U.S. patent application number 15/288150 was filed with the patent office on 2017-10-19 for downhole tool for removing a casing portion.
The applicant listed for this patent is SMITH INTERNATIONAL, INC.. Invention is credited to Timothy M. O'Rourke, Jonathan Park.
Application Number | 20170298704 15/288150 |
Document ID | / |
Family ID | 51486410 |
Filed Date | 2017-10-19 |
United States Patent
Application |
20170298704 |
Kind Code |
A9 |
O'Rourke; Timothy M. ; et
al. |
October 19, 2017 |
DOWNHOLE TOOL FOR REMOVING A CASING PORTION
Abstract
A packoff device is disclosed for sealing an annulus within a
wellbore, and for bypassing the sealed annulus. The packoff device
may include a mandrel having a bore formed axially therethrough and
first and second ports extending radially from the bore. A sealing
element that extends radially-outwardly from the mandrel may be
positioned axially between the first and second ports, and may
create a seal within an annulus between the mandrel and a casing,
to isolate a portion of the annulus above the sealing element from
a portion below the sealing element. A sleeve within the bore may,
with the mandrel, form a channel providing fluid communication
between the first and second ports. The sleeve may be movable
between open and closed states. The first and second ports may be
unobstructed by the sleeve in the open state, one or more may be
obstructed in the closed state.
Inventors: |
O'Rourke; Timothy M.;
(Austin, TX) ; Park; Jonathan; (Ness, GB) |
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Applicant: |
Name |
City |
State |
Country |
Type |
SMITH INTERNATIONAL, INC. |
Houston |
TX |
US |
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|
Prior
Publication: |
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Document Identifier |
Publication Date |
|
US 20170022773 A1 |
January 26, 2017 |
|
|
Family ID: |
51486410 |
Appl. No.: |
15/288150 |
Filed: |
October 7, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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14195542 |
Mar 3, 2014 |
9464496 |
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15288150 |
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61773031 |
Mar 5, 2013 |
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61820023 |
May 6, 2013 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/1208 20130101;
E21B 29/005 20130101; E21B 33/16 20130101; E21B 31/20 20130101;
E21B 33/126 20130101; E21B 2200/06 20200501; E21B 33/146
20130101 |
International
Class: |
E21B 29/00 20060101
E21B029/00; E21B 33/12 20060101 E21B033/12; E21B 43/12 20060101
E21B043/12; E21B 31/20 20060101 E21B031/20 |
Claims
1. A packoff device, comprising: a mandrel having an axial bore and
one or more ports extending radially from the axial bore to an
exterior surface of the mandrel; a sealing element extending
radially-outward from the mandrel; and a sleeve configured to
selectively move relative to the mandrel to open and close the one
or more ports, the sleeve being movable between at least: a first
configuration in which flow from an annulus around the mandrel and
below the sealing element is permitted to flow axially upwardly
through the sealing element into an annulus around the mandrel and
above the sealing element; and a second configuration in which flow
from the annulus around the mandrel and below the sealing element
is blocked from flowing axially upwardly through the sealing
element and into the annulus around the mandrel and above the
sealing element.
2. The packoff device of claim 1, the packoff device comprising one
or more swab cups having downward facing lips.
3. The packoff device of claim 1, the sealing element having a
fixed outer diameter.
4. The packoff device of claim 1, the sleeve being positioned
inside the mandrel.
5. The packoff device of claim 1, further comprising a biasing
element biasing the sleeve toward the first or second
configuration.
6. The packoff device of claim 5, the biasing element biasing the
sleeve toward the first configuration.
7. The packoff device of claim 1, further comprising a seat within
the bore, the seat configured to receive an impediment to cause
fluid pressure to build behind the impediment and thereby move the
sleeve between the first and second configurations.
8. The packoff device of claim 7, the sleeve being configured to
move with the seat.
9. The packoff device of claim 1, further comprising one or more
seals coupled to the sleeve, the one or more seals configured to
restrict fluid flow through the sealing element when the sleeve is
in the second configuration, and not to restrict fluid flow through
the sealing element when the sleeve is in the first position.
10. The packoff device of claim 1, the one or more seals blocking
radial flow through at least some of the one or more ports when the
sleeve is in the second position.
11. A downhole tool, comprising: a packoff device having a body
defining an axial bore and a sealing element coupled to the body
and configured to seal against an interior surface of wellbore
casing, the packoff device configured to selectively move between:
a closed configuration in which the sealing element maintains a
seal with the wellbore casing in an annulus between the body and
the wellbore casing, and in which fluid flow is permitted
downwardly through the bore but is blocked upwardly from a portion
of the annulus below the sealing element to a portion of the
annulus above the sealing element; and an open configuration in
which the sealing element maintains the seal with the wellbore
casing and fluid is permitted to flow downwardly through the bore
and upwardly from the portion of the below the sealing element to
the portion of the annulus above the sealing element; an engagement
device coupled to the packoff device and configured to restrict
axial movement of the downhole tool relative to the wellbore
casing; and a casing cutter coupled to, and axially below, the
packoff device and the engagement device.
12. The downhole tool of claim 11, wherein when the packoff device
is in the open configuration, the packoff device enables fluid flow
from the portion of the annulus below the sealing element, axially
through one or more flow channels radially within the sealing
element, and into the portion of the annulus above the sealing
element.
13. The downhole tool of claim 12, wherein when the packoff device
is in the closed configuration, the packoff device blocks fluid
from entering the one or more flow channels for axial flow
therein.
14. The downhole tool of claim 11, further comprising a circulation
sub configured to selectively allow fluid flow from an interior of
the downhole tool into the annulus.
15. A method for circulating fluid in a wellbore, comprising:
running a downhole tool into a casing, the downhole tool including
a packoff device and a casing cutter, the packoff device including
a sealing element having a diameter about equal to an inner
diameter of the casing while running the downhole tool into the
casing; flowing fluid through an interior of the packoff device,
into a first annulus between the downhole tool and the casing, and
from a portion of the first annulus below the sealing element, into
an interior of the sealing element, and out of the packoff device
to a portion of the first annulus above the sealing element; using
the casing cutter to form an opening in the casing; after forming
the opening in the casing, blocking fluid flow from the portion of
the first annulus below the sealing element from flowing through
the interior of the sealing element and into the portion of the
first annulus above the sealing element; and while blocking the
fluid flow, flowing fluid from the portion of the first annulus
below the sealing element through the opening in the casing, into a
second annulus around the casing, and upwardly within the second
annulus toward a surface of the wellbore.
16. The method of claim 15, the downhole tool further including an
engagement device and the method further comprising: activating the
engagement device and thereby engaging the downhole tool with the
casing and restricting relative movement between the downhole tool
and the casing.
17. The method of claim 16, wherein engaging the downhole tool with
the casing includes engaging a portion of the casing above the
opening in the casing.
18. The method of claim 17, further comprising pulling the portion
of the casing above the opening at least partially out of the
wellbore.
19. The method of claim 15, wherein the sealing element is
malleable and maintains the seal against the interior surface of
wellbore casing while running the downhole tool into the
casing.
20. The method of claim 15, wherein blocking fluid flow includes
moving a sleeve and one or more seals coupled to the sleeve to
restrict fluid flow from entering one or more axial flow channels
within the sealing element.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. patent
application Ser. No. 14/195,542, filed on Mar. 3, 2014, which
claims the benefit of, and priority to, U.S. Patent Application No.
61/775,031, filed on Mar. 5, 2013 and to U.S. Patent Application
No. 61/820,023 filed on May 6, 2013, each of which is expressly
incorporated herein by this reference in its entirety.
BACKGROUND
[0002] After a wellbore ceases to produce, or the production is no
longer profitable, the wellbore may become abandoned. To abandon
the wellbore, a plug (e.g., a cement plug) is placed in the casing
to block uphole and downhole fluid flow through the wellbore. A
rotating casing cutter that is coupled to a first downhole tool is
then used to make a cut above the cement plug and separate the
casing into a first or upper portion and a second or lower
portion.
[0003] An annulus formed between the casing and the wellbore wall,
or between the casing and another, outer casing, may be filled with
fluids. For instance, water, hydrocarbon liquids and/or gases, or
other fluids, may be within the annulus and should be removed prior
to abandonment of the wellbore. After the casing has been cut, a
second downhole tool is run into the wellbore to circulate or flush
these fluids out of the wellbore.
SUMMARY
[0004] Some embodiments of the present disclosure relate to a
downhole tool for removing a portion of casing from a wellbore. An
illustrative downhole tool may include a packoff device for sealing
an annulus between the downhole tool and a casing of a wellbore. A
spear may be coupled to the packoff device and configured to engage
the casing to restrict relative movement between the downhole tool
and the casing. A circulating sub coupled to the spear may have a
port therein. The port may extend in an at least partial radial
direction and be in fluid communication with the annulus. A casing
cutter may be coupled to the circulating sub and configured to cut
the casing.
[0005] A method for removing a casing from a wellbore is also
disclosed, and in one or more embodiments includes running a
downhole tool into a first casing. The downhole tool may include a
packoff device, a spear, a circulating sub, and a casing cutter.
The spear may be engaged with the first casing to restrict relative
movement therebetween, and the first casing may be cut using the
casing cutter. Cutting the first casing may include forming an
opening in the casing, and defining upper and lower portions of the
casing. An annulus between the downhole tool and the first casing
may be sealed using the packoff device, which is optionally
positioned above the spear, the circulating sub, and the casing
cutter relative to the surface of the wellbore. Drilling fluid may
be flowed through a port in the circulating sub and into the first
annulus. At least some of the drilling fluid may flow from the
first annulus, through the opening formed between the upper and
lower portions of the first casing, and into a second annulus
formed between the first casing and a second casing. The upper
portion of the first casing may be pulled out of the wellbore after
flowing drilling fluid into the second annulus.
[0006] In one or more additional embodiments, a method for removing
casing from a wellbore may include running a downhole tool into a
first casing. The downhole tool may include a packoff device, a
spear, a circulating sub, and a casing cutter. The spear may be
used to restrict relative movement between the downhole tool and
the first casing, and thereafter the casing cutter may be used to
form an opening in the first casing. The opening may define a
separation between upper and lower portions of the first casing. A
port in the circulating sub may be opened. The port may provide a
path of fluid communication between an axial bore in the downhole
tool and a first annulus between the downhole tool and the first
casing. Optionally, the circulating sub may be positioned between
the spear and the casing cutter. After the port is opened, the
spear may be disengaged from the casing and the downhole tool may
be moved relative to the first casing. The first annulus may be
sealed with the packoff device, with the seal be positioned
potentially above the spear. Drilling fluid may be flowed through
the port in the circulating sub and into the first annulus. Such
flow may occur when the packoff device seals the first annulus,
with at least a portion of the drilling fluid flowing from the
first annulus, through the opening formed between the upper and
lower portions of the first casing, and into a second annulus
formed between the first casing and a second casing. The spear may
be activated to restrict relative movement between the downhole
tool and the upper portion of the first casing after flow of
drilling fluid into the second annulus, and the upper portion of
the first casing may be pulled out of the wellbore.
[0007] According to some embodiments of the present disclosure, a
packoff device may include a mandrel having an axial bore and first
and second ports extending radially from the axial bore. A sealing
element may extend radially outwardly from the mandrel and may be
positioned axially between the first and second ports. A sleeve may
be positioned fully or partially within the axial bore and define,
with the mandrel, a channel providing a path of fluid communication
between the first and second ports. The sleeve may be movable
between open and closed states. In the open state, the first and
second ports may be unobstructed by the sleeve, while in the closed
state the first and/or second port may be unobstructed by the
sleeve.
[0008] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] So that the recited features may be understood in detail, a
more particular description, briefly summarized above, may be had
by reference to one or more embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings are illustrative embodiments, and are,
therefore, not to be considered limiting of its scope.
[0010] FIG. 1 schematically illustrates a side view of a downhole
tool in a wellbore, the downhole tool being in a run-in position
prior to cutting a wellbore casing, according to one or more
embodiments of the present disclosure.
[0011] FIG. 2 schematically illustrates a side view of a downhole
tool that includes a spear engaging the wellbore casing, according
to one or more embodiments of the present disclosure.
[0012] FIG. 3 schematically illustrates a side view of a downhole
tool that includes a casing cutter for cutting the wellbore casing,
according to one or more embodiments of the present disclosure.
[0013] FIG. 4 schematically illustrates a side view of a downhole
tool within a wellbore, and after the wellbore casing is cut by a
casing cutter, according to one or more embodiments of the present
disclosure.
[0014] FIG. 5 schematically illustrates a side view of a downhole
tool used to flow drilling fluid flowing through a port in a
circulating sub and into an annulus between the wellbore casing and
the downhole tool, according to one or more embodiments of the
present disclosure.
[0015] FIG. 6 schematically illustrates a side view of a downhole
tool being lowered into a wellbore to position one or more packoff
devices within the wellbore casing, according to one or more
embodiments of the present disclosure.
[0016] FIG. 7 schematically illustrates a side view of a downhole
tool used to flow drilling fluid through a port in the circulating
sub and into an annulus between wellbore casing and a formation or
outer casing, according to one or more embodiments of the present
disclosure.
[0017] FIG. 8 schematically illustrates a downhole tool that
includes a spear engaging an upper portion of wellbore casing for
pulling the upper portion of the wellbore casing out of the
wellbore, according to one or more embodiments of the present
disclosure.
[0018] FIG. 9 schematically illustrates a side view of a downhole
tool positioned within the casing of a wellbore, according to one
or more embodiments of the present disclosure.
[0019] FIG. 10 schematically illustrates a side view of the
downhole tool of FIG. 9 with a spear engaging the casing and
restricting relative movement between the downhole tool and the
casing, according to one or more embodiments of the present
disclosure.
[0020] FIG. 11 schematically illustrates a side view of the
downhole tool of FIG. 9, with a casing cutter cutting the casing,
according to one or more embodiments of the present disclosure.
[0021] FIG. 12 schematically illustrates a side view the downhole
tool of FIG. 9, with drilling fluid flowing through a port in a
circulating sub and into an annulus of the wellbore, according to
one or more embodiments of the present disclosure.
[0022] FIG. 13 depicts a cross-sectional view of a first packoff
device usable in the downhole tool of FIG. 9, the first packoff
device being in an open state, according to one or more embodiments
of the present disclosure.
[0023] FIG. 14 depicts a cross-sectional view of a first packoff
device of FIG. 13 when in a closed state, according to one or more
embodiments of the present disclosure.
[0024] FIG. 15 depicts a cross-sectional view of another
illustrative first packoff device usable in the downhole tool of
FIG. 9, the first packoff device being in an open state, according
to one or more embodiments of the present disclosure.
[0025] FIG. 16 depicts a cross-sectional view of a first packoff
device of FIG. 15 when in a closed state, according to one or more
embodiments of the present disclosure.
[0026] FIG. 17 schematically illustrates a side view of the
downhole tool of FIG. 9, with drilling fluid flowing through the
port in the circulating sub and into a second annulus of the
wellbore, according to one or more embodiments of the present
disclosure.
[0027] FIG. 18 schematically illustrates a side view of the
downhole tool of FIG. 9 when pulling the upper portion of the first
casing out of the wellbore, according to one or more embodiments of
the present disclosure.
DETAILED DESCRIPTION
[0028] Some embodiments described herein generally relate to
downhole tools. More particularly, some embodiments of the present
disclosure relate to downhole tools for removing a casing from a
wellbore after the wellbore has been abandoned. More particularly
still, some embodiments of the present disclosure relate to
methods, systems, assemblies, and downhole tools for removing a
casing from a wellbore and circulating fluids out of the wellbore
in a single downhole trip.
[0029] FIG. 1 depicts a schematic side view of a downhole tool 100
within a wellbore 102 according to one or more embodiments of the
present disclosure. As shown in FIG. 1, the downhole tool 100 may
include various components. For instance, the downhole tool 100 may
include a casing cutter 104 and/or a spear 106 in some embodiments.
Other illustrative components of the downhole tool 100 may include
a circulating sub 108, a motor 110, and a packoff assembly 111. In
some embodiments, the packoff assembly 111 may include one or more
packoff devices (two are shown as packoff devices 112, 114). A
tubular component such as drill pipe or a work string 116 may
connect to the downhole tool 100 to facilitate use of the downhole
tool 100, including insertion of the downhole tool 100 into the
wellbore 102 and removal of the downhole tool 100 from the wellbore
102. The downhole tool 100 may also include other components in
other embodiments. For instance, some embodiments contemplate a
downhole tool 100 that includes one or more bumper subs, jars,
jetted subs, drill bits, mill bits, drill collars, string magnets,
ball catching subs, cross overs, bit subs, or other components, or
any combination of the foregoing.
[0030] In accordance with at least some embodiments, the wellbore
102 may be a cased wellbore having one or more casings (three are
shown as casings 118, 120, 122) installed therein. In the
particular, the casings 118, 120, 122 may extend from a wellhead
124 downward into the wellbore 102. As shown, a first or inner
casing 118 may be disposed at least partially within a second or
intermediate casing 120. The second casing 120 may be disposed at
least partially within a third or outer casing 122. The diameter or
width of each casing 118, 120, 122 may change, and in FIG. 1 the
first casing 118 may have a smaller diameter that the second casing
120, which may in turn have a smaller diameter than the third
casing 122. In accordance with at least some embodiments, a plug
126, which may be a cement plug, a bridge plug, or some other type
of plug, may be disposed within the first casing 118 and positioned
a distance below the downhole tool 100 prior to the downhole tool
100 being lowered into the wellbore 102. In other embodiments, the
downhole tool 100 may be or include a cementing tool or the like
and may be used to set the plug 126. In some embodiments, the plug
126 may restrict and potentially prevent fluid flow in both axial
directions (i.e., uphole and downhole directions) through the first
casing 118.
[0031] The downhole tool 100 may be in a run-in position when
inserted into the wellbore 102. The run-in position may correspond
to a retracted or other position of the casing cutter 104, which
may be a position of the casing cutter 104 prior to cutting the
first casing 118. In the run-in position, the spear 106 may also be
in a retracted or other similar position, which may be a position
in which the spear 106 is not engaged with the first casing
118.
[0032] Any number of packoff devices 112, 114 may be used in
accordance with various embodiments of the present disclosure. The
packoff devices 112, 114 may be configured to form a seal between
the downhole tool 100 and the casing 118 to restrict, and
potentially prevent, fluid flow in at least one direction through
an annulus 128 formed between the downhole tool 100 and the
interior surface of the casing 118. In one embodiment, the packoff
devices 112, 114 may be configured or otherwise designed to
restrict or even prevent fluid flow in one direction (e.g., an
upward or uphole direction) through the annulus 128. In another
embodiment, the packoff devices 112, 114 may be configured or
otherwise designed to restrict or even prevent fluid flow in both
axial directions (e.g., upward/uphole and downward/downhole)
through the annulus 128. The packoff devices 112, 114 may withstand
fluid pressure as desirable for a wellbore operation. For instance,
the packoff devices 112, 114 may withstand pressures up to about 5
MPa (725 psi), about 10 MPa (1,450 psi), about 25 MPa (3,635 psi),
about 50 MPa (7,250 psi), about 75 MPa (10,875 psi), about 100 MPa
(14,500 psi), about 125 MPa (18,125 psi), about 150 MPa (21,750
psi), or even more.
[0033] In at least some embodiments, the packoff device 112, 114
may include or be coupled to a body or mandrel 130 and/or a
malleable sealing element 132. In some embodiments, the malleable
sealing element 132 may take the form of sealing lips. The mandrel
130 may be substantially cylindrical in some embodiments, and may
have a cavity or bore 134 formed axially therethrough. The mandrel
130 may be made of any suitable materials, including one or more
metals or metal alloys (e.g., steel, titanium, etc.), composite
materials, organic materials, polymeric materials, or the like. In
some embodiments, the sealing element 132 may be disposed proximate
the top portion of the mandrel 130 and/or radially-outward from the
mandrel 130. The sealing element 132 may face upwardly toward the
surface or downwardly toward the spear 106 and/or the casing cutter
104. The sealing element 132 may be made of any material capable of
sealing the annulus 128, and in some embodiments may include one or
more polymers, elastomers, rubber materials, or the like. For
example, the sealing element 132 may be made of silicone, nitrile
butadiene rubber, hydrogenated nitrile butadiene rubber, other
materials, or some combination of the foregoing. When the cavity or
bore 134 is pressurized, the pressure may cause a force to be
exerted on the sealing element 132 that causes the sealing element
132 to form a seal with the casing 118 (see FIG. 7). The packoff
devices 112, 114 may be or include swab cups or the like, such as
those manufactured and sold by Rubberatkins Ltd. based in Aberdeen,
United Kingdom.
[0034] The outer diameter of the packoff devices 112, 114 may be
different for a number of different applications or systems, may in
some embodiments be based on the size of the first casing 100, 118.
For instance, the outer diameter of the packoff devices 112, 114
may range from a low of about 5 cm (2 in.), about 10 cm (3.9 in.),
about 15 cm (5.9 in.), about 20 cm (7.9 in.), about 25 cm (9.8
in.), or about 30 cm (11.8 in.) to a high of about 40 cm (15.7
in.), about 50 cm (19.7 in.), about 60 cm (23.6 in.), about 70 cm
(27.6 in.), about 80 cm (31.5 in.), 156 cm (47.2 in.), 150 cm (59.1
in.), or more. For example, the outer diameter of the packoff
devices 112, 114 and/or the inner diameter of the first casing 118
may be between about 5 cm (2 in.) and about 15 cm (5.9 in.),
between about 10 cm (3.9 in.) and about 20 cm (7.9 in.), between
about 15 cm (5.9 in.) and about 30 cm (11.8 in.), between about 20
cm (7.9 in.) and about 40 cm (15.7 in.), between about 30 cm (11.8
in.) and about 50 cm (19.7 in.), between about 40 cm (15.7 in.) and
about 70 cm (27.6 in.), or greater than 70 cm (27.6 in.). In at
least one embodiment, the outer diameter of the packoff devices
112, 114 may vary along the axial length thereof. For instance, a
first axial end portion of each packoff device 112, 114 (e.g., a
downhole end portion) may have a greater outer diameter than a
second axial end portion of the packoff device 112, 114 (e.g., an
uphole end portion).
[0035] In accordance with at least some embodiments of the present
disclosure, a cup stabilizer 136 may be coupled to the packoff
devices 112, 114 or the work string 116. As shown in FIG. 1, the
cup stabilizer 136 may be positioned below or downhole relative to
the packoff devices 112, 114. The cup stabilizer 136 may be used to
maintain the alignment of the downhole tool 100 within the casing
118 (e.g., when the cup stabilizer 136 is disposed within the
casing 118 as shown in FIG. 7). In addition, the cup stabilizer 136
may reduce the vibration experienced by the downhole tool 100 and
help guide the packoff devices 112, 114 through the wellhead 124
and/or the first casing 118. The cup stabilizer 136 may be sized,
shaped, or otherwise configured to minimize lateral movement of the
packoff devices 112, 114 and to allow flow circulation within the
annulus 128.
[0036] The spear 106 of some embodiments of the present disclosure
may be included within the downhole tool 100 and may be coupled to
the work string 116 and positioned below the cup stabilizer 136
and/or the packoff devices 112, 114. For example, the spear 106 may
be coupled to the cup stabilizer 136 and/or the packoff devices
112, 114 via one or more segments of the drill pipe or work string
116. A distance between the packoff devices 112, 114 and the spear
106 may, in some embodiments, be between about 0.25 m (0.8 ft.) and
about 1 m (3.3 ft.), between about 1 m (3.3 ft.) and about 2 m (6.6
ft.), between about 2 m (6.6 ft.) and about 5 m (16.4 ft.), between
about 5 m (16.4 ft.) and about 10 m (32.8 ft.), between about 10 m
(32.8 ft.) and about 20 m (65.6 ft.), between about 20 m (65.6 ft.)
and about 50 m (165 ft.), between about 50 m (165 ft.) and about
150 m (490 ft.), or greater than 150 m (490 ft.). The spear 106 may
include one or more arms 138 or other latching devices (see FIG. 2)
configured or otherwise designed to expand radially-outward to
engage the casing 118. Once engaged, the spear 106 may
substantially lock the downhole tool 100 at a particular axial
position within the first casing 118 by restricting or even
preventing axial movement between the downhole tool 100 and the
first casing 118.
[0037] The circulating sub 108 may be coupled to spear 106 and/or
the work string 116, and in some embodiments may be positioned
below the spear 106. The circulating sub 108 may be substantially
cylindrical with a bore formed axially through at least a portion
thereof, and potentially through the entire circulating sub 108.
The circulating sub 108 may have one or more ports 140 (see FIG. 5)
formed at least partially radially therethrough, and which may
provide a path of fluid communication between the bore of the
circulating sub 108 and the annulus 128. For example, the
circulating sub 108 may have a plurality of ports 140 that are
circumferentially-offset from one another, and which may be at the
same or different axial positions within the circulating sub 108.
The circulating sub 108 may be configured or otherwise designed to
actuate from an inactive state to an active state. When the
circulating sub 108 is in the inactive state, the ports 140 may be
blocked such that fluid may not flow therethrough and into the
annulus 128. When the circulating sub 108 is in the active state,
the ports 140 may be unobstructed, and fluid may flow therethrough
and into the annulus 128.
[0038] The circulating sub 108 may have a seat 143 (see FIG. 4)
disposed therein that is configured or otherwise designed to
receive an impediment 152 such as a ball, dart, or the like (see
FIG. 5). When the impediment 152 is received in the seat 143, a
pump (not shown) may cause drilling fluid to flow down the work
string 116 and into the downhole tool 100. In some embodiments, the
pump may be disposed on or proximate to a drilling rig at the
surface. As used herein, the term "drilling fluid" includes any
drilling fluid known in the art, such as air, an air/water mixture,
an air/polymer mixture (e.g., a foaming agent), water, water-based
mud or "gel" (e.g., bentonite), oil-based mud, synthetic-based
fluid, other fluid, or any combination of the foregoing.
[0039] The engagement between the impediment and the seat 143 may
restrict or even prevent the drilling fluid from flowing axially
through the circulating sub 108. As the pump continues to operate,
the pressure of the drilling fluid within the circulating sub 108
may increase, which can actuate the circulating sub 108 from the
inactive state to the active state. Such activation result from
bursting a burst disk or other flow restriction element, shearing a
shear screw, responding to an increased pressure, or in other
manners. Actuating the circulating sub 108 may be used for a
variety of different purposes. For instance, actuating the
circulating sub 108 to transition to the active state may be used
to open the one or more ports 140 (see FIG. 5), expand the spear
108, etc. In some embodiments, multiple impediments may be used to
perform different actions and/or multiple circulating subs 108,
activation subs, or the like may be used.
[0040] A motor 110 may be coupled to the circulating sub 108 and/or
work string 116 in some embodiments. As shown in FIG. 1, the motor
134 may be positioned below the circulating sub 108. In accordance
with some embodiments, the motor 110 may be a positive displacement
motor or a "mud motor," although in other embodiments an electrical
motor, magnetic drive, or other motor may be used. In the case of a
mud motor, when drilling fluid is pumped downward through the
downhole tool 100, the motor 110 can convert energy from the
flowing drilling fluid to rotational mechanical energy. In some
embodiments, the rotational mechanical energy may be used to rotate
the casing cutter 104 about a longitudinal axis extending
therethrough.
[0041] A pipe cutter (e.g., the casing cutter 104) may be coupled
to the work string 116, the motor 110, the circulating sub 108, or
some combination of the foregoing. As shown in FIG. 1, the casing
cutter 104 may in some embodiments be positioned below the motor
110 and/or the circulating sub 108. The casing cutter 104 may
include one or more blades 142 (see FIG. 3) arranged
circumferentially and/or axially along the body of the casing
cutter 104. For instance, the casing cutter 104 may include a
multi-cycle casing cutter with axially offset blades 142, and which
may be cycled to independently expand some blades 142 while others
remain retracted. As shown in FIG. 3, for instance, the distal-most
set of blades 142 may be expanded while one or more other more
proximal or uphole sets of blades 142 remain retracted.
[0042] The blades 142 may be configured or otherwise designed to
actuate from an inactive state (FIG. 1) to an active state (FIG. 3)
when the drilling fluid is being pumped downwardly through the
downhole tool 100. When the casing cutter 104 actuates from the
inactive state to the active state, the blades 142 may expand
radially-outwardly to engage the first casing 118.
[0043] An example manner in which the downhole tool 100 may be used
within the wellbore 102 is illustrated in, and described in greater
detail with reference to, FIGS. 1-8. As shown in FIG. 1, the
downhole tool 100 may be lowered through a riser 144 and into the
wellbore 102. A blow-out preventer ("BOP") 146 may be disposed
proximate the lower end portion of the riser 144, and the wellhead
124 may be disposed below the blow-out preventer 146. In FIG. 1,
the downhole tool 100 is shown in an inactive or run-in state in
which the casing cutter 104 and/or spear 106 may be in retracted
positions.
[0044] FIG. 2 schematically illustrates an example side view of the
downhole tool 100, and particularly illustrates an example
embodiment in which the spear 106 may be activated to engage the
first casing 118. By engaging the first casing 118, the spear 106
may restrict or even prevent relative movement between the downhole
tool 100 and the first casing 118, according to one or more
embodiments. The downhole tool 100 may be run into the wellbore 102
until the spear 106 and the casing cutter 104 are both disposed
within the first casing 118; however, the packoff devices 112, 114
may remain outside of the wellbore 102 and/or the first casing 118.
Rather, the packoff devices 112, 114 may be positioned in the riser
144 above the first casing 118. Once the downhole tool 100 is at
the desired depth, the downhole tool 100 may be lifted and rotated
(e.g., clockwise or counterclockwise), which may cause the arms 138
of the spear 106 to expand radially-outwardly to engage the first
casing 118. The engagement may restrict and substantially prevent
axial movement between the downhole tool 100 and the first casing
118.
[0045] FIG. 3 schematically illustrates a side view of the downhole
tool 100 within the wellbore 102 when the casing cutter 104 of the
downhole tool 100 is activated to cut the first casing 118. In this
particular embodiment, the blades 142 of the casing cutter 104 may
be expanded radially outwardly and rotated to cut the first casing
118 into upper and lower portions 148, 150, according to one or
more embodiments. Once the downhole tool 100 is secured to the
first casing 118 via the spear 106, the pump (not shown) may cause
the drilling fluid to flow down through the drill pipe or work
string 116 and into the downhole tool 100, as shown by the arrow A
in FIG. 3. As the drilling fluid flows downwardly through the
casing cutter 104, the blades 142 may expand radially outwardly and
into engagement with the first casing 118. Further, as the drilling
fluid flows downwardly through the motor 110, the motor 110 may
cause the casing cutter 104 to rotate about a longitudinal axis
extending therethrough. When the blades 142 are in contact with the
first casing 118 and rotate about the longitudinal axis extending
through the casing cutter 104, the blades 142 may cut the first
casing 118 into two portions. In particular, the first casing 118
may be cut into a first or upper portion 148 and a second or lower
portion 150. As may be appreciated, in some embodiments, the
wellbore 102 may be deviated or horizontal. In such instances, the
first or upper portion of the casing 118 may be the portion nearer
to the wellhead 124 or the blow-out preventer 146 than the second
or lower portion.
[0046] FIG. 4 schematically illustrates a side view of the wellbore
102 and the downhole tool 102, and particularly shows the first
casing 118 after it has been cut into the upper and lower portions
148, 150, according to one or more embodiments. In this particular
embodiment, the casing cutter 104 is also shown as having been
deactivated or retracted.
[0047] More particularly, once the first casing 118 has been cut
into the upper and lower portions 148, 150, the pump may be turned
off to stop the flow of the drilling fluid through the work string
116 and the downhole tool 100. In another embodiment, the pump may
remain on, but the amount/rate of the drilling fluid flowing
through the work string 116 and the downhole tool 100 may be
decreased. Once the downward flow of drilling fluid through the
work string 116 and the downhole tool 100 decreases or stops, the
blades 142 (see FIG. 3) of the casing cutter 104 may actuate back
into the inactive state. Optionally, the motor 110 may also no
longer cause the casing cutter 104 to rotate, or may rotate the
casing cutter 104 at a reduced rotational speed. When the casing
cutter 104 actuates into the inactive state, the blades 142 may
retract radially inwardly, and potentially into the body of the
casing cutter 104, such that they are no longer in contact with the
first casing 118.
[0048] FIG. 5 schematically illustrates a side view of the wellbore
102 and the downhole tool 100, and illustrates an example
embodiment in which drilling fluid may flow out through the port
140 in the circulating sub 108 and into the first annulus 128,
according to one or more embodiments. When the casing cutter 104 is
in the inactive state, an impediment 152 (e.g., a ball, dart, etc.)
may be introduced into the downhole tool 100. In at least one
embodiment, the impediment 152 may be dropped into the work string
116 from the surface and travel downward through the work string
116 and into the downhole tool 100. The impediment 152 may come to
rest in the seat 143 (see FIG. 4) disposed within the circulating
sub 108. Optionally, the impediment 152 may be degradable at a
predetermined temperature, pressure, pH, or the like. In another
embodiment, the impediment 152 may pass through the seat 143 when
exposed to a predetermined pressure.
[0049] When the impediment 152 is in the seat 143, the pump may
once again be turned on, and/or the amount/rate of the drilling
fluid flowing through the work string 116 and the downhole tool 100
may be increased. The impediment 152 may obstruct the downward flow
of the drilling fluid through the circulating sub 108, which may
increase the pressure of the drilling fluid in the circulating sub
108. The increased pressure may cause one or more shear elements,
such as shear pins, burst discs, or the like to break, thereby
opening the ports 140 in the circulating sub 108. In another
embodiment, the ports 140 may be opened or uncovered via movement
of a sliding sleeve or other mechanical device in response to
increased pressure. Once the ports 140 are open, the drilling fluid
that is pumped downwardly through the downhole tool 100 may flow
radially outwardly through the ports 140 and into the first annulus
128 formed between the downhole tool 100 and the first casing 118,
as shown by the arrows B.
[0050] FIG. 6 schematically illustrates a side view of the downhole
tool 100 as it is being lowered into the wellbore 102 to position
in which the packoff devices 112, 114 may be positioned within the
first casing 118, according to one or more embodiments of the
present disclosure. Once the ports 140 have been opened, tension on
the downhole tool 100 may be slacked, and the downhole tool 100 may
be rotated (e.g., clockwise or counterclockwise), which may cause
the arms 138 (see FIG. 5) of the spear 106 to disengage the first
casing 118. The arms 138 may also be disengaged in other manners,
such as by decreasing fluid pressure, degrading a drop ball or
other impediment, or passing an impediment through a seat (e.g.,
above a particular pressure). Disengaging the arms 138 may allow
the downhole tool 100 to move axially with respect to the first
casing 118. In another embodiment, the arms 138 of the spear 106
may disengage the first casing 118 before the ports 140 are opened.
After the arms 138 of the spear 106 disengage the first casing 118,
the work string 116 may lower the downhole tool 100 further into
the wellbore 102.
[0051] FIG. 7 schematically illustrates a side view of the downhole
tool 100 within the wellbore 102 when drilling fluid flows through
a port 140 in the circulating sub 108 and into a second annulus
156, according to one or more embodiments of the present
disclosure. The downhole tool 100 may be lowered until the packoff
devices 112, 114 are disposed within the upper portion 148 of the
first casing 118. When disposed within the first casing 118, the
packoff devices 112, 114 may seal the first annulus 128 between the
downhole tool 100 and the first casing 118, thereby restricting and
potentially preventing fluid flow in at least one direction (e.g.,
upwardly) through the first annulus 128. With the packoff devices
112, 114 sealing the first annulus 128, the drilling fluid flowing
through the ports 140 and into the first annulus 128 may fill the
first annulus 128. Additional fluid passing through the ports 140
may then flow from the first annulus 128, and through an opening
154 formed by the casing cutter 104 between the upper and lower
portions 148, 150 of the first casing 118 as shown by arrows C. The
fluid may then flow into the second annulus 156 formed between the
first casing 118 and the second casing 120.
[0052] At least a portion of the drilling fluid flowing into the
second annulus 156 may flow upwardly and potentially out of the
second annulus 156. For example, the drilling fluid may flow
upwardly and out of the second annulus 156 through the blow-out
preventer 146 and/or through one or more so called "kill lines"
(not shown). The drilling fluid flowing through the second annulus
156 may circulate or flush any existing fluids in the second
annulus 156 out of the second annulus 156, leaving the second
annulus 156 filled with the "clean" or "new" drilling fluid. The
existing fluids (i.e., those existing in the second annulus 156
before being flushed out by the clean drilling fluid) may include
liquid hydrocarbons, gaseous hydrocarbons, other fluids present in
the wellbore 102 or the surrounding formation, or any combination
of the foregoing.
[0053] In addition to flushing the existing fluids out of the
second annulus 156, the flow of the drilling fluid through the
second annulus 156 may, at least partially, erode any physical
bonds (e.g., barite, cement, etc.) formed between the upper portion
148 of the first casing 118 and the second casing 120 that would
otherwise hinder removal of the upper portion 148 of the first
casing 118. For example, the drilling fluid may include one or more
additives designed to erode the physical bonds formed between the
upper portion 148 of the first casing 118 and the second casing
120.
[0054] FIG. 8 schematically illustrates a side view of downhole
tool 100 when the spear 106 is engaged with the upper portion 148
of the first casing 118 and the downhole tool 100 is pulling the
upper portion 148 of the first casing 118 out of the wellbore 102,
according to one or more embodiments of the present disclosure.
After drilling fluid has circulated through the second annulus 156,
the work string 116 may raise the downhole tool 100 until the spear
106 is disposed within the upper portion 148 of the first casing
118. In at least one embodiment, the spear 106 may be positioned
adjacent an upper axial end portion of the upper portion 148 of the
first casing 118, although in other embodiments the spear 106 may
be positioned a lower axial end portion of the upper portion 148 of
the first casing, or between the upper and lower axial end portions
of the upper portion 148 of the first casing 118. The spear 106 may
then re-engage the upper portion 148 of the first casing 118 to
substantially restrict or even prevent axial movement between the
downhole tool 100 and the upper portion 148 of the first casing
118.
[0055] Once the spear 106 has re-engaged the upper portion 144 of
the first casing 118, the work string 116 may raise the downhole
tool 100 and the upper portion 148 of the first casing 118, which
may be coupled to the downhole tool 100 via the spear 106. The
downhole tool 100 and the upper portion 148 of the first casing 118
may then be raised up and out of the wellbore 102. Thus, as may be
appreciated, the downhole tool 100 of some embodiments of the
present disclosure is capable of completing a process of cutting
the first casing 118, flushing the existing fluids out of the
second annulus 156, and removing the upper portion 148 of the first
casing 118 from the wellbore 102 in a single trip downhole. The
wellbore 102 may then be fully or partially filled with surrounding
formation materials (e.g., sand or mud), and abandoned. In some
embodiments, a wellhead running or retrieving tool 158 may also be
used to remove and/or retrieve the wellhead 124 once the wellbore
102 is abandoned.
[0056] FIGS. 9-14, 17, and 18 show another embodiment of the
operation of a downhole tool 200 in a wellbore 202, and FIGS. 15
and 16 illustrate an additional embodiment of a packoff device 300
that may be used in the operation of a downhole tool (e.g.,
downhole tool 100 or 200). In the embodiments of FIGS. 9-18, axial
movement of the drill pipe or work string 216 and the downhole tool
200 may be reduced relative to the operation of the downhole tool
of FIGS. 1-8.
[0057] More particularly, FIG. 9 schematically illustrates a side
view of the downhole tool 200 positioned within a first casing 218
in the wellbore 202, according to one or more embodiments of the
present disclosure. After the plug 226 (e.g., a bridge plug, cement
plug, etc.) is disposed within the first casing 208, the work
string 216 may be used to lower the downhole tool 200 at least
partially into the first casing 218 to a distance above the plug
226. The downhole tool 200 may be lowered until one or more packoff
devices 212, 214 are disposed within the first casing 218, as shown
in FIG. 9.
[0058] FIG. 10 schematically illustrates a side view of a spear 206
for engaging the first casing 218 to restrict, and potentially
prevent, relative movement between the downhole tool 200 and the
first casing 218, according to one or more embodiments of the
present disclosure. Once the downhole tool 200 is at a desired
depth within the wellbore 202, the downhole tool 200 may be lifted
and rotated (e.g., clockwise or counterclockwise), which may cause
one or more arms 238 of the spear 206 to expand radially-outwardly
and engage the first casing 218. Such engagement may restrict or
even substantially prevent axial movement between the downhole tool
200 and the first casing 218.
[0059] FIG. 11 schematically illustrates a side view of a casing
cutter 204 cutting the first casing 218 into respective upper and
lower portions 248, 250, according to one or more embodiments of
the present disclosure. Once the downhole tool 200 is secured to
the first casing 218 (e.g., via the spear 206), a pump (not shown)
may cause drilling fluid to flow down through the work string 216
and into the downhole tool 200, as shown by the arrow D in FIG. 11.
As the drilling fluid flows downwardly through the casing cutter
204, one or more blades 242 may expand radially-outwardly and into
engagement with the first casing 218. Further, as the drilling
fluid flows downwardly through a motor 210, the motor 210 may cause
the casing cutter 204 to rotate about a longitudinal axis extending
therethrough. When the blades 242 rotate and contact the first
casing 218, the blades 242 may cut the first casing 218 into the
upper portion 248 and the lower portion 250. As may be appreciated
by a person having ordinary skill in the art in view of the
disclosure herein, in some embodiments, the wellbore 202 may be
deviated, inclined, or even horizontal. In such instances, the
upper portion 248 of the first casing 218 may be the portion of the
first casing 218 nearer the wellhead 224 or a blow-out preventer
246 than the so-called lower portion 250.
[0060] Once the first casing 218 has been cut into the upper and
lower portions 248, 250, the pump may optionally be turned off to
stop the flow of the drilling fluid through the work string 216 and
the downhole tool 200. In another embodiment, the pump may remain
on, and the amount or flow rate of the drilling fluid flowing
through the work string 216 and/or the downhole tool 200 may be
decreased. Once the downward flow of drilling fluid through the
work string 216 and the downhole tool 200 decreases or stops, the
blades 242 of the casing cutter 204 may be deactivated and/or the
motor 210 may no longer cause the casing cutter 204 to rotate. When
the blades 242 are deactivated and/or the casing cutter 204 is no
longer rotated, the casing cutter 204 may be in an inactive state.
In the inactive state, the blades 242 may retract radially-inwardly
toward or into the body of the casing cutter 204, or may otherwise
move to no longer be in contact with the first casing 218.
[0061] FIG. 12 schematically illustrates a side view of an example
embodiment of the drilling tool 200 when drilling fluid flows
through a port 240 in a circulating sub 132, and into a first
annulus 228, according to one or more embodiments of the present
disclosure. When the casing cutter 204 is in the inactive state, an
impediment 252 (e.g., a ball or dart) may be introduced into the
downhole tool 200. In at least one embodiment, the impediment 252
may be dropped into the work string 216 from the surface and may
travel downwardly through the work string 216 and into the downhole
tool 200. The impediment may come to rest in a seat disposed within
the circulating sub 208, or another component coupled to the
circulating sub 208 (e.g., a ball catching sub, not shown). In some
embodiments, the impediment 252 may be degradable at a
predetermined temperature, pressure, pH, or the like. In another
embodiment, the impediment 252 may pass through the seat (e.g.,
when exposed to a predetermined pressure).
[0062] When the impediment 252 is in the work string 216 and
potentially on the seat, the pump may once again be turned on
and/or increase the drilling fluid flow rate through the work
string 216 and to the downhole tool 200. The impediment 252 may
obstruct the downward flow of the drilling fluid through the
circulating sub 208, which may increase the pressure of the
drilling fluid in the circulating sub 208 (e.g., uphole relative to
the impediment 252). The increased pressure may cause one or more
shear elements, such as shear pins, to break, thereby opening the
one or more ports 240 in the circulating sub 208. In another
embodiment, the ports 240 may be opened or uncovered via movement
of a sliding sleeve or other mechanical device in response to
increased pressure. Once the ports 240 are open, the drilling fluid
that is pumped downward through the downhole tool 200 may flow
radially-outwardly through the ports 240--which themselves may
extend radially through the circulating sub 208--and into the first
annulus 228 as shown by the arrows E. As shown in FIG. 12, the
first annulus 228 may be the annular region existing between the
downhole tool 200 and the first casing 218.
[0063] In at least one embodiment, the packoff devices 212, 214 may
be actuated between a first or open state and a second or closed
state. In the first or open state, the drilling fluid that flows
out through the ports 240 and within the first annulus 228 may flow
axially upwardly through the packoff devices 212, 214, and toward
the surface, as shown by the arrows F in FIG. 12. More
particularly, the drilling fluid may flow up the first annulus 228
and through the packoff devices 212, 214 toward the surface.
[0064] FIG. 13 depicts a cross-sectional view of an illustrative
first packoff device 212 having an illustrative sleeve 260 disposed
at least partially in a bore 234 extending through the work string
216 or mandrel 230, and positioned such that the first packoff
device 212 is in an open state, according to one or more
embodiments of the present disclosure. Although the first packoff
device 212 is shown and described, it should be appreciated that
the description of the first packoff device 212 may also apply to
the second packoff device 214 and/or any additional packoff
devices. The mandrel 230 (and the sleeve 260) of the first packoff
device 212 may have a bore 234 formed axially therethrough. A pump
(not shown) may cause drilling fluid to flow downwardly through the
bore 234 as shown by arrows G. The fluid may flow through the bore
234 to other components, such as those shown in FIG. 9 (e.g.,
casing cutter 204, circulating sub 208, motor 210, spear 206, drill
bit or mill 203, etc.).
[0065] The mandrel 230 of the first packoff device 212 may also
have first and second ports 262, 264 formed radially therethrough,
which ports 262, 264 may be in fluid communication with one another
through an axial channel 266. A sealing element 232 may be disposed
axially between the ports 260, 262, and radially between the
mandrel 230 and the first casing 218.
[0066] At least a portion of the channel 266 may be formed radially
between the mandrel 230 and the sleeve 260. In addition, the
channel 266 may be positioned radially-inwardly relative to at
least a portion of the sealing element 232. The channel 266 may
provide a flow path through the first packoff device 212 such that
the drilling fluid may bypass the sealing element 232 and flow
upwardly through the first annulus 228, as shown by arrows H. While
a single channel 266 is shown in the cross-sectional view of FIG.
13, it should be appreciated that there may be multiple axial
channels (e.g., two, three, four, or more) circumferentially offset
around the sleeve 260.
[0067] According to some embodiments of the present disclosure, one
or more biasing members 268 (e.g., springs) may be disposed within
the mandrel 230 and/or proximate the sleeve 260. The spring or
other biasing member 268 may be positioned between a stop block
269, such as a stop ring, and the sleeve 260. The biasing member
268 may exert a force on the sleeve 260 that maintains the first
packoff device 212 in the open state (FIG. 13) or in a closed state
(FIG. 14).
[0068] FIG. 14 depicts a cross-sectional view of the first packoff
device 212 of FIG. 13 having the sleeve 260 disposed therein and
positioned such that the first packoff device 212 is in a closed
state, according to one or more embodiments of the present
disclosure. When the flow rate of the drilling fluid through the
bore 234 extending through the first packoff device 212 increases
beyond a predetermined level, the hydrostatic force exerted by the
drilling fluid on the sleeve 260 may become greater than the
opposing force exerted by the spring or other biasing member 268,
and may move the sleeve 260 and compress the biasing member 268. In
some embodiments, the predetermined drilling fluid flow rate that
causes the sleeve 260 to move may range from about 100 L/min (0.44
gps), about 250 L/min (1.1 gps), or about 500 L/min (2.2 gps) to
about 1,000 L/min (4.4 gps), about 2,000 L/min (8.8 gps), about
3,000 L/min (13.2 gps), or more.
[0069] Increasing the flow rate may cause the first packoff device
212 to actuate, and transition from an open state (FIG. 13) into a
closed state (FIG. 14). In the closed state, the sleeve 260 may
obstruct the first and/or second port 262, 264, and the drilling
fluid may be restricted and potentially prevented from flowing
through the channel 266. As a result, the first packoff device 212
may seal (i.e., isolate upper and lower portions of) the first
annulus 228 between the first casing 228 and the mandrel 230 so
that fluid is restricted, if not prevented, from flowing axially
therethrough.
[0070] More particularly, when the first packoff device 212
actuates into the closed state, the sleeve 260 may slide or
otherwise move axially within the mandrel 230 to block or obstruct
the first and/or second port 262, 264. As shown, the sleeve 260 may
move upwardly and obstruct the first port 262. When the sleeve 260
obstructs the first and/or second ports 262, 264, the fluid in the
first annulus 228 may be diverted through an opening 254 and into a
second annulus 256, as shown in FIG. 17. One or more seals 270, 272
(e.g., O-rings, T-Rings, etc.) may be disposed on an outer surface
of the sleeve 260 and/or between the sleeve 260 and the mandrel 230
to limit leakage of drilling fluid when the first packoff device
212 is in the closed state.
[0071] Although FIGS. 13 and 14 illustrate an example embodiment
having a single sealing element 232, other embodiments are
contemplated which include multiple sealing elements 232. For
instance, multiple sealing elements 232 may be positioned between
the first and second ports 262, 264. An axial channel 266 between
the first and second ports 262, 264 may then be used to allow fluid
to bypass the multiple sealing elements 232. In other embodiments,
each sealing element 232 may have its own corresponding set of
first and second ports 262, 264.
[0072] FIG. 15 depicts a cross-sectional view of another
illustrative sleeve 360 disposed within a first packoff device 312
and positioned such that the first packoff device 312 is in an open
state, according to one or more embodiments of the present
disclosure. In at least one embodiment, the sleeve 360 may have a
seat 374 coupled thereto or integral therewith. The seat 374 may
extend radially-inwardly from the inner surface of the sleeve 360
in some embodiments. When there is no impediment engaged with the
seat 374, the drilling fluid may flow downwardly through the bore
334, as shown by arrows G, as well as upwardly through the channel
366 and through a first annulus 328, as shown by arrows H.
[0073] FIG. 16 depicts a cross-sectional view of the first packoff
device 312 of FIG. 15 having the sleeve 360 disposed therein and
positioned such that the first packoff device 312 is in a closed
state, according to one or more embodiments of the present
disclosure. An impediment 376 may be introduced to the bore 334 of
the first packoff device 312. For example, the impediment 376 may
be dropped into a drill pipe or work string from the surface, and
flowed down through a downhole tool and into the bore 334 of the
first packoff device 312. The impediment 376 may be a ball, a dart,
or the like, and may be sized and/or shaped to be received in the
seat 374. The impediment 376 may be degradable at a predetermined
temperature, pressure, pH, or the like. When the impediment 376 is
engaged with the seat 374, downward flow of the drilling fluid may
be obstructed through the bore 334.
[0074] When the bore 334 is obstructed, the pressure of the
drilling fluid in the bore 334 may increase behind (i.e., uphole
of) the impediment 376, and the hydrostatic force exerted by the
drilling fluid on the sleeve 360 may become greater than the
opposing force exerted by a biasing member 368 positioned between
the sleeve 360 and a stop block 369. This may cause the sleeve 360
to slide or otherwise move axially within or along a mandrel 330,
compressing the biasing member 368 and blocking or obstructing the
first and/or second ports 362, 364, thereby actuating the first
packoff device 312 so as to cause a transition from an open state
to a closed state. As shown, the sleeve 360 may move downwardly and
obstruct the second port 364. When the sleeve 360 blocks or
obstructs the first and/or second port 362, 364 (i.e., the when
first packoff device 312 is in a closed state), drilling fluid may
be restricted or even prevented from flowing through upwardly
through the one or more channels 366 and into the first annulus
328. When this occurs, the first packoff device 312 may seal a
first annulus 328 between the first casing 318 and the mandrel 330
so that fluid is restricted or potentially prevented from flowing
axially therethrough.
[0075] In some embodiments, the sleeve 360 may be configured to be
secured in position to maintain the first packoff device 312 in the
closed state. For example, the sleeve 360 may include a radial
protrusion 378 disposed on the outer surface thereof, and the
mandrel 330 may have a groove 380 disposed on the inner surface
thereof. The protrusion 378 may engage the groove 380 when the
sleeve 360 moves (e.g., downwardly as shown in FIG. 16). In another
embodiment, the sleeve 360 may have a groove 380 disposed on the
outer surface thereof, and the mandrel 330 may have a radial
protrusion 378 disposed on the inner surface thereof. Once the
protrusion 378 is within the groove 380 and the sleeve 360 is
secured in place, the impediment 376 may degrade, or the pressure
of the fluid in the bore 334 may be increased until the seat 374
and/or the impediment 376 deforms, thereby allowing the impediment
376 to pass through the seat 374.
[0076] When two or more packoff devices are used (e.g., packoff
devices 212, 214 in FIGS. 9-12), an impediment 376 that engages the
seat 374 in the lower packoff device may be smaller than the
impediment 376 that engages the seat 374 in the upper packoff
device. This arrangement may allow the first impediment 376 to pass
through the upper packoff device and engage the seat 374 in the
lower packoff device. In other embodiments, a single one of the
multiple packoff devices may use an impediment (e.g., one packoff
device may be configured similar to the packoff device 212 of FIGS.
13 and 14, while another packoff device may be configured similar
to the packoff device 312 of FIGS. 15 and 16).
[0077] FIG. 17 schematically illustrates a side view of the
downhole tool 200 in which drilling fluid may flow through the
port(s) 240 in the circulating sub 208 and into a second annulus
256, according to one or more embodiments of the present
disclosure. When a sleeve (e.g., sleeve 260 of FIGS. 13 and 14 or
sleeve 360 of FIGS. 15 and 16) obstructs the flow of drilling fluid
through a channel in the packoff devices 212, 214 (e.g., channels
266, 366) due to an increase in the flow rate of the drilling fluid
through a bore 234 (as shown in FIG. 14) and/or an impediment 376
being received in a seat 374 (as shown in FIG. 16), the packoff
devices 212, 214 may seal the first annulus 228 between the first
casing 218 and the mandrel 230. When this occurs, the drilling
fluid flowing through the ports 240 in the circulating sub 208 and
into the first annulus 228 may no longer flow up and out of the
first annulus 228, as shown in FIG. 12. Rather, the drilling fluid
may now flow from the first annulus 228, through the opening 254
formed by the casing cutter 204 between the upper and lower
portions 248, 250 of the first casing 218, and into the second
annulus 256 formed between the first casing 218 and the second
casing 220.
[0078] At least a portion of the drilling fluid flowing into the
second annulus 256 may flow upwardly and out of the second annulus
256. For example, drilling fluid may flow upwardly and out of the
second annulus 256 through a blow-out preventer 246 and/or through
one or more so-called "kill lines" (not shown). The drilling fluid
flowing through the second annulus 256 may circulate or flush any
existing fluids in the second annulus 256 out of the second annulus
256, leaving the second annulus 256 filled with clean or new
drilling fluid. The fluids that are disposed in the second annulus
256 before being flushed out by the drilling fluid (i.e., the
"existing fluids") may include liquid hydrocarbons, gaseous
hydrocarbons, or any other fluid present in the wellbore 202 or the
surrounding formation.
[0079] In addition to flushing the existing fluids out of the
second annulus 256, the flow of the drilling fluid through the
second annulus 256 may, at least partially, erode physical bonds
(e.g., barite) formed between the upper portion 248 of the first
casing 218 and the second casing 220 that would otherwise hinder
removal of the upper portion 248 of the first casing 218. For
example, the drilling fluid may include one or more additives
designed to erode the physical bonds formed between the upper
portion 248 of the first casing 218 and the second casing 220.
[0080] FIG. 18 schematically illustrates a side view of the
downhole tool 200 pulling the upper portion 248 of the first casing
218 out of the wellbore 202, according to one or more embodiments
of the present disclosure. The spear 206 may still be engaged with
the upper portion 248 of the first casing 218 as the drilling fluid
circulates through the second annulus 256. After circulation is
complete, the work string 216 may raise the downhole tool 200 and
the upper portion 248 of the first casing 218, which may be coupled
to the downhole tool 200 via the spear 206. The downhole tool 200
and the upper portion 248 of the first casing 218 may be raised up
and out of the wellbore 202. The wellbore 202 may then be filled in
with surrounding formation materials (e.g., sand or mud).
[0081] As should be appreciated by one having ordinary skill in the
art in view of the present disclosure, the downhole tool 200 may be
capable of completing a process that includes cutting the first
casing 218, flushing the existing fluids out of second annulus 256,
and removing the upper portion 248 of the first casing 218 from the
wellbore 202 in a single trip. In addition, by incorporating a
bypass channel (e.g., channels 266 and 366 of FIGS. 13-16) and
sleeve (e.g., sleeves 260, 360 of FIGS. 13-16) into the packoff
devices 212, 214, the downhole tool 200 may remain substantially
stationary with respect to the upper portion 248 of the first
casing 218 from the time the spear 206 engages the first casing 218
until the time the upper portion 248 of the first casing 218 is
removed from the wellbore 202. In other words, the embodiments of
FIGS. 9-18 may allow the downhole tool 202 to remove the upper
portion 248 of the first casing 218 potentially without disengaging
the spear 206 to allow movement of the casing cutter 104. Further,
rather than potentially cutting the casing while the packoff
devices 212, 214 are outside the wellbore 202, the packoff devices
212, 214 may be initially located within the wellbore 202 prior to
engaging the spear 206 and/or cutting the first casing 218.
[0082] According to some embodiments of the present disclosure, a
method for removing casing from a wellbore may include running a
downhole tool into a first casing. The downhole tool may include a
packoff device, a spear, a circulating sub, and a casing cutter.
The spear may be used to restrict relative movement between the
downhole tool and the first casing, and thereafter the casing
cutter may be used to form an opening in the first casing. The
opening may define a separation between upper and lower portions of
the first casing. A port in the circulating sub may be opened. The
port may provide a path of fluid communication between an axial
bore in the downhole tool and a first annulus between the downhole
tool and the first casing. Optionally, the circulating sub may be
positioned between the spear and the casing cutter. After the port
is opened, the spear may be disengaged from the casing and the
downhole tool may be moved relative to the first casing. The first
annulus may be sealed with the packoff device, with the seal be
positioned potentially above the spear. Drilling fluid may be
flowed through the port in the circulating sub and into the first
annulus. Such flow may occur when the packoff device seals the
first annulus, with at least a portion of the drilling fluid
flowing from the first annulus, through the opening formed between
the upper and lower portions of the first casing, and into a second
annulus formed between the first casing and a second casing. The
spear may be activated to restrict relative movement between the
downhole tool and the upper portion of the first casing after flow
of drilling fluid into the second annulus, and the upper portion of
the first casing may be pulled out of the wellbore.
[0083] According to at least some embodiments, a method for
removing casing may include opening the port by introducing an
impediment into the downhole tool such that the impediment engages
and forms a seal with a seat in the downhole tool. With the
impediment engaged with the seat, pressure of the drilling fluid
may be increased in the circulating sub and the port may be opened
in response to such increased pressure. In accordance with at least
some embodiments, flowing drilling fluid through the port in the
circulating sub may include flushing existing fluid in the second
annulus out of the second annulus. Moving the downhole tool
relative to the first casing may also include lowering the downhole
tool relative to the first casing to dispose the packoff device
within the first annulus.
[0084] According to at least some embodiments, the spear may be
coupled to and positioned between the packoff device and the
circulating sub. The casing cutter may also be coupled to and
positioned below the circulating sub. In at least some embodiments,
a packoff device may include a biasing member within the bore,
which biasing member may exert a force on the sleeve to bias the
sleeve in the open state. In some embodiments, a predetermined
level of a flow rate of fluid through the axial bore may be between
about 100 L/min and about 3,000 L/min to move a sleeve of the
packoff device from an open state to a closed state. A packoff
device according to some embodiments may further include a seat
coupled to the sleeve, with the seat being configured to receive an
impediment introduced into the axial bore. A sleeve of a packoff
device according to some embodiments may be configured to move from
the open state to the closed state when the impediment is received
in the seat. In some embodiments, a sealing element of a packoff
device may be configured to isolate upper and lower portions of an
annulus formed between the mandrel and a casing positioned
radially-outwardly relative to the mandrel.
[0085] In accordance with other embodiments of the present
disclosure, a downhole tool for removing a portion of a casing from
a wellbore may include a packoff device, spear, circulating sub,
and casing cutter. The packoff device may include a mandrel,
sealing element, and sleeve. The mandrel may have an axial bore and
axially offset first and second radial ports. The sealing element
may be coupled to the mandrel and configured to isolate an annulus
formed between the mandrel and a casing. The sleeve may be disposed
at least partially within the axial bore, and the sleeve and
mandrel may form a channel providing a path of fluid communication
between the first and second radial ports. The sleeve may be
configured to move between an open state in which the first and
second radial ports are unobstructed by the sleeve and a closed
state in which the first radial port, the second radial port, or
both are obstructed by the sleeve. The spear of the downhole tool
may be coupled to the packoff device and adapted to engage the
casing to restrict relative movement between the downhole tool and
the casing. The circulating sub may be coupled to the spear and may
have a port in fluid communication with the annulus. The casing
cutter may be coupled to circulating sub and configured to rotate
to cut the casing.
[0086] A sealing element of a packoff device of a downhole too may,
according to some embodiments be adapted to isolate upper and lower
portions of the annulus. A sleeve may be configured to permit fluid
to flow through the first radial port, the channel, and the second
radial port when the sleeve is in the open state, thereby bypassing
the sealing element. In some embodiments, the packoff device may be
positioned axially above the spear, circulating sub, and the casing
cutter. Further, a downhole tool may include a seat coupled to the
sleeve, the seat being configured to receive an impediment
introduced to the axial bore.
[0087] A method for removing a casing from a wellbore may,
according to some embodiments of the present disclosure, include
running a downhole tool into a first casing, the downhole tool
including a packoff device, a spear, a circulating sub, and a
casing cutter. The first casing may be engaged with the spear to
restrict relative movement between the downhole tool and the first
casing, and the first casing may be cut to form an opening between
upper and lower portions of the first casing. At least a portion of
a first annulus defined between the downhole tool and the first
casing may be isolated by using the packoff device. The packoff
device may include a mandrel having an axial bore and first and
second radial ports, a sealing element coupled to the mandrel and
extending radially-outwardly from the mandrel to contact the first
casing, and a sleeve disposed at least partially within the axial
bore. The sleeve and the mandrel may define a channel that provides
a path of fluid communication between the first and second radial
ports, the first and second radial ports being unobstructed by the
sleeve when the packoff device in an open state, and the first
radial port, the second radial port, or both being obstructed by
the sleeve in a closed state. The method may also include flowing a
drilling fluid through a port in the circulating sub and into the
first annulus, at least a portion of the drilling fluid flowing
from the first annulus, through the opening formed between the
upper and lower portions of the first casing, and into a second
annulus formed between the first casing and a second casing. The
upper portion of the first casing may also be pulled out of the
wellbore after the drilling fluid flows into the second
annulus.
[0088] According to some embodiments, flowing the drilling fluid
may include flushing existing fluid in the second annulus out of
the second annulus with the drilling fluid, and during a same
downhole trip that includes cutting the first casing. A packoff
device used in a method for removing casing from a wellbore may
provide a fluid bypass in the open state, thereby permitting fluid
to bypass the sealing element. In some embodiments, the packoff
device may close the fluid bypass in the closed state, thereby
restricting fluid from bypassing the sealing element.
[0089] A method of some embodiments of the present disclosure may
include isolating at least a portion of the first annulus by
actuating the packoff device from the open state to the closed
state in response to increasing a flow rate of drilling fluid
through the axial bore of the mandrel beyond a predetermined level.
Isolating may include actuating the packoff device from the open
state to the closed state in response to an impediment being
introduced to the bore of the mandrel and engaging a seat coupled
to the sleeve. In some embodiments, the sealing element may be
positioned axially between first and second radial ports.
[0090] As used herein, the terms "inner" and "outer"; "up" and
"down"; "upper" and "lower"; "upward" and "downward"; "above" and
"below"; "inward" and "outward"; and other like terms as used
herein refer to relative positions to one another and are not
intended to denote a particular direction or spatial orientation.
The terms "couple," "coupled," "connect," "connection,"
"connected," "in connection with," and "connecting" refer to "in
direct connection with," "integral with," or "in connection with
via one or more intermediate elements or members."
[0091] Although various example embodiments have been described in
detail herein, those skilled in the art will readily appreciate in
view of the present disclosure that many modifications are possible
in the example embodiment without materially departing from the
present disclosure. Accordingly, any such modifications are
intended to be included in the scope of this disclosure. Likewise,
while the disclosure herein contains many specifics, these
specifics should not be construed as limiting the scope of the
disclosure or of any of the appended claims, but merely as
providing information pertinent to one or more specific embodiments
that may fall within the scope of the disclosure and the appended
claims. Any described features from the various embodiments
disclosed may be employed in combination. In addition, other
embodiments of the present disclosure may also be devised which lie
within the scopes of the disclosure and the appended claims. Each
addition, deletion, and modification to the embodiments that falls
within the meaning and scope of the claims is to be embraced by the
claims.
[0092] In the claims, means-plus-function clauses are intended to
cover the structures described herein as performing the recited
function, including both structural equivalents and equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail employs a cylindrical surface to couple
wooden parts together, whereas a screw employs a helical surface,
in the environment of fastening wooden parts, a nail and a screw
may be equivalent structures. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn.112, paragraph 6 for any
limitations of any of the claims herein, except for those in which
the claim expressly uses the words `means for` together with an
associated function.
[0093] Certain embodiments and features may have been described
using a set of numerical upper limits and a set of numerical lower
limits. It should be appreciated that ranges including the
combination of any two values, e.g., the combination of any lower
value with any upper value, the combination of any two lower
values, and/or the combination of any two upper values are
contemplated unless otherwise indicated. Certain lower limits,
upper limits and ranges may appear in one or more claims below. Any
numerical value is "about" or "approximately" the indicated value,
and take into account experimental error and variations that would
be expected by a person having ordinary skill in the art.
* * * * *