Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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EXTERNAL GRIP TUBULAR RUNNING TOOL
BACKGROUND
This application is a divisional application of co-pending application Serial
No. 2.741.532,
filed April 21,2011.
[0001] This section provides background information to facilitate a better
understanding of
the various aspects of the present invention. It should be understood that the
statements in
this section of this document are to be read in this light, and not as
admissions of prior art,
[0002] A string of wellbore tubulars (e.g., pipe, casing, drillpipe, etc.) may
weigh hundreds
of thousands of pounds. Despite this significant weight, the tubular string
must be carefully
controlled as tubular segments are connected and the string is lowered into
the wellbore and
as tubular segments are disconnected and the tubular string is raised and
removed from the
wellbore. Fluidicly (e.gõ hydraulic and/or pneumatic) actuated tools, such as
elevator slips
and spider slips, are commonly used to make-up and run the tubular string into
the wellbore
and to break the tubular string and raise it from the wellbore. The elevator
(e.g., string
elevator) is carried by the traveling block and moves vertically relative to
the spider which is
mounted at the drill floor (e.g., rotary table). Fluidic (e.g., hydraulic
and/or pneumatic)
control equipment is provided to operate the slips in the elevator and/or in
the spider.
Examples of fluid ically actuated slip assemblies (e,g, elevator slip
assemblies and spider slip
assemblies) and controls are disclosed for example in U.S. Pat. No. 5,909,768;
and U.S. Pat.
Appl. Pub. Nos. 2009/0056930 and 2009/0057032.
[0003] The tubular string it typically constructed of tubular segments which
are connected by
threading together. Traditionally, the top segment (e.g., add-on tubular)
relative to the
wellbore is stabbed into a box end connection of the tubular string which is
supported in the
wellbore by the spider. It is noted that the pin and box end may be unitary
portions of the
tubular segments (e.g., drillpipe) or may be provided by a connector (e.g.,
casing) which is
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commonly connected to one end of each tubular prior to running operations. In
many
operations, the threaded connection is then made-up or broken utilizing tools
such as
spinners, tongs and wrenches. One style of devices for making and breaking
wellbore tubular
strings includes a frame that supports up to three power wrenches and a power
spinner each
aligned vertically with respect to each other. Examples of such devices are
disclosed in U.S.
Pat. No. 6,634,259. Examples of some internal grip tubular running devices are
disclosed in
U.S. Pat. Nos. 6,309,002 and No. 6,431,626.
[0004] The tubular segments may be transported to and from the rig floor and
alignment with
the wellbore by various means including without limitation, cables and
drawworks, pipe
racking devices, and single joint manipulators. An example of a single joint
manipulator arm
(e.g., elevator) is disclosed in U.S. Pat. Appl. Publ. No. 2008/0060818. The
disclosed
manipulator is mounted to a sub positioned between the top drive and the
tubular running
device. A sub mounted manipulator (e.g., single arm, double arm, etc.) may be
utilized with
the device of the present disclosure.
[0005] It may be desired to fill (e.g., fill-up and/or circulate) the tubular
string with a fluid
(e.g., drilling fluid, mud) in particular when running the tubular string into
the wellbore. In
some operations it may be desired to perform cementing operations when running
tubular
strings, in particular casing strings. Examples of some fill-up devices and
cementing devices
are disclosed in U.S. Patent Nos. 7,096,948; 6,595,288; 6,279,654; 5,918,673
and 5,735,348.
=
[0006] Tubular strings are often tapered, meaning that the outside diameter
(OD) of the
tubular segments differ along the length of the tubular string, e.g., have at
least one outside
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diameter transition. Generally the larger diameter tubular sections are placed
at the top of the
wellbore and the smaller size at the bottom of the wellbore, although a
tubular string may
include transitions having the larger OD section positioned below= the smaller
OD section.
Running tapered tubular strings typically requires that specifically sized
pipe-handling tools
(e.g., elevators, spiders, tongs, etc.) must be available on-site for each
tubular pipe size. In
some cases, the tubular, in particular casing, may have a relatively thin wall
that can be
crushed if excess force is applied further complicating the process of running
tubular strings.
[0007] It is a desire, according to one or more aspects of the present
disclosure, to provide a
method and device for running a tapered tubular string into and/or out of a
wellbore. It is a
further desire, according to one or more aspects of the present disclosure, to
provide a method
and device that facilitates filling a tubular string with fluid during a
tubular running
operation.
SUMMARY
[0008] A tubular running tool according to one or more aspects of the present
disclosure
includes a carrier connected to traveling block of a drilling rig; a body
having a tapered
surface, the body rotationally connected to the carrier; slips moveably
disposed along the
tapered surface for selectively gripping a tubular; and a rotational device
connected to the
slips, the rotational device selectively rotating the slips and gripped
tubular relative to the
carrier.
[0009] A method for running a tubular string in wellbore operations according
to one or more
aspects of the present disclosure includes providing a tubular running tool
comprising
gripping assembly rotationally connected to a carrier, the gripping assembly
comprising a
body and slips; connecting the carrier to a quill of a top drive of a drilling
rig; positioning an
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end of a tubular for gripping with the slips; actuating the slips into
gripping engagement with
the tubular; and rotating the tubular with the slips in gripping engagement
therewith.
[0010] According to one or more aspects of the present disclosure, a method
for running a
tubular string with at least one outer diameter transition into a wellbore
includes suspending a
tubular running device from a drilling rig, the tubular running device
comprising a carrier, a
body forming a bowl, the body rotationally connected to the carrier, slips
moveably disposed
in the bowl, an actuator for at least one of raising and lowering the slips
relative to the bowl,
and a rotational actuator for selectively rotating the slips; gripping a
tubular string with a
spider to suspend the tubular string in the wellbore, the tubular string
having a first outside
diameter; gripping a first add-on tubular with the slips of the tubular
running device, the add-
on tubular having a first outside diameter; threadedly connecting the add-on
tubular to the
tubular string; releasing the grip of the spider on the tubular string and
suspending the tubular
string in the wellbore from the tubular running device; lowering the tubular
string into the
wellbore by lowering the tubular running device toward the spider; engaging
the spider into
gripping engagement of the tubular string; releasing the tubular running
device from the
tubular string; gripping a second add-on tubular with the tubular running
device, the second
add-on tubular gripped at a location thereof having a second outside diameter
different from
the first outside diameter of the tubular string; and threadedly connecting
the add-on tubular
to the tubular string.
[0011) The foregoing has outlined some features and technical advantages of
the present
disclosure in order that the detailed description that follows may be better
understood.
Additional features and advantages will be described hereinafter which form
the subject of
the claims of the invention.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The present disclosure is best understood from the following detailed
description
when read with the accompanying figures. It is emphasized that, in accordance
with standard
practice in the industry, various features are not drawn to scale. In fact,
the dimensions of
various features may be arbitrarily increased or reduced for clarity of
discussion.
[0013] Figure 1 is a schematic 'view of an apparatus and system according to
one or more
aspects of the present disclosure.
[0014] Figure 2 is a schematic, perspective view of a tubular running device
according to
one or more aspects of the present disclosure.
[0015] Figure 3 is a schematic, cut-away view of tubular running device
according to one or
more aspects of the present disclosure.
[0016] Figure 4 is a sectional top view of a tubular running device according
to one or more
aspects of the present disclosure.
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DETAILED DESCRIPTION
[0017] It is to be understood that the following disclosure provides many
different
embodiments, or examples, for implementing different features of various
embodiments.
Specific examples of components and arrangements are described below to
simplify the
present disclosure. These are, of course, merely examples and are not intended
to be limiting.
In addition, the present disclosure may repeat reference numerals and/or
letters in the various
examples. This repetition is for the purpose of simplicity and clarity and
does not in itself
dictate a relationship between the various embodiments and/or configurations
discussed.
Moreover, the formation of a first feature over or on a second feature in the
description that
follows may include embodiments in which the first and second features are
formed in direct
contact, and may also include embodiments in which additional features may be
formed
interposing the first and second features, such that the first and second
features may not be in
direct contact.
[00181 As used herein, the terms "up" and "down"; "upper" and "lower"; "top"
and "bottom";
and other like terms indicating relative positions to a given point or element
are utilized to
more clearly describe some elements. Commonly, these terms relate to a
reference point as
the surface from which drilling operations are initiated as being the top
point and the total
depth of the well being the lowest point, wherein the well (e.g., wellbore,
borehole) is
vertical, horizontal or slanted relative to the surface. The terms "pipe,"
"tubular," "tubular'
member," "casing," "liner," tubing," "drillpipe," "drillstring" and other like
terms can be used
interchangeably.
[0019] In this disclosure, "fluidically coupled" or "fluidically connected"
and similar terms
(e.g., hydraulically, pneumatically), may be used to describe bodies that are
connected in
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such a way that fluid pressure may be transmitted between and among the
connected items.
The term "in fluid communication" is used to describe bodies that are
connected in such a
way that fluid can flow between and among the connected items. Fluidically
coupled may
include certain arrangements where fluid may not flow between the items, but
the fluid
pressure may nonetheless be transmitted. Thus, fluid communication is a-subset
of fluidically
coupled.
[0020] The present disclosure relates in particular to devices, systems and
methods for
making and/or breaking tubular strings and/or running tubular strings. For
example devices,
systems and methods for applying torque to a tubular segment and/or tubular
string, gripping
and suspending tubular segments and/or tubular strings (e.g., lifting and/or
lowering), and
rotating (e.g., rotating while reciprocating) tubular segments and/or tubular
strings.
According to one or more aspects of the present disclosure, a tubular gripping
tool may
include fill-up, circulating, and/or cementing functionality.
[0021] Figure 1 is a schematic view of a tubular running device, generally
denoted by the
numeral 10, according to one or more aspects of the present disclosure being
utilized in a
wellbore tubular running operation. Tubular running device (e.g., tool) 10 is
suspended from
a structure 2 (e.g., rig, drilling rig, etc.) above a wellbore 4 by a
traveling block 6. In the
depicted embodiment, tubular running device 10 is connected to a top drive 8
which includes
a rotational motor (e.g., pneumatic, electric, hydraulic). Top drive 8 is
suspended from
traveling block 6 for vertical movement relative to wellbore 4. Top drive 8
may be connected
with guide rails. According to one or more aspects of the present disclosure,
tubular running
device 10 may be suspended from bails 18 or the like which may be suspended by
traveling
block 6 and/or top drive 8.
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[0022] Depicted device 10 is connected to top drive 8 via quill 12 (e.g.,
drive shaft) which
includes a bore for disposing fluid (e.g., drilling fluid, mud). In this
embodiment, device 10
also comprises a thread compensator 14. Thread compensator 14 may be
threadedly
connected between quill 12 and device 10, e.g., carrier 34 thereof.
Additionally or
alternatively, device 10 can be connected (e.g., supported) from bails 18,
e.g., in an
embodiment where the quill is not utilized to rotate device 10. Thread
compensator 14 may
provide vertical movement (e.g., compensation) associated with the travel
distance of the
add-on tubular when it is being threadedly connected to or disconnected from
the tubular
string. Examples of thread compensators include fluidic actuators (e.g.,
cylinders) and biased
(e.g., spring) devices. For example, the thread compensator may permit
vertical movement of
the connected device 10 in response to the downward force and movement of add-
on tubular
7a as it is threadedly connected to tubular string 5. One example of a thread
compensator is
disclosed in U.S. Pat. Appl. Publ. No. 2009/0314496.
100231 Tubular running device 10 is depicted supporting a string 5 of
interconnected tubular
segments generally denoted by the numeral 7. The upper most or top tubular
segment is
referred to as the add-on tubular, denoted in Figure 1 by call-out 7a. The
lower end 1 (e.g.,
pin end, distal end relative to traveling block 6) of add-on tubular 7a is
depicted disposed
with the top end 3 (e.g., box end) of the top tubular segment of tubular
string 5. Tubular
string 5 is disposed through support device 30 (e.g., spider slip assembly
i.e., spider) disposed
at floor 31. Spider 31 is operable to grip and suspend tubular string 5 in
wellbore 4 for
example while add-on tubular 7a is being connected to or disconnected from
tubular string 5.
10024] In Figure 1, add-on tubular 7a is depicted threadedly connected to
tubular string 5 at
threaded connection 11. For purposes of description, threaded connection 11 is
depicted to
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illustrate a box connection, e.g., proximal end of a drillpipe or an
internally threaded collar
which may be utilized when connecting casing segments for example. Depicted
tubular
string 5 is a tapered tubular string which has at least one outer diameter
transition, e.g.,
different outside diameters of the body of the tubular itself along its
length. For example,
tubular string 5 depicted in Figure 1 comprises add-on tubular 7a having an
outside diameter
DI connected to a section of string 5 having an outside diameter D2 which is
connected to a
section of string 5 that has an outside diameter D3. Although two outer
diameter transitions
are depicted in Figure 1, tool 10 may be used to run a single or greater than
two outer
diameter transitions. In one embodiment, the outer diameters refer to the body
of the tubular
itself, and not a differing OD connector portion thereof. Optional drill bit 9
is depicted
connected to the bottom end of tubular string 5 in Figure 1. According to one
or more
aspects of the present disclosure, tubular running device 10 may be utilized
while drilling (or
reaming) a portion of wellbore 4 with a drill bit (or reamer, etc.).
[0025] A single joint elevator 16 is depicted in Figure I suspended from bails
18 (e.g., link
arms which can be actuated, e.g., actuated to a non-vertical position to pick
up pipe from a V-
door of a rig) and traveling block 6 to illustrate at least one example of a
means for
transporting add-on tubular 7a to and from general alignment (e.g., staging
area) with
wellbore 4, e.g., for gripping the tubular at the top end 3 (e.g., proximal)
via tubular running
device 10. Bails 18, and thus elevator 16, may be connected to traveling block
6, top drive 8,
tubular running device 10, and/or other 'non-rotating devices (e.g., subs
etc.) intervening
traveling block 6 and tubular running device 10. For example, elevator 16 and
actuatable link
arms may be connected to a sub type member connected between traveling block 6
and/or top
drive 8 and tubular running device 10. In some embodiments, elevator 16 may be
suspended
for example on bails (e.g., actuatable members) from traveling block 6 or top
drive 8.
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Tubular running device 10 may include a pipe guide 76 positioned proximate to
the bottom
end of carrier 34 oriented toward spider 30 to guide the top end 3 of add-on
tubular 7a and/or
the top end of tubular string 5 into tubular running device 10. Pipe guide 76
may be
adjustable to grip a range of outside diameter tubular segments, such as
disclosed in U.S. Pat.
Appl. Pub. Nos. 2009/0056930 and 2009/0057032.
100261 Power and operational communication may be provided to tubular running
device 10
and/or other operating systems via lines 20. For example, pressurized fluid
(e.g., hydraulic,
pneumatic) and/or electricity may be provided to power and/or control one or
more devices,
e.g., actuators. In the depicted system, a fluid 22 (e.g., drilling fluid,
mud, cement, liquid,
gas) may be provided to tubular string 5 via mud line 24. Mud line 24 is
generically depicted
extending from a reservoir 26 (e.g., tank, pit) of fluid 22 via pump 28 and
into tubular string 5
via device 10 (e.g., fluidic connector, fill-up device, etc.). Fluid 22 may be
introduced to
device 10 and add-on tubular 7a and tubular string 5 in various manners
including through a
bore extending from top drive 8 and the devices intervening the connection of
the top drive to
device 10 as well as introduced radially into the section/devices intervening
the connection of
top drive 8 and device 10. For example, rotary swivel unions may be utilized
to provide fluid
connections for fluidic power and/or control lines 20 and/or mud line 24.
Swivel unions may
be adapted so that the inner member rotates for example through a connection
to the rotating
quill. Swivel unions may be obtained from various sources including Dynamic
Sealing
Technologies located at Andover, Minnesota, USA (www.sealingdynamics.com).
Swivel
unions may be used in one or more locations to provide relative movement
between and/or
across a device in addition to providing a mechanism for attaching and or
routing fluidic line
and/or electric lines.
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[00271 Figure 2 is a schematic view of a tubular running device 10 according
to one or more
aspects of the present disclosure. Depicted device 10 comprises a gripping
assembly 32
disposed with a carrier 34. Carrier 34 includes an upper member 36 and arms
38. A passage
40 is depicted formed through upper member 36. Passage 40 may provide access
for
disposing and/or connecting top drive 8 (e.g., quill 12 thereof). Passage 40
can be threaded,
e.g., internally threaded, to connect quill 12 for example. Top drive 8 via
quill 12, subs, and
the like may be connected to carrier 34 via top member 36 by threading for
example.
Referring to Figure 3, a rotary swivel union 72 is depicted connecting a lines
20 to device 10,
for example provide fluidic power and/or control to actuators connected with
the slips and
which rotate with the slips.
[00281 Gripping assembly 32 includes slips 42 and actuators 44. Although
multiple actuators
are depicted, a single actuator may be used to power the slips up and/or down
relative to bowl
60. According to one or more aspects, actuators 44 may be hydraulic or
pneumatic actuators
to raise and/or lower slips 42 relative to bowl 60 (Figure 3). In the depicted
embodiment,
gripping assembly 32 comprises more than one slip 42. Slip 42 may include
tubular gripping
surface, e.g., only one or two columns of gripping dies. A timing ring 45 may
be connected
to slips 42 to facilitate setting slips 42 at substantially the same vertical
position relative to
one another in the bowl and/or relative to the gripped tubular. Although bowl
60 is depicted
as having a continuous surface 62 therein, a "bowl" having a discontinuous
surface, e.g., gaps
between where a slip contacts the "bowl" surface, may be used.
100291 A rotational driver 46, carried with running device 10, is connected to
gripping
assembly 32. For example, rotational driver 46 is connected to slips 42 via
bowl 60 (Figure
3). As will be further understood, rotation may be provided to the gripped
tubular via
gripping assembly 32 via top drive 8 and/or rotational driver 46. In one
embodiment,
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rotational driver 46 includes an actuator 48, for example, a motor (e.g.,
electric, hydraulic,
pneumatic) and may include a driver assembly 50, such as, and without
limitation to, the spur
gears illustrated in Figure 4. Utilization of rotational driver 46 may
minimize the rotational
mass that would be seen, e.g., by top drive 8 by reducing the number of
components rotating
relative to the structure 2 (e.g., rig). In one embodiment, rotational driver
46 may be used to
rotate the gripped tubular (e.g., to make up and/or break out a threaded
connection and/or to
rotate a casing joint and/or casing string). For example, top drive quill 12
may be locked into
a substantially non-rotating position and used to react the torque generated
by rotational
driver "46 and allow relative rotation of the gripped tubular (e.g., add-on
tubular 7a and/or
string 5 of Figure 1) via gripping assembly 32 (e.g., body 58, slips 42, bowl
60) relative to
carrier 34. In one embodiment, one of rotational driver 46 and top drive 8 may
be utilized to
make and break threaded connections 11 (Figure 1) and the other utilized to
rotate tubular
string 5 (Figure 1). For example, rotational driver 46 may be actuated to make-
up the
threaded connection between the add-on tubular and the tubular string and the
top drive may
be actuated to rotate the connected tubular string or vice versa. In the
embodiments depicted
in Figures 2 and 4, a reaction member 74 is connected to rotational driver 46
(e.g., rotational
driver housing 46a) to react the torque generated by rotational driver 46. For
example,
rotational driver 46 is depicted disposed with body 58 and connected to
gripping assembly 32
at body 58 and drive assembly 50 (e.g., gears, belt, etc.). Reaction member
74, depicted in
Figures 2 and 4, is connected to rotational driver 46 (e.g., at housing 46a).
When rotational
driver 46 is actuated, actuator 48 moves drive assembly 50 which is connected
to body 58.
Rotation of rotational driver 46 relative to carrier 34 is stopped by reaction
member 74
contacting carrier 34 (e.g., arms 38) in the depicted embodiment and the
torque is reacted to
gripping assembly 32 and the gripped tubular, rotating the gripped tubular and
gripping
assembly 32 relative to carrier 34. Reaction member 74 may comprise a load
cell(s) 74a to
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measuring the torque being applied to the gripped tubular. Reaction member 74
may include
two load cells for example to measure the force applied in a clockwise
rotation and/or in a
counter-clockwise rotation. A single load cell 74a may be also be used to
measure the torque
applied in either direction. In another embodiment, top drive 8 is rotated to
rotate the tubular
gripped by gripping assembly 32. In this example, carrier 34 is rotated by the
rotation of top
drive 8. With rotational driver 46 locked (or removed but with the gripping
assembly 32
connected to reaction member 74 to restrict rotation therebetween), the
rotation and torque
applied to carrier 34 by top drive 8 is reacted to gripping assembly 32, for
example by
reaction member 74. In this example, carrier 34, gripping assembly 32, and the
gripped
tubular rotate in unison. Again, reaction member 74 may include a load cell or
other device
for measuring the torque applied to the gripped tubular.
[0030] Various other devices, sensors and the like may be included although
not described in
detail herein. For example, a pipe end sensor 52 schematically depicted in
Figure 2 may be
provided to detect the presence of the tubular in device 10. Pipe end sensor
52 may be
utilized to prevent the engagement of slips 42 until the end of the tubular is
present. An
example of a pipe and sensor is disclosed in U. S. Pub. Appl. No.
2003/0145984.
[0031] Figure 3 is a sectional schematic of a tubular running device 10
according to one or
more aspects of the present disclosure. Figure 3 depicts a sectional view of
device 10 along
longitudinal axis "X". In this embodiment a fluidic device 54 (e.g., stinger,
fill-up device,
etc.) is depicted for providing fluid into the add-on tubular and/or tubular
string. Referring to
Figure 1, fluidic device 54 provides a fluidic connection of fluid 22 from
reservoir 26 into
' add-on
tubular 7a and tubular string 5. The depicted fluidic connector 54 includes a
seal 56
(e.g., packer cup) for sealing in add-on tubular 7a. Fluidic device 54 is
depicted connected
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with carrier 34 (e.g., top member 36) and swivel union 72. In the depicted
embodiment,
fluidic device 54 is connected to carrier 34 (at top member 36) and it is
stationary relative to
carrier 34 and top drive 8 (e.g., quill 12) in configuration depicted in
Figure 1. In other
words, when top drive is not rotating (e.g., quill 12 is locked) then carrier
34 is stationary
relative to quill 12. Swivel union 72 provides one mechanism for routing
fluidic pressure, for
example via lines 20 (Figure 1), to actuators 44 which rotate with slips 42.
In the depicted
example, a fluid line 20 is connected to inner sleeve 72a of swivel union 72
and is discharged
through the outer (rotating) sleeve 72b of swivel union 72 to actuator 44.
Other mechanisms
including fluid reservoirs and the like may be utilized to provide the energy
necessary to
operate actuators 44 for example. The fluidic device may be extendable, for
example
telescopic, for selectively extending in length. Fluid 22, including without
limitation drilling
mud and cement, may be provided. Device 10 and passage 40 may be adapted for
performing cementing operations and may include a remotely Iaunchable
cementing plug,
e.g., attached to a distal end (e.g., distal relative to device 10) of fluidic
device 54.
[00321 Referring to Figures 2 and 3 in particular, gripping assembly 32
includes a body 58
forming bowl 60 in which tubular (e.g., add-on tubular 7a) is disposed and
slips 42 are
translated into and out of engagement with the disposed tubular. Depicted bowl
60 is defined
by a conical surface 62 rotated about longitudinal axis "X". In the
illustrated embodiment,
surface 62 is a smooth surface and is referred to herein as a tapered (e.g.,
straight tapered)
surface. A straight tapered bowl 60 facilitates utilizing tubular running
device 10 for running
a tapered tubular string 5 (Figure 1) wherein the tubular string has different
outside diameters
along its length. However, in some embodiments, surface 62 may be stepped,
e.g., to allow
rapid advance or retraction of slips 42. In a stepped configuration, surface
62 may have
multiple surface portions that extend toward and away from axis "X".
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[0033] Depicted surface 62 mates with the outer surface 64 of slips 42 to move
slips 42
toward and away from axis "X" when slips 42 are translated vertically along
longitudinal axis
"X" (e.g., by actuators 44 and/or timing ring 45). Each slip 42, e.g., all
slips, may be retained
along a radial line extending from the longitudinal axis "X" of the device 10
for example via
timing ring 45. For example, and with reference to Figure 3, the slips are
movable between a
tubular engaged position and a tubular disengaged position. Timing ring 45 may
be actuated
downward against surface 62 (e.g., bowl 60) via actuators 44 moving into body
58 to engage
slips 42 against the tubular that is disposed in bowl 60. Surface 62 extends
at an angle alpha
(a) from vertical as illustrated by longitudinal axis "X". Slips 42 include
gripping surface,
e.g., elements 66 (e.g., dies) which may be arranged in die columns. Depicted
slips 42
include gripping elements 66 arranged in die columns on the face 70 of slips
42 opposite
surface 64. Depicted slips 42 include two columns of gripping elements 66.
Slips 42 can
include a single column of gripping elements. It is suggested that slips with
three or more
columns of gripping elements do not conform to the tubular as well as slips
that have one or
two columns, in particular if the tubular is over or undersized. It is also
suggested that slips
42 that have three or more columns of gripping elements do not grip out-of-
round tubular
segments as well as single or double columns. Gripping elements 66 may be
unitary to slips
42 or may be separate die members connected to slips 42. Device may include
any number
of slips 42 (e.g., slip assemblies), e.g., 6, 8, 10, 12, 14, 16, 18 or more,
or any range
therebetween. In Fig. 4, device 10 includes eight slips 42.
[0034] Body 58 is connected to traveling block 6 and/or top drive 8 (Figure 1)
via carrier 34.
In the embodiment depicted in Figure 3, bearings 68 connect body 58 and
carriage 34
facilitating the rotational movement of body 58 and slips 42 relative to
carrier 34. Depicted
bearings 68 are dual bearings that facilitate using device 10 to push and pull
(e.g., via
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traveling block 6) the gripped tubular (e.g., add-on tubular 7a and/or tubular
string 5),
although a single or a plurality of bearings, e.g., thrust bearing, can be
used without departing
from the spirit of the invention.
[0035] Rotational drive assembly 50 (e.g., gears, belt, etc.) is depicted as
connected to body
58 (e.g., gripping assembly 32) in Figure 3. Actuation of the rotational
driver, e.g., actuator
48, rotates driver assembly 50 and gripping assembly 32 relative to carrier
34. Rotational
driver 46 (e.g., driver housing 46a) may be fixedly connected to carrier 34
(e.g., stationary
relative to carrier 34). If driver housing 46a is fixedly connected (not shown
in the Figures)
to carrier 34, torque generated by rotational driver 46 (e.g., actuator 48 and
driver assembly
50) is reacted into carrier 34 which is connected to traveling block 6 (e.g.,
via quill 12 of top
drive 8).
[0036] Figure 4 is a schematic, sectional top view of tubular running device
10 revealing
portions of gripping assembly 32. The view depicts fluidic connector 54
disposed
substantially centered between slips 42. Drive assembly 50 as noted with
reference to Figure
2 is also revealed.
[0037] According to one or more aspects of the present disclosure, a method
for running a
tapered tubular string into a wellbore is now described with reference to
Figures 1-4. The
method comprises suspending a running device 10 from a drilling rig 2. Running
device 10
may comprise a carrier 34, a body 58 forming a bowl 60 rotationally connected
to carrier 34,
slips 42 moveably disposed in bowl 60, an actuator 44 for raising and/or
lowering slips 42
relative to bowl 60, and a rotational driver 46 for selectively rotating slips
42 (e.g., gripping
assembly 32 relative to carrier 34). Tubular string 5 is gripped with a
supporting device 30,
e.g., spider, suspending tubular string 5 in wellbore 4, tubular string 5
having a first outside
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CA 02833524 2013-11-15
diameter D2 section. A first add-on tubular may be transferred to the
wellbore. A top, or
proximal, end of the first add-on tubular is disposed into bowl 60, for
example through pipe
guide 76 (e.g., an adjustable pipe guide). Gripping the first add-on tubular
with slips 42 of
running device 10, the first add-on tubular has a first outside diameter D2;
threadedly
connecting the add-on tubular 7a to the tubular string 5; releasing the grip
of the spider on the
tubular string, suspending the tubular string in the wellbore from running
device 10; lowering
tubular string 5 into the wellbore by lowering running device 10 toward spider
30; engaging
the spider, gripping tubular string 5; releasing running device 10 from the
tubular string 5. A
second add-on tubular having a second diameter DI may than be added to the
tubular string
without changing tubular running device 1 0 , body 58, or slips 42 to run the
tubular with the
secbnd outside diameter that is different from the outside diameter of the
first tubular. The
second add-on tubular, having a second diameter D1 different from the first
diameter D2 of
the first add-on tubular is stabbed into bowl 60 (e.g., through pipe guide 76)
and gripped by
tubular running device 10 (e.g., slips 42). Actuator(s) 44 are operated to
lower slips 42
against surface 62 until gripping members 66 are engaging the disposed
tubular. The second
add-on tubular is rotated via device 10 threadedly connecting the second add-
on tubular to the
tubular string. The process is repeated until the desired length of tubular
string is positioned
in the wellbore. All or part of the tubular string may be cemented in the
wellbore utilizing
tubular running tool 5. The steps of thrcadedly connecting the add-on tubulars
to the tubular
string may comprise actuating the rotational driver 46 to rotate the gripped
tubular and or
actuating the top drive to rotated the running device and the gripped tubular.
Similarly, the
tubing string (when disengaged from the spider) may be rotated via top drive 8
a running tool
and/or by actuating rotational driver actuator 48 to rotate the tubular string
gripped by the
gripping assembly (e.g., relative to carrier 34).
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CA 02833524 2015-12-02
[0038] The foregoing outlines features of several embodiments so that those
skilled in the art
may better understand the aspects of the present disclosure. Those skilled in
the art should
appreciate that they may readily use the present disclosure as a basis for
designing or
modifying other processes and structures for carrying out the same purposes
and/or achieving
the same advantages of the embodiments introduced herein. The scope of the
claims should
not be limited by particular embodiments set forth herein, but should be
construed in a
manner consistent with the specification as a whole. The term "comprising"
within the claims
is intended to mean "including at least" such that the recited listing of
elements in a claim are
an open group. The terms "a," "an" and other singular terms are intended to
include the plural
forms thereof unless specifically excluded.
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