Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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1 COMPOSITE DOWNHOLE TOOL WITH REDUCED SLIP VOLUME
2
3 FIELD OF THE INVENTION
4 The present invention relates to the field of downhole tools, and in
particular to downhole tools such as bridge plugs, frac-plugs, and packers.
6
7 BACKGROUND OF THE INVENTION
8 An oil or gas well includes a wellbore extending into a well to some
9 depth below the surface. Typically, the wellbore is lined with tubulars or
casing to
strengthen the walls of the borehole. To strengthen the walls of the borehole
11 further, the annular area formed between the casing and the borehole is
typically
12 filled with cement to set the casing permanently in the wellbore.
Perforating the
13 casing allows production fluid to enter the wellbore and flow to the
surface of the
14 well.
Downhole tools with sealing elements are placed within the wellbore
16 to isolate the production fluid or to manage production fluid flow through
the well.
17 For example, a bridge plug or frac-plug placed within the wellbore can
isolate upper
18 and lower sections of production zones. Bridge plugs and frac-plugs create
a
19 pressure seal in the wellbore to allow pressurized fluids or solids to
treat an isolated
formation.
21 Packers are typically used to seal an annular area formed between
22 two co-axially disposed tubulars within a wellbore. For example, packers
may seal
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1 an annulus formed between production tubing disposed within wellbore casing.
2 Alternatively, packers may seal an annulus between the outside of a tubular
and an
3 unlined borehole. Routine uses of packers include the protection of casing
from
4 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
6 formations or leaks within a wellbore casing or multiple producing zones,
thereby
7 preventing the migration of fluid between zones. Packers may also be used to
hold
8 kill fluids or treating fluids within the casing annulus.
9 The downhole tools are usually constructed of cast iron, aluminum, or
other alloyed metals, but can be made of non-metallic materials, such as
composite
11 materials. A sealing member is typically made of a composite or synthetic
rubber
12 malleable material that seals off an annulus within the wellbore to prevent
the
13 passage of fluids. The sealing member is compressed or swells, thereby
expanding
14 radially outward from the tool to engage and seal with a surrounding
tubular.
Conventional bridge plug, frac plugs, and packers typically comprise a
synthetic
16 sealing member located between upper and lower metallic retaining rings,
17 commonly known as slips, that prevent the downhole tool from moving up or
down
18 in the wellbore.
19 One problem associated with conventional element systems of
downhole tools arises when the tool is no longer needed to seal an annulus and
21 must be removed from the wellbore. For example, plugs and packers are
22 sometimes intended to be temporary and must be removed to access the
wellbore.
23 Rather than de-actuate the tool and bring it to the surface of the well,
the tool is
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1 typically destroyed with a rotating milling or drilling device. As the mill
contacts the
2 tool, the tool is "drilled up" or reduced to small pieces that are either
washed out of
3 the wellbore or simply left at the bottom of the wellbore. The more metal
parts
4 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
6 or drill bits.
7 Slips have been designed to reduce the amount of metal to reduce
8 drill up time. Although some have attempted to create composite material
slips,
9 often pressure holding at temperature has been sacrificed to gain up drill
up speed.
11 SUMMARY OF INVENTION
12 The conventional two slips of a downhole tool are combined into a
13 single bi-directional slip, thereby reducing the volume of metal and
allowing an
14 increased drill up speed. A dual sealing element system, with one sealing
element
above and one below the bi-directional slip, provides boost forces going
through the
16 sealing elements to the slip. In some embodiments, teeth sections of the
slip are
17 separated by a substantially flat circumference section for placing a band
around
18 the slip to improve fracturing uniformity. The teeth sections can have any
of a
19 variety of configurations, including orientations axially away from the
central portion
of the slip and orientations axially toward the central portion of the slip.
21
22 BRIEF DESCRIPTION OF DRAWINGS
23 Figure 1 is a cutaway view of a bridge plug according to the prior art;
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1 Figure 2 is a cutaway view of a bridge plug according to one
2 embodiment;
3 Figure 3 is a cutaway view of a bi-directional slip according to one
4 embodiment;
Figure 4 is a cross-sectional view of a bi-directional slip according to
6 another embodiment; and
7 Figure 5 is a cross-sectional view of a bi-directional slip according to
8 yet another embodiment.
9
DESCRIPTION OF EMBODIMENTS
11 Fig. 1 is a cutaway view of a conventional bridge plug 100 according
12 to the prior art. The bridge plug 100 comprises a mandrel 110, about which
are
13 disposed various elements, which are typically formed of metal, but can be
made of
14 a composite material, such as is described in U.S. Patent No. 7,124,831.
Even
when most of the bridge plug 100 is made of composite materials, the two slips
130
16 are typically made of metal, such as a ductile cast iron.
17 As shown in Fig. 1, a sealing member 120 and other related elements
18 125 are disposed about the mandrel 110. Axial force through the slips 130
and the
19 other elements 125 compress the sealing member 120, causing it to expand
and to
seal with the surrounding tubular (not shown). The two slips 130, oriented
opposite
21 to each other, expand to engage with the surrounding tubular and help
retain the
22 downhole tool in place in the wellbore. Boost forces from the sealing
member 120
23 on the slips 130 increase their holding ability. As described above, the
two slips 130
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1 are made of metal, typically a ductile cast iron, and increase the mill up
time of the
2 downhole tool 100.
3 Turning to Fig. 2, a cutaway view illustrates an improved downhole
4 tool 200 that uses a single bi-directional slip with reduced metal volume,
allowing
faster mill up time, but providing sufficient retaining ability against uphole
and
6 downhole forces when engaged with the surrounding tubular. Instead of
confining a
7 single sealing member 120 with two slips 130, in this embodiment, a single
slip 210
8 is confined by two sealing systems 220, as described in detail below. The
downhole
9 tool 200 can be configured as a bridge plug, a frac plug, a packer, or any
other
desired downhole tool.
11 As with the conventional downhole tool 100, the downhole tool 200
12 uses a mandrel 110, disposing the remainder of the downhole tool 200 about
the
13 mandrel 110. Although shown in Fig. 2 as a hollow core mandrel 110, the
mandrel
14 110 can be a solid core mandrel or can be a hollow core mandrel that is
plugged
with a core plug (not shown in Fig. 2) as desired. Most of the downhole tool
200,
16 including the mandrel 110 and the sealing systems 220, is typically non-
metallic,
17 and the non-metallic elements are usually manufactured from one or more
18 composite materials.
19 Instead of two unidirectional slips 130, each of which resists
movement in a single axial direction and tends to disengage from the
surrounding
21 tubular in the opposite axial direction, the embodiment illustrated in Fig.
2 uses a
22 single bi-directional slip 210 that resists movement in either axial
direction once
23 activated by the sealing systems 220 to engage with the surrounding
tubular.
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1 Although made of metal, such as a ductile cast iron, the single slip 210
contains
2 less metal than the conventional pair of slips 130.
3 To provide sealing with the tubular, the downhole tool 200 uses two
4 sealing systems 220, one axially on either end of the slip 210. Each sealing
system
220, in addition to sealing the downhole tool 200 with the surrounding
tubular, also
6 provides boost forces to the slip 210, increasing its ability to engage with
the tubular
7 and hold the downhole tool 200 in place under high pressure.
8 Each sealing system 220 includes a sealing member 225, which is a
9 malleable, synthetic element. The sealing member 225 can have any desired
configuration to seal an annulus within the wellbore. For example, the sealing
11 member 225 can include grooves, ridges, indentations, or protrusions
designed to
12 allow the sealing member 225 to conform to variations in the shape of the
interior of
13 the surrounding tubular. The sealing member is capable in one embodiment of
14 withstanding temperatures of 232 C (450 F) and pressure differentials of
up to
103,000 kPa (15,000 psi). Other temperature and pressure configurations can be
16 used, as well.
17 As illustrated in Fig. 2, according to one embodiment each sealing
18 system 220 comprises, in addition to the sealing member 225, a cone 221 and
two
19 each of cones 224, expansion rings 223, and support rings 222. In other
embodiments, a second cone 221 is also included. In the embodiment illustrated
in
21 Fig. 2, axial force is applied to the sealing system distal to the slip 210
by either a
22 mule shoe 250 or a setting ring 240 and a setting tool (not shown), as
described
23 below. In the embodiment with a second cone 221, the additional cone 221 is
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1 interposed between the setting ring 240 and support ring 230. Such an
2 embodiment would allow manufacture of a sealing system 220 that could be
used
3 unchanged both in downhole tools such as the downhole tool of Fig. 2 and
also in
4 conventional downhole tools such as illustrated in Fig. 1.
The sealing system 220, as illustrated in Fig. 2, transfers axial force
6 onto the sealing member 225, compressing the sealing member 225 and thereby
7 sealing with the surrounding tubular. Each cone 224 transfers axial force
from the
8 rest of the sealing system 220 onto the sealing member 225, compressing the
9 sealing member 225, and causing the sealing member 225 to expand radially
toward the inner surface of the surrounding tubular, sealing with the
surrounding
11 tubular.
12 The expansion ring 223 flows and expands in one embodiment across
13 a tapered surface of the cone 224, applying a collapse load through the
cone 224
14 on the mandrel 110, which helps prevent slippage of the system 220 one
activated.
The collapse load also prevents the cone 224 and sealing member 225 from
16 rotating when milling up the downhole tool 200, reducing the mill up time.
The cone
17 224 thus transfers axial force from the expansion ring 223 to the sealing
member
18 225 to cause radial expansion of the sealing member 225.
19 The support ring 222 transfers axial force to the expansion ring 223.
In one embodiment, the support ring 222 comprises sections that are designed
to
21 hinge radially outwardly, toward the surrounding tubular as sections are
forced
22 across a tapered section of the expansion ring 223. At full deployment, the
sections
23 expand outwardly sufficient to engage the surrounding tubular.
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1 The cone 221 transfers axial force to the support ring 222, forcing it
2 across the expansion ring 223 and causing the support ring 222 to expand as
3 described above. The cone 221 proximal to the slip 210 in turn receives
axial force
4 in the opposite direction, and transfers boost force to the end of the slip
210.
The mule shoe 250 is positioned on the downhole end of the
6 downhole tool 200, and is typically threadedly attached to the mandrel 110.
The
7 mule shoe 250 is typically pinned in position on the mandrel 110.
8 The setting ring 240 is an annular member that provides a
9 substantially flat surface for use with a setting tool (not shown), and
transfers axial
force from the setting tool to the sealing system 220 through the other
elements of
11 the sealing system 220. In one embodiment, the support ring 230 has an
outer
12 diameter less than the outer diameter of the setting ring 240, providing a
shoulder
13 for engagement with the setting tool, which thus slips over the support
ring 240 to
14 engage with the shoulder of the setting ring 240 to transfer force from the
setting
tool to the sealing system 220.
16 The downhole tool 200 can be installed in a weilbore with any desired
17 non-rigid system, such as electric wireline or coiled tubing. A setting
tool, such as a
18 Baker E-4 Wireline Setting Assembly commercially available from Baker
Hughes,
19 Inc., connects to an upper portion of the mandrel 110. Specifically, an
outer
movable portion of the setting tool is disposed about the outer diameter of
the
21 support ring 230, abutting the first end of the setting ring 240. An inner
portion of
22 the setting tool is fastened about the outer diameter of the support ring
230. The
23 setting tool and downhole tool 200 are then run into the well casing to the
desired
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1 depth where the downhole tool 200 is to be installed.
2 To set or activate the downhole tool 200, the mandrel 110 is held by
3 the wireline, through the inner portion of the setting tool, as an axial
force is applied
4 through the outer movable portion of the setting tool to the setting ring
240. The
axial forces cause the outer portions of the downhole tool 200 to move axially
6 relative to the mandrel 110.
7 The force asserted against the setting ring 240 is transmitted by the
8 setting ring 240. An equal and opposite force is asserted by the stationary
mule
9 shoe 250 on the other end of the downhole tool 200. The force from both ends
is
transmitted to the sealing systems 220, which causes the sealing members 225
to
11 expand and to seal with the surrounding tubular. The force is further
transmitted to
12 the slip 210, activating each end of the slip 210 by causing each end of
the slip 210
13 to expand and to engage with the surrounding tubular, setting the slip 210
and thus
14 the downhole tool as a whole.
The slip 210 fractures under radial stress. The slip 240 in one
16 embodiment, illustrated in Fig. 2, has a pineapple configuration that
includes at least
17 one and typically a plurality of recessed grooves 212, milled or otherwise
formed
18 therein as fracture zones, allowing the slip 210 to fracture along the
grooves 212 to
19 engage the teeth of the slip 210 with the inner surface of the surrounding
tubular.
The slip 210 is disposed between the sealing systems 220 about the
21 mandrel 110. An outer surface of the slip can include two or more
outwardly,
22 extending wickers, comprising serrations or edge teeth, with at least one
of the
23 wickers oriented toward the setting ring 240, to resist uphole axial
movement, and
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1 at least one of the wickers oriented toward the mule shoe 250, to resist
downhole
2 axial movement. As each end of the slip 210 is driven across the cones 221,
the
3 cone 221 drives that end of the slip radially outward from the mandrel 110,
in
4 addition to providing axial force through the cones 221 to the support rings
222, and
thus to the sealing member 225.
6 In another embodiment, the sealing system 220 illustrated proximal to
7 the mule shoe 250 in Fig. 2 can be replaced with a bias piston. Because such
a
8 biasing piston is more complicated than the sealing system 220, the use of a
9 second sealing system 220 instead of a biasing piston is preferred.
The slip 210 of Fig. 2 is illustrated with circumferential rows of wickers
11 211 oriented to resist axially downhole movement adjacent to rows of teeth
213
12 oriented to resist axially uphole movement. The tooth configuration of the
slip 210
13 in Fig. 2 is illustrative and by way of example only. In particular, the
number, shape,
14 and configuration of teeth are illustrative and by way of example only, and
other
numbers, shapes, and configurations of teeth can be used as desired. For
16 example, instead of biasing the teeth 211 and 213 towards either end of the
17 downhole tool 200, the teeth 211 and 213 can extend radially perpendicular
from a
18 central axis of the slip 210 and resist movement in either axial direction.
19 Fig. 3 is a cutaway view that illustrates another embodiment of a slip
300. In this embodiment, teeth sections 310 and 330 are separated by a central
21 portion with a substantially flat circumferential configuration around
which a band
22 340 is disposed. The band or strap 340 helps ensure that the slip 300, when
axial
23 force is exerted on it from both directions, fractures more evenly,
providing
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1 substantially equal expansion and engagement of the teeth section 310 and
330.
2 Thus, the slip 300 can provide substantially equal resistance to axial
movement in
3 either direction.
4 Figs. 4 and 5 are cross-sectional views along the central axis A-A of
two other embodiments of a slip 400 and 500. In Fig. 4, the teeth 410 and 430
are
6 oriented toward each end of the slip 400. As in the slip 300 of Fig. 3, a
central
7 section can be surrounded with a strap 340, not shown in Fig. 4, for
improved
8 evenness of fracture and engagement with the surrounding tubular, although
9 embodiments without the central section can be used. Unlike the teeth of the
embodiments of Figs. 2 and 3, which have a complex shape, the teeth 410 and
430
11 of slip 400 are simple triangular teeth, forming a right triangle
perpendicular to the
12 axis A-A with the right angle oriented toward the end of the slip 400.
13 An alternate embodiment is shown in Fig. 5. As in the embodiment of
14 Fig. 4, the teeth sections 510 and 530 comprise simple triangular teeth
separated
by a central section 520 for the attachment of the band 340. The orientation
of the
16 teeth 510 and 530 are reversed from the orientation of the teeth 410 and
430, so
17 that the teeth are oriented toward the central portion 520.
18 The number, shape, and configuration of teeth illustrated in Figs. 2-5
19 are illustrative and by way of example only, and any number, shape, and
configuration of teeth can be used as desired, including orientation axially
either
21 toward the ends of the slip or toward the center. The use of wickers or
teeth is
22 illustrative and by way of example only. In some embodiments, other surface
23 treatments other than wickers or teeth can be used to provide gripping
ability for the
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1 slip.
2 The bi-directional slip and dual sealing systems described herein may
3 be used in conjunction with any downhole tool used for sealing an annulus
within a
4 wellbore, such as frac-plugs, bridge plugs, or packers, for example.
In conclusion, by using a single bi-directional slip surrounded by two
6 sealing systems, various embodiments provide a downhole tool with reduced
metal
7 content, allowing faster mill up and less metal waste to fall downhole, but
without
8 sacrificing the ability to hold the downhole tool in place under high
temperature and
9 pressure conditions. The two sealing systems, in addition to doubly sealing
with the
surrounding tubular, provide boost force on the single slip in both
directions, thus
11 increasing the holding power of the single slip.
12
12
