U.S. patent application number 12/844509 was filed with the patent office on 2010-11-18 for non-metallic mandrel and element system.
This patent application is currently assigned to Weatherford/Lamb, Inc.. Invention is credited to William J. Eldridge, Craig Fishbeck, Roland Freihet, William F. Hines, III, Bill Murray, Michael R. Niklasch, Rami Al Oudat, Charles D. Parker, Rocky A. Turley, Patrick J. Zimmerman.
Application Number | 20100288488 12/844509 |
Document ID | / |
Family ID | 25401685 |
Filed Date | 2010-11-18 |
United States Patent
Application |
20100288488 |
Kind Code |
A1 |
Turley; Rocky A. ; et
al. |
November 18, 2010 |
Non-Metallic Mandrel and Element System
Abstract
A non-metallic element system is provided as part of a downhole
tool that can effectively seal or pack-off an annulus under
elevated temperatures. The element system can also resist high
differential pressures without sacrificing performance or suffering
mechanical degradation, and is considerably faster to drill-up than
a conventional element system. In one aspect, the composite
material comprises an epoxy blend reinforced with glass fibers
stacked layer upon layer at about 30 to about 70 degrees. In
another aspect, a mandrel is formed of a non-metallic polymeric
composite material. A downhole tool, such as a bridge plug,
frac-plug, or packer, is also provided. The tool comprises a
support ring having one or more wedges, an expansion ring, and a
sealing member positioned with the expansion ring.
Inventors: |
Turley; Rocky A.; (Houston,
TX) ; Fishbeck; Craig; (Houston, TX) ; Oudat;
Rami Al; (Huntsville, TX) ; Zimmerman; Patrick
J.; (Houston, TX) ; Parker; Charles D.; (Sugar
Land, TX) ; Niklasch; Michael R.; (Big Spring,
TX) ; Eldridge; William J.; (Cypress, TX) ;
Freihet; Roland; (Edmonton, CA) ; Hines, III; William
F.; (Houston, TX) ; Murray; Bill; (Alberdeen,
GB) |
Correspondence
Address: |
(Weatherford) Wong Cabello Lutsch Rutherford &Brucculeri LLP
20333 Tomball Parkway, 6th floor
Houston
TX
77070
US
|
Assignee: |
Weatherford/Lamb, Inc.
Houston
TX
|
Family ID: |
25401685 |
Appl. No.: |
12/844509 |
Filed: |
July 27, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12646066 |
Dec 23, 2009 |
7789137 |
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12844509 |
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|
11533679 |
Sep 20, 2006 |
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12646066 |
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|
11101855 |
Apr 8, 2005 |
7124831 |
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11533679 |
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10811559 |
Mar 29, 2004 |
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11101855 |
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09893505 |
Jun 27, 2001 |
6712153 |
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10811559 |
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Current U.S.
Class: |
166/140 |
Current CPC
Class: |
E21B 33/1208 20130101;
Y10T 29/49885 20150115 |
Class at
Publication: |
166/140 |
International
Class: |
E21B 33/12 20060101
E21B033/12 |
Claims
1. A downhole tool, comprising: a non-metallic mandrel; an element
system disposed about the mandrel, wherein the element system
comprises: a first non-metallic support ring comprising: an annular
section; and a plurality of wedges detachable from the annular
section under axial pressure on the first support ring; a first
expansion ring, deformable to fill gaps formed between the wedges
of the first support ring; and a sealing member disposed with the
first expansion ring.
2. The downhole tool of claim 1, wherein the element system further
comprises: a second expansion ring, disposed with the sealing
member, distal to the first expansion ring; and a second support
ring, disposed with the second expansion ring.
3. The downhole tool of claim 1, wherein the first expansion ring
is formed of a flexible plastic, elastomeric, or resin material
that flows at a predetermined temperature.
4. The downhole tool of claim 1, wherein the first non-metallic
support ring is formed of a polymeric composite reinforced by
fibers stacked in layers angled at about 30 to about 70 degrees
relative to an axis of the first support ring.
5. The downhole tool of claim 1, wherein the mandrel is formed of a
polymeric composite reinforced by fibers stacked in layers angled
at about 30 to about 70 degrees relative to an axis of the
mandrel.
6. The downhole tool of claim 1, wherein at least one of the
plurality of wedges extends radially upon exertion of a
predetermined force on the first support ring.
7. The downhole tool of claim 1, wherein at least one of the
plurality of wedges is manufactured to angle outwardly from a
center axis of the first support ring at about 10 degrees to about
30 degrees.
8. The downhole tool of claim 7, wherein the first expansion ring
comprises: a first section, tapered to a complementary angle of the
plurality of wedges of the first support ring.
9. The downhole tool of claim 1, wherein at least one of the
plurality of wedges are disposed about an outer diameter of the
first expansion ring.
10. The downhole tool of claim 1, wherein the element system
further comprises: a first non-metallic cone, disposed between the
first expansion ring and one end of the sealing member.
11. The downhole tool of claim 10, wherein the first cone
comprises: a tapered first section, wherein the first expansion
ring is disposed about the tapered first section of the first
cone.
12. The downhole tool of claim 10, wherein the first cone is formed
of a polymeric composite reinforced by fibers in layers angled at
about 30 to about 70 degrees relative to an axis of the cone.
13. A downhole tool, comprising: a non-metallic mandrel; and a
non-metallic element system disposed about the mandrel, wherein the
element system comprises: a first and a second support ring each
having a plurality of wedges, detachable from the corresponding
support ring and radially expandable at a predetermined force on
the corresponding support ring; a first and second expansion ring
disposed with the first and the second support ring, each
deformable to fill gaps between the plurality of wedges of the
corresponding support ring; and a sealing member disposed between
the first and the second expansion rings.
14. A downhole tool, comprising: a non-metallic mandrel; and an
element system disposed about the mandrel, the element system
comprising: a first support ring, comprising: a plurality of
wedges, detachable from the first support ring and radially
expandable; a first expansion ring, disposed with the first support
ring and flowable to fill gaps between the expanded plurality of
wedges of the first support ring; a first cone, disposed with the
first expansion ring; and a sealing member disposed with the first
cone.
15. The downhole tool of claim 14, wherein the first expansion ring
is formed of a flexible plastic, elastomeric, or resin material
that flows at a predetermined temperature.
16. The downhole tool of claim 14, wherein the mandrel is formed of
a polymeric composite reinforced with fibers in layers angled at
about 30 to about 70 degrees relative to an axis of the
mandrel.
17. The downhole tool of claim 14, wherein the first support ring
is formed of a polymeric composite reinforced with fibers in layers
angled at about 30 to about 70 degrees relative to an axis of the
first support ring.
18. The downhole tool of claim 14, wherein the first cone is formed
of a polymeric composite reinforced with fibers in layers angled at
about 30 to about 70 degrees relative to an axis of the first
cone.
19. The downhole tool of claim 14, wherein the first expansion ring
is disposed about a tapered section of the first cone.
20. The downhole tool of claim 14, wherein the first expansion ring
creates a collapse load on the first cone as the first expansion
ring flows to fill gaps formed between the expanded plurality of
wedges of the first support ring, wherein the collapsed first cone
prevents axial movement of the sealing member relative to the
mandrel, and wherein the collapsed first cone prevents rotation of
the first cone and the sealing member relative to the mandrel.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation application of U.S.
patent application Ser. No. 12/646,066, filed Dec. 23, 2009, which
is a divisional of U.S. patent application Ser. No. 11/533,679,
filed on Sep. 20, 2006, which is a divisional of U.S. patent
application Ser. No. 11/101,855, filed on Apr. 8, 2005, now issued
as U.S. Pat. No. 7,124,831, which is a continuation of U.S. patent
application Ser. No. 10/811,559, filed on Mar. 29, 2004, now
abandoned, which is a continuation of U.S. patent application Ser.
No. 09/893,505, filed on Jun. 27, 2001, now issued as U.S. Pat. No.
6,712,153, which are each incorporated by reference herein in their
entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to a downhole non-metallic
sealing element system. More particularly, the present invention
relates to downhole tools such as bridge plugs, frac-plugs, and
packers having a non-metallic sealing element system.
[0004] 2. Background of the Related Art
[0005] An oil or gas well includes a wellbore extending into a well
to some depth below the surface. Typically, the wellbore is lined
with tubulars or casing to strengthen the walls of the borehole. To
further strengthen the walls of the borehole, the annular area
formed between the casing and the borehole is typically filled with
cement to permanently set the casing in the wellbore. The casing is
then perforated to allow production fluid to enter the wellbore and
be retrieved at the surface of the well.
[0006] Downhole tools with sealing elements are placed within the
wellbore to isolate the production fluid or to manage production
fluid flow through the well. The tools, such as plugs or packers
for example, are usually constructed of cast iron, aluminum, or
other alloyed metals, but have a malleable, synthetic element
system. An element system is typically made of a composite or
synthetic rubber material which seals off an annulus within the
wellbore to prevent the passage of fluids. The element system is
compressed, thereby expanding radially outward from the tool to
sealingly engage a surrounding tubular. For example, a bridge plug
or frac-plug is placed within the wellbore to isolate upper and
lower sections of production zones. By creating a pressure seal in
the wellbore, bridge plugs and frac-plugs allow pressurized fluids
or solids to treat an isolated formation.
[0007] FIG. 1 is a cross sectional view of a conventional bridge
plug 50. The bridge plug 50 generally includes a metallic body 80,
a synthetic sealing member 52 to seal an annular area between the
bridge plug 50 and an inner wall of casing there-around (not
shown), and one or more metallic slips 56, 61. The sealing member
52 is disposed between an upper metallic retaining portion 55 and a
lower metallic retaining portion 60. In operation, axial forces are
applied to the slip 56 while the body 80 and slip 61 are held in a
fixed position. As the slip 56 moves down in relation to the body
80 and slip 61, the sealing member is actuated and the slips 56, 61
are driven up cones 55, 60. The movement of the cones and slips
axially compress and radially expand the sealing member 52 thereby
forcing the sealing portion radially outward from the plug to
contact the inner surface of the well bore casing. In this manner,
the compressed sealing member 52 provides a fluid seal to prevent
movement of fluids across the bridge plug 50.
[0008] Like the bridge plug described above, conventional packers
typically comprise a synthetic sealing element located between
upper and lower metallic retaining rings. Packers are typically
used to seal an annular area formed between two co-axially disposed
tubulars within a wellbore. For example, packers may seal an
annulus formed between production tubing disposed within wellbore
casing. Alternatively, packers may seal an annulus between the
outside of a tubular and an unlined borehole. Routine uses of
packers include the protection of casing from pressure, both well
and stimulation pressures, as well as the protection of the
wellbore casing from corrosive fluids. Other common uses include
the isolation of formations or leaks within a wellbore casing or
multiple producing zones, thereby preventing the migration of fluid
between zones. Packers may also be used to hold kill fluids or
treating fluids within the casing annulus.
[0009] One problem associated with conventional element systems of
downhole tools arises in high temperature and/or high pressure
applications. High temperatures are generally defined as downhole
temperatures above 200.degree. F. and up to 450.degree. F. High
pressures are generally defined as downhole pressures above 7,500
psi and up to 15,000 psi. Another problem with conventional element
systems occurs in both high and low pH environments. Low pH is
generally defined as less than 6.0, and high pH is generally
defined as more than 8.0. In these extreme downhole conditions,
conventional sealing elements become ineffective. Most often, the
physical properties of the sealing element suffer from degradation
due to extreme downhole conditions. For example, the sealing
element may melt, solidify, or otherwise loose elasticity.
[0010] Yet another problem associated with conventional element
systems of downhole tools arises when the tool is no longer needed
to seal an annulus and must be removed from the wellbore. For
example, plugs and packers are sometimes intended to be temporary
and must be removed to access the wellbore. Rather than de-actuate
the tool and bring it to the surface of the well, the tool is
typically destroyed with a rotating milling or drilling device. As
the mill contacts the tool, the tool is "drilled up" or reduced to
small pieces that are either washed out of the wellbore or simply
left at the bottom of the wellbore. The more metal parts making up
the tool, the longer the milling operation takes. Metallic
components also typically require numerous trips in and out of the
wellbore to replace worn out mills or drill bits.
[0011] There is a need, therefore, for a non-metallic element
system that will effectively seal an annulus at high temperatures
and withstand high pressure differentials without experiencing
physical degradation. There is also a need for a downhole tool made
substantially of a non-metallic material that is easier and faster
to mill.
SUMMARY OF THE INVENTION
[0012] A non-metallic element system is provided which can
effectively seal or pack-off an annulus under elevated
temperatures. The element system can also resist high differential
pressures as well as high and low pH environments without
sacrificing performance or suffering mechanical degradation.
Further, the non-metallic element system will drill up considerably
faster than a conventional element system that contains metal.
[0013] The element system comprises a non-metallic, composite
material that can withstand high temperatures and high pressure
differentials. In one aspect, the composite material comprises an
epoxy blend reinforced with glass fibers stacked layer upon layer
at about 30 to about 70 degrees.
[0014] A downhole tool, such as a bridge plug, frac-plug, or
packer, is also provided that comprises in substantial part a
non-metallic, composite material which is easier and faster to mill
than a conventional bridge plug containing metallic parts. In one
aspect, the tool comprises one or more support rings having one or
more wedges, one or more expansion rings and a sealing member
disposed in a functional relationship with the one or more
expansion rings This assemblage of components is referred to
hereing as "an element system."
[0015] In another aspect, a non-metallic mandrel for the downhole
tool is formed of a polymeric composite material reinforced by
fibers in layers angled at about 30 to about 70 degrees relative to
an axis of the mandrel. Methods are provided for the manufacture
and assembly of the tool and the mandrel, as well as for sealing an
annulus in a wellbore using a downhole tool that includes a
non-metallic mandrel and an element system.
BRIEF DESCRIPTION OF DRAWINGS
[0016] So that the manner in which the above recited features,
advantages and objects of the present invention are attained and
can be understood in detail, a more particular description of the
invention, briefly summarized above, may be had by reference to the
embodiments thereof which are illustrated in the appended
drawings.
[0017] It is to be noted, however, that the appended drawings
illustrate only typical embodiments of this invention and are
therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
[0018] FIG. 1 is a partial section view of a conventional bridge
plug.
[0019] FIG. 2 is a partial section view of a non-metallic sealing
system of the present invention.
[0020] FIG. 3 is an enlarged isometric view of a support ring of
the non-metallic sealing system.
[0021] FIG. 4 is a cross sectional view along lines A-A of FIG.
2.
[0022] FIG. 5 is partial section view of a frac-plug having a
non-metallic sealing system of the present invention in a run-in
position.
[0023] FIG. 6 is section view of a frac-plug having a non-metallic
sealing system of the present invention in a set position within a
wellbore.
[0024] FIG. 6A is an enlarged view of a non-metallic sealing system
activated within a wellbore.
[0025] FIG. 7 is a cross sectional view along lines B-B of FIG.
6.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0026] A non-metallic element system that is capable of sealing an
annulus in very high or low pH environments as well as at elevated
temperatures and high pressure differentials is provided. The
non-metallic element system is made of a fiber reinforced polymer
composite that is compressible and expandable or otherwise
malleable to create a permanent set position.
[0027] The composite material is constructed of a polymeric
composite that is reinforced by a continuous fiber such as glass,
carbon, or aramid, for example. The individual fibers are typically
layered parallel to each other, and wound layer upon layer.
However, each individual layer is wound at an angle of about 30 to
about 70 degrees to provide additional strength and stiffness to
the composite material in high temperature and pressure downhole
conditions. The tool mandrel is preferably wound at an angle of 30
to 55 degrees, and the other tool components are preferably wound
at angles between about 40 and about 70 degrees. The difference in
the winding phase is dependent on the required strength and
rigidity of the overall composite material.
[0028] The polymeric composite is preferably an epoxy blend.
However, the polymeric composite may also consist of polyurethanes
or phenolics, for example. In one aspect, the polymeric composite
is a blend of two or more epoxy resins. Preferably, the composite
is a blend of a first epoxy resin of bisphenol A and
epichlorohydrin and a second cycoaliphatic epoxy resin. Preferably,
the cycloaphatic epoxy resin is Araldite.RTM. liquid epoxy resin,
commercially available from Ciga-Geigy Corporation of Brewster,
N.Y. A 50:50 blend by weight of the two resins has been found to
provide the required stability and strength for use in high
temperature and pressure applications. The 50:50 epoxy blend also
provides good resistance in both high and low pH environments.
[0029] The fiber is typically wet wound, however, a prepreg roving
can also be used to form a matrix. A post cure process is
preferable to achieve greater strength of the material. Typically,
the post cure process is a two stage cure consisting of a gel
period and a cross linking period using an anhydride hardener, as
is commonly know in the art. Heat is added during the curing
process to provide the appropriate reaction energy which drives the
cross-linking of the matrix to completion. The composite may also
be exposed to ultraviolet light or a high-intensity electron beam
to provide the reaction energy to cure the composite material.
[0030] FIG. 2 is a partial cross section of a non-metallic element
system 200 made of the composite, filament wound material described
above. The element system 200 includes a sealing member 210, a
first and second cone 220, 225, a first and second expansion ring
230, 235, and a first and second support ring 240, 245 disposed
about a body 250. The sealing member 210 is backed by the cones
220, 225. The expansion rings 230, 235 are disposed about the body
250 between the cones 220, 225, and the support rings 240, 245, as
shown in FIG. 2.
[0031] FIG. 3 is an isometric view of the support ring 240, 245. As
shown, the support ring 240, 245 is an annular member having a
first section 242 of a first diameter that steps up to a second
section 244 of a second diameter. An interface or shoulder 246 is
therefore formed between the two sections 242, 244. Equally spaced
longitudinal cuts 247 are fabricated in the second section to
create one or more fingers or wedges 248 there-between. The number
of cuts 247 is determined by the size of the annulus to be sealed
and the forces exerted on the support ring 240, 245.
[0032] Still referring to FIG. 3, the wedges 248 are angled
outwardly from a center line or axis of the support ring 240, 245
at about 10 degrees to about 30 degrees. As will be explained below
in more detail, the angled wedges 248 hinge radially outward as the
support ring 240, 245 moves axially across the outer surface of the
expansion ring 230, 235. The wedges 248 then break or separate from
the first section 242, and are extended radially to contact an
inner diameter of the surrounding tubular (not shown). This radial
extension allows the entire outer surface area of the wedges 248 to
contact the inner wall of the surrounding tubular. Therefore, a
greater amount of frictional force is generated against the
surrounding tubular. The extended wedges 248 thus generate a
"brake" that prevents slippage of the element system 200 relative
to the surrounding tubular.
[0033] Referring again to FIG. 2, the expansion ring 230, 235 may
be manufactured from any flexible plastic, elastomeric, or resin
material which flows at a predetermined temperature, such as
Teflon.RTM. for example. The second section 244 of the support ring
240, 245 is disposed about a first section of the expansion ring
230, 235. The first section of the expansion ring 230, 235 is
tapered corresponding to a complementary angle of the wedges 248. A
second section of the expansion ring 230, 235 is also tapered to
complement a sloped surface of the cone 220, 225. At high
temperatures, the expansion ring 230, 235 expands radially outward
from the body 250 and flows across the outer surface of the body
250. As will be explained below, the expansion ring 230, 235 fills
the voids created between the cuts 247 of the support ring 240,
245, thereby providing an effective seal.
[0034] The cone 220, 225 is an annular member disposed about the
body 250 adjacent each end of the sealing member 210. The cone 220,
225 has a tapered first section and a substantially flat second
section. The second section of the cone 220, 225 abuts the
substantially flat end of the sealing member 210. As will be
explained in more detail below, the tapered first section urges the
expansion ring 230, 235 radially outward from the body 250 as the
element system 200 is activated. As the expansion ring 230, 235
progresses across the tapered first section and expands under high
temperature and/or pressure conditions, the expansion ring 230, 235
creates a collapse load on the cone 220, 225. This collapse load
holds the cone 220, 225 firmly against the body 250 and prevents
axial slippage of the element system 200 components once the
element system 200 has been activated in the wellbore. The collapse
load also prevents the cones 220, 225 and sealing member 210 from
rotating during a subsequent mill up operation.
[0035] The sealing member 210 may have any number of configurations
to effectively seal an annulus within the wellbore. For example,
the sealing member 210 may include grooves, ridges, indentations,
or protrusions designed to allow the sealing member 210 to conform
to variations in the shape of the interior of a surrounding tubular
(not shown). The sealing member 210, however, should be capable of
withstanding temperatures up to 450.degree. F., and pressure
differentials up to 15,000 psi.
[0036] In operation, opposing forces are exerted on the element
system 200 which causes the malleable outer portions of the body
250 to compress and radially expand toward a surrounding tubular. A
force in a first direction is exerted against a first surface of
the support ring 240. A force in a second direction is exerted
against a first surface of the support ring 245. The opposing
forces cause the support rings 240, 245 to move across the tapered
first section of the expansion rings 230, 235. The first section of
the support rings 240, 245 expands radially from the mandrel 250
while the wedges 248 hinge radially toward the surrounding tubular.
At a predetermined force, the wedges 248 will break away or
separate from the first section 242 of the support rings 240, 245.
The wedges 248 then extend radially outward to engage the
surrounding tubular. The compressive force causes the expansion
rings 230, 235 to flow and expand as they are forced across the
tapered section of the cones 220, 225. As the expansion rings 230,
235 flow and expand, they fill the gaps or voids between the wedges
248 of the support rings 240, 245. The expansion of the expansion
rings 230, 235 also applies a collapse load through the cones 220,
225 on the body 250, which helps prevent slippage of the element
system 200 once activated. The collapse load also prevents the
cones 220, 225 and sealing member 210 from rotating during the mill
up operation which significantly reduces the required time to
complete the mill up operation. The cones 220, 225 then transfer
the axial force to the sealing member 210 to compress and expand
the sealing member 210 radially. The expanded sealing member 210
effectively seals or packs off an annulus formed between the body
250 and an inner diameter of a surrounding tubular.
[0037] The non-metallic element system 200 can be used on either a
metal or more preferably, a non-metallic mandrel. The non-metallic
element system 200 may also be used with a hollow or solid mandrel.
For example, the non-metallic element system 200 can be used with a
bridge plug or frac-plug to seal off a wellbore or the element
system may be used with a packer to pack-off an annulus between two
tubulars disposed in a wellbore. For simplicity and ease of
description however, the non-metallic element system will now be
described in reference to a frac-plug for sealing off a well
bore.
[0038] FIG. 5 is a partial cross section of a frac-plug 300 having
the non-metallic element system 200 described above. In addition to
the non-metallic element system 200, the frac-plug 300 includes a
mandrel 301, slips 310, 315, and cones 320, 325. The non-metallic
element system 200 is disposed about the mandrel 301 between the
cones 320, 325. The mandrel 301 is a tubular member having a ball
309 disposed therein to act as a check valve by allowing flow
through the mandrel 301 in only a single axial direction.
[0039] The slips 310, 315 are disposed about the mandrel 302
adjacent a first end of the cones 320, 325. Each slip 310, 315
comprises a tapered inner surface conforming to the first end of
the cone 320, 325. An outer surface of the slip 310, 315,
preferably includes at least one outwardly extending serration or
edged tooth, to engage an inner surface of a surrounding tubular
(not shown) when the slip 310, 315 is driven radially outward from
the mandrel 301 due to the axial movement across the first end of
the cones 320, 325 thereunder.
[0040] The slip 310, 315 is designed to fracture with radial
stress. The slip 310, 315 typically includes at least one recessed
groove (not shown) milled therein to fracture under stress allowing
the slip 310, 315 to expand outwards to engage an inner surface of
the surrounding tubular. For example, the slip 310, 315 may include
four sloped segments separated by equally spaced recessed grooves
to contact the surrounding tubular, which become evenly distributed
about the outer surface of the mandrel 301.
[0041] The cone 320, 325 is disposed about the mandrel 301 adjacent
the non-metallic sealing system 200 and is secured to the mandrel
301 by a plurality of shearable members 330 such as screws or pins.
The shearable members 330 may be fabricated from the same composite
material as the non-metallic sealing system 200, or the shearable
members may be of a different kind of composite material or metal.
The cone 320, 325 has an undercut 322 machined in an inner surface
thereof so that the cone 320, 325 can be disposed about the first
section 242 of the support ring 240, 245, and butt against the
shoulder 246 of the support ring 240, 245.
[0042] As stated above, the cones 320, 325 comprise a tapered first
end which rests underneath the tapered inner surface of the slips
310, 315. The slips 310, 315 travel about the tapered first end of
the cones 320, 325, thereby expanding radially outward from the
mandrel 301 to engage the inner surface of the surrounding
tubular.
[0043] A setting ring 340 is disposed about the mandrel 301
adjacent a first end of the slip 310. The setting ring 340 is an
annular member having a first end that is a substantially flat
surface. The first end serves as a shoulder which abuts a setting
tool described below.
[0044] A support ring 350 is disposed about the mandrel 301
adjacent a first end of the setting ring 340. A plurality of pins
345 secure the support ring 350 to the mandrel 301. The support
ring 350 is an annular member and has a smaller outer diameter than
the setting ring 340. The smaller outer diameter allows the support
ring 350 to fit within the inner diameter of a setting tool so the
setting tool can be mounted against the first end of the setting
ring 340.
[0045] The frac-plug 300 may be installed in a wellbore with some
non-rigid system, such as electric wireline or coiled tubing. A
setting tool, such as a Baker E-4 Wireline Setting Assembly
commercially available from Baker Hughes, Inc., for example,
connects to an upper portion of the mandrel 301. Specifically, an
outer movable portion of the setting tool is disposed about the
outer diameter of the support ring 350, abutting the first end of
the setting ring 340. An inner portion of the setting tool is
fastened about the outer diameter of the support ring 350. The
setting tool and frac-plug 300 are then run into the well casing to
the desired depth where the frac-plug 300 is to be installed.
[0046] To set or activate the frac-plug 300, the mandrel 301 is
held by the wireline, through the inner portion of the setting
tool, as an axial force is applied through the outer movable
portion of the setting tool to the setting ring 340. The axial
forces cause the outer portions of the frac-plug 300 to move
axially relative to the mandrel 301. FIGS. 6 and 6A show a section
view of a frac-plug having a non-metallic sealing system of the
present invention in a set position within a wellbore.
[0047] Referring to both FIGS. 6 and 6A, the force asserted against
the setting ring 340 transmits force to the slips 310, 315 and
cones 320, 325. The slips 310, 315 move up and across the tapered
surface of the cones 320, 325 and contact an inner surface of a
surrounding tubular 700. The axial and radial forces applied to
slips 310, 315 causes the recessed grooves to fracture into equal
segments, permitting the serrations or teeth of the slips 310, 315
to firmly engage the inner surface of the surrounding tubular.
[0048] Axial movement of the cones 320, 325 transfers force to the
support rings 240, 245. As explained above, the opposing forces
cause the support rings 240, 245 to move across the tapered first
section of the expansion rings 230, 235. As the support rings 240,
245 move axially, the first section of the support rings 240, 245
expands radially from the mandrel 250 while the wedges 248 hinge
radially toward the surrounding tubular. At a pre-determined force,
the wedges 248 break away or separate from the first section 242 of
the support rings 240, 245. The wedges 248 then extend radially
outward to engage the surrounding tubular 700. The compressive
force causes the expansion rings 230, 235 to flow and expand as
they are forced across the tapered section of the cones 220, 225.
As the expansion rings 230, 235 flow and expand, the rings 230, 235
fill the gaps or voids between the wedges 248 of the support rings
240, 245, as shown in FIG. 7. FIG. 7 is a cross sectional view
along lines B-B of FIG. 6.
[0049] Referring again to FIGS. 6 and 6A, the growth of the
expansion rings 230, 235 applies a collapse load through the cones
220, 225 on the mandrel 301, which helps prevent slippage of the
element system 200 once activated. The cones 220, 225 then transfer
the axial force to the sealing member 210 which is compressed and
expanded radially to seal an annulus formed between the mandrel 301
and an inner diameter of the surrounding tubular 700.
[0050] In addition to frac-plugs as described above, the
non-metallic element system 200 described herein may also be used
in conjunction with any other downhole tool used for sealing an
annulus within a wellbore, such as bridge plugs or packers, for
example. Moreover, while foregoing is directed to the preferred
embodiment of the present invention, other and further embodiments
of the invention may be devised without departing from the basic
scope thereof, and the scope thereof is determined by the claims
that follow.
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