into many pieces.
[0024] In a seventh embodiment, the protective element is a bag
placed over the seal assembly 22. Here, for example, a plastic or
Teflon.RTM. bag may be custom fit to the seal assembly 22. In other
embodiments, the bag may have a continuous zip-lock type sealing
method, thus allowing for more efficient application to the seal
assembly.
[0025] All of the methods describes herein may be used alone or
combined with one another to extend the life of the packer elements
in incompatible wellbore fluids. In certain embodiments, exposure
to the incompatible wellbore fluid does not begin until after the
packer is set. In other embodiments, the protective elements
continue to protect the packer elements even after setting, thus
extending the useful life even more.
[0026] Accordingly, the embodiments described herein greatly
increase the useful life of packer elements. Earlier attempts to
extend the useful life molded the entire packer element from fluid
compatible materials; however, the disadvantage to such techniques
was that the fluid compatible material had a low extrusion
resistance that greatly reduced the pressure holding capability of
the packer. As a result, the prior art approaches produced poor
performing packers. However, in the illustrative embodiments
described herein, protection from incompatible fluids is achieved
while maintaining the pressure holding capabilities of
state-of-the-art packers.
[0027] Embodiments and methods of the present disclosure described
herein further relate to any one or more of the following
paragraphs:
[0028] 1. A packer element protection method, comprising: deploying
a workstring along a wellbore, the workstring having a packer
element thereon, wherein a protective element is positioned over
the packer element; insulating the packer element from wellbore
fluids using the protective element; and setting the packer
element.
[0029] 2. A method as defined in paragraph 1, wherein the packer
element is insulated using a protective tape wrapped around the
packer element.
[0030] 3. A method as defined in paragraphs 1 or 2, wherein the
packer element is insulated using a layer of fluid compatible
rubber placed over the packer element.
[0031] 4. A method as defined in any of paragraphs 1-3, wherein the
packer element is insulated using a protective coating painted on
the packer element.
[0032] 5. A method as defined in any of paragraphs 1-4, wherein the
packer element is insulated using a selectively actuatable sleeve
positioned over the packer element.
[0033] 6. A method as defined in any of paragraphs 1-5, wherein
setting the packer element comprises actuating the sleeve to
uncover the packer element and setting the packer element.
[0034] 7. A method as defined in any of paragraphs 1-6, wherein the
packer element is insulated using a tube positioned over the packer
element.
[0035] 8. A method as defined in any of paragraphs 1-7, wherein
setting the packer element comprises expanding the tube along with
the packer element or breaking the tube when the packer element is
set.
[0036] 9. A method as defined in any of paragraphs 1-8, wherein the
packer element is insulated using a bag positioned over the packer
element.
[0037] 10. A method as defined in any of paragraphs 1-9, further
comprising exposing the packer element to the wellbore fluids after
the packer element is set.
[0038] 11. A method of constructing a protected packer element,
comprising applying a protective element over a packer element; and
positioning the packer element on a workstring.
[0039] 12. A method as defined in paragraph 11, wherein applying
the protective element comprises wrapping the packer element with a
protective tape.
[0040] 13. A method as defined in paragraphs 11 or 12, wherein
applying the protective element comprises applying a layer of fluid
compatible rubber to the packer element.
[0041] 14. A method as defined in any of paragraphs 11-13, wherein
applying the protective element comprises painting a protective
coating on the packer element.
[0042] 15. A method as defined in any of paragraphs 11-14, wherein
applying the protective element comprises positioning a selectively
actuatable sleeve over the packer element.
[0043] 16. A method as defined in any of paragraphs 11-15, wherein
protecting the packer element comprises placing a tube over the
packer element.
[0044] 17. A method as defined in any of paragraphs 11-16, wherein
applying the protective element comprises applying an expandable
tube over the packer element.
[0045] 18. A method as defined in any of paragraphs 11-17, wherein
applying the protective element comprises placing a bag over the
packer element.
[0046] 19. A protected packer element, comprising a packer element;
and a protective element placed over the packer element, wherein
the protective element insulates the packer element from wellbore
fluids.
[0047] 20. A packer element as defined in paragraph 19, wherein the
protective element is a protective tape wrapped around the packer
element.
[0048] 21. A packer element as defined in paragraphs 19 or 20,
wherein the protective element is a layer of fluid compatible
rubber applied to the packer element.
[0049] 22. A packer element as defined in any of paragraphs 19-21,
wherein the protective element is a protective coating painted on
the packer element.
[0050] 23. A packer element as defined in any of paragraphs 19-22,
wherein the protective element is a selectively actuatable sleeve
positioned over the packer element.
[0051] 24. A packer element as defined in any of paragraphs 19-23,
wherein the protective element is a tube placed around the packer
element.
[0052] 25. A packer element as defined in any of paragraphs 19-24,
wherein the tube is an expandable tube.
[0053] 26. A packer element as defined in any of paragraphs 19-25,
wherein the protective element is a bag placed over the packer
element.
[0054] 27. A packer element as defined in any of paragraphs 19-26,
wherein the protective element is no longer insulates the packer
element from the wellbore fluids after the packer element is
set.
[0055] The foregoing disclosure may repeat reference numerals
and/or letters in the various examples. This repetition is for the
purpose of simplicity and clarity and does not in itself dictate a
relationship between the various embodiments and/or configurations
discussed. Further, spatially relative terms, such as "beneath,"
"below," "lower," "above," "upper" and the like, may be used herein
for ease of description to describe one element or feature's
relationship to another element(s) or feature(s) as illustrated in
the figures. The spatially relative terms are intended to encompass
different orientations of the apparatus in use or operation in
addition to the orientation depicted in the figures. For example,
if the apparatus in the figures is turned over, elements described
as being "below" or "beneath" other elements or features would then
be oriented "above" the other elements or features. Thus, the
illustrative term "below" can encompass both an orientation of
above and below. The apparatus may be otherwise oriented (rotated
90 degrees or at other orientations) and the spatially relative
descriptors used herein may likewise be interpreted
accordingly.
[0056] Although various embodiments and methods have been shown and
described, the invention is not limited to such embodiments and
methods and will be understood to include all modifications and
variations as would be apparent to one skilled in the art.
Therefore, it should be understood that the invention is not
intended to be limited to the particular forms disclosed. Rather,
the intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the invention
as defined by the appended claims.
* * * * *