Note: Descriptions are shown in the official language in which they were submitted.
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FRAC PLUG
2 PRIOR APPLICATIONS
3 This
application incorporates herein in their entirety the disclosure and drawings
of
4 the
following prior applications by reference: non-provisional patent application
entitled
"Frac Plug", U.S. Serial No. 15/055,696, filed February 29, 2016, and
provisional patent
6 application entitled "Frac Plug", U.S. Serial No. 62/149,553, filed April
18, 2015.
7 FIELD OF THE INVENTION
8 The
present invention relates generally to plugs that may be used to isolate a
portion
9 of a
well, and more particularly, to plugs that may be used in fracturing or other
processes
ro for stimulating oil and gas wells.
11 BACKGROUND OF THE INVENTION
12
Hydrocarbons, such as oil and gas, may be recovered from various types of
13
subsurface geological formations. The formations typically consist of a porous
layer, such
14 as
limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise
through
IS the
nonporous layer, and thus, the porous layer forms an area or reservoir in
which
16
hydrocarbons are able to collect. A well is drilled through the earth until
the hydrocarbon
17
bearing formation is reached. Hydrocarbons then are able to flow from the
porous
18 formation into the well.
19 In
what is perhaps the most basic form of rotary drilling methods, a drill bit is
20
attached to a series of pipe sections referred to as a drill string. The drill
string is suspended
21 from a
derrick and rotated by a motor in the derrick. A drilling fluid or "mud" is
pumped
22 down
the drill string, through the bit, and into the well bore. This fluid serves
to lubricate
23 the
bit and carry cuttings from the drilling process back to the surface. As the
drilling
24 progresses downward, the drill string is extended by adding more pipe
sections.
25 When
the drill bit has reached the desired depth, larger diameter pipes, or
casings,
26 are
placed in the well and cemented in place to prevent the sides of the borehole
from
27 caving
in. Cement is introduced through a work string. As it flows out the bottom of
the
28 work
string, fluids already in the well, so-called "returns," are displaced up the
annulus
29 between the casing and the borehole and are collected at the surface.
30 Once
the casing is cemented in place, it is perforated at the level of the oil
bearing
31
formation to create openings through which oil can enter the cased well.
Production tubing,
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valves, and other equipment are installed in the well so that the hydrocarbons
may flow in
2 a controlled manner from the formation, into the cased well bore, and
through the
3 production tubing up to the surface for storage or transport.
4 This simplified drilling and completion process, however, is rarely
possible in the
real world. Hydrocarbon bearing formations may be quite deep or otherwise
difficult to
6 access. Thus, many wells today are drilled in stages. An initial section
is drilled, cased,
7 and cemented. Drilling then proceeds with a somewhat smaller well bore
which is lined
8 with somewhat smaller casings or "liners." The liner is suspended from
the original or
9 "host" casing by an anchor or "hanger." A seal also is typically
established between the
to liner and the casing and, like the original casing, the liner is
cemented in the well. That
11 process then may be repeated to further extend the well and install
additional liners. In
12 essence, then, a modern oil well typically includes a number of tubes
telescoped wholly or
13 partially within other tubes.
14 Moreover, hydrocarbons are not always able to flow easily from a
formation to a
well. Some subsurface formations, such as sandstone, are very porous.
Hydrocarbons are
16 able to flow easily from the formation into a well. Other formations,
however, such as
17 shale rock, limestone, and coal beds, are only minimally porous. The
formation may
18 contain large quantities of hydrocarbons, but production through a
conventional well may
19 not be commercially practical because hydrocarbons flow though the
formation and collect
in the well at very low rates. The industry, therefore, relies on various
techniques for
21 improving the well and stimulating production from formations. In
particular, various
22 techniques are available for increasing production from formations which
are relatively
23 nonporous.
24 One technique involves drilling a well in a more or less horizontal
direction, so that
the borehole extends along a formation instead of passing through it. More of
the formation
26 is exposed to the borehole, and the average distance hydrocarbons must
flow to reach the
27 well is decreased. Another technique involves creating fractures in a
formation which will
28 allow hydrocarbons to flow more easily. Indeed, the combination of
horizontal drilling
29 and fracturing, or "frac'ing" or `Tracking" as it is known in the
industry, is presently the
only commercially viable way of producing natural gas from the vast majority
of North
31 American gas reserves.
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Fracturing a formation is accomplished by pumping fluid, most commonly water,
2 into the well at high pressure and flow rates. The fluid is injected into
the formation,
3 fracturing it and creating flow paths to the well. Proppants, such as
grains of sand, ceramic
4 or other particulates, usually are added to the frac fluid and are
carried into the fractures.
The proppant serves to prevent fractures from closing when pumping is stopped.
6 Fracturing typically involves installing a production liner in the
portion of the well
7 bore which passes through the hydrocarbon bearing formation. The
production liner may
8 incorporate valves, typically sliding sleeve valves, which may be
actuated to open ports in
9 the valve. The valves also incorporate a plug. The plug restricts flow
through the liner and
diverts it through the valve ports and into the formation. Once fracturing is
complete
11 various operations will be performed to "unplug" the valve and allow
fluids from the
12 formation to enter the liner and travel to the surface.
13 In many wells, however, the production liner does not incorporate
valves. Instead,
14 fracturing will be accomplished by "plugging and perfing" the liner. In
a "plug and per?'
job, the production liner is made up from standard lengths of liner. The liner
does not have
16 any openings through its sidewalls, nor does it incorporate frac valves.
It is installed in the
17 well bore, and holes then are punched in the liner walls. The
perforations typically are
18 created by so-called "per?' guns which discharge shaped charges through
the liner and, if
19 present, adjacent cement.
A plug and perf operation can allow a well to be fractured at many different
21 locations, but rarely, if ever, will the well be fractured all at once.
The liner typically will
22 be perforated first in a zone near the bottom of the well. Fluids then
are pumped into the
23 well to fracture the formation in the vicinity of the bottom
perforations.
24 After the initial zone is fractured, a plug is installed in the liner at
a point above the
fractured zone. The liner is perforated again, this time in a second zone
located above the
26 plug. A ball then is deployed onto the plug. The ball will restrict
fluids from flowing
27 through and past the plug. When fluids are injected into the liner,
therefore, they will be
28 forced to flow out the perforations and into the second zone. After the
second zone is
29 fractured, the process is repeated until all zones in the well are
fractured.
After the well has been fractured, however, plugs may interfere with
installation of
31 production equipment in the liner or may restrict the flow of production
fluids upward
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1 through the liner. Thus, the plugs typically are removed from the liner
after the well has
2 been fractured. Retrievable plugs are designed to be set and then unset.
Once unset, they
3 may be removed from the well. Non-retrievable plugs are designed to be
more or less
4 permanently installed in the liner. Once installed, they must be drilled
out to open up the
liner. Moreover, the debris created by drilling out non-retrievable plugs must
be circulated
6 out of the well so it does not interfere with production equipment that
will be installed in
7 the liner.
8 Many conventional non-retrievable plugs have a common basic design built
around
9 a central support mandrel. The support mandrel is generally cylindrical
and somewhat
elongated. It has a central conduit extending axially through it. The support
mandrel serves
ii as a core for the plug and provides support for the other plug
components. The other plug
12 components ¨ slips, wedges, and sealing elements ¨ are all generally
annular and are carried
13 on and around the support mandrel in an array extending along the length
of the mandrel.
14 More particularly, an upper set of slips is carried on the support
mandrel adjacent
to an upper wedge (also referred to as a "cone"). A lower set of slips is
disposed adjacent
16 to a lower wedge. The slips and wedges have mating, ramped surfaces. An
annular sealing
17 element, usually an elastomeric sealing element, is carried on the
support mandrel between
18 the upper and lower wedges. The sealing element often is provided with
backup rings.
19 The various components are carried on the support mandrel such that they
may slide along
zo the mandrel.
21 Such conventional frac plugs have nominal outer diameters in their
"unset" position
22 that allow them to be deployed into a liner. Once deployed, they will be
set by radially
23 expanding the slips and sealing element into contact with the liner
walls. More specifically,
24 the plugs are installed with a setting tool which may be actuated to
apply opposing axial
forces to the components carried around the plug support mandrel. The axial
forces cause
26 the components to slide axially along the support mandrel and squeeze
together. As they
27 are squeezed together, the ramped surfaces on the inside of the slips
will cause the slips to
28 ride up the ramped outer surface of the wedges. As they ride up the
outer surface of the
29 wedges, the slips expand radially until they contact the inner wall of
the liner. The outer
3o surfaces of the slips have teeth, serrations, and the like that enable
the slips to jam and bite
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1 into the liner wall. The slips, therefore, provide the primary anchor
which holds the plug
2 in place.
3 Squeezing the components also will cause the elastomeric sealing element
to
4 expand radially until it seals against the liner wall. Backup rings, if
present, serve to
minimize axial extrusion of the elastomeric material as it is squeezed between
the upper
6 and lower wedges. The elastomeric sealing element thus can minimize or
eliminate flow
7 around the plug, i.e., between the plug and the liner wall.
8 The support mandrel has a ball seat at or very near the upper end of the
mandrel
9 central conduit. Once the plug is installed, and the setting tool
withdrawn, fluids can flow
io in both directions through the central conduit. A ball may be deployed
or "dropped" onto
ii the ball seat, however, to substantially isolate the portions of the
liner below the plug. The
12 ball will restrict fluid from flowing downward through the plug.
13 Such designs are well known in the art and variations thereof are
disclosed, for
14 example, in U.S. Pat. 7,475,736 to D. Lehr etal., U.S. Pat. 7,789,137 to
R. Turley etal.,
U.S. Pat. 8,047,280 to L. Tran etal., and U.S. Pat. No. 9,316,086 to D.
VanLue. Plugs of
16 that general design also are commercially available, such as
Schlumberger's Diamondback
17 composite drillable frac plug and Weatherford's TruFrac composite frac
plug.
18 Frac plugs must resist very high hydraulic pressure ¨ often as high as
15,000 psi or
19 more. They also may be exposed to elevated temperatures and corrosive
liquids. Thus,
frac plugs traditionally were composed of relatively durable materials such as
steel. Frac
21 plugs fabricated with metal components have greater structural strength
that may in turn
22 facilitate installation of the plug. Metal components also may be less
likely to loosen up
23 and become unset, and they are more resistant to corrosion. On the other
hand, the required
24 service life of frac plugs may be relatively short, and metallic plugs
are difficult to drill
01.1t.
26 Thus, some or all of the components of many conventional non-retrievable
frac
27 plugs now are fabricated from more easily drillable materials. Such
materials include cast
28 iron, aluminum, and other more brittle or softer metals. Other more
easily drillable
29 materials include fiberglass, carbon fiber materials, and other
composite materials.
Composite materials in particular are more easily drilled and, therefore, can
make it easier
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1 to drill out a plug. They also can allow for less aggressive drilling and
reduce the likelihood
2 and amount of resulting damage to a liner.
3 It will be appreciated, however, that the central conduit of many
conventional
4 composite plugs has a relatively small diameter. Smaller diameter bores
make it more
likely that the plug will significantly restrict the flow of production fluids
through the plug,
6 or that it will not accommodate the passage of other tools that may be
needed for remedial
7 operations. Thus, there is a greater likelihood with small-bore plugs
that the plugs will
8 have to be drilled out.
9 Even with composite plugs, drill out operations can be costly and time
consuming.
Coil tubing drill outs typically cost $100,000.00 per day, and the process may
take two to
ii three days. Moreover, a plug and perf frac job may require the
installation of dozens of
12 plugs. Thus, even a small increase in the time required to drill an
individual plug may
13 considerably lengthen the overall cost and time required for the
operation.
14 It also will be appreciated that composite materials lack the hardness
and strength
of metals such as steel, cast iron, and aluminum. Plugs fabricated from
composite materials
16 may not hold their set or seal. They may be dislodged, damaged, or leak
during the
17 fracturing process as composite materials generally lack the yield
strength of metals.
18 Composites also have much lower lateral shear strengths, and thus, are
more susceptible to
19 being blown out by a ball once hydraulic pressure above the ball is
increased. Such
deficiencies often are minimized by increasing the length and thickness of the
plug
21 components.
22 For example, making a support mandrel thicker will increase its radial
yield
23 strength and will help maintain the engagement of the slips with a liner
wall. A longer
24 support mandrel will have a proportionately higher lateral shear
strength and, therefore, is
better able to resist the force of a ball seated in the mandrel passageway.
Increasing the
26 size of the components, however, necessarily increases the time required
to drill the plug
27 and increased the amount of debris that must be circulated out of the
well.
28 Additionally, while many of their components are fabricated from
composites,
29 many so-called composite plugs may still incorporate metal components
which can slow
down or complicate drilling out of the plug. For example, many predominantly
composite
31 plugs incorporate metallic slips which increase the time required to
drill out the plug. Metal
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slips also can break up into relatively large pieces that may be more
difficult to circulate
2 01It of a well.
3 Also, as noted, the elastomeric sealing element in many conventional
plugs is
4 disposed initially between the upper and lower wedges. As the wedges are
squeezed
together, the elastomeric sealing element is expanded radially. There also
will be a
6 tendency, however, for the elastomeric materials to extrude axially over
and around the
7 surface of the wedges. When hydraulic pressure later is applied behind
the plug, it also
8 may tend to extrude the elastomeric seal. Thus, many composite plugs
incorporate metal
9 or composite rings to back up the elastomeric seal. Such backup rings are
not always
io effective in preventing extrusion. Metal rings especially can become
entangled around the
ii bit used to drill the plug.
12 The process of drilling out plugs also can be exacerbated by what is
referred to as
13 "spinning." That is, as a plug is drilled out, the portions of the plug
components remaining
14 after most of the plug has been drilled out tend to spin with the bit.
Given their relatively
is lower mechanical properties, spinning is a particular problem in
composite plugs and can
16 significantly increase the time required to drill out a plugs. A common
solution is to
17 provide interlocking mechanical features on the top and bottom of the
plugs. Thus, if the
18 remnant of a plug begins to spin with a bit, it will be pushed down by
the bit until its lower
19 end interlocks with the top of a plug installed lower down in the liner.
That interlocking
20 engagement will stop the plug remnant from spinning. Such interlocking
geometrical
21 features, however, can add length and material to the plug.
22 Finally, as various problems attendant to their installation and
drilling out have been
23 addressed, composite plugs have tended to become relatively complex.
Composite
24 materials in general can be relatively expensive, and adding to the
complexity and number
25 of components in a plug generally tends to increase the cost of
fabricating and assembling
26 the plug. Typical plug and perf jobs will require dozens of plugs, so
even small increases
27 in the cost of a plug can add up to a significant expense.
28 The statements in this section are intended to provide background
information
29 related to the invention disclosed and claimed herein. Such information
may or may not
3o constitute prior art. It will be appreciated from the foregoing,
however, that there remains
31 a need for new and improved composite plugs and for new and improved
methods for
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1 fracking or otherwise stimulating formations using composite plugs. Such
disadvantages
2 and others inherent in the prior art are addressed by various aspects and
embodiments of
3 the subject invention.
4 SUMMARY OF THE INVENTION
The subject invention relates generally to plugs that may be used to isolate a
portion
6 of a well and encompasses various embodiments and aspects, some of which
are
7 specifically described and illustrated herein.
8 In one embodiment, a plug apparatus includes an annular wedge having a
wedge
9 first end and a wedge second end. The wedge includes an axial wedge
passage
therethrough from the wedge first end to the wedge second end. The wedge
includes an
ii inner seat defined in the wedge passage for receiving and seating a
ball. The wedge has a
12 tapered outer surface adjacent the wedge second end. The tapered outer
surface increases
13 in outside diameter from the wedge second end toward but not necessarily
all the way to
14 the wedge first end. A sealing ring is received about the tapered outer
surface of the wedge.
is The sealing ring is radially expandable. An annular slip has a slip
first end and a slip
16 second end. The slip has an axial slip passage therethrough from the
slip first end to the
17 slip second end. The slip passage has a tapered inner surface adjacent
the slip first end.
18 The tapered inner surface decreases in inside diameter from the slip
first end toward but
19 not necessarily all the way to the slip second end. The wedge second end
is received in the
zo slip first end so that the tapered outer surface of the wedge engages
the tapered inner surface
21 of the slip. The slip first end faces the sealing ring for abutment with
the sealing ring.
22 The annular slip can include a plurality of separate slip segments. The
annular
23 wedge can also include a plurality of collet fingers extending from the
wedge second end
24 and circumferentially spaced to form slots between the collet fingers,
each collet finger
25 extending through the axial slip passage to a distal end beyond the slip
second end. The
26 plug apparatus can further include a setting ring having an outer
diameter, slidably mounted
27 around the collet fingers between the slip second end and the distal end
of each collet
28 finger. The setting ring can have a first radial thickness and one or
more keys that protrude
29 radially inward into one or more of the slots from the first radial
thickness to a second
30 radial thickness. The plug apparatus can further include a gauge ring
fixably connected to
31 the distal end of the collet fingers having an outer diameter at least
the same as the outer
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1 diameter of the setting ring or greater. As an alternative option, the
setting ring can be
2 located adjacent to the gauge ring and to the slip second end, and the
gauge ring can include
3 a peripheral annular wall that extends around the setting ring and
extends at least to the slip
4 second end.
According to one aspect, the setting ring is slidable between an unset
position and
6 a set position. In the unset position, the slip and the sealing ring are
each in a first radial
7 position wherein the setting ring is located adjacent to the gauge ring
and to the slip second
8 end. In the set position, the slip and the sealing ring are each radially
expanded from the
9 first radial position to a second radial position, wherein the setting
ring is displaced along
the collet fingers towards the wedge second end and the adjacent slip and
sealing ring are
ii correspondingly displaced towards the wedge first end.
12 The plug apparatus can yet further include a mandrel connected to a
setting tool,
13 the mandrel extending through the axial wedge passage and releasably
coupled to the
14 setting ring via a frangible coupling. The plug apparatus can still
further include an annular
is sleeve adapter connected to the setting tool and coupled to the first
wedge end of the
16 annular wedge, wherein the setting tool is configured to displace the
mandrel axially
17 relative to the annular sleeve adapter and thereby move the setting ring
from the unset
18 position to the set position.
19 In an alternative embodiment, a plug apparatus comprises an annular slip
formed
zo from a plurality of separate slip segments disposed adjacently to one
another. The slip has
21 an upper end and a lower end, and a slip bore that extends from the
slip's upper end to its
22 lower end and is also inwardly tapered from the upper end toward the
lower end. The plug
23 apparatus further comprises a wedge with a tapered lower outer surface
portion that is
24 received in the upper end of the slip and engages the tapered slip bore.
The wedge includes
25 a wedge bore with an upwardly facing annular seat defined therein. A
plurality of collet
26 fingers, circumferentially spaced in an annular arrangement, extends
axially from a lower
27 end of the tapered lower outer surface portion of the wedge. Each collet
finger extends
28 through the slip bore to a distal end beyond the slip lower end. A
setting ring is slidably
29 located on the plurality of collet fingers between the slip lower end
and the distal end of
30 the collet fingers. The plug apparatus yet further comprises a sealing
ring received about
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the tapered lower outer surface portion of the wedge above the slip upper end
and is
2 configured to be engaged by the slip upper end.
3 A method is disclosed for setting a plug in a casing bore, the method
comprising
4 initially retaining a wedge and a slip in an unset axially extended
position with a lower
tapered outer surface of the wedge received in an upper tapered inner bore of
the slip. A
6 sealing ring is received about the wedge above the slip and engaged with
an upper end of
7 the slip. While the wedge and the slip are retained in the unset
position, the plug is run
8 into a casing to a casing location to be plugged. The plug then is set in
the casing by forcing
9 the wedge axially into the slip and the sealing ring; thereby radially
expanding the slip to
io anchor the plug in the casing, and radially expanding the sealing ring
to seal between the
ii plug and the casing.
12 In another embodiment, an adapter apparatus is provided for attaching a
plug onto
13 a downhole setting tool. The setting tool including an inner setting
tool part and an outer
14 setting tool part. The setting tool is configured to provide a relative
longitudinal motion
between the inner and outer setting tool parts. The adapter apparatus includes
an outer
16 adapter portion configured to be attached to the outer setting tool
part, the outer adapter
17 portion including downward facing setting surface. The adapter apparatus
further includes
18 an inner adapter portion configured to be attached to the inner setting
tool part, the inner
19 adapter portion including an inner mandrel, a release sleeve, and a
releasable connector.
zo The release sleeve is slidably received on the inner mandrel, the
release sleeve carrying an
21 upward facing setting surface. The releasable connector is configured to
hold the release
22 sleeve in an initial position relative to the inner mandrel until a
compressive force
23 transmitted between the downward facing setting surface and the upward
facing setting
24 surface exceeds a predetermined release value.
In another embodiment, an adapter apparatus is provided for attaching a plug
onto
26 a downhole setting tool. The setting tool including an inner setting
tool part and an outer
27 setting tool part. The setting tool is configured to provide a relative
longitudinal motion
28 between the inner and outer setting tool parts. The adapter apparatus
includes an outer
29 adapter portion configured to be attached to the outer setting tool
part, the outer adapter
portion including downward facing setting surface. The adapter apparatus
further includes
31 an inner adapter portion configured to be attached to the inner setting
tool part, the inner
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adapter portion including an inner mandrel, a release sleeve, and a releasable
connector.
2 The release sleeve is slidably received on the inner mandrel, the release
sleeve carrying an
3 upward facing setting surface. The releasable connector is configured to
hold the release
4 sleeve in an initial position relative to the inner mandrel until a
compressive force
transmitted between the downward facing setting surface and the upward facing
setting
6 surface exceeds a predetermined release value.
7 A method is provided for setting a plug assembly in a casing bore. The
method
8 comprises connecting the plug assembly in an initial arrangement with a
setting tool using
9 an adapter kit. The initial arrangement includes the plug assembly
including a plug wedge
io in an initial position partially received in a plug slip, with a sealing
ring received around
it the plug wedge adjacent an end of the slip. The plug wedge and plug slip
are received
12 about an inner part of the adapter kit, with an upward facing setting
surface of the inner
13 part facing a lower end of the plug assembly. An outer part of the
adapter kit including a
14 downward facing setting surface facing an upper end of the plug
assembly. The plug
assembly, the adapter kit, and the setting tool is run into the casing bore in
the initial
16 arrangement. The plug assembly is set in the casing bore by actuating
the setting tool and
17 compressing the plug assembly between the upward facing and downward
facing setting
18 surfaces. The plug assembly is released from the adapter kit.
19 The subject invention provides other embodiments and aspects, including
a plug
apparatus, comprising a wedge, a sealing ring, and a slip. The wedge comprises
an axial
21 wedge bore. A seat is defined in the wedge bore. The seat is adapted to
receive a ball.
22 The wedge also has a tapered outer surface. The tapered outer surface
decreases in
23 diameter from the upper extent of the tapered outer surface toward the
lower extent of the
24 tapered outer surface. The sealing ring is received around the tapered
outer surface of the
wedge. The sealing ring has an axial ring bore and is radially expandable. The
slip
26 comprises an axial slip bore. The slip bore provides the slip with a
tapered inner surface.
27 The tapered inner surface decreases in diameter from the upper extent of
the tapered inner
28 surface toward the lower extent of the tapered inner surface. The inner
surface is adapted
29 to receive the wedge along the tapered outer surface of the wedge. The
wedge is adapted
for displacement from an unset position generally above the slip to a set
position wherein
31 the wedge is received in the slip bore along the tapered outer surface
of the wedge.
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1 Other
embodiments include such plug apparatus where the sealing ring and the slip
2 are
adapted to expand radially from an unset condition. In the unset position the
sealing
3 ring
and the slip have nominal outer diameters. The slip expands radially from its
unset
4
condition to a set condition as the wedge is displaced from its unset position
to its set
position. In its set condition, the sealing ring and the slip have enlarged
outer diameters.
6
Additional aspects are directed to such plug assemblies where a lower portion
of
7 the
tapered outer surface of the wedge, when the wedge is in its unset position,
extends into
8 and engages an upper portion of the tapered inner surface of the slip.
9 Still
other embodiments are directed to such plug assemblies where the sealing ring
lo
includes an annular ring body. The annular ring body has a tapered ring bore
11
complementary to the tapered outer surface of the wedge. An annular inner
groove is
12
defined in the ring bore. An annular outer groove is defined in the outer
surface of the ring
13 body.
An inner elastomeric seal is received in the inner groove. An outer
elastomeric seal
14 is received in the outer groove.
Further aspects and embodiments are directed to such plug assemblies where the
16 slip
comprises a plurality of separate slip segments. Yet others are direct to such
plug
17
assemblies where the sealing ring is radially expandable without breaking and
where the
18
sealing ring includes an annular ring body constructed of a sufficiently
ductile material
19 such that the sealing ring can expand radially to its set condition
without breaking.
The subject invention also is directed to embodiments where such plug
assemblies
21 have a
sealing ring fabricated from plastic and especially from engineering plastics.
In
22 other
embodiments the plastic is selected from plastics or engineering plastics
selected
23 from
the group consisting of polycarbonates, polyamides, polyether ether ketones,
and
24
polyetherimides and copolymers and mixtures thereof or the groups consisting
of subsets
of such groups.
26 In
other aspects and embodiments the sealing ring is fabricated from plastic and
has
27 a
elongation factor of at least about 10% or at least about 30%. In other
aspects, the plastic
28 will
have a useful operating temperature of at least 250 F or at least 350 F, or
will have a
29 tensile strength of a least 5,000 psi or at least about 1,500 psi.
Still other embodiments include such plug apparatus where the ball seat is
located
31 in the
wedge bore such that when the wedge is in its set position the ball seat is
situated
12
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1 axially proximate to the sealing ring, or where the ball seat is located
in the wedge bore
2 axially below the upper end of the wedge bore, or where the ball seat is
located in the
3 wedge bore such that when the wedge is in its set position the ball seat
is situated axially
4 between the upper end of the sealing ring and the lower end of the slip,
or where the ball
seat is located in the wedge bore such that when the wedge is in its set
position the ball seat
6 is situated axially below the midpoint of the slip bore.
7 Additional aspects are directed to such plug assemblies where the ball
seat is
8 provided by an upward facing tapered reduction in the diameter of the
wedge bore or where
9 the tapered reduction in diameter is approximately 150 off center.
In other embodiments, such plug apparatus have wedges where the tapered outer
11 surface of the wedge is a truncated, inverted cone and the tapered inner
surface of the slip
12 is a truncated, inverted cone. In other aspects, the tapered outer
surface of the wedge and
13 the tapered inner surface of the slip are provided with a taper from
about 10 to about 100
14 off center or where the tapered outer surface of the wedge and the
tapered inner surface of
the slip provide a self-locking taper fit between the wedge and the slip.
16 Other embodiments of the invention are directed to such plug apparatus
where the
17 slip comprises a plurality of separate slip segments. Each of the slip
segments are
18 configured generally as lateral segments of an open cylinder. In other
aspects, the slip
19 segments are aligned axially. When the wedge is in its unset position,
the slip segments
zo circumferentially abut along their sides and provide a substantially
continuous inner
21 tapered surface of the slip. In still other aspects the upper end of the
slip abuts the sealing
22 ring about the lower end of the sealing ring as the wedge moves from its
unset position to
23 its set position. In other embodiments, the upper end of the slip, when
the wedge is in its
24 unset position, abuts the sealing ring substantially continuously about
the lower end of the
sealing ring.
26 Other embodiments and aspects of the invention are directed to plug
apparatus
27 comprising a wedge, a plastic sealing ring, and a slip. The wedge
comprises an axial wedge
28 bore and a tapered outer surface. The tapered outer surface decreases in
diameter from the
29 upper extent of the tapered outer surface toward the lower extent of the
tapered outer
surface. The plastic sealing ring is received around the tapered outer surface
of the wedge.
31 The sealing ring has an axial ring bore and is radially expandable. The
slip comprises an
13
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axial slip bore. The slip bore provides the slip with a tapered inner surface.
The tapered
2 inner surface decreases in diameter from the upper extent of the tapered
inner surface
3 toward the lower extent of the tapered inner surface. The inner surface
is adapted to receive
4 the wedge along the tapered outer surface of the wedge. The wedge is
adapted for
displacement from an unset position generally above the slip to a set position
wherein the
6 wedge is received in the slip bore along the tapered outer surface of the
wedge.
7 Displacement of the wedge is adapted to radially expand the sealing ring
into sealing
8 engagement with a liner without breaking the sealing ring.
9 Additional aspects and embodiments are directed to such plug apparatus
where the
to comprises a plurality of collet fingers. The collet fingers extend
axially below the tapered
ii outer surface of the wedge. They are circumferentially spaced to form
axial slots between
12 the collet fingers. They also extend through the slip bore to a distal
end beyond the slip
13 when the wedge is in the unset position.
14 In other embodiments, such plug apparatus have a setting ring slidably
mounted
around the collet fingers between the slip and the distal end of the collet
fingers. The
16 setting ring has an outer diameter, a first radial thickness; and one or
more keys that
17 protrude radially inward from the first radial thickness to a second
radial thickness and into
18 one or more of the slots between the collet fingers.
19 Further embodiments are directed to such plug apparatus having a gauge
ring
zo connected to the distal end of the collet fingers and having an outer
diameter equal to or
21 greater than the outer diameter of the setting ring. In other
embodiments, the setting ring
22 is between the slip and a lower portion of the gauge ring and the gauge
ring includes a
23 peripheral annular wall that extends axially upward around the setting
ring and at least of
24 portion of the slip.
Yet other embodiments are directed to plug apparatus where the wedge is
adapted
26 for displacement from the unset position to the set position. In the
unset position the slip
27 and the sealing ring are each in a first radial position and the setting
ring is located adjacent
28 to the gauge ring and to the slip. In the set position, the slip and the
sealing ring are each
29 radially expanded from the first radial position to a second radial
position and the setting
ring is located adjacent to the slip and the distal ends of the collet fingers
are displaced
31 away from the setting ring.
14
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1
Additional aspects and embodiments are directed to such plug apparatus which
2 have a
mandrel and a sleeve adapter. The mandrel is operably connected to a setting
tool
3 and
extends through the wedge bore and releasably coupled to the setting ring by a
4
frangible coupling. The sleeve adapter is operably connected to the setting
tool and abuts
the upper end of the wedge. The setting tool is configured to displace the
sleeve adapter
6
axially downward relative to the mandrel and thereby displace the wedge from
the unset
7 position to the set position.
8 In
other aspects, the invention is directed to such plug assemblies as a composed
of
9
drillable materials, including composite materials, and especially where the
wedge and slip
are fabricated from such materials.
11 The
subject invention in other aspects and embodiments also provides for methods
12 of
setting a plug in a liner bore. The methods comprise running the plug into the
liner to a
13
location to be plugged. The plug is in an unset state in which a tapered outer
surface of a
14 wedge
is generally above a tapered inner bore of a slip. A sealing ring is received
around
the tapered outer surface of the wedge above the slip. The plug then is set in
the liner by
16
forcing the wedge axially into the slip bore and the sealing ring. Thus, the
slip will be
17
radially expanded to anchor the plug in the liner, and the sealing ring will
be radially
18 expanded to seal between the plug and the liner.
19 Other
aspects provide such methods where the sealing ring expands radially without
breaking. In other embodiments, the slip abuts the sealing ring as the wedge
is forced into
21 the
slip bore and sealing ring. In yet other embodiments the slip, when the plug
is in its
22 unset
state, abuts the sealing ring substantially continuously about the sealing
ring. Other
23
embodiments include deploying a ball onto an annular seat defined in an axial
bore of the
24 wedge to occlude the axial bore.
Still other aspects of the invention are directed to liner assemblies which
comprise
26 a
liner with the novel plug assemblies set therein and to oil and gas wells
incorporating
27 such liner assemblies.
28
Finally, still other aspect and embodiments of the novel apparatus and methods
will
29 have various combinations of such features as will be apparent to
workers in the art.
Thus, the present invention in its various aspects and embodiments comprises a
31
combination of features and characteristics that are directed to overcoming
various
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1 shortcomings of the prior art. The various features and characteristics
described above, as
2 well as other features and characteristics, will be readily apparent to
those skilled in the art
3 upon reading the following detailed description of the preferred
embodiments and by
4 reference to the appended drawings.
Since the description and drawings that follow are directed to particular
6 embodiments, however, they shall not be understood as limiting the scope
of the invention.
7 They are included to provide a better understanding of the invention and
the manner in
8 which it may be practiced. The subject invention encompasses other
embodiments
9 consistent with the claims set forth herein.
BRIEF DESCRIPTION OF THE DRAWINGS
11 FIGURE 1A is a schematic illustration of an early stage of a "plug and
pelf'
12 fracturing operation showing a tool string 10 deployed into a liner
assembly 4, where tool
13 string 10 includes a perf gun 11, a setting tool 12, an adapter kit 14,
and a first preferred
14 embodiment 16 of the plug assemblies of the subject invention.
FIG. 1B is a schematic illustration of liner assembly 4 after completion of
the plug
16 and perf fracturing operation, but before removal of plugs 16 from liner
4.
17 FIGS. 2-4 are sequential axial cross-sectional schematic views of plug
16 in a well
18 liner 4 which omit, for the sake of clarity, various components of
adapter kit 14.
19 FIG. 2 shows plug 16 in its run-in state, that is, as it is run into a
well to a desired
location in liner 4.
21 FUG. 3 shows plug 16 after it has been installed in liner 4.
22 FIG. 4 shows plug 16 after it has been closed with a ball 76 to restrict
the flow of
23 fluids downward through plug 16.
24 FIG. 5 is an enlarged axial cross-sectional view of an annular wedge 62
of plug 16.
FIG. 6 is an enlarged axial cross-sectional view of a sealing ring 64 of plug
16.
26 FIG. 7 is an enlarged axial cross-sectional view of an annular slip 66
of plug 16.
27 FIG. 8 is bottom elevationa1 view of slip 66 of plug 16.
28 FIGURES 9A and 9B are axial cross-sectional views of a portion of a tool
string
29 10 which includes setting tool 12, adapter kit 14 and plug 16. Setting
tool 12, adapter kit
14, and plug 16 are shown as they are run into a well. FIG. 9A shows an upper
portion of
31 tool string 10, and FIG. 9B shows a lower portion of tool string 10.
16
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1 FIG.
10 is an enlarged cross-sectional view of a lower portion of setting tool 12,
2 adapter kit 14, and plug 16 shown in FIGS. 9A-9B.
3 FUG.
11 is an enlarged axial cross-sectional view of adapter kit 14 and plug 16
4 shown
in FIGS. 9B and 10. Adapter kit 14 and plug 16 are in their unactuated, run-in
state.
FIG. 12 is a still further enlarged axial cross-sectional view of plug 16 and
various
6 components of adapter kit 14.
7 FIGS.
13-16 are sequential axial cross-sectional views of adapter kit 14 and plug
8 16
which, together with FIGS. 11-12, illustrate the operation of setting tool 12
and adapter
9 kit 14
as they are deployed into a well with plug 16, are actuated to install plug 16
in liner
4, and then are released from plug 16.
11 FIG.
13 shows adapter kit 14 and plug 16 after they have been actuated from their
12 run-in state shown in FIG. 11 to install plug 16 in liner 4.
13 FIG.
14 shows an initial stage of releasing and withdrawing adapter kit 14 from set
14 plug 16.
FIG. 15 shows an intermediate stage of releasing and withdrawing adapter kit
14
16 from set plug 16.
17 FIG. 16 shows a later stage of releasing and withdrawing adapter kit 14.
18 FIG.
17 is an axial cross-sectional view of the lower end of adapter kit 14 and
plug
19 16 shown in FIG. 12 with an optional pump down fin 144 connected to
adapter kit 14.
FIG. 18 is a perspective view of a tension mandrel lock spring 150 used in
21 connecting certain components of adapter kit 14.
22 FIG.
19 is an enlarged axial cross-sectional view of a second preferred embodiment
23 216 of
plug assemblies of the subject invention. Plug 216 is shown in its run-in
state, and
24 the figure omits for the sake of clarity certain components of an
adapter kit 214.
FIG. 20 is side elevational view, including a partial cut-away axial cross-
section,
26 of
plug 216. Plug 216 is shown in its run-in state, and the figure omits for the
sake of
27 clarity certain components of adapter kit 214.
28 FIG. 21 is an axial cross-sectional view of an annular wedge 262 of plug
216.
29 FIG.
22 is a radial cross-section view, taken generally along lines 22-22 of FIG.
19, of plug 216.
17
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1 FIGS. 23 and 24 are sequential axial cross-sectional views of plug 216
in liner 4
2 omitting, for the sake of clarity, various components of adapter kit 214
FUG. 23 shows plug 216 in an unset position as it is run into a well to a
desired
4 location in liner 4.
FIG. 24 shows plug 216 after it has been set in liner 4 and it has been closed
with
6 a ball 76 to restrict the flow of fluids downward through plug 216.
7 FIG. 25 is a top elevational view of a setting ring 270 of plug 216.
8 FIG. 26 is an axial cross-sectional view of setting ring 270 shown in
FIG. 25.
9 FIG. 27 is an axial cross-sectional view of a gauge ring 280 of plug
216.
FIG. 28 is a bottom elevational view of gauge ring 280 shown in FIG. 27.
11 FIG. 29 is an axial cross-sectional view, similar to the view of FIG.
12, showing
12 portions of setting tool 12 and adapter kit 214 with plug 216. Setting
tool 12, adapter kit
13 214, and plug 216 are in their unactuated, run-in state.
14 FIG. 30 is an enlarged axial cross-sectional view of adapter kit 214 and
plug 216
is shown in FIG. 29.
16 FIG. 31 is an axial cross-sectional view of an actuating mandrel 222 of
adapter kit
17 214.
18 FIG. 32 is an axial cross-sectional view of a top cap 224 of adapter kit
214.
19 FIG. 33 is an axial cross-sectional view of a sleeve adapter 210 of
adapter kit 214.
In the drawings and description that follows, like parts are identified by the
same
21 reference numerals. The drawing figures are not necessarily to scale.
Certain features of
22 the embodiments may be shown exaggerated in scale or in somewhat
schematic form and
23 some details of conventional design and construction may not be shown in
the interest of
24 clarity and conciseness.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
26 The present invention generally relates to plugs that may be used to
isolate a portion
27 of a well, and more particularly, to plugs that may be used in
fracturing or other processes
28 which require isolation of selected portions of a liner. Some broader
embodiments of the
29 novel plugs comprise an annular wedge having an inner ball seat, a
sealing ring, and an
3o annular slip. Other broad embodiments comprise an annular wedge, a
plastic sealing ring
31 which can expand radially without breaking, and an annular slip.
18
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Overview of Plug and Perf Fracturing Operations
2 A
first preferred frac plug 16, for example, will be described by reference to
FIGS.
3 1-18.
As may be seen in the schematic representations of FIGS 1, plugs 16 may be
used
4 to
perform a "plug and per?' fracturing operation in an oil and gas well 1. Well
1 is serviced
by a well head 2 and various other surface equipment (not shown). Well head 2
and the
6 other
surface equipment will allow frac fluids to be introduced into the well at
high
7
pressures and flow rates. The upper portion of well 1 is provided with a
casing 3 which
8
extends to the surface. A production liner 4 has been installed in the lower
portion of
9 casing
3 via a liner hanger 5. It will be noted that the lower part of well 1 extends
generally
io
horizontally through a hydrocarbon bearing formation 6 and that liner 2, as
installed in well
ii 1, is
not provided with valves or any openings in the walls thereof. Liner 2 also
has been
12
cemented in place. That is, cement 7 has been introduced into the annular
space between
13 liner 2 and the well bore 8.
14 FIG.
1A shows well 1 after the initial stage of a frac job has been completed. As
is
discussed in greater detail below, a typical frac job will proceed from the
lowermost zone
16 in a
well to the uppermost zone. FIG. 1A, therefore, shows that the bottom portion
of liner
17 4 has
been perforated and that fractures 9 extending from perforations 13a have been
18
created in a first zone near the bottom of well 1. Tool string 10 has been run
into liner 4
19 on a wireline 15.
20 Tool
string 10 comprises a perf gun 11, setting tool 12, adapter kit 14, and frac
plug
21 16a.
Tool string 10 is positioned in liner 4 such that frac plug 16a is uphole from
22
perforations 13a. Frac plug 16a is coupled to setting tool 12 by adapter kit
14 and, as
23 discussed in greater detail below, will be installed in liner 4 by
actuating setting tool 12.
24 Once
plug 16a has been installed, setting tool 12 and adapter kit 14 will be
released
25 from
plug 16a. Perf gun 11 then will be fired to create perforations 13b in liner 4
uphole
26 from
plug 16a. Perf gun 11, setting tool 12, and adapter kit 14 then will be pulled
out of
27 well 1 by wireline 15.
28 A frac
ball (not shown) then will be deployed onto plug 16a to restrict the
29
downward flow of fluids through plug 16a. Plug 16a, therefore, will
substantially isolate
30 the
lower portion of well 1 and the first fractures 9 extending from perforations
13a. Fluid
19
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I then can be pumped into liner 4 and forced out through perforations 13b
to create fractures
2 9 in a second zone.
3 Additional plugs 16b to 16y then will be run into well 1 and set, liner
4 will be
4 perforated at perforations 13c to 13z, and well 1 will be fractured in
succession as described
above until, as shown in FUG. 1B, all stages of the frac job have been
completed and
6 fractures 9 have been established in all zones.
7 Some operators may prefer to produce hydrocarbons from well 1 without
removing
8 plugs 16 from liner 4. In such instances, dissolvable frac balls will be
used in the fracturing
9 operation. Dissolvable balls, as their name implies, are fabricated from
a material that
ro dissolves, softens, or disintegrates in the presence of well fluids
after a period of time
11 (typically 1 to 30 days) such that the balls do not thereafter interfere
with the upward flow
12 of fluids through plugs 16.
13 More commonly, however, operators will prefer to remove plugs 16 from
liner 4,
14 even if dissolvable frac balls are employed. Frac plugs 16 may interfere
with the
installation of production equipment in liner 4 and, depending on production
rates, may
16 restrict the upward flow of production fluids through liner 4. Thus, for
example, a motor
17 with a drill bit may be deployed into liner 4 on coiled tubing. Mill
bits also may be used
18 but generally are less preferable. In either event, plugs 16 will be
drilled out in succession
19 from top to bottom. The drilling process, of course, creates debris
which, if left in liner 4,
may interfere with production equipment or otherwise may hinder production
from well 1.
21 Debris from plugs 16, therefore, preferably is circulated out of liner 4
during the drilling
22 process.
23 It will be noted that MS. 1 are greatly simplified schematic
representations of a
24 plug and perf fracturing operation. Production liner 4 is shown only in
part as such liners
may extend for a substantial distance. The portion of liner 4 not shown also
will be
26 provided with perforations 13 and plugs 16, and fractures 9 will be
established therein. In
27 addition, FIGS. 1 depict only a few perforations 13 in each zone,
whereas typically a zone
28 will be provided with many perforations. Likewise, a well may be
fractured in any number
29 of zones, thus liner 4 may be provided with more or fewer plugs 16 than
depicted.
The terms "upper" and "lower" as used herein to describe location or
orientation
31 are relative to the well and to the tool as run into and installed in
the well. Thus, "upper"
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1 refers to a location or orientation toward the upper or surface end of
the well. "Lower" is
2 relative to the lower end or bottom of the well. It also will be
appreciated that the course
3 of the well bore may not necessarily be as depicted schematically in
FIGS. 1. Depending
4 on the location and orientation of the hydrocarbon bearing formation to
be accessed, the
course of the well bore may be more or less deviated in any number of ways.
"Axial,"
6 "radial," and forms thereof reference the central axis of the tool. For
example, axial
7 movement or position refers to movement or position generally along or
parallel to the
8 central axis. "Lateral" movement and the like generally refers to up and
down movement
9 or position up and down the tool.
Jo Overview of First Preferred Frac Plug
11 The novel plugs incorporate a wedge, a sealing ring, and a slip, all of
which have
12 truncated inverted conical or other tapered surfaces. The tapered
surfaces complement
13 each other and allow the wedge to be driven into and radially expand the
sealing ring and
14 slip to seal and anchor the plug in a liner. For example, consider
preferred novel frac plug
16 which is shown in isolation and in greater detail in FIGS. 2-4. As shown
therein, plug
16 16 generally comprises an annular wedge 62, a sealing ring 64, and an
annular slip 66. The
17 construction of those plug components perhaps can be best appreciated
from FIGS. 5-8.
18 Annular wedge 62 is shown in isolation in FIG. 5, sealing ring 64 is
shown in isolation in
19 FIG. 6, and annular slip 66 is shown in isolation in FIGS. 7 and 8. All
of those figures
zo show plug 16 and its components in their as-fabricated, run-in state.
21 As best seen in FIG. 5, wedge 62 may be described in general terms as
having a
22 generally tapered annular or open cylindrical shape. More particularly,
wedge 62 has an
23 axial passage or bore 72 extending from the upper end 68 of wedge 62 to
the lower end 70
24 of wedge 68. An inner ball seat 74 is defined in wedge bore 72, bore 72
otherwise having
a substantially uniform diameter. Ball seat 74 is provided by a shallow angle,
upward
26 facing tapered reduction in the diameter of wedge bore 72 situated
axially below the upper
27 end 68 of wedge 62.
28 The outer surface of wedge 62 in large part tapers radially outward from
bottom to
29 top. More specifically, the outer diameter of wedge 62 increases from
the wedge lower
end 70 toward the wedge upper end 68, thus providing wedge 62 with an inverted
truncated
31 conical outer surface 78 adjacent to the wedge lower end 70. Tapered
outer surface 78
21
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i extends along the majority of the length of wedge 62 and terminates near
its upper end 68.
2 Though perhaps not readily apparent in FIG. 5, a relatively short upper
portion 80 of wedge
3 62 has a substantially uniform, non-tapered outer diameter.
4 As seen best in FIG. 6, sealing ring 64 has a relatively short, annular
body 82
defining an axial passage or bore 84. Ring bore 84 has a generally inverted
truncated
6 conical shape, that is, it tapers radially outward from its lower end to
its upper end. The
7 taper of ring bore 84 is complementary to the tapered outer surface 78 of
wedge 62. Sealing
8 ring 64 preferably is provided with elastomeric seals which ultimately
will enhance the seal
9 between plug 16 and liner 4 when, as described in detail below, plug 16
is set. Thus, as
appreciated best from FIG. 6, ring body 82 has an annular groove 86 in its
outer surface
ii 88 and an annular groove 90 in its ring bore 84. Outer groove 86 and
inner groove 90 are
12 filled, respectively, with elastomeric seal material 92 and 94.
Elastomeric seal material 92
13 and 94 may be molded in grooves 86 and 90 or they may be molded and then
inserted
14 therein.
As best seen in FIGS. 7-8, slip 66 also may be described in general terms as
having
16 a generally tapered annular or open cylindrical shape. More
particularly, slip 66 has an
17 axial passage or bore 100 extending from the upper end 96 of slip 66 to
the lower end 98
18 of slip 66. Slip bore 100 in large part has a generally inverted
truncated conical shape, that
19 is, it in large part tapers radially inward from top to bottom. More
specifically, the inner
zo diameter of slip bore 100 decreases from the slip upper end 96 toward
the slip lower end
21 98, thus providing slip 66 with a tapered inner surface 102 adjacent the
slip upper end 96.
22 Tapered inner surface 102 extends along most of slip bore 100 and
terminates near the
23 lower end 98 of slip 66. The taper of inner surface 102 of slip 66 is
complementary to the
24 taper of outer surface 78 of wedge 62. Though perhaps not readily
apparent in FIG. 7, a
relatively short lower portion 104 of slip bore 100 has a substantially
uniform, non-tapered
26 .. inner diameter.
27 Slip 66 is a breakaway type slip which is designed to break apart into a
number of
28 segments. More particularly, slip 66 has a plurality of slip segments
112, such as slip
29 segments 112A, 112B, and 112C. Slip segments 112 are joined initially by
frangible
portions 114. Slip segments 112 are arranged around the circumference of slip
66 and
31 extend laterally (or lengthwise) from the slip upper end 96 to the slip
lower end 98.
22
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1 Longitudinal cuts separate the upper portion of adjacent slip segments
112 and align with
2 grooves 116 in the outer surface of slip 66. When plug 16 is set, as
described in detail
3 below, the longitudinal cuts and grooves 116 encourage slip segments 112
to break apart
4 at frangible portions 114. Alternately, however, slip 66 may be assembled
from discrete
slip segments. In any event, the substantial length of the outer surface of
slip segments 112
6 is covered with downward facing serrations or teeth which will allow slip
segments 112 to
7 engage and grip liner 4.
8 As described in greater detail below, wedge 62 will be driven downward
into
9 sealing ring 64 and annular slip 66. As wedge 62 is driven downward, it
will force sealing
ring 64 and slip 66 to expand and thereby set and seal plug 16 in liner 4. The
operation of
11 plug 16 perhaps can be best appreciated from FIGS. 2-4 which show plug
16, respectively,
12 as it is run into well 1 and positioned in liner 4, after it has been
set in liner 4, and with a
13 frac ball 76 seated in plug 16 to isolate lower portions of liner 4.
14 As shown in FIG. 2, when plug 16 is assembled for running into a well,
wedge 62
is situated generally above slip 66. Preferably, to ensure reliable
displacement of wedge
16 62 into slip 66 and to reduce the length of plug 16, lower end 70 of
wedge 62 is received
17 in upper end 96 of slip 66 as shown. Thus, the smaller outer diameter
portion of tapered
18 outer surface 78 of wedge 62 engages the upper, larger inner diameter
portion of tapered
19 inner surface 102 of slip 66. Sealing ring 64 is carried on tapered
outer surface 78 of wedge
zo 62 near its lower end 70 and above slips 66. Preferably, as shown,
sealing ring 64 abuts
zi the upper end 96 of slip 66.
22 Preferably the wedge and slip are releasably connected to each other to
prevent
23 unintended setting of the plug as it is run into a well. For example, as
shown in FIG. 2,
24 plug 16 is provided with a plurality of shear pins 106. Shear pins 16
extend through radial
bores 108 near the upper end 96 of slip 66 and into an annular groove 110 in
the tapered
26 outer surface 78 of wedge 62 near its lower end 70. Preferably, as
shown, there is one
27 shear pin 106 provided for each slip segment 112. Shear pins 106 serve
as a frangible
28 retainer which prevents relative movement between wedge 62 and slip 66
as plug 16 is run
29 into a well, but allows movement when a predetermined actuating force is
applied across
shear pins 66. Shear pins 66 made be made of relatively soft metals, such as
brass or
23
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aluminum. It will be appreciated, however, that any number of frangible
connectors are
2 known in the art and may be used to releasably connect wedge 62 and slip
66.
3 FUG. 3 shows plug 16 after it has been set in liner 4. As will be
appreciated by
4 comparing FIG. 3 to FIG. 2, shear pins 106 have been sheared and wedge 62
has been
driven into sealing ring 64 and slip 66. Wedge 62 has traveled axially
downward to a point
6 where sealing ring 64 is now proximate to the upper end 68 of wedge 62.
As wedge 62
7 travels axially downward, the complementary tapers on outer surface 78 of
wedge 62 and
8 on ring bore 84 and inner surface 102 of slip 66 allow wedge 62 to ride
under sealing ring
9 64 and slip 66. As wedge 62 rides under sealing ring 64 and slip 66, it
forces them to
io expand radially from their nominal run-in outer diameters.
11 In accordance with a preferred aspect of the subject invention, body 82
of sealing
12 ring 64 is fabricated from a sufficiently ductile material to allow
sealing ring 64 to expand
13 radially into contact with liner 4 without breaking. As sealing ring 64
expands radially,
14 outer elastomeric seal 92 seals against liner 4 and inner elastomeric
seal 94 seals against
is outer surface 78 of wedge 62. Sealing ring 64 is thus able to provide a
seal between plug
16 16 and liner 4.
17 As slip 66 is expanded radially by wedge 62 at least some of the
frangible portions
18 114 between slip segments 112 break, allowing individual slip segments
112 to expand
19 further into contact with liner 4. Slip segments 112, therefore, are
able to anchor plug 16
zo within liner 4. Upper end 96 of slip 66 abuts the lower end of sealing
ring 64, thus also
zi providing hard backup for sealing ring 64 as it expands radially to seal
against liner 4.
22 Once plug 16 has been sealed and anchored in liner 4, a frac ball may be
flowed
23 into well 1 to restrict the flow of fluid through plug 16 and to
substantially isolate portions
24 of well 1 below plug 16. More specifically, as shown in FIG. 4, a frac
ball 76 may be
25 deployed onto seat 74. As best seen in FIGS. 3 and 5, ball seat 74
provides a beveled
26 shoulder upon which ball 76 will rest. Moreover, as seen in FIG. 3 and
4, when wedge 62
27 has been fully inserted into slip 66, ball seat 74 is situated axially
between the upper end
28 of sealing ring 64 and the lower end 98 of slip 66. More specifically,
ball seat 74 is situated
29 axially proximate to, and almost directly inward of sealing ring 64.
Thus, when hydraulic
3o pressure is applied to ball 76, a portion of the force transmitted from
ball 76 to wedge 62
31 will be directed radially outward through sealing ring 64. Moreover,
given the circular
24
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1 contact point between ball 76 and seat 74, that force will be directed
uniformly outward
2 through the circumference of seat 74. The force transmitted through ball
76 and seat 74
3 will help ensure that sealing ring 64 maintains an effective seal between
plug 16 and liner
4 4.
Other closure devices and arrangements, however, may be used in the novel
plugs.
6 For example, a standing valve may be used to restrict passage through the
wedge bore.
7 Non-spherical closure devices may be used as well, along with non-
circular seats and
8 wedge bores. Moreover, as used herein, the term "bore" is only used to
indicate that a
9 passage exists and does not imply that the passage necessarily was formed
by a boring
process or that the passage is axially aligned with the well bore or tool.
11 Similarly, outer surface 78 of wedge 62, bore 84 of sealing ring 64, and
bore 100
12 of slip 66 all have been described as having an inverted truncated
conical shape. It will be
13 appreciated, however, that the mating tapered surfaces of wedge 62,
sealing ring 64, and
14 slip 66 may have different geometries. Wedge 62, for example, may be
provided with a
is number of discrete, flat ramped surfaces arrayed circumferentially about
its outer surface
16 78. Such ramps may be visualized as bevels or as grooves on a conical
surface or, as the
17 sides of a tapered prism having a polygonal cross-section. Bore 84 of
sealing ring 64 and
18 bore 100 of slip 66 would be modified so that they mate with and
accommodate wedge 62
19 as it is driven downward. For example, the novel plug may be provided
with discrete slip
segments which ride up flat grooves or tracks provided in the wedge.
21 In general, the novel plugs may be fabricated from materials typically
used in plugs
22 of this type. Such materials may be relatively hard metals, especially
if removal of the
23 plugs is not necessary, but typically the materials will be relatively
soft, more easily drilled
24 materials. For example, wedge 62 and slip 66 may be fabricated from non-
metallic
materials commonly used in plugs, such as fiberglass and carbon fiber resinous
materials.
26 The components may be molded, but more typically will be machined from
wound fiber
27 resin blanks, such as a wound fiberglass cylinder. Alternately, suitable
wedges and slips
28 may be fabricated from softer or more brittle metals that are easier to
drill. For example,
29 slip 66 may be fabricated from surface hardened cast iron, especially
cast iron having a
surface hardness in the range of 50-60 Rockwell C. Such materials and methods
of
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1 fabricating wedge and slip components are well known in the art and may
be obtained
2 commercially from many sources.
3 As noted, the sealing ring in the novel plugs preferably are fabricated
from a
4 sufficiently ductile material so as to allow the ring to expand radially
into contact with a
liner without breaking. For example, ring body 82 may be fabricated from
aluminum,
6 bronze, brass, brass, copper, mild steel, or magnesium and magnesium
alloys. Alternately,
7 the ring body may be made of hard, elastomeric rubbers, such as butyl
rubber.
8 Preferably, however, the sealing ring is fabricated from a plastic
material. Plastic
9 components are more easily drilled and the resulting debris more easily
circulated out of a
well. Engineering plastics, that is, plastics having better thermal and
mechanical properties
ii than more commonly used plastics, are preferred. Engineering plastics
that may be suitable
12 for use include polycarbonates and Nylon 6, Nylon 66, and other
polyamides, including
13 fiber reinforced polyamides such as Reny polyamide. "Super" engineering
plastics, such
14 as polyether ether ketone (PEEK) and polyetherimides such as Ultem , are
especially
preferred. Mixtures and copolymers of such plastics also may be suitable.
Preferred
16 materials generally will have useful operating temperatures of at least
250 F, and
17 preferably at least 350 F, and a tensile strength of a least 5,000 psi,
preferably at least about
18 1,500 psi. Such preferred materials also generally will provide the ring
body with an
19 elongation factor of at least 10%, and preferably at least 30%.
As noted above, the sealing ring may be provided with elastomeric material
around
n its outer or inner surface. Such elastomeric materials include those
commonly employed
22 in downhole tools, such as butyl rubbers, hydrogenated nitrile butadiene
rubber (HNBR)
23 and other nitrile rubbers, and fluoropolymer elastomers such as Viton.
24 Overview of Preferred Tool String
The novel plugs typically will be run into a well as part of a tool string 10
which
26 includes a perf gun 11, setting tool 12, and adapter kit 14 as shown
schematically in FIG.
27 1A. Perf gun 11, as noted above, is used to perforate liner 4. Adapter
kit 14 releasably
28 connects and transmits setting force from setting tool 12 to plug 16.
Tool string 10 also
29 may incorporate additional tools to facilitate the fracturing operation
or to perform
additional operations. For example, sinker bars, centralizers, rope sockets,
pump down
31 fins, and collar locators may be incorporated into tool string 10.
26
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1 Tool
string 10, as described above, may be run into well on wireline 15. Wirelines
2 are
heavy cables that include electrical wires through which a tool, such as perf
gun 11 and
3
setting tool 12, may be actuated or otherwise controlled. Fluid will be pumped
into the
4 well
to carry the tools to the desired location in the liner. Other conventional
equipment,
however, such as coiled tubing or pipe, may be used to deploy the novel plugs
and tool
6 strings in a liner.
7 FIGS.
9-16 show setting tool 12, adapter kit 14, and plug 16 in greater detail
during
8
various stages of deploying and operating those tools, with FIGS. 9-12 showing
the tools
9
12/14/16 as they are run into a well. As may be seen therein, plug 16 is
coupled at its upper
end to adapter kit 14 which is connected to setting tool 12.
11 A
variety of setting tools and adapter kits may be used with the novel plugs.
For
12
example, setting tool 12 is a pyrotechnic "Baker Style" setting tool similar
to the E-4 series
13
pyrotechnic setting tools sold by Baker Hughes. It has combustible powder
charges which
14 are
electrically ignited through a wireline. Ignition of the charges generates
pressure that
is will
actuate the tool. Other pyrotechnic setting tools, however, may be used, such
as the
16
Compact wireline setting tools sold by Owen Oil Tools, the GO-style setting
tools available
17 from
The Wahl Company, and the Shorty series tools available from Halliburton.
18
Likewise, other types of setting tools may be used. For example,
electrohydraulic setting
19 tools,
such as Weatherford's DPST setting tool, may be used. Hydraulic setting tools,
such
zo as
Schlumberger's Model E setting tool, or ball activated hydraulic setting
tools, such as
zt
Weatherford's HST setting tool and American Completion Tools Fury 20 setting
tools, also
22 may be
used. If hydraulic setting tools are used, the tools will be run in a coiled
tubing or
23 a pipe string.
24
Details of the construction and operation of such setting tools are well known
in the
25 art
and will not be expounded upon. Suffice it to say, however, that setting tool
12 includes
26 an
inner part 18 and an outer part 20, as may be seen in FIGS. 9-10. When setting
tool 12
27 is
actuated, outer part 20 moves downward relative to inner part 18 transmitting
actuating
28 force through adapter kit 14 to plug 16.
29
Likewise, various adaptor kits may be used with the novel plugs, the specific
design
3o of
which will be tailored to a particular setting tool. Adapter kit 14, for
example, generally
31
includes a setting tool adapter 26, a top cap 24, an inner mandrel 22, a
collet or release
27
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sleeve 32, an adjusting sleeve 54, and an outer setting sleeve 52. Adapter 26,
top cap 24,
2 inner mandrel 22, and release sleeve 32 in general serve to releasably
connect plug 16 to
3 inner part 18 of setting tool 12. Adjusting sleeve 54 and outer setting
sleeve 52 serve
4 generally to transmit downward movement of setting tool outer part 20 to
plug 16.
As seen best in FUG. 11, inner mandrel 22 of adapter kit 14 has a generally
open
6 cylindrical shape. It is connected to the lower end of inner part 18 of
setting tool 12 by
7 setting tool adapter 26 and top cap 24. Release sleeve 32 is carried on
mandrel 22 and in
8 turn carries plug 16.
9 More particularly, mandrel 22 includes an upper cylindrical outer
surface 28 and a
to lower, enlarged diameter cylindrical outer surface 30. Release sleeve 32
has an upper
11 generally cylindrical portion defining an inner bore 34. Mandrel 22
extends through bore
12 34 of release sleeve 32, with release sleeve 32 being carried about the
upper portion of
13 outer surface 28 of mandrel 22. A plurality of collet arms 36 extend
downward from the
14 upper portion of release sleeve 32. Each collet arm 36 includes a collet
head 38. Collet
heads 38 have a radially inward extending protrusion 40 and a radially outward
extending
16 protrusion 42. Radially inward surface 44 on inward extending
protrusions 40 of collet
17 heads 38 slidably engage the lower, enlarged diameter outer surface 30
of mandrel 22. It
18 will be appreciated, therefore, that except at their heads 38, collet
arms 36 are
19 concentrically spaced radially outward of mandrel 22.
During operation of setting tool 12, mandrel 22 can slide freely within bore
34 of
21 release sleeve 32. Initially, however, mandrel 22 and release sleeve 32
are releasably
22 restricted from relative movement as they are run into well 1. As
described further below,
23 the releasable connection between mandrel 22 and release sleeve 34
prevents plug 16 from
24 being set prematurely as it is run into a well. It can be broken after
plug 16 is deployed,
however, to allow plug 16 to be installed and ultimately to allow setting tool
12 and adapter
26 kit 14 to be released and withdrawn from plug 16.
27 Thus, as shown in FIG. 12, upper outer surface 28 of mandrel 22 has an
annular
28 groove 46, and the upper portion of release sleeve 32 has a plurality of
radial bores 50.
29 Shear pins 48 extend through radial bores 50 and into groove 46, thus
collectively
providing what may be referred to as connector 48 and a frangible connection
between
31 mandrel 22 and release sleeve 32. Other frangible connections, however,
may be used with
28
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1 other
interfering geometries. For example, instead of groove 46 a series of detents,
2
spotfaces, or threaded, flat-bottomed, or through holes may be machined into
mandrel 22.
3 Outer
setting sleeve 52 of adapter kit 14 is a generally cylindrical sleeve which is
4
disposed about and radially spaced outward from mandrel 22. As seen in FIG.
11, outer
setting sleeve 52 is connected to the lower end of outer part 20 of setting
tool 12 via an
6
adjusting sleeve 54. It will be appreciated that in their run-in, unset state,
plug 16 is carried
7 on release sleeve 32 between collet heads 38 and outer setting sleeve 52.
8 More
particularly, as seen best in FIG. 12, outer setting sleeve 52 includes a
9
downward facing lower end or setting surface 56. Setting surface 56 is
substantially normal
or perpendicular to the longitudinal axis 60 of the tools such that it can
abut and bear on
ii the
upper end 68 of plug wedge 62. Outward protrusion 42 of collet heads 38 have
an
12
upwardly facing setting surface 58. Setting surfaces 58 are tapered downwardly
and
13
outwardly, thus mating with the upwardly and inwardly taper surface 124 at the
lower end
14 98 of plug slip 66.
It will be appreciated that the liner into which frac plugs are deployed may
not have
16 a
uniform diameter. There may be protrusions in the liner resulting from
accumulation of
17
debris, scale, and rust. The liner also may have manufacturing defects or
dents and other
18 damage
caused by well operations. Moreover, well fluids can contain solids and
debris.
19
Tolerances between the frac plug and the nominal inner diameter of the liner
can be
zo
relatively small, leaving only a small gap allowing for the downward travel of
the plug and
21 for
the flow of fluid between the plug and liner. Thus, frac plugs can be
susceptible to
22 getting stuck, damaged, or prematurely set as they are deployed into a
liner.
23
Accordingly, the novel plugs and tool strings preferably are provided with
gauge
24 points
or surfaces to facilitate deployment and to protect the tool as it is
deployed. Thus,
as may be seen in FIG. 12, which shows plug 16 in its unset, run-in position,
the outside
26
diameter of wedge 62 at its upper cylindrical outer surface portion 80 is
substantially equal
27 to an
outer diameter defined by outer surfaces 138 of collet heads 38. The outside
28
diameters of sealing ring 64 and slip 66 are less than the outside diameters
of wedge outer
29
surface portion 80 and collet head outer surface portions 138. Surfaces 80 and
138,
therefore, serve as gauge points supporting plug 16 against liner 4 and
minimizing contact
31
between sealing ring 64 and slip 66 and liner 4 as plug 16 is deployed through
liner 4.
29
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I Preferably, the tolerances are such that it provides sufficient clearance
for plug 16 to be
2 lowered past more typically encountered obstructions, protrusions, and
bends in liner 4
3 without catching or damage. Such protection is particularly important
when plug 16 is
4 deployed into horizontally oriented portions of liner 4.
The outer surfaces of setting sleeve 52 of adapter kit 14 and outer part 20 of
setting
6 tool 12 also preferably are treated with a friction reducing material
such as Teflon ,
7 Xylan , and other fluoropolymers or other similar materials. Such
materials can reduce
8 resistance to deployment of the tool string through a liner. Reducing
resistance is
9 particularly helpful when the tool string is being pumped into or through
a horizontal
ro portion of a liner on a wireline.
11 Moreover, if tool string 10 will be pumped down liner 4 on wireline 15,
and
12 especially if it will be pumped into a horizontal extension of liner 4,
plug 16 preferably is
13 provided with a pump down fin 144. As shown in FIG. 17, pump down fin
144 is attached
14 to the lower end of mandrel 22 by an annular nut 146 threaded into
threads 148 provided
inside mandrel 22. It will be appreciated that pump down fin is sized such
that it can
16 slidingly engage liner 4 and thus assist in pumping tool string 10 into
liner 4. Pump down
17 fin 144 also preferably is composed of a rubber or elastomeric material
and is somewhat
18 flexible so that, as described in detail below, it does not impede
release or withdrawal of
19 adapter kit 14 from plug 16.
FIG. 13 shows adapter kit 14 and plug 16 after setting tool 12 has been
actuated to
21 set plug 16 in liner 4. Specifically, it will be noted that outer part
20 of setting tool 12 and
22 setting sleeve 52 of adapter kit 14 have moved axially downward.
Downwardly facing
23 setting surface 56 of setting sleeve 52 and upwardly facing setting
surface 58 on collet
24 heads 38 are aligned, thus allowing plug 16 to be compressed
longitudinally therebetween.
More particularly, as described in detail above, wedge 62 has been driven into
sealing ring
26 62 and slip 66 to seal and anchor plug 16 in liner 4.
27 It will be appreciated that wedge 62 is described as being displaced
downward into
28 sealing ring 62 and slip 66 as plug 16 is set. During normal operation
of setting tool 12
29 wedge 62 will be driven downward in an absolute sense, that is, it will
move further down
liner 4 while sealing ring 62 and slip 66 remain in place relative to liner 4.
In other words,
31 wedge 62 will be driven into sealing ring 62 and slip 66, instead of
sealing ring 62 and slip
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66 being pushed up and over wedge 62. If any of the tools hang up in liner 4,
however,
2 that may not be strictly the case. Thus, "downward" movement of wedge 62
will be
3 understood as relative to sealing ring 62 and slip 66.
4 FIG. 14 shows an initial stage of releasing and withdrawing adapter kit
14 from set
plug 16. As noted above, mandrel 22 and release sleeve 32 of adapter kit 14
initially are
6 restricted from moving relative to each other by frangible connector 48.
Frangible
7 connector 48, however, is subjected to shear forces as plug 16 is set.
Specifically, a
8 downward force is applied by setting tool outer part 20t0 release sleeve
32 (through adapter
9 kit setting sleeve 52, plug 16, and collet heads 38) and an upward force
is applied by setting
tool inner part 18 to mandrel 22. After plug 16 is fully set, those shear
forces will increase
11 rapidly until they exceed a predetermined setting force. It will be
appreciated, of course,
12 that the number, size, and composition of shear pins 50 or other
frangible connectors may
13 be varied to provide the desired upper limit of setting force which can
be applied to plug
14 16.
At that point, frangible connector 48 will shear, eliminating any further
16 compressive force on plug 16. As will be appreciated by comparing FIG.
14 to FIG. 13,
17 shearing of frangible connection 48 also allows mandrel 22 (and setting
tool inner part 18)
18 to begin moving upward relative to release sleeve 32 (and setting tool
outer part 20).
19 Release sleeve 32 at this point is still held in position by plug 16 by
the engagement of
collet heads 38 with the lower end 98 of slip 66. It also will be noted that
pump down fin
21 144, if provided, will be deformed and will not impede travel of mandrel
22 upward
22 through release sleeve 32.
23 FIG. 15 shows an intermediate stage of releasing and withdrawing adapter
kit 14
24 from set plug 16. As seen therein, mandrel 22 has continued traveling
upward to a point
where it engages collet sleeve 32. In particular, the outer, upward facing
shoulder 140 on
26 the lower end of mandrel 22 now is bearing on an inner, downward facing
shoulder 142 on
27 the upper end of release sleeve 32.
28 FIG. 16 shows a later stage of releasing and withdrawing adapter kit 14
where
29 mandrel 22 has pulled release sleeve 32 upward and partially out of set
plug 16. That is,
3(-) once mandrel 22 engages release sleeve 32 it will pull release sleeve
32 up with it.
31 Downward facing tapered lower surface 124 on the lower end 98 of slip 66
and upward
31
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facing setting surface portions 58 of collet heads 38 have complementary
angles. Thus,
upward motion of release sleeve 32 will cause collet heads 38 to cam radially
inward.
Release sleeve 32 is thereby released from lateral engagement with slip 66 and
can travel
-I upward through inner bore 72 of wedge 62.
Thus, it will be noted that in FUG. 16 release sleeve 32 has traveled upward
and
6 partially through plug 16. Setting tool 12 then can be pulled further out
of liner 4 via setting
7 tool inner part 18 or wireline 15 such that adapter kit 14 and, in
particular, release sleeve
8 32 eventually is pulled completely out of plug 16. Plug 16 then will be
fully installed as
9 depicted in FIG. 3 and will be ready to receive frac ball 76 as depicted
in FIG. 4. It will
be noted that when adapter kit 14 has been removed from plug 16, inner bore 72
of wedge
ii 62 provides a relatively large conduit and is free of any structures
substantially restricting
12 the flow of production fluids up through plug 16.
13 Assembly of Preferred Tool String
14 Preparing setting tool 12, adapter kit 14, and plug 16 for deployment
into well 1 is
perhaps best visualized by reference to FIG. 11. First, setting tool adapter
26 is threaded
16 on to the lower end of inner part 18 of setting tool. The threaded
connection 132 may be
17 secured by one or more set screws (not shown).
18 Next, adjusting sleeve 54 is threaded to the lower end of the outer part
20 of setting
19 tool 12 and setting sleeve 52 is threaded onto adjusting sleeve 54. The
threaded connection
zo 130 between adjusting sleeve 54 and setting tool outer part 20 may be
secured by one or
21 more set screws (not shown). The threaded connection 134 between setting
sleeve 52 and
22 adjusting sleeve 54 is configured such that it may be completely overrun
by setting sleeve
23 52. When setting sleeve 52 overruns threaded connection 134 it is free
to slide upward
24 past adjusting sleeve 54.
Mandrel 22 of adapter kit 14 then is inserted upwards through release sleeve
32 and
26 top cap 24 is threaded on to the upper end of mandrel 22. Threaded
connection 126
27 between top cap 24 and mandrel 22 preferably is secured by one or more
set screws 128.
28 Shear pins 48 then are installed through bores 50 in release sleeve 32
and into groove 46
29 of mandrel 22 to frangibly connect release sleeve 32 to mandrel 22.
The subassembly of mandrel 22, release sleeve 32, and top cap 24 then is
inserted
31 upward through the bore of plug 16 such that setting surface portions 58
of collet heads 38
32
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I bear on mating lower surface 124 of slip 66. That subassembly, in turn,
is connected to
2 setting tool 12 by first sliding setting sleeve 52 upward and past
adjusting sleeve 54,
3 thereby allowing access to setting tool adaptor 26. Tension lock spring
150 then is inserted
4 around the upper end of top cap 24, and top cap 24 is threaded into
adapter 26. Threaded
connection 136 between top cap 24 and adapter 26 may be secured by one or more
set
6 screws (not shown). Tension lock spring 150 also helps to prevent
rotation between top
7 cap 24 and adapter 26. As shown in FIG. 18, lock spring 150 has upper and
lower end
g prongs 152 and 154 which engage radial recesses (not shown) in the lower
end of adapter
9 26 and in the upward facing shoulder of top cap 24.
to Finally, setting sleeve 52 is slid back down over adjusting sleeve 54
toward wedge
ii 62 of plug 16. Once it again engages threaded connection 134 with
adjusting sleeve 54,
12 setting sleeve 52 is rotated about threaded connection 134 to move it
downward until its
13 lower end 56 engages the upper end 68 of wedge 62. Setting sleeve 12,
adapter kit 14, and
14 plug 16 are now ready for deployment.
Overview of Second Preferred Plug
16 A second preferred embodiment 216 of the novel plugs is illustrated in
FIGS. 19-
17 33. Second preferred plugs 216 may be used to perform "plug and perf'
fracturing
18 operations in substantially the same manner as described above for first
preferred plugs 16
19 and schematic FIGS. 1. Plug 216 may be connected to setting tool 12 via
an adapter kit
zo 214. Those tools then will be deployed into well 1 along with perf gun
11 via wireline 15.
21 Setting tool 12 will be actuated to install plug 216 in liner 4 and to
release adapter kit 214
22 from plug 216. Perf gun then will be actuated to perforate liner 4,
after which perf gun 11,
23 setting tool 12, and adapter kit 214 will be pulled out of well 1 by
wireline 15. Fluid will
24 be pumped into liner 4 to establish fractures 9 adjacent the
perforations. The plugging and
perfing will be repeated until fractures 9 have been established in formation
6 along the
26 length of liner 4.
27 As seen best in FIGS. 19-20 and 23, which show plug 216 in its run-in
state, plug
28 216 generally comprises an annular wedge 262, a sealing ring 264, an
annular slip 266, a
29 setting ring 270, and a gauge ring 280. Annular wedge 262 is shown in
isolation in FIG.
21. As seen therein, wedge 262 is similar in respects to wedge 62 of plug 16.
Wedge 262
31 also may be described in general terms as having an annular or open
cylindrical shape. The
33
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upper portion of wedge 262 is generally tapered, but in contrast to wedge 62,
the lower
2 portion of wedge 262 comprises a plurality of collet fingers 268.
3 Collet fingers 268 are integrally formed with wedge 262 and extend
axially
4 downward from the lower end of the wedge upper portion. Collet fingers
268 are spaced
circumferentially around annular wedge 262 and terminate in collet heads 275.
As will be
6 appreciated from the discussion that follows, collet fingers 268 provide
support for slip 266
7 as it is assembled and a base for connecting gage ring 280.
8 Wedge 262 also has an axial passage or bore 263 extending through its
upper
9 portion. An inner ball seat 291 is defined in wedge bore 263, bore 263
otherwise having a
io substantially uniform diameter.
11 The upper portion of wedge 262 has an outer, generally truncated
inverted conical
12 surface 267. That is, outer conical surface 267 tapers downwardly and
inwardly, and the
13 diameter of its upper end is greater than the diameter of its lower end.
The upper end of
14 wedge 262 may have, as does wedge 62 of plug 16, a substantially
cylindrical outer surface
if desired. That is, conical surface 267 does not necessarily extend all the
way to the upper
16 end of wedge 262. Preferably, however, it extends along the
substantially majority of the
17 upper portion of wedge 262.
18 As best appreciated from FIGS. 19-20, sealing ring 264 of plug 216 is
quite similar
19 to sealing ring 64 in plug 16. Sealing ring 264 has a relatively short,
annular body 288
defining an axial passage or bore. The ring bore has a generally inverted
truncated conical
21 shape, that is, it tapers radially outward from its lower end to its
upper end. The inner taper
22 of the bore of sealing ring 264 is complementary to the taper provided
on outer conical
23 surface 267 of wedge 262. Sealing ring 264 preferably is provided with
one or more
24 elastomeric seals which ultimately will enhance the seal between plug
216 and liner 4 when
plug 216 is set. Thus, ring body 288 is provided with one or more outer
elastomeric seals
26 284 in corresponding grooves on the outer surface of ring body 288. One
or more inner
27 elastomeric seals 286 are provided in corresponding grooves in the ring
bore. Other seal
28 configurations may be used, however, or the seals may be eliminated
depending on the
29 design of the sealing ring and the materials from which it is
fabricated.
Slip 266 of plug 216, like slip 66 of plug 16, is designed to grip and engage
liner 4.
31 Slip 66, however, is a breakaway slip designed to break apart into
several segments. In
34
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1 contrast, slip 266 of plug 216 is an assembly of discrete, separate slip
segments. More
2 specifically, slip 266 has six individual slip segments 266a to 266f.
Individual slip
3 segments 266a-f may be visualized as a lateral segment of an open
cylinder. When plug
4 216 is in its run-in condition, as best appreciated from FIGS. 20 and 22,
segments 266a-f
are aligned along, and arranged angularly about the tool axis. Preferably,
slip segments
6 266a-f are closely adjacent or abut each other. Thus, slip segments 266a-
f collectively
7 define an open cylindrical slip 266 having an axial inner passage or bore
274.
8 Bore
274 of slip 266 has a generally truncated inverted conical surface. That is,
9 slip bore 274 tapers radially inward from top to bottom, and the diameter
of slip bore 274
at its upper end is greater than the diameter at its lower end. Preferably the
taper in slip
ii bore 274 is complementary to the taper on outer conical surface 267 of
the upper portion
12 of wedge 262.
13 The
outer surface of slip 266 is generally cylindrical. Preferably, it is provided
with
14 features to assist slip 266 in engaging and gripping liner 4 when plug
216 is set. Thus, for
is example, slip 266 may be provided with high-strength or hardened
particles, grit or inserts,
16 such as buttons 265 embedded in its outer surface. Buttons 265 may be,
for example, a
17 ceramic material containing aluminum, such as a fused alumina or
sintered bauxite, or
18 zirconia, such as CeramaZirc available from Precision Ceramics. Buttons
also may be
19 fabricated from heat treated steel or cast iron, fused or sintered high-
strength materials, or
a carbide such as tungsten carbide. The precise number and arrangement of
buttons 265 or
21 other such members may be varied. The outer surface of slip 266 also may
be provided
22 with teeth or serrations in addition to or in lieu of buttons or other
gripping features.
23 In
general terms, plug 216 will be set in liner 4 in the same manner as is plug
16.
24 Annular wedge 262 will be driven into sealing ring 264 and annular slip
266. As wedge
262 is driven downward, it will force sealing ring 264 and slip 266 to expand
and seal and
26 anchor 216 in liner 4. The operation of plug 216 may be understood in
greater detail by
27 comparing FIGS. 19-20 and 23 with FIG. 24. FIGS. 19-20 and 23 show plug
216 in its
28 run-in condition. FIG. 24 shows plug 216 after it has been set in liner
4 and frac ball 76
29 has seated in plug 216 to isolate lower portions of liner 4.
As shown in FIGS. 19-20 and 23, when plug 216 is assembled for running into a
31 well, slip 266 is disposed generally around collet fingers 268 of wedge
262 with the upper
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1 end of slip 266 extending over the lower portion of outer conical surface
267 of wedge 262.
2 Outer conical surface 267 of wedge 262 thus is received in and engages
conical bore 274
3 of slip 266.
4 Sealing ring 265 is carried on outer conical surface 267 of wedge 262
near its lower
end such that it abuts the upper end of slip 266. Slip segments 266a-f
preferably are secured
6 at their upper ends. Thus, for example, the lower end of sealing ring 264
is provided with
7 an annular projection or lip 289. Slip segments 266a-f have a
complementary lip 273 on
8 their upper ends. Sealing ring lip 289 and slip lip 273 engage each
other, thus securing the
9 upper end of slip 266.
Collet fingers 268 extend downward through slip bore 274 and terminate beyond
it the lower end of slip 266. Setting ring 270 is carried slidably around
that lower portion of
12 collet fingers 268. More particularly, the upper end of setting ring 270
abuts the lower end
13 of slip 266 and the lower end of setting ring 270 abuts heads 275 of
collet fingers 268 and
14 an upward facing shoulder on gauge ring 280.
Setting ring 270 is shown in isolation in FIGS. 25-26. As shown therein,
setting
16 ring 270 has a generally annular body 277 having a plurality of keys
271. Keys 271 are
17 arranged circumferentially on the inner surface or bore of setting ring
body 277 and
18 protrude radially inward. Setting ring 270 is slidably carried around
the lower portion of
19 collet fingers 268 such that keys 271 on setting ring 270 extend inward
into slots 269
between collet fingers 268.
21 As shown in FIGS. 19-20 and 23, gauge ring 280 may be viewed as a bottom
cap
22 for plug 216. It is attached to the lower end of collet fingers 268 and
extends generally
23 around setting ring 270 and the lower end of slip 266. More
particularly, and referring to
24 those figures and to FIGS. 27-28 which show gauge ring 280 in isolation,
it will be
appreciated that the lower portion of gauge ring 280 is generally enlarged and
fits around
26 and below heads 275 of collet fingers 268. Gauge ring 280 may be
connected to heads 275
27 of collet fingers 268, for example, by fasteners 285 shown in FIG. 20.
Fasteners 285 may
28 be screws, bolts, or pins inserted through radial holes 283 in the lower
portion of gauge
29 ring 280 (see FIG. 27) into radial holes 276 provide in collet heads 275
(see FIG. 21).
Gauge ring 280 also has a relatively thin upper perimeter wall or skirt 282
extending
31 upwardly from its lower portion. Skirt 282 extends upwardly beyond
setting ring 270 and
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terminates just beyond the lower end of slip 266. Gauge ring 280 and, in
particular, skirt
2 282 is thus able to hold the lower portions of slip segments 266a-f
together in a close
annular arrangement.
4 Gauge ring 280 also helps protect the lower end of plug 216 as it is
deployed into
a well. Skirt 266 of gauge ring 280 extends around the lower portions of slip
segments
6 266a-f, thus helping to protect them from catching on debris,
protrusions, and the like that
7 might cause them to deploy prematurely. It also will be noted that the
outer diameter of
8 gauge ring 280 is greater than the outer diameter of the setting ring
270, slips 266, sealing
9 ring 264, and the upper portion of wedge 266. More particularly, the
outer diameter of
to gauge ring 280, relative to the inner walls of liner 4, is such that it
presents a leading edge
it sufficient to prevent plug 216 from being lowered into constrictions in
liner 4 that are too
12 narrow to allow passage of plug 216. Preferably, the tolerances are such
that it provides
13 sufficient clearance for plug 216 to be lowered past more typically
encountered
14 obstructions, protrusions, and bends in liner 4 without catching or
damage.
Plug 216 may be deployed and installed in much the same manner as plug 16. As
16 shown in FIGS. 29-30, plug 216 is coupled at its upper end to setting
tool 12 and adapter
17 kit 214. Setting tool 12, as noted above, includes inner part 18 and
outer part 20. When
18 actuated, outer part 20 moves downward relative to inner part 18 and
transmits force
19 through adapter kit 214 to plug 216.
Adapter kit 214 generally includes setting tool adapter 26, a top cap 224, an
21 actuating mandrel 222, adjusting sleeve 54, outer setting sleeve 52, and
a sleeve adapter
22 210. Adapter 26, top cap 224, and actuating mandrel 222 in general serve
to releasably
23 connect plug 216 to inner part 18 of setting tool 12. Adjusting sleeve
54, outer setting
24 sleeve 52, and sleeve adapter 210 serve generally to transmit downward
movement of
setting tool outer part 20 to plug 216.
26 Actuating mandrel 222 of adapter kit 214 has a generally open
cylindrical shape.
27 As shown in FIG. 29, it is connected to the lower end of setting tool
inner part 18 by setting
28 tool adapter 26 and top cap 224. Mandrel 222 is releasably connected at
its lower end to
29 plug 216. As described further below, that releasable connection allows
plug 216 to be set
3o and ultimately allows setting tool 12 and adapter kit 214 to be released
and withdrawn from
31 plug 216.
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1 More
particularly, when plug 216 is run into a well mandrel 222 is releasably
2
connected to setting ring 270 of plug 216 by a plurality of frangible
fasteners 278.
3
Frangible shear screws 278 extend through threaded radial holes 272 (see FIGS.
25-26) in
4 keys
271 of setting ring 270 and into recesses such as grooves 290 (see FIG. 31) at
the
lower end of mandrel 222. Shear screws 278 will be designed to break at a
desired shear
6 force
and thereby release mandrel 222 from plug 216 after it has been installed in
liner 4.
7 Other
frangible connectors, such as pins, may be used for such purposes. Similarly,
instead
8 of
grooves 290, mandrel 222 may be provided with a series of detents, spotfaces,
or holes.
9 As
noted above, outer setting sleeve 52 of adapter kit 214 is connected at its
upper
to end to
the lower end of outer part 20 of setting tool 12 via adjusting sleeve 54. The
lower
ii end of
outer setting sleeve 52 abuts and is connected to sleeve adapter 210. For
example,
12 the
upper end of sleeve adapter 210 may be threaded into the lower end of outer
setting
13 sleeve
52. Set screws or the like (not shown) may extend through radial holes 240 in
the
14 lower
end of outer setting sleeve 52 and into holes, a groove, or other outer recess
211 in
is sleeve adapter 210 (see FIG. 33).
16 Sleeve
adapter 210 is slidably carried about the lower, enlarged end of top cap 224.
17 When
plug 216 is in its run-in state, however, sleeve adapter 210 and top cap 224
are
18
releasably restricted from relative movement. Thus, for example, frangible
screws, pins,
19 or
other suitable connectors 242 may extend through radial holes 212 in the lower
end of
zo sleeve
adapter 210 and into a groove 213 or other detents, spotfaces, or holes
machined
zi into
the outer surface of top cap 224 (see FIG. 32). As described further below,
the
22
releasable connection between sleeve adapter 210 and top cap 224 prevents plug
216 from
23 being
set prematurely as it is run into a well, but it can be broken after plug 216
is deployed
24 to allow plug 216 to be installed.
25 Once
coupled to adapter kit 214 and setting tool 12, plug 216 may be deployed and
26
installed in a well. Though there are differences in the operation, plug 216
will be installed
27 in
liner 4 generally in the same manner as is plug 16. Annular wedge 262 will be
driven
28 into
sealing ring 264 and annular slip 266 to force sealing ring 264 and slip 266
to expand
29 and set and seal plug 216 in liner 4 as shown in FIG. 24.
30 More
particularly, once plug 216 is deployed to the desired location in liner 4,
31
setting tool 12 will be actuated. Once a predetermined force is generated
within setting
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1 tool 12, the frangible connection between sleeve adapter 210 and top cap
224 of adapter
2 kit 214 will be broken. Setting tool outer part 20, adjusting sleeve 54,
outer setting sleeve
3 52, and sleeve adapter 210 then are able to move downward relative to
setting tool inner
4 part 18, setting tool adapter 26, top cap 224, and mandrel 222.
Sleeve adapter 210 bears down on the upper end of wedge 262 which, as noted
6 above, carries sealing ring 264 and extends through slip 266 and setting
ring 270. Sealing
7 ring 264 abuts the upper end of slip 266, and setting ring 270 abuts the
lower end of slip
8 266. Setting ring 270 is held in position by mandrel 222, to which it is
connected by
9 frangible fasteners 278. Collet fingers 268 of wedge 262, however, are
able to slide freely
io within the bore of setting ring 270. That will allow plug 216 to be
installed, in essence, by
11 compressing wedge 262, sealing ring 264, and slip 266 together between
sleeve adapter
12 210 and setting ring 270.
13 More
particularly, wedge 262 will be driven downward into sealing ring 264 and
14 slip 266. As wedge 262 travels axially downward, the complementary
conical surfaces on
the upper portion of wedge 262 and in the bore of sealing ring 265 and bore
274 of slip 266
16 allow wedge 262 to ride under sealing ring 264 and slip 266. As wedge
262 rides under
17 sealing ring 264 and slip 266, it forces them to expand radially.
18 In
accordance with a preferred aspect of the subject invention, body 288 of
sealing
19 ring 264 is fabricated from a sufficiently ductile material to allow
sealing ring 264 to
zo expand radially into contact with liner 4 without breaking. As sealing
ring 264 expands
zi radially, outer elastomeric seal 284 seals against liner 4 and the inner
elastomeric seal 286
22 seals against the outer conical surface 267 of wedge 262. Sealing ring
264 is thus able to
23 provide a seal between plug 216 and liner 4.
24 As
slip 266 is expanded radially by wedge 262, slip segments 266a-f will be
forced
radially outward and eventually into contact with liner 4. Thus jammed between
outer
26 conical surface 267 of wedge 262 and liner 4, they are able to anchor
plug 216 within liner
27 4. Upper end of slip 266 abuts the lower end of sealing ring 264, thus
also providing hard
28 backup for sealing ring 264 as it expands radially to seal against liner
4.
29 As
noted above, mandrel 222 is releasably connected to setting ring 270 by
3o frangible fasteners 278. When wedge 262 has been fully driven into
sealing ring 264 and
31 slip 266, a downward facing, beveled shoulder at the lower end of upper
portion of wedge
39
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262 will engage setting ring 270. Sealing ring 264 and slip 266 also will have
been
2 expanded into engagement with liner 4. At that point the shear forces
across frangible
3 fasteners 278 will increase rapidly. When those forces exceed a
predetermine limit,
4 frangible fasteners 278 will shear, relieving any further compressive
force on plug 216.
Shearing of fasteners 278 also releases mandrel 222 from setting ring 270.
Inner part 18
6 of setting tool 12 will continue its stroke, pulling mandrel 222 upward.
Preferably, the
7 stoke of setting tool 12 will be such that mandrel 222 is withdrawn to a
point where its
8 lower end is within the enlarge diameter portion of wedge bore 263 above
ball seat 291.
9 Adapter kit 214 and setting tool 12 then can be pulled out of plug 216
and liner 4 via
wireline 15.
11 FIG. 24 shows plug 216 after it has been installed in liner 4 and frac
ball 76 has
12 been deployed. Frac ball 76 has landed on seat 291 in bore 263 of wedge
262. Seat 291
13 has a beveled surface which allows ball 76 to substantially restrict or
preferably to shut off
14 fluid flow through plug 216, thereby substantially isolating portions of
well 1 below plug
216. Preferably, when plug 216 is installed, seat 291 will be located at a
level between the
16 upper and lower ends of slip 266.
17 For example, as appreciated from FIG. 24, seat 291 is situated within
bore 263 of
18 wedge 262 such that when wedge 262 has been driven fully downward it is
disposed below
19 the mid-point of slip 266 and well below sealing ring 264. Thus, when
fluid is pumped
zo into liner 4 hydraulic pressure will build not only against frac ball
76, but also within a
21 substantial portion of wedge bore 263. The hydraulic pressure within
wedge bore 263 will
22 bear radially outward through wedge 262, thereby enhancing the seal
between sealing ring
23 264 and liner 4 as well as the engagement of slip 266 with liner 4. The
shallow bevel on
24 ball seat 291 also allows ball 76 to transmit a substantial portion of
the hydraulic pressure
applied to it radially outward through wedge 262 to slip segments 266a4,
further enhancing
26 the anchoring of plug 216 in liner 4.
27 As described above with respect to plug 16, various modifications may be
made to
28 illustrative plug 216. Other closure devices and arrangements may be
provided. Standing
29 valves and non-spherical closure devices may be used. Wedge 264 may have
a break-away
configuration, or it may be configured to provide discrete ramped surfaces.
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1 Plug
216 also may be fabricated from materials typically used in plugs of this
type,
2 and
preferably will be softer, more easily drilled materials. Wedge 262 and slip
266, for
3
example, preferably are machined from wound fiber resin blanks, such as a
wound
4
fiberglass cylinder. Body 288 of sealing ring 264 also preferably is
fabricated from a
ductile material, especially ductile plastics as described above for sealing
ring 64.
6 Plug
216 can be assembled from its component parts and prepared for deployment
7 into
liner 4 as follows. First, setting tool adapter 26 is threaded on to the lower
end of inner
8 part
18 of setting tool, adjusting sleeve 54 is threaded to the lower end of the
outer part 20
9 of
setting tool 12, and setting sleeve 52 is threaded onto adjusting sleeve 54,
all as described
io above
in relation to plug 16. Next, sleeve adapter 210 may be threaded into the
lower end
ii of outer setting sleeve 52.
12 Plug
216 then may be assembled in an upside-down fashion. Specifically, annular
13 wedge
262 may be inverted with collet fingers 268 pointing up. Sealing ring 264,
with
14 ring
lip 289 facing up, then is passed over collet heads 275 and slid down onto
outer surface
267 of wedge 262. With sealing ring 264 resting on wedge 262, slip segments
266a-f then
16 may be
loaded (upside down) around wedge 262 such that lip 273 of each segment 266a-f
17
engages lip 289 of sealing ring 264. Setting ring 270 then is passed (upside
down) over
18 collet
heads 275 and slid down wedge 262 with ring keys 271 traveling through slots
269
19
between collet fingers 268 until it abuts slip segments 266a-f. Gauge ring 280
then can be
zo
connected to heads 275 of collet fingers 268, for example, by fasteners 285.
Skirt 282 of
zt gauge
ring 280 will extend around and past setting ring 270 such that it is able to
hold slip
22
segments 266a-f in their annular arrangement. Plug 216 now is ready for
attachment to
23 adapter kit 214 and, thereby, to setting tool 12.
24 First,
mandrel 222 is releasably connected to plug 216. Specifically, top cap 224 is
threaded onto mandrel 222 as described above for plug 16. The threaded
connection
26
preferably is secured, e.g., by set screws 228 or the like as may be inserted
through radial
27 holes
229 in top cap 224 and into groove 230 on mandrel 222. Mandrel 222 then is
inserted
28 into
bore 263 of wedge 262 such that grooves 290 at the lower end of mandrel 222
are
29
aligned with radial holes 272 in keys 271 of setting ring 270. Frangible shear
screws 278
then are screwed into setting ring holes 272 and into mandrel grooves 290. It
will be noted
31 that
gauge ring 280 is provided with openings 281 seen best in FIG. 27. Openings
281
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1 allow sighting and alignment of setting ring holes 272 and mandrel
grooves 290 and
2 insertion of shear screws 278.
3 Setting sleeve 52 and sleeve adapter 224 then can be raised to allow
access to setting
4 tool adapter 26. Top cap 224 now can be threaded into setting tool
adapter 26 as described
above in relative to plug 16. Finally, setting sleeve 52 and sleeve adapter
224 are slid
6 downward until the lower end of sleeve adapter 224 abuts the upper end of
wedge 262.
7 Sleeve adapter 210 then is releasably connected to top cap 224 by
frangible connectors 240
8 extending through radial holes 212 in the lower end of sleeve adapter
210. Setting tool 12,
9 adapter kit 224, and plug 216 now are ready for deployment into a well.
It will be appreciated from the foregoing description of preferred plugs 16
and 216
ii that the novel plugs share certain general features with prior art plug
designs, but in general
12 incorporate fewer parts. They rely on three primary components, a wedge,
a sealing ring,
13 and a slip, and design features which allow those three components to
perform the essential
14 functions of sealing and anchoring the plug. They do not rely on a
central support
component, such as a support mandrel, to support the wedge, sealing element,
and slips as
16 do conventional plugs, either during setting of the plug or after it has
been installed.
17 Instead, as described further below, the wedge in the novel plugs is
self-supporting, and
18 the wedge provides the support for the sealing ring and slip. No special
backup rings, as
19 are common in conventional plugs, are required to protect the sealing
ring against
zo extrusion. The slips in the novel plugs provide a dual function of
anchoring the plug and
zt providing a hard backup for the sealing ring. Thus, in general, they may
be more easily
22 and economically fabricated and assembled.
23 Moreover, primarily because they do not incorporate a support mandrel,
the novel
24 plugs may have a relatively large central bore. The central bore also is
free of any structure
which might substantially restrict flow of production fluids up through the
plug. Thus, the
26 novel plugs may allow an operator to use dissolvable frac balls. After
the balls dissolve,
27 the well may be produced without the considerable time and expense of
drilling out the
28 plugs. The novel plugs also may facilitate unexpected remedial
operations which must be
29 performed through the plug before it is removed.
For a given liner size, the central bore in the wedge and slip of the novel
plugs will
31 be larger than the central passageway in the support mandrel of
conventional designs.
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I Thus, by essentially eliminating the support mandrel, the novel plugs
provide a central
2 passageway for fluids which is relatively larger. For example,
conventional plugs for
3 installation in a 5.5" liner typically will have a central passageway
through the support
4 mandrel of approximately 1" in diameter. In contrast, the novel plugs may
have an internal
diameter of approximately 3".
6 The large central bore relative to the length of the wedge and the
overall length of
7 the plug is particularly important when the wedge and slip are fabricated
from drillable
8 composites such as wound fiberglass. Wound fiberglass has fibrous cords
which are
9 wound around a cylindrical core and impregnated with resin. Manufacturers
have
io developed various winding patterns designed to minimize this, but such
materials are
ii particularly susceptible to axial shear stress. They may be visualized
as having a spiral
12 shear plane running axially through the part, with the inner portions of
the spiral being the
13 weakest. Thus, when pressure is applied behind a seated ball, shear
forces will be
14 transmitted axially into the part through the seat. Excessive pressure
can "blow" the ball
is through the part, essentially shearing away internal layers of the bore.
16 In conventional designs, the ball seat is provided in a relatively
smaller bore of a
17 support mandrel. The shear forces, therefore, will be applied through a
smaller
18 circumference where the support mandrel is more susceptible to shearing.
In order to
19 compensate for the relative weakness of the support mandrel, the support
mandrel typically
20 will be relatively elongated. The proportionally greater length provides
the requisite
21 resistance to shearing.
22 In contrast, the shallow bevel on ball seat 74/291 in plug 16/216 allows
shortening
23 of the parts. That is, the shallow bevel on ball seat 74/291 allows ball
76 to transmit a
24 substantial portion of the hydraulic pressure applied to it radially
outward. That not only
25 enhances sealing and anchoring of plug 16/216, as discussed above, but
it also means that
26 a smaller vector component of the force applied to ball 76 is
transmitted axially to wedge
27 62/262. Those parts may be made shorter as the amount of shear stress
which they must
28 resist is reduced. Accordingly, the novel plugs will have ball seats
wherein the bevel is
29 from about 100 to about 30 , preferably about 150 off center.
30 It will be appreciated that it is possible for the novel plugs to
eliminate the support
31 mandrel typically incorporated into conventional plugs primarily because
of the taper
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1 applied to the wedge and slip and the location of the ball seat within
the wedge. For
2 example, the taper angle on wedges 62/262 and slips 66/266 in plugs
16/216 is relatively
3 shallow. Preferably, the taper on the wedges and slips of the novel plugs
is such that the
4 wedges and slips are self-locking as opposed to self-releasing. With hard
materials, such
as steel, the upper limit for self-locking tapers is about 70. With softer,
more elastic
6 materials, such as the preferred composite materials, steeper taper
angles still will be self-
7 locking. Accordingly, when fabricated from preferred composite materials
the taper on the
8 wedges and slips typically will be from about 10 to about 100, preferably
about 40 off
9 center. Conventional plugs typically incorporate wedges and slips where
the mating taper
is relatively steep, usually self-releasing. Thus, a relatively thick, strong
support mandrel
it is required to back up the wedge and slip to ensure that they do not
separate and, thereby,
12 compromise the seal or anchor of the plug.
13 Locating the ball seat within the bore and below the upper end of the
wedge also
14 helps minimize the need for support otherwise provided by a support
mandrel. For
example, and regarding preferred plug 216, ball seat 291 is situated within
bore 263 of
16 wedge 262 well below the upper end of wedge 262. When wedge 262 is set,
ball seat 291
17 is located below the axial midpoint of slip 266. Hydraulic pressure
behind a seated ball
18 76, therefore, will build within and bear radially outward through wedge
bore 72 providing
19 support for wedge 262 which in turn will enhance the support provided by
wedge 262 to
both sealing ring 264 and slip 266.
21 Shorter plugs are more easily deployed into liners, especially deviated
liners, and
22 other factors being equal, may be drilled more quickly. Eliminating the
support mandrel
23 also helps to shorten the overall length of the novel plugs. The support
mandrel typically
24 is the longest component in conventional plugs. Conventional plugs also
typically require
a pair of wedges and slips in order to maintain the radial expansion of the
elastomeric
26 sealing element against the liner wall. In contrast, the novel plugs
preferably incorporate
27 a single wedge and slip. Moreover, the sealing ring, carried as it is on
the wedge, adds no
28 length to the novel plugs.
29 Though perhaps not as readily apparent, seating a ball within the wedge
also can
help shorten the length of the novel plugs. For example, the upper end of
wedge 262 and
31 the lower end of gage ring 280 may be provided with mating geometries,
such as
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1 castellations 292 on wedge 262 and castellations 293 on gauge ring 280.
Castellations
2 292/293 help minimize "spinning" and speed up drill out of a series of
plugs 216. That is,
3 if the remains of an upper plug 216 start to spin as material is drilled
away, the bit will push
4 the upper plug 216 down until the castellations 293 on the remnants of
uphole plug 216
engage the castellations 292 on a still set, downhole plug 216. The remnants
of plug 216
6 will stop spinning and may be drilled away.
7 The provision of castellations, bevels, or other mating geometries at
the ends of
8 plugs is well known. Many conventional plugs, however, locate the ball
seat at the top of
9 the support mandrel. A seated ball, therefore, actually serves as a
bearing surface to
ro encourage spinning of a plug remnant pushed down onto the ball. Other
plugs may provide
11 a ball seat within the support mandrel bore, but typically it is located
above the level of the
12 wedge. That placement essentially means that the support mandrel has
been lengthened to
13 allow mating geometric features to extend above the ball. In contrast,
by locating ball seat
14 291 of plug 216 well inside wedge bore 263, mating geometries may be
provided on wedge
262 with minimal or essentially no lengthening of wedge 262.
16 Indeed, it will be appreciated that the novel plugs may be drilled more
easily and
17 will produce less material than conventional frac plugs offering
comparable performance,
18 even conventional composite plugs. All of the components may be made of
easily drillable
19 composite materials or, in the case of the sealing ring, from plastics.
As noted, the support
mandrel is eliminated, eliminating what often is the single largest component
in
21 conventional composite plugs. The overall reduced dimensions of the
novel plugs mean
22 there is less material present in the plug. Especially when a large
number of plugs must be
23 drilled out, other factors being equal less material can mean much
faster drilling times with
24 far less debris which must be circulated out of the well.
For example, consider the Obsidian frac plugs available from Halliburton and
the
26 Diamondback frac plugs available from Schlumberger. Those are all
composite frac plugs
27 like preferred embodiments of the subject invention. It will be
appreciated that plug 216
28 sized for a 5.5" liner has only about 20% of the volume of material as
in comparably sized
29 Obsidian and Diamondback plugs.
Preferred embodiments of the sealing ring in the novel plugs also can
facilitate
31 drilling in two other ways. As compared to sealing elements in
conventional plugs, sealing
CA 03016153 2018-08-29
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1 rings
64/264 in plugs 16/216 are much smaller and will produce less debris when
drilled
2 out.
Sealing rings 64/264 are relatively small even when composed of more easily
drilled
3 plastic material instead of soft metals.
4
Sealing elements in conventional plugs, as well as plastic sealing rings
64/264 in
novel plugs 16/216, are subject to extrusion if not when the plug is set, then
when the plug
6 is
later exposed to hydraulic pressure during fracturing operations. That is,
hydraulic
7
pressure will bear down on the seal. That pressure can open up channels in the
seal or even
8 push
the seal material out from around the plug. Thus, conventional plugs
incorporate
9
various backup rings which are designed to back up the sealing element and
minimize
ro extrusion.
11
Typically, backup rings are made of relatively thin, somewhat flimsy metal
which
12 still
allows what is viewed as a manageable amount of extrusion. Manageable
extrusion,
13 in
turn, necessarily means the sealing element must be somewhat larger and
comprise more
14
material. Having ring-like shapes, conventional backup rings also become
entangled
is around
a bit. Many such rings might be "gathered" by the bit as it works its way
through
16 multiple plugs.
17
Sealing rings 64/264 of novel plugs 16/216, however, even when made of
plastic,
18
comprise less ductile and, therefore, less extrudable material. Moreover,
sealing rings
19 64/264
are provided with hard backup from slips 66/266. For example, when plug 216 is
zo in its
run-in condition, segments 266a-f are closely adjacent and preferably abut
each other.
21
Collectively, slip segments 266a-f define an open cylinder the upper end of
which abuts
22 the
lower end of sealing ring 264. Segments 266a-f, therefore, provides continuous
support
23 for
sealing ring 264 as wedge 262 starts to expand sealing ring 264 radially
outward. Even
24 when
completely set, from a cross-sectional perspective, slip segments 266a-f have
25
separated only a relatively short distance. Thus, slip segments 266a-f can
provide near
26
continuous, hard backup for sealing ring 264 and, thereby, minimize the
likelihood of
27
significant extrusion of sealing ring 264 during fracturing operations.
Importantly, they do
28 so
without incorporating metallic backup rings which later can complicate
drilling of plugs.
29 It
also has been observed that due to the contact between the lower end of
sealing
30 ring
264 and the upper end of slip segments 266a-f, segments 266a-f expand radially
more
31
uniformly as wedge 262 is driven into segments 266a-f. It also will be
appreciated that the
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1 inner and outer radii of slip segments 266a-f preferably are matched,
respectively, with the
2 outer radii of the upper portion of wedge 262 and the inner diameter of
liner 4.
3 Consequently, there is more uniformly distributed contact between slip
segments 266a-f
4 and the inner wall of line 4. In particular, the contact between buttons
265 will be more
uniformly distributed around plug 216, and the degree of contact between each
button 265
6 will be more uniform from button 265 to button 265.
7 Though described to a certain extent, it will be appreciated that novel
plugs 16 and
8 216, along with setting tool 12 and adapter kits 14 and 214, along with
other embodiments
9 thereof, may incorporate additional shear screws and the like to
immobilize components
during assembly, shipping, or run-in of the plug. Additional set screws and
the like may
ii be provided to prevent unintentional disassembly. Other sealing elements
may be provided
12 between components, and various ports accommodating fluid flow around
and through the
13 assembly also may be provided. Such features are shown to a certain
degree in the figures,
14 but their design and use in tools such as the novel plugs is well known
and well within the
skill of workers in the art. In many respects, therefore, discussion of such
features is
16 omitted from this description of preferred embodiments.
17 Plugs 16 and 216 and other embodiments have been described as installed
in a liner
18 and, more specifically, a production liner used to fracture a well in
various zones along the
19 well bore. A "liner," however, can have a fairly specific meaning within
the industry, as
zo do "casing" and "tubing." In its narrow sense, a "casing" is generally
considered to be a
zt relatively large tubular conduit, usually greater than 4.5" in diameter,
that extends into a
22 well from the surface. A "liner" is generally considered to be a
relatively large tubular
23 conduit that does not extend from the surface of the well, and instead
is supported within
24 an existing casing or another liner. It is, in essence, a "casing" that
does not extend from
the surface. "Tubing" refers to a smaller tubular conduit, usually less than
4.5" in diameter.
26 The novel plugs, however, are not limited in their application to liners
as that term may be
27 understood in its narrow sense. They may be used to advantage in liners,
casings, tubing,
28 and other tubular conduits or "tubulars" as are commonly employed in oil
and gas wells.
29 Likewise, while the exemplified plugs are particularly useful in
fracturing a
formation and have been exemplified in that context, they may be used
advantageously in
31 other processes for stimulating production from a well. For example, an
aqueous acid such
47
CA 03016153 2018-08-29
WO 2017/151384 PCT/US2017/019117
1 as hydrochloric acid may be injected into a formation to clean up the
formation and
2 ultimately increase the flow of hydrocarbons into a well. In other cases,
"stimulation"
3 wells may be drilled near a "production" well. Water or other fluids then
would be injected
4 into the formation through the stimulation wells to drive hydrocarbons
toward the
production well. The novel plugs may be used in all such stimulation processes
where it
6 may be desirable to create and control fluid flow in defined zones
through a well bore.
7 Though fracturing a well bore is a common and important stimulation
process, the novel
8 plugs are not limited thereto.
9 The novel plugs also may incorporate additional closure devices. For
example, a
to standing valve may be used to restrict passage through the wedge bore.
Standing valves
11 may be useful if it is necessary to pressure test a liner.
12 It also will be appreciated that the description references frac balls.
Spherical balls
13 are preferred, as they generally will be transported though tubulars and
into engagement
14 with downhole components with greater reliability. Other conventional
plugs, darts, and
the like which do not have a spherical shape, however, also may be used to
occlude the
16 wedge bore in the novel plugs. The configuration of the "ball" seats
necessarily would be
17 coordinated with the geometry of such devices. "Balls" as used herein,
therefore, will be
18 understood to include any of the various conventional closure devices
that are commonly
19 pumped down a well to occlude plugs, even if such devices are not
spherical. "Ball" seats
zo is used in a similar manner. Moreover, as used herein, the term "bore"
is only used to
21 indicate that a passage exists and does not imply that the passage
necessarily was formed
22 by a boring process or that the passage is axially aligned with the well
bore or tool.
23 While this invention has been disclosed and discussed primarily in terms
of specific
24 embodiments thereof, it is not intended to be limited thereto. Other
modifications and
embodiments will be apparent to the worker in the art.
26
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