Note: Descriptions are shown in the official language in which they were submitted.
CA 02733339 2011-03-03
1 WELLBORE OBSTRUCTION-CLEARING TOOL AND METHOD OF USE
2
3
4 FIELD OF THE INVENTION
Embodiments herein related to apparatus and methods for clearing
6 obstructions in wellbores during casing of the wellbores and more
particularly to
7 apparatus connected at a bottom of a typically non-rotating tubular
string for clearing
8 obstructions encountered in the wellbore as the tubular string is run
into an open hole,
9 such as prior to cementing.
11 BACKGROUND OF THE INVENTION
12 In the oil and gas industry, following drilling of a vertical
or horizontal
13 wellbore into a formation for the production of oil or gas therefrom,
the wellbore is
14 typically cased and cemented to line the length of the wellbore to
ensure safe control
of production of fluids therefrom, to prevent water from entering the wellbore
and to
16 keep the formation from "sloughing" or "bridging" into the wellbore.
17 It is well known that during the running in of a tubing string,
such as
18 casing and particularly the production casing, the casing may encounter
tight spots
19 and obstructions in the open wellbore, such as that created by sloughing
of the
wellbore wall into the open hole or as a result of the casing pushing debris
ahead of
21 the bottom end of the casing along the open hole until it forms a
bridge. Such
22 obstructions prevent the advance of the casing and require the open hole
to be
23 cleared in order to advance the casing to the bottom of the hole. This
is particularly
24 problematic in horizontal wellbores.
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1 Should the casing string become sufficiently engaged in a mud pack
2 formed at the obstruction, differential sticking may also occur, making
advancing or
3 removal of the casing from the wellbore extremely difficult.
4 While casing strings have been rotated to assist with moving past
or
through an obstruction, high torque created by trying to rotate a long string
of casing
6 may result in significant damage to the threads between casing joints and
may cause
7 centralizers and the like to drag and ream into the wellbore. While
rotation of casing
8 may be a viable option in a vertical wellbore, albeit fraught with
problems, it is
9 extremely difficult, if not impossible in a horizontal wellbore.
One option is to employ a washing technique, pumping fluids through
11 the casing while the casing is axially reciprocated uphole and downhole.
The fluids
12 exiting the downhole end of the casing bore act on the obstruction in
the wellbore to
13 wash out or erode the wellbore obstruction creating debris which is
lifted or conveyed
14 through the annulus to surface by fluid circulation therein. Should the
washing
technique be unsuccessful, it is known to trip out the casing and run in a mud
motor
16 on a drill string to drill out or ream the obstruction from the
wellbore. Such repeated
17 running in and tripping out of tubulars is time consuming, labor
intensive and, as a
18 result, very expensive. Alternatively, others have contemplated
providing teeth on the
19 bottom of the casing string or on a shoe at the bottom of the casing
string to assist
with cutting away the obstruction as the casing is advanced during running in.
21 Typically, the casing is also reciprocated or stroked during the
clearing operation, or,
22 in some cases, at the same time as the casing is rotated.
2
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1
Further, it has been contemplated to attach costly apparatus, such as
2 mud
motors, jetting or reaming tools, to the bottom of the casing string, however
the
3
apparatus is not retrievable thereafter from the wellbore and adds
significantly to the
4 cost of the casing operation.
Ideally, what is required is a relatively simple and inexpensive apparatus
6 that
can be incorporated into the casing string for clearing wellbore obstructions
7 without
the need for rotating the casing string. Ideally, the apparatus could be left
8 downhole, after the casing and cementing operations are complete, without a
9 significant increase in operational costs.
11 SUMMARY OF THE INVENTION
12 A
wellbore obstruction-clearing tool is fit to a downhole end of a string of
13
tubulars, such as a casing string or a string of coiled tubing (CT). The tool
comprises a
14 tubular
mandrel having a rotatable tubular sleeve concentrically fit thereabouts. A
helical drive is positioned between the mandrel and the sleeve, permitting the
sleeve
16 to
reciprocate axially along the mandrel and to rotate relative thereto. The
sleeve is
17 driven
to extend or retract axially and to rotate relative to the mandrel through
axial
18
reciprocation of the tubulars and the mandrel in the wellbore, commonly
referred to as
19
stroking of the tubulars within the wellbore. At least the rotation of the
sleeve
engaging the wellbore obstructions causes the obstructions to break up or
erode,
21 forming
debris therefrom which is conveyed to surface by fluids circulated downhole
22 through
the string and uphole to surface in an annulus between the tubulars and the
3
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1 wellbore. The fluids can also aid in hydraulically extending the sleeve
during the
2 upstroke and fluidly eroding wellbore obstructions.
3 In a broad aspect, a wellbore obstruction-clearing tool is fit to
a
4 downhole end of a tubing string for advancing the tubing string through
obstructions in
a wellbore. The tubing string has an axial bore therethrough for communicating
fluids
6 to an annulus between the tubing string and the wellbore for circulation
to surface.
7 The obstruction-clearing tool comprises ad tubular mandrel a tubular
sleeve and a
8 helical drive therebetween. The tubular mandrel connects to the downhole
end of the
9 tubing string, the mandrel having a mandrel bore extending axially
therethrough, and
the mandrel bore being fluidly connected to the axial bore. The tubular sleeve
has a
11 sleeve bore extending axially therethrough and fit concentrically fit
about the mandrel,
12 the sleeve bore being fluidly connected with the mandrel bore, and a
downhole end for
13 engaging the wellbore obstructions. The helical drive arrangement acts
between the
14 mandrel and the sleeve for driving the sleeve axially and rotationally
along the
mandrel between a retracted position and an extended position in response to
16 reciprocating axial movement of the tubing string and mandrel. The
engagement of
17 the downhole end of the sleeve creates debris from the wellbore
obstructions, and
18 wherein the fluids from the sleeve bore convey debris along the annulus
to surface.
19 The obstruction-clearing tool enables methods for clearing
obstructions
in a wellbore and advancing a tubing string therein without rotation of the
tubing string.
21 Such method comprises running a wellbore obstruction-clearing tool on a
downhole
22 end of the tubing string, such as casing or CT, the wellbore obstruction-
clearing tool
23 having a tubular mandrel for connection to the tubing string and tubular
sleeve which
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is axially and rotationally moveable therealong between a retracted position
and an
2 extended position; and when the wellbore obstruction-clearing tool
encounters a
3 wellbore obstruction. In operation, the method comprises stroking the
tubing string
4 uphole and downhole so as to drive the tubular sleeve to rotate and
reciprocate axially
between the retracted position and the extended position for engaging the
wellbore
6 obstruction and creating debris therefrom; and discharging fluid through
contiguous
7 bores in the tubing string, the mandrel and the sleeve for conveying
debris to surface.
8
9 BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a fanciful schematic sectional VieW of an embodiment of
11 obstruction-clearing tool connected to a downhole end of a casing
string;
12 Figure 2 is a cross-sectional view of the tool of Fig. 1, taken
along
13 section lines 11-11, and illustrating guide pins on an inner surface of
a sleeve engaging
14 helical grooves on an outer surface of a mandrel;
Figure 3 is a longitudinal sectional view of a tapered discharge of a tool
16 of Fig. 1, the tool having centralizing ribs formed on a sleeve and
having a flow
17 restrictor;
18 Figure 4A is a longitudinal side view of a mandrel having helical
grooves
19 with a uniform pitch of about 45 degrees;
Figure 4B is a longitudinal side view of a mandrel having helical grooves
21 having a pitch that varies from 60 degrees to 45 degrees, from 45
degrees to 30
22 degrees, from 30 degrees to 45 degrees, and from 45 degrees to 60
degrees;
5
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1 Figure
5 is a longitudinal perspective view of an embodiment of the
2 obstruction-clearing tool a PDC equipped bit at a downhole end of the
sleeve;
3 Figure
6A is a longitudinal partial sectional view of the embodiment of
4 Fig. 5,
illustrating the mandrel in side view and the sleeve in cross-sectional view
and
in an extended position;
6 Figures
6B and 60 are detailed partial sectional views of the mandrel's
7 uphole end and downhole end respectively, according to Fig. 6A;
8 Figure
7 is a perspective view of a PDC equipped bit embodiment
9
according to Fig. 5, the bit having a plurality of openings for the passage of
fluids
therethrough;
11 Figure
8 is a perspective sectional view of the bit according to Fig. 7,
12 showing an uphole face and the plurality of openings for fluid passage;
13 Figures
9A, 9B and 9C illustrate another embodiment of an obstruction-
14 clearing tool which is optimized for horizontal wellbores and drillable
embodiments:
Figure 9A is a longitudinal side view of the tool in the extended
16 position;
17 Figure
9B is a partial sectional view of Fig. 9A with the mandrel is
18 side view and the sleeve in cross-sectional view;
19 Figure
90 is a partial sectional view of Fig. 9B with the sleeve
retracted over the mandrel;
21 Figure
10A is a longitudinal partial sectional view of the embodiment of
22 Fig.
9A, illustrating the mandrel in side view and the sleeve in cross-sectional
view and
23 in an extended position;
6
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1 Figures
10B and 10C are detailed partial sectional views of the
2 mandrel's uphole end and downhole end respectively, according to Fig.
10A;
3 Figure 11 is a perspective view illustrating the tubular bit of
Fig. 10A;
4 Figure 12 is a sectional view of the tubular bit of Fig. 1;
Figure 13 is a longitudinal partial sectional view illustrating an
6
embodiment of a drill-throughable bit having a less competent bit insert and a
7 locking
mechanism between the mandrel (shown in side view) and the bit at the
8 downhole end of the sleeve (shown in section);
9 Figure
14 is a perspective view of an embodiment of the mandrel
having a first castellated profile at a downhole end for forming a locking
mechanism;
11 Figure
15 is a perspective sectional view of a downhole end of the
12 sleeve, illustrating a tubular bit having a second castellated profile for
13
correspondingly interlocking with the first castellated profile of Fig. 14 to
form a
14 locking mechanism;
Figure 16 is a perspective view of an alternative form of a locking
16 mechanism comprising a screw head-type interlocking interface;
17 Figure
17A is a longitudinal partial sectional view of the embodiment
18 of Fig.
13 illustrating a drill-throughable wellbore obstruction-clearing tool having
a
19 casing
shell extending over the mandrel (in said view) and the sleeve (in sectional
view), the sleeve being in the retracted position;
21 Figure
17B illustrates the sleeve of Fig. 17A its fully extended position
22 and the
casing shell surrounding the mandrel for providing a guide for a subsequent
23 or secondary drill string;
7
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1 Figure
18 is a schematic representation illustrating a six-step
2
progression of a wellbore obstruction-clearing tool engaging an obstruction in
a
3 vertical wellbore and being activated by shearing of shear pins;
4 Figure
19 is a schematic representation illustrating a five-step
progression of a wellbore obstruction-clearing tool engaging an obstruction in
a
6 horizontal wellbore, the sleeve being axially extended through fluid
hydraulics;
7 Figure
20 is a schematic representation illustrating a six-step, left-to-
8 right
progression of a downstroke of the casing and wellbore obstruction-clearing
tool
9 acting against an obstruction in a vertical wellbore;
Figure 21 is a schematic representation illustrating a six-step, right -to-
11 left
progression of an resetting, upstroke of the casing and wellbore obstruction-
12 clearing tool; and
13 Figures
22A and 22B are schematic representations of a drill-
14
throughable tool according to Fig 17A, which is cemented in a wellbore and
then being
drilled out by a secondary drill string respectively, for extending a
previously cased
16 wellbore.
17
18 DETAILED DECRIPTION OF THE INVENTION
19
Embodiments of a wellbore obstruction-clearing tool are connected to a
downhole end of a string of tubulars, such as casing or coiled tubing (CT), to
aid in
21
advancing or removing the tubulars within a wellbore. Thus, the obstruction-
clearing
22 tool
obviates the need to rotate the casing thereby, substantially avoiding
problems
23
associated therewith, such as torque build up along the casing. For the
purposes of
8
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1 the description which follows, Applicant has described the tool in the
context of use
2 with casing. Those of skill in the art will appreciate however, that
embodiments
3 disclosed herein are not limited for use with casing and are suitable for
use with other
4 tubulars having a bore formed therethrough and for which rotation is to
be avoided.
In embodiments, a tubular sleeve is caused to rotate while extending
6 and retracting along a mandrel connected to the downhole end of the
casing. Axial
7 reciprocation and rotation of the sleeve along the mandrel is initiated
by axial
8 reciprocation of the casing in the wellbore, commonly referred to as
stroking of the
9 casing. At least the rotation of the sleeve within the wellbore clears
any obstruction,
creating debris, the debris being conveyed to surface by circulation of fluids
downhole
11 through the casing and uphole to surface through an annulus between the
casing and
12 the wellbore. When the obstructions are removed from the wellbore, the
casing can
13 be lowered to a target depth such as prior to cementing the casing into
place in the
14 wellbore.
In embodiments, fluid, such as a drilling fluid, is injected or pumped
16 downhole through the casing. The mud is circulated up the annulus for
conveying the
17 debris to surface. Further, extending or resetting of the tubular sleeve
can be through
18 hydraulic impetus from the drilling fluid and gravity depending on the
wellbore
19
orientation. The fluids discharging from the casing can also aid in
clearing
obstructions by fluidly engaging the wellbore obstructions, such as in a
jetting action,
21 fluidly eroding the wellbore obstructions for creating debris therefrom.
A velocity of the
22 fluids discharged can be increased for enhancing the fluid erosion. The
downhole end
23 of the sleeve can also physically disrupt the obstructions for creating
debris therefrom.
9
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1 In more detail, and having reference to Figs. 1 and 2 of one
2 embodiment, an obstruction-clearing tool 100 is connected at a downhole
end 12 of
3 a tubing string, such as casing 10 or coiled tubing (CT) for clearing
obstructions 119
4 from a wellbore 14.
The obstruction-clearing tool 100 comprises a tubular mandrel 120,
6 connected, such as by threading, to the downhole end 12 of the casing 10
and
7 having a mandrel bore 121 which is fluidly connected to an axial bore 11
of the
8 casing 10.
9 A tubular sleeve 110 having a sleeve bore 115 is fit
concentrically
about the tubular mandrel 120 and is axially displaceable therealong between
11 a fully retracted position, wherein a downhole end 112 of the sleeve 110
is adjacent
12 a downhole end 127 of the mandrel 120, and a fully extended position,
wherein the
13 downhole end 112 of the sleeve 110 is displaced axially away from the
downhole
14 end 127 of the mandrel 120.
In embodiments, fluid F is pumped through the contiguous bores of
16 the casing's axial bore 11, the mandrel bore 121 and the sleeve bore
115. The fluid
17 F discharges from the sleeve bore 115 and into the wellbore 14. The
fluid F is
18 circulated along an annulus 20, between the casing 10 and the wellbore
14, to
19 surface through the annulus 20.
A drive arrangement, co-operates between the mandrel 120 and the
21 sleeve 110, and permits the sleeve 110 to be rotated as the sleeve 110
is axially
22 displaced along the mandrel 120. Thus, the sleeve 110 is axially and
rotationally
23 displaceable between the extended and retracted positions.
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1 The
tubular sleeve 110 engages obstructions 119 in the wellbore 14.
2
Applicant believes that at least the engagement of the sleeve 110, and
rotational
3
movement thereof, aids in agitating or disrupting the obstructions 119. The
fluids F
4
discharged through the sleeve bore 115 convey the debris from the wellbore 14
as the
fluid F is circulated to surface through the annulus 20. Fluid F, where
discharged so
6 as to
contact the obstruction 119, further acts to fluidly erode the obstructions
119,
7 enhancing the production of debris therefrom.
8 In
greater detail, as shown in Figs. 1, 2, 4A and 4B, the drive
9
arrangement is a helical drive arrangement formed between the mandrel 120 and
the
sleeve 110. One or more helical slots or grooves 122 cooperate with one or
more
11
protrusions 111, such as buttons, pins or the like, for guiding the sleeve 110
12
rotationally and axially relative to the mandrel 120. In an embodiment, the
one or more
13
helical grooves 122 are formed on either of an inner surface 115 of the sleeve
110 or
14 on an
external surface 126 of the mandrel 120. The one or more protrusions or guide
pins 111 extend radially from the other of the outer surface of the mandrel
120 or the
16 inner surface of the sleeve 110.
17
Referring again to Figs. 1 to 3, in an embodiment, the helical drive
18
arrangement comprises three helical grooves 122, 122, 122, equally spaced
apart in
19 the
external surface 126 of the mandrel 120, and three corresponding guide pins
111,111,111 spaced equally apart and extending radially inwardly from an inner
21
surface 115 of the sleeve 110. Each pin 111 engages a corresponding helical
groove
22 122.
Use of the three helical grooves 122, 122, 122 and corresponding guide pins
23 111,
111, 111 acts to centralize the mandrel 120 within the sleeve 110. As the
sleeve
11
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1 110 is
extended or retracted along the mandrel 120, the sleeve 110 rotates as the pin
2 111
follows the path of the helical groove 122. The three pins 111,111,111 are
3
positioned adjacent the uphole end 114 of the sleeve 110 to permit full axial
extension
4 of the
sleeve 110 along the mandrel 120. The tolerance between the sleeve 110 and
the mandrel 120 is sufficiently tight such that the each guide pin 111 remains
in the
6
corresponding helical groove 122, when the tool 100 is assembled. The
direction of
7 the
helical grooves 122, 122, 122 ensures that rotational loading on the mandrel
120
8 is
compatible with conventional threaded connection of the mandrel 120 to the
casing
9 10 to
avoid separation of the obstruction-clearing tool 100 from the casing 10
during
use.
11 With
reference to Figs. 4A and 4B, a pitch of each helical groove 122
12 may be
uniform along the path of the helical grooves 122, being substantially a
length
13 of the
mandrel 120 (Fig. 4A) or may vary (Fig. 4B) to change the speed of rotation
and
14 the
corresponding effort to initiate rotation of the sleeve 110 as the sleeve 110
moves
axially along the length of the mandrel 120.
16 In an
embodiment as shown in Fig. 4B, the pitch of the helical grooves
17 122 is
about 60 degrees, measured from a transverse plane, at a location adjacent the
18 uphole
end 128 of the mandrel 120, which decreases to about 45 degrees, then to
19 about
30 degrees and thereafter increases again from 30 degrees, to about 45
degrees and then to about 60 degrees at the downhole end 127 of the mandrel
120.
21 Thus,
the sleeve 110, as it extends or retracts axially along the length of the
mandrel
22 120,
begins to easily and slowly rotate at either the uphole or downhole end
128,127
23 of the
mandrel 120. As the sleeve 110 moves axially along the mandrel 120, the
12
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1 rotational speed increases as the sleeve 110 passes through the about 45
degree
2 section and then the about 30 degree section. Thereafter, as the sleeve
110 continues
3 to move axially and enters the subsequent about 45 degree section,
rotation of the
4 sleeve 110 begins to slow and as the sleeve 110 enters the about 60
degree section,
the sleeve 110 has slowed once again to the easy, slow rotation.
6 Axial movement of the mandrel 120, fixed to the casing 10, causes
the
7 sleeve 110 to reciprocate along the mandrel 120. A downhole stroke of the
casing 10
8 causes the sleeve 110 to rotate in one direction and an uphole stroke of
the casing
9 causes the sleeve 110 to rotate in the opposite direction. The downhole
stroke
causes the sleeve 110 to retract along the mandrel 120 and the uphole stroke
permits
11 the sleeve 110 to extend along the mandrel 120. The impetus to retract
the sleeve 110
12 relative to the mandrel 120 is by resistance encountered at the sleeve,
such as by the
13 obstruction 119, or a tight wellbore 14. The impetus to extend the
sleeve 110 relative
14 to the mandrel 120 is by hydraulic force created by the fluid F on the
downhole end of
the sleeve and gravity depending on the orientation of the wellbore, being
most
16 effective in vertical wellbores.
17 In one method of manufacture the sleeve 110 is slipped over the
18 mandrel 120 and the pins 111 are installed through the sleeve 110 to
engage the
19 helical grooves 122. The pins 111 are retained therein, such as by
deformation of the
installation hole, or use of a cap screw or welding.
21 In an embodiment of the invention, the mandrel 120 is threadably
22 connected to a last joint of casing 10. The uphole end 128 of the
mandrel 120 has a
23 box end which is threaded to a conventional pin end at the downhole end
12 of the
13
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1 casing
10. A thickness of the tubular mandrel 120 is generally greater than a
2 thickness of the casing 10 to permit machining of the helical grooves 122
therein.
3 As
shown in Fig. 1 and in greater detail in Figs. 6B, 6C, 10B and 100, at
4 least
one stop is formed between the sleeve 110 and the mandrel 120 to limit the
axial
movement of the sleeve 110 along the mandrel 120 and to retain the sleeve 110
6 thereon.
7 As
shown in Figs. 60 and 10C, an uphole stop 113 is formed at the
8 uphole
end 114 of the sleeve 110. A downhole stop 123 is formed between the
9
downhole end 127 of the mandrel 120 and the uphole end 114 of the tubular
sleeve
110 for retaining the sleeve 110 on the mandrel 120 when in the fully extended
11
position. Similarly, as shown in Figs. 6B and 10B, an uphole stop 125 is
formed
12 between
an uphole end 128 of the mandrel 120 and the sleeve's uphole stop 113 for
13 retaining the sleeve 110 on the mandrel 120 when in the fully retracted
position.
14 Annular
seals are positioned to fluidly seal between the sleeve 110 and
the mandrel 120. A downhole annular seal 124 is positioned such that the
downhole
16 seal
124 becomes sandwiched axially between the mandrel's downhole stop 123 and
17 the
sleeve's uphole stop member 113 when the sleeve 110 is in the fully extended
18
position. An annular seal 126 is positioned such that it becomes sandwiched
axially
19 between
the uphole stop 125 and the sleeve's uphole stop member 113 when the
sleeve 110 is in the fully retracted position.
21 In an
embodiment, a shipping or shear pin 129 is employed to maintain
22 the
sleeve 110 in the axially retracted position during shipping. Depending on
23
operator technique, the shear pins can also maintain the sleeve 110 in the
axially
14
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1 retracted position running-in of the casing 10 and the tool 100. The
shear pin 129
2 extends radially inwardly from the stop member 113 on the uphole end 114
of the
3 sleeve 110 to engage the uphole end 128 of the mandrel 120. When removed
after
4 shipping, or if retained, when sheared in the wellbore, the sleeve 110 is
freed to
reciprocate as described herein in response to the axial reciprocation of the
casing 10
6 and mandrel 120.
7 As shown in Figs. 1 and 3, the downhole end 112 of the sleeve 110
may
8 be tapered, such as to a truncated cone shape, so as to narrow the cross-
section area
9 of the sleeve bore 115 to increase the velocity of fluids F exiting
therefrom. The
increase in velocity acts to increase the degree of agitation caused by the
fluids F
11 exiting therefrom. Alternatively, the sleeve bore 115 can be configure
to affect the
12 fluid F issuing therefrom for forming an extending force and for jetting
fluids therefrom.
13 Having reference again to Fig. 3, in an embodiment, the downhole
end
14 112 of the sleeve bore 115 is fit with a flow restrictor 140. The flow
restrictor 140
reduces the diameter of the sleeve bore 115 or forms one or more openings 142
of
16 smaller diameter therein for increasing the extending force acting on
the sleeve and
17 for increasing velocity of the fluid F discharged therethrough. The
higher velocity
18 causes the discharged fluid F to increase the degree of agitation caused
by the fluids
19 F exiting therefrom and to engage the obstructions 119 with greater
force to further aid
in erosion of the obstructions 119.
21 In vertical wellbores, stroking the casing 10 uphole permits
gravity to act
22 on the sleeve 110 for causing axial extension of the sleeve 110 along
the mandrel
23 120. In the case of horizontal wellbores, there is little to no
gravitational impetus to
CA 02733339 2011-03-03
1 cause axial extension of the sleeve 110. In this case, the flow
restrictor 140 further
2 acts to create an uphole face or shoulder 141 upon which the fluid F
pumped through
3 the sleeve bore acts, creating a backpressure and an extending force or
impetus for
4 hydraulic extension of the sleeve 110.
Optionally, as shown in Fig. 3, ribs 116 may be formed on an outer
6 surface 117 of the sleeve 110 to act as centralizers for avoiding contact
between the
7 sleeve 100 and the wellbore 14, preventing reaming of the wellbore 14. In
an
8 embodiment, the ribs 116 are helical and are formed on the outer surface
117 of the
9 sleeve 110 to minimize reaming should the ribs 16 come into contact with
the wellbore
14. Further, helical ribs 116 provide a passage for fluids circulated in the
annulus 20
11 to surface and therefore do not block the annulus 20 to the passage of
fluids
12 therethrough, permitting fluid F and debris to be directed up the
annulus 20 to surface.
13 Further, in the case of horizontal wellbores, the centralizing
ribs 116 may
14 engage and drag in the wellbore 14 during uphole stroking of the casing
10, assisting
with axial extension of the sleeve 110 relative to the mandrel 120.
16 In an embodiment, as shown in Fig. 3, the downhole end 112 of the
17 sleeve 110, further comprises a plurality of protrusions 131 (Fig. 3),
such as teeth,
18 extending outwardly therefrom. The plurality of protrusions 131 act to
either physically
19 engage the obstruction for disrupting the obstruction and forming debris
therefrom or
to agitate fluid about the obstructions for fluidly eroding the obstruction or
a
21 combination thereof. The plurality of protrusions 131 are made from
tungsten carbide
22 or are coated with tungsten carbide to increase the strength and to
enhance the
23 cutting ability of the plurality of protrusions 131. The plurality of
protrusions 131 are
16
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1 formed on the downhole end 112 of the sleeve 110, are welded to the
downhole end
2 112 of the sleeve 110 or are replaceably threaded to the downhole end 112
of the
3 sleeve 110, such as on a threaded shoe 130, as shown in Fig. 1.
4 Similarly, as shown in Figs. 7, 12 and 13 the protrusions 131 can
be
various forms of teeth 161. The plurality of protrusions 131 or teeth 161 are
positioned
6 circumferentially about the downhole end 112 of the sleeve 110. As shown
Fig. 1 , the
7 plurality of protrusions 131 can be generally offset from one another,
such as radially
8 set, or opposingly oriented circumferentially, or both, to aid in
engaging and agitating
9 obstructions, aiding in the erosion thereof. Further turbulence aids in
keeping the
debris from settling out of the fluid F so as to lift the debris with the
fluid F to surface.
11 With reference to Figs. 5 to 12, and in an embodiment, the
protrusions
12 131 are provided by mechanical means, such as conventional cutters or
teeth 161, on
13 a drill bit 150 fit to the downhole end 112 of the sleeve 110. The drill
bit 150 has one or
14 more openings 151 therein for discharging the fluid F therefrom.
As shown in Figs. 7 and 8, and in an embodiment, the drill bit 150 is a
16 PDC-equipped drill bit comprising a tapered or bullet-shaped leading
surface 152 and
17 PDC cutter elements 153. A tapered or bullet contoured leading surface
152 aids in
18 tracking of the wellbore such as in horizontal wells. The leading
surface 152 of the
19 drill bit further comprises at least one opening 151 for permitting
fluid F to pass
therethrough from the sleeve bore 115 to the annulus 20. The at least one
opening
21 151 functions similarly to the flow restrictor 140 and acts to restrict
the flow of the fluid
22 F passing therethrough for increasing the velocity of the fluid F.
Further, an uphole
17
CA 02733339 2011-03-03
1 face 154 created by the leading surface 152 aids in increasing the
backpressure
2 acting thereon for extension of the sleeve 110 to the extended position.
3 With reference to Figs. 9A-12, the drill bit 150 is a tubular
drill bit 160
4 having an open bore 162 which is contiguous with the sleeve bore 115 for
delivery of
fluids F therethrough and a plurality of teeth 161 (Figs. 11 and 12) extending
6 downwardly therefrom for forming the protrusions 131. The tubular drill
bit 160 further
7 comprises flow restrictor 140. The flow restrictor 140 is positioned
within the bore 162
8 for increasing the velocity of the fluids passing therethrough and
provides uphole
9 surface 154 for hydraulically extending the tubular sleeve 110.
In the case of horizontal wellbores 14, the teeth 161 formed about the
11 open bore 162 can engage and ream the wellbore 14. An alternate
embodiment of bit
12 179 is shown in Fig. 13.
13 In some embodiments, there may be an objective to drill through
the
14 obstruction-clearing tool 100. In a conventional casing operation,
casing is advanced
into the wellbore 14 until the casing 10 is landed at the target depth. The
casing 10 is
16 cemented into place. In embodiments, for use where there is no
expectation to extend
17 the wellbore 14 after cementing the casing 10, the obstruction-clearing
tool 100 is
18 manufactured of robust 4140 steel.
19 In embodiments, for use where the depth of the wellbore 14 is to
be
extended following cementing of at least a first section of casing 10, at
least portions
21 of the obstruction-clearing tool 100 are made to be drillable. Due to
the nature of the
22 tool 100 to have relative rotatable components, accommodations are made
to avoid
18
CA 02733339 2011-03-03
1
reactive rotation of one or more portions of the tool 100 when drilling
through the tool
2 100.
3
Generally, the drillable portions are made of less competent materials,
4 such as
aluminum and aluminum composites, which facilitate being drilled out. In
such cases, the portions that are made drillable are generally internal
components
6 which
would otherwise interfere with or retard passage of a drill string
therethrough,.
7 The bit
150 can also be drillable or its design accommodates passage of a drill string
8
therethrough, such as in the tubular drill bit 160 embodiment of Fig. 12,
which
9 minimally obstructs the bore 115 of the sleeve 110.
For example, the mandrel 120 may be formed of aluminum and the
11 guide
pins 111 may be made of bronze while the remaining components such as the
12 sleeve
110 are made of 4140 steel. The bit 150 is also made of less competent
13 materials permitting drilling therethrough.
14 In an
embodiment, shown in Fig. 13, a drillable bit incorporates robust
characteristics used for engaging and clearing the wellbore obstructions 119,
yet
16 permits
drilling out for passage of a subsequent drill string therethrough for
extending
17 the
wellbore 14 beyond the initial target depth. . The bit 150 comprises a tubular
bit
18 body
170 made of robust steel construction including polycrystalline diamond
compact
19 (PDC)
cutter elements (not shown), which are not readily drilled through. The
tubular
bit body 170 has a bit bore 171 formed therein through which the drill string
may pass,
21 the bit
170 body being substantially avoided. A less competent bit insert 173 is fit
22 within
the bit bore 171, the bit insert 173 having a leading bit surface 174
comprising
23 the
plurality of protrusions 131 such as teeth of cutters 175 formed thereon. The
19
CA 02733339 2011-03-03
1 plurality of cutters 175 engage the obstructions 119 much like the
protrusions 131 and
2 drill bits 150, 160 of the previously described embodiments. The bit
insert 173 further
3 forms the flow restrictor 140, as previously described both for
increasing the velocity of
4 fluid F discharged therefrom and for hydraulic extension of the sleeve
110.
The bit body 170 is manufactured from robust 4140 hardened steel.
6 The bit insert 173 and the flow restrictor 140 are manufactured from 6061
aluminum,
7 which is suitable to withstand the rigors of the casing stroking
operation yet are
8 drillable.
9 The drillable embodiment of the obstruction-clearing tool 100 is
connected to the downhole end 11 of the casing 10 and casing 10 is lowered to
the
11 target depth, the obstruction-clearing tool 100 acting as a landing
tool. The casing 10
12 is thereafter cemented into with wellbore 14 using conventional
cementing operations.
13 Cement is pumped through the casing 10 and is discharged from the
downhole end
14 112 of the sleeve 110 and into the annulus 20. The cement hardened about
the
sleeve 110 prevents any further axial or rotational movement of the sleeve 110
about
16 the stationary mandrel.
17 In drill-through operations, a secondary drill string and drill
bit can
18 damage or drill out the helical drive connection between the mandrel 120
and the
19 sleeve 110. Free rotation of the mandrel ahead of the secondary drill
string nullifies
the drilling operation. Several features are provided in one or more
embodiments, to
21 minimize problems when drilling through the tool 100.
22 In one embodiment, shown in Figs. 13-16, a locking mechanism 180
23 connects between the mandrel 120 and sleeve 110 in the fully retracted
position,
CA 02733339 2011-03-03
1 preventing independent rotation of the mandrel 120 should the connection
between
2 the mandrel 120 and the casing 10 and the mandrel 120 and the sleeve 110 be
3 compromised. As shown in greater detail in Figs. 14 and 15, the locking
mechanism
4 180 is an interlocking interface, such as a castellated interface,
between the downhole
end 127 of the mandrel 120 and the downhole end 112 of the sleeve 110 for
6 interlocking the components and preventing relative rotational movement
7 therebetween. The downhole end 127 of the mandrel 120 comprises a first
8 castellated profile 181 (Fig. 14) having a plurality of circumferentially-
spaced axially-
9 extending projections 182 formed thereon and a plurality of recesses 186
therebetween. Similarly, the downhole end 112 of the sleeve 110 comprises a
second
11 castellated profile 183 (Fig. 15) having a plurality of
circumferentially-spaced, axially-
12 extending projections 184 formed thereon and a plurality of recesses 188
13 therebetween. In an interlocked position, with the first and second
castellated profiles
14 181,183 being face-to-face, the projections 182 of the first castellated
profile 181 are
engaged in the recesses 188 of the second castellated profile 183.
Accordingly, the
16 projections 184 of the second castellated profile 183 are engaged in the
recesses of
17 the first castellated profile 181. In the interlocked position, the
mandrel 120 is
18 prevented from rotating.
19 The mandrel 120 and the sleeve 110 may not be in the interlocked
position when the drilling operation begins, such as when the sleeve 110 is in
the
21 axially extended position when cemented in. In such instances, when the
mandrel
22 120 becomes free to rotate with the drill string, the remaining portion
of the mandrel
23 120 having the first castellated profile 181 is pushed downhole by the
secondary drill
21
CA 02733339 2011-03-03
1 string.
The first castellated profile 181 is caused to engage with the second
2
castellated profile 183 of the sleeve 110 in the interlocked position
preventing further
3
rotational movement of the mandrel 120 and permitting the drilling operation
to
4 continue.
In an embodiment as shown in Figs. 13 and 16, the locking mechanism
6 180
comprises a uni-directional, screw-head-type interlocking cog-like interface
having
7
cooperating and rotationally ramped axial faces 185, 186 for arresting co-
rotation of
8 the mandrel 120 during drilling out.
9 In an
embodiment which minimizes deviation of the extended wellbore
when drilling through the tool, the mandrel and sleeve are provided with a
casing shell
11 190 which guides the second drill through the tool 100.
12 Having
reference to Figs. 17A and 17B, an obstruction-clearing tool 100
13 having
a drillable bit 170, further comprises a casing shell 190 manufactured from
14
materials that are resistant to drilling or milling, such as 4140 hardened
steel. The
casing shell 190 shields the mandrel 110 for guiding the second drill string
along a
16
drilling path substantially in alignment with the mandrel 120 and into the
sleeve 110.
17 The
casing shell 190 is fit concentrically over the mandrel 120, and
concentrically and
18
slidably over the sleeve 110, and extends along a length of the mandrel 120
from
19 about
the mandrel's upper end 128 to the mandrel's downhole end 127. The casing
shell 190 is secured to the mandrel's upper end 128 by an upper collar 191 and
21
slidable over the sleeve 110. The casing shell 190 is stationary with the
mandrel 120
22 during
axial extension of the sleeve 110. A downhole end 192 of the casing shell 190
23 is
slidably and rotatably stabilized about the sleeve 110 by a downhole collar
192. As
22
CA 02733339 2013-03-18
1 shown in Fig. 17B, the sleeve 110 passes through the downhole collar 192
when
2 the sleeve 110 is axially extended, the casing shell 190 remaining
3 substantially surrounding the mandrel 120.
4 As one of skill in the art will appreciate, the obstruction-
clearing tool
100 can be sized appropriately depending upon the size of the casing 10 being
6 utilized. That is, the obstruction-clearing tool 100 can be adapted to
operatively and
7 fluidly connect to tubulars commonly used in the industry, such as 4 1/2
inch, 5 %
8 inch, 7 inch, or 9 5/8 inch casings and 2 7/8 inch coiled tubing, or can
be custom
9 sized for any size casing 10 or CT.
As shown in Figs. 5 and 6A to 6C, an obstruction-clearing tool 100,
11 particularly suited for use in vertical wellbores with 5 % inch casing
10, comprises a
12 mandrel 120 having a diameter of about 4.25 inches and a length of about
68
13 inches (about 1.73 m) and a sleeve 110 having a length of about 92
inches (about
14 2.34 m). The sleeve 110 has an inside diameter of about 4.89 inches
(about 12.42
cm) forming a clearance fit concentrically about the mandrel 120 and an
outside
16 diameter of about 5 IA inches (13.97 cm). Three, 1 inch (about 2.43 cm)
diameter
17 guide pins (not shown) are provided at about 120 degrees apart for
engaging three
18 parallel and helical grooves 122 in the mandrel 120. Annular seals 124,
126, such
19 as rubber cushions or large 0-rings, are fit about the mandrel's uphole
end 128 and
downhole end 127 as cushions between the mandrel 120 and sleeve 110 when the
21 sleeve 110 bottoms at each end of the stroke. The resulting stroke of
the
22 obstruction-clearing tool 100 is about 68.5 inches or about 5 feet (1.52
m) the
23 sleeve 110 rotating approximately 4.9 revolutions about the mandrel 120
per stroke.
23
CA 02733339 2011-03-03
1 With reference to Figs. 9A to 90, 10A to 10C, 11 and 12, an
2 embodiment well-suited for passing through and cleaning deviated or
horizontal
3 wellbores is shown. In Figs. 9A to 9C, a shorter or stubby embodiment
comprises a
4 mandrel 120 having a length of about 32 inches (about 81.28 cm) a
corresponding
sleeve 110 having a length of about 54.38 inches (about 1.38 m). When sized
for use
6 with a 7 inch casing, the mandrel 120 has a diameter of about 5.7 inches
(about 14.48
7 cm) and the sleeve 110 has an outside diameter of 7 inches (about 17.78
cm) and an
8 inside diameter of about 6.37 inches (about 16.18 cm). The stroke length
is about 32
9 inches (81.28 cm) and the sleeve 110 makes about 2 revolutions about the
mandrel
120 per stroke.
11
12 In Operation
13 Embodiments of the wellbore obstruction-clearing tool 100 are used
14 during casing of an open hole or wellbore 14 which has been drilled in a
previous
drilling operation. A survey can log obstructions, including tight spots,
requiring
16 clearing. The wellbore obstruction-clearing tool 100 is connected to a
bottom of a joint
17 of conventional casing and the casing is run into the wellbore.
18 Some operators prefer to remove the shipping or shear pin or pins
129
19 and run the tool 100 in extended, possibly operating passiveiy and
periodically on the
trip downhole. In other cases the shear pin or pins 129 remain in place to
retain the
21 sleeve 110 in the retracted position during tripping into the wellbore
14.
22 As shown in Fig. 18, with the shear pins 129 in place, and in a
vertical
23 wellbore, the casing 10 and tool 100 are lowered into the wellbore at
(1) and (2) to an
24
CA 02733339 2011-03-03
1 obstruction 119 at (3). A downhole shear force, such as a downhole set-
down load of
2 about 1000 lbs, is applied to the tool 100 at (4), sufficient to shear
the shear pins 129,
3 permitting the sleeve 110 to be free to move relative to the mandrel 120.
4 Once the sleeve 110 is free to move axially and rotationally
relative to
the mandrel 120, the casing 10 and mandrel 120 are lifted or stroked uphole at
(5)
6 with sleeve 110 moving rotationally towards its extended position. The
casing is
7 stroked upwardly and the sleeve 110 reaches the extended position at (6).
The stoke
8 of the casing can be controlled and is not necessarily stroked to the
full extension or
9 the full retraction.
The stroking of the casing 10 continues uphole and downhole so as to
11 drive the tubular sleeve to rotate and reciprocate axially between the
retracted position
12 and the extended position for engaging the wellbore obstruction,
creating debris and is
13 repeated until the obstruction is cleared and the tool 100 can be landed
at target
14 depth, or the next obstruction.
In a vertical wellbore, extension of the sleeve 110, as the mandrel 120 is
16 stroked uphole, is largely under the influence of gravity and thus
lifting of the casing 10
17 may be sufficient to cause the sleeve 110 to extend. Fluid F is
typically used as well
18 for removal of debris and for extension of the sleeve 110.
19 With reference to Fig. 19, in a horizontal wellbore where gravity
provides
no gravitational impetus for the sleeve 110 to extend along the mandrel 120,
the fluid
21 F hydraulically extends the tubular sleeve to the extended position as
the tubing string
22 is stroked uphole. In this case, as the casing 10 is stroked uphole at
(3), the fluid F
CA 02733339 2011-03-03
1 forces the sleeve 110 to remain downhole, while rotating and may be
engaged against
2 the obstruction 119.
3 With reference to Figs. 20, in a typical clearing operation as
shown from
4 left to right, whether the wellbore 14 is vertical or horizontal, the
casing 10 is stroked
downhole from an extended position at (1) to a retracted position at (6). The
stroking
6 of the casing and mandrel 120 causes the sleeve 110 to axially and
rotationally retract
7 along the mandrel 120. The rotation of the sleeve 110 engages the
obstruction 119
8 and creates debris therefrom. The fluids F circulated uphole through the
annulus 20
9 convey the debris to surface.
Thereafter, as shown from right to left in Fig. 21, and beginning with the
11 tool at the retracted position at step (7), the casing 10 and mandrel
120 are lifted clear
12 of any remaining obstruction 119. As shown in steps (8) through (12), as
the sleeve
13 110 extends along the mandrel 120 the sleeve 110 rotates in the opposite
direction to
14 that when the sleeve is retracted along the mandrel 120. The sleeve 110
resets for a
subsequent downstroke of Fig. 20, but also continues to rotate and discharge
fluid F
16 for engaging the obstruction.
17 The operation of Figs. 20 and 21 is repeated as many times as is
18 necessary to clear the obstruction 119, and for each and any subsequent
obstructions,
19 sufficient that the casing 10 can be advanced thereby until the casing
10 reaches the
target depth. As will be appreciated by those of skill in the art the tool 100
according
21 to embodiments of the invention acts as a casing landing tool.
Thereafter, such
22 apparatus as may be required to cement the casing into the wellbore is
run into the
23 casing 10.
26
CA 02733339 2011-03-03
1 With
reference to Figs. 22A and 22B, in a drillable embodiment using a
2 form of
tool 100 set forth in Figs. 17A and 17B, a length of a wellbore 14 is
extended,
3 As
secondary drill string 200 and drill bit 201, has an outer diameter smaller
than the
4 inner
diameter of the sleeve 110. At least a portion of the mandrel 120, the bit 150
and the flow restrictor 140 are drilled through for gaining access to the
formation below
6 the previously cased wellbore 14 and drilling an extension of the
wellbore therein.
7
8 Example
9 An
embodiment of the invention was tested during casing of a vertical
wellbore in which normal casing operations were first attempted and had
failed.
11
Obstructions were encountered at about 1 kilometer downhole preventing passage
of
12 the casing to the target depth.
13
Previously, a drilling fluid was circulated through the casing and adjacent
14 the
obstructions in an attempt to hydraulically clear the obstruction. The process
lasted
three successive days, at great expense, and was ultimately unsuccessful in
clearing
16 a first
obstruction. The casing was tripped out and a mud motor was run downhole to
17
mechanically drill through the first obstruction. The conventional mandrel,
drill bit and
18 bottom
sub of the expensive mud motor were eventually lost downhole without
19
successfully clearing the first obstruction. The bottom sub of the mud motor
was
eventually recovered by a fishing operation. Several weeks were lost and the
first
21 obstruction was still not cleared.
22
Thereafter, an obstruction-clearing tool 100 was operatively and fluidly
23
connected to the casing and run downhole. The obstruction-clearing tool was
27
CA 02733339 2011-03-03
1 actuated when the first obstructions was reached. The casing and the tool
were
2 stroked fully, uphole and downhole, three times. The obstruction was
successfully
3 cleared and the casing advanced thereby.
4
28
