Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEM AND METHOD FOR SEVERING A TUBULAR
BACKGROUND OF THE INVENTION
Field of the Invention
This present invention relates generally to techniques for performing wellsite
operations. More specifically, the present invention relates to techniques for
preventing blowouts, for example, involving severing a tubular at the
wellsite.
Description of Related Art
Oilfield operations are typically performed to locate and gather valuable
downhole fluids. Oil rigs are positioned at wellsites, and downhole tools,
such as
drilling tools, are deployed into the ground to reach subsurface reservoirs.
Once the
downhole tools form a wellbore (or borehole) to reach a desired reservoir,
casings
may be cemented into place within the wellbore, and the wellbore completed to
initiate production of fluids from the reservoir. Tubulars (or tubular
strings) may be
positioned in the wellbore to enable the passage of subsurface fluids to the
surface.
Leakage of subsurface fluids may pose an environmental threat if released
from the wellbore. Equipment, such as blow out preventers (B0Ps), are often
positioned about the wellbore to form a seal about a tubular therein to
prevent
leakage of fluid as it is brought to the surface. Typical BOPs may have
selectively
actuat-able rams or ram bonnets, such as pipe rams (to contact, engage, and
encompass tubulars and/or tools to seal a wellbore) or shear rams (to contact
and
physically shear a tubular), that may be activated to sever and/or seal a
tubular in a
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wellbore. Some examples of BOPs and/or ram blocks arc provided in U.S.
Patent/Application Nos. 4647002, 6173770, 5025708, 5575452, 5655745, 5918851,
4550895, 5575451, 3554278, 5505426, 5013005, 5056418, 7051989, 5575452,
2008/0265188, 5735502, 5897094, 7234530 and 2009/0056132. Additional
examples of BOPs, shear rams, and/or blades for cutting tubulars are disclosed
in
U.S. Pat. Nos. 3946806, 4043389, 4313496, 4132267, 4558842, 4969390, 4492359,
4504037, 2752119, 3272222, 3744749, 4253638, 4523639, 5025708, 5400857,
4313496, 5360061, 4923005, 4537250, 5515916, 6173770, 3863667, 6158505,
4057887, 5178215, and 6016880. Some BOPs may be spherical (or rotating or
rotary) BOPs as described, for example, in US Patent Nos. 5588491 and 5662171.
Despite the development of techniques for addressing blowouts, there remains
a need to provide advanced techniques for more effectively severing a tubular
within
a BOP. The invention herein is directed to fulfilling this need in the art.
SUMMARY OF THE INVENTION
The invention relates to a cutting tool for severing a tubular of a wellbore.
The cutting tool is positionablc in a housing and actuatable by an actuator of
a
blowout preventer. The blowout preventer has a bore thcrethrough for receiving
the
tubular. The cutting tool has a base supportable by the actuator and
selectively
movable thereby, and a cutting head supported by the base. The cutting head
has a
tip with a piercing point at an end thereof and at least one cutting surface.
The
piercing point is for piercing the tubular. The cutting surface tapers away
from the
piercing point for cutting through the tubular whereby the cutting head passes
through tubular.
The tip may be removeable. The tip may have a connector receivable by a
hole in the cutting head. The tip may also be frangible, or terminate at a
leading edge
or at a point. The cutting surface may have a plurality of flat surfaces, each
of the
plurality of flat surfaces extending at an angle from the tip.
The cutting tool may be made of a hardening material. The cutting head may
have a guide surface for slidably engaging a guide of the housing. The cutting
tool
may also have a body between the base and the cutting head.
In another aspect, the invention may relate to a blowout preventer for
severing
a tubular of a wellbore. The blowout preventer may have a housing having a
bore
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therethrough for receiving the tubular, an actuator positionable in the
housing, and a
plurality of cutting tools positionable in the housing and selectively movable
into an
actuated position with the actuator. Each of the cutting tools may have a base
supportable by the actuator and selectively movable thereby, and a cutting
head
supported by the base. The cutting head has a tip with a piercing point at an
end
thereof and at least one cutting surface. The piercing point is for piercing
the tubular.
The cutting surface tapers away from the piercing point for cutting through
the
tubular whereby the cutting head passes through tubular.
The housing may have an insert therein defining a guide, and the cutting head
may have a guide surface for slidably engaging the guide. The actuator may
have a
piston having a piston head for engaging an actuation surface of the base. The
blowout preventer may also have at least one elastomeric element positionable
between the cutting tools, a cutting tool carrier for supporting the cutting
tools, and a
seal for sealing the bore. The cutting tools may be arranged in a dome-shaped
or
inverted dome-shaped configuration with the tips of each of the cutting tools
converging about the tubular.
In yet another aspect, the invention may relate to a method of severing a
tubular of a wellbore. The method involves positioning a BOP about the tubular
(the
BOP comprising a housing and an actuator), and positioning a plurality of
cutting
tools in the housing. Each cutting tool has a base supportable by the actuator
and
selectively movable thereby, and a cutting head supported by the base. The
cutting
head has a tip with a piercing point at an end thereof and at least one
cutting surface.
The piercing point is for piercing the tubular. The cutting surface tapers
away from
the piercing point. The method may further involve selectively moving the
cutting
tools to an actuated position with the actuator such that the cutting head
passes
through the tubular by piercing the tubular with the tip of the cutting head
and cutting
through the tubular with the cutting surface of the cutting head.
The method may also involve guiding the plurality of cutting tools along a
guide of the housing, sealing a bore of the housing with a seal, breaking off
a portion
of the cutting head, replacing a portion of the cutting head, selectively
retracting the
plurality of cutting tools, and/or securing the plurality of cutting tools
with the cutting
tool carrier.
BRIEF DESCRIPTION OF THE DRAWINGS
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So that the above recited features and advantages of the invention can be
understood in detail, a more particular description of the invention, briefly
summarized above, may be had by reference to the embodiments thereof that are
illustrated in the appended drawings. It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this invention and are,
therefore, not
to be considered limiting of its scope, for the invention may admit to other
equally
effective embodiments. The Figures are not necessarily to scale, and certain
features
and certain views of the Figures may be shown exaggerated in scale or in
schematic
in the interest of clarity and conciseness.
FIG. 1 is a schematic view of an offshore wellsite having a blowout preventer
(BOP) with a tubular severing system.
FIG. 2 is a cross-sectional view of the BOP of Figure 1 taken along line 2-2.
FIG. 3 is a schematic, top view of a portion of the BOP of Figure 1 depicting
the tubular severing system in a closed position.
FIGS. 4A and 4B are schematic views of a portion of the tubular severing
system of Figure 1 in an actuated position. FIG. 4A shows the portion of the
tubular
severing system without a tubular. FIG. 4B shows the portion of the tubular
severing
system with a tubular.
FIGS. 5A and 5B are various perspective views of a cutting tool of the tubular
severing system of Figure 1.
FIGS. 6A-6C are various perspective views of a cutting tool of the tubular
severing system of Figure 1 having a replaceable tip.
FIG. 7 is a perspective view of the replaceable tip of Figure 6A.
FIG. 8 is a flow chart depicting a method of severing a tubular.
DETAILED DESCRIPTION OF THE INVENTION
The description that follows includes exemplary apparatus, methods,
techniques, and instruction sequences that embody techniques of the inventive
subject matter. However, it is understood that the described embodiments may
be
practiced without these specific details.
This application relates to a BOP and tubular severing system used to sever a
tubular at a wellsite. The tubular may be, for example, a tubular that is run
through
the BOP during wellsite operations and/or other downhole tubular devices, such
as
pipes, certain downhole tools, casings, drill pipe, liner, coiled tubing,
production
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tubing, wireline, slickline, or other tubular members positioned in the
wellbore and
associated components, such as drill collars, tool joints, drill bits, logging
tools,
packers, and the like, (referred to as `tubulars' or 'tubular strings'). The
severing
operation may allow the tubular to be removed from the BOP and/or the
wellhead.
Severing the tubular may be performed, for example, in order to seal off a
borehole in
the event the borehole has experienced a leak, and/or a blow out. The BOP and
tubular severing system may be provided with various configurations for
facilitating
severance of the tubular. These configurations are provided with cutting tools
intended to reduce the force required to sever a tubular. The invention
provides
techniques for severing a variety of tubulars (or tubular strings), such as
those having
a diameter of up to about 8.5 inches (21.59 cm) or more. Preferably, the BOP
and
severing system provide one or more of the following, among others: efficient
part
(e.g., the severing system) replacement, reduced wear, less force required to
sever
tubular, automatic sealing of the BOP, efficient severing, incorporation into
(or use
with) existing equipment and less maintenance time for part replacement.
Figure 1 depicts an offshore wellsite 100 having a subsea system 106 and a
surface system 120. The subsea system 106 has a stripper 102, a BOP 108 a
wellhead 110, and a tubing delivery system 112. The stripper 102 and/or the
BOP
108 may be configured to seal a tubular string 118 (and/or conveyance), and
run into
a wellbore 116 in the sea floor 107. The BOP 108 has a tubular severing system
150
for severing the tubular string 118, a downhole tool 114, and/or a tool joint
(or other
tubular not shown). The BOP 108 may have one or more actuators 152 for
actuating
the tubular severing system 150 thereby severing the tubular string 118. One
or more
controllers 126 and/or 128 may operate, monitor and/or control the BOP 108,
the
stripper 102, the tubing delivery system 112 and/or other portions of the
wellsite 100.
The tubing delivery system 112 may be configured to convey one or more
downhole tools 114 into the wellbore 116 on the tubular string 118. Although
the
BOP 108 is described as being used in subsea operations, it will be
appreciated that
the wellsite 100 may be land or water based and the BOP 108 may be used in any
wellsite environment.
The surface system 120 may be used to facilitate the oilfield operations at
the
offshore wellsite 100. The surface system 120 may comprise a rig 122, a
platform
124 (or vessel) and the controller 126. As shown the controller 126 is at a
surface
location and the subsea controller 128 is in a subsea location, it will be
appreciated
that the one or more controllers 126/128 may be located at various locations
to
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control the surface 120 and/or the subsea systems 106. Communication links 134
may be provided by the controllers 126/128 for communication with various
parts of
the wellsite 100.
As shown, the tubing delivery system 112 may be located within a conduit
111, although it should be appreciated that it may be located at any suitable
location,
such as at the sea surface, proximate the subsea equipment 106, without the
conduit
Ill, within the rig 122, and the like. The tubing delivery system 112 may be
any
tubular delivery system such as a coiled tubing injector, a drilling rig
having
equipment such as a top drive, a Kelly, a hoist and the like (not shown).
Further, the
tubular string 118 to be severed may be any suitable tubular and/or tubular
string as
described herein. The downhole tools 114 may be any suitable downhole tools
for
drilling, completing, evaluating and/or producing the wellbore 116, such as
drill bits,
packers, testing equipment, perforating guns, and the like. Other devices may
optionally be positioned about the wellsite for performing various functions,
such as
a packer system 104 hosting the stripper 102 and a sleeve 130.
Figure 2 shows a cross-sectional view of the BOP 108 of Figure I taken along
line 2-2. The BOP 108 as shown has a housing 12 with the tubular severing
system
150 and the actuators 152 therein. The tubular severing system 150 includes a
plurality of cutting (or metal) elements 248 with elastomeric elements 52 and
54
therebetween. Elastomerie elements 52, 54 may be a single or multiple elements
positioned between the cutting elements. The BOP 108 may be similar to the
spherical BOPs 108 as described, for example in US Patent Nos. 5588491 and
5662171. The BOP 108 may be
modified by providing the plurality of cutting tools 248 arranged radially
around the
BOP 108 as shown in Figure 2. While the BOP 108 as shown is depicted in a dome
configuration, it will be appreciated that the BOP 108 may be inverted such
that the
BOP 108 is in a bowl configuration. One or more tubular severing systems 150
may
be positioned about the BOP 108.
The cutting tools 248 may be supported by the elastomeric elements 52, 54.
The cutting tools 248 may also be supported in the housing 12 by a cutting
tool
carrier 202. The cutting tool carrier 202 may be constructed of a resilient
material.
The cutting tool carrier 202 may be any suitable member, bonnet, carriage and
the
like configured to be engaged by the actuator 152. The cutting tool carrier
202 may
be a single member that radially surrounds the bore 32, or may be a plurality
of
members that hold the cutting tools 248 and surround the bore 32.
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The cutting tools 248 may travel in a guideway (or curved outer surface) 50.
The guideway 50 may direct each of the cutting tools 248 radially toward the
tubular
string 118 as the actuator 152 actuates the tubular severing system 150. The
guideway 50 may be constructed of one or more bowl shaped inserts (or
rotatable
inner housings) 38 configured to guide the cutting tools 248. Although the
bowl
shaped inserts 38 are shown as a separate attachable piece, the bowl shaped
inserts 38
may be integral with the BOP 108. The guideway 50 is shown as a bowl shape
formed by the bowl shaped inserts 38, although the guideway 50 may take any
suitable form, so long as the guideway 50 guides the plurality of cutting
tools 248
into engagement with the tubular string 118 thereby severing the tubular
string 118.
A seal 250 may seal the central bore 32. The cutting tool carrier 202 may be
configured as the seal 250 to seal the central bore 32, and/or add flexibility
to the
travel paths of the cutting tools 248 as they travel in the guideway 50. If
the cutting
tool carrier 202 is configured to seal the central bore 32 upon severing the
tubular
string 118, the cutting tools 248, and/or portions thereof, may be configured
to break
off and/or move out of the way of the cutting tool carrier 202 as the cutting
tool
carrier moves into the central bore 32. The elastomeric seals 52, 54 may also
be used
to form a seal about the tubular string 118.
Figure 2 also shows, for demonstrative purposes, a portion (left side) of the
tubular severing system 150 in the BOP 108 in the actuated position, while
another
portion (right side) of the tubular severing system 150 is shown in the un-
actuated
position. In the un-actuated position, the actuator 152 is retracted, in this
case toward
a downhole end of the BOP 108. With the actuator 152 retracted, each of the
cutting
tools 248 is retracted out of a central bore 32 of the BOP 108, thereby
allowing the
tubular string 118 to move freely through the BOP 108.
When an event occurs requiring the severing of the tubular string 118, such as
a pressure surge in the wellbore 116 (FIG. 1), an operator command, a
controller
command, etc., the actuator 152 actuates the cutting tools 248. To actuate the
actuator 152, hydraulic fluid may be introduced into a piston chamber 90 via
flow
line 26. As the fluid pressure in the piston chamber 90 increases, a piston 56
may
move toward the actuated position as shown on the left side of the BOP 108 in
Figure
2. The piston 56 has a piston head 57 for engaging the cutting tools 248 and
advancing them to the actuated position. As shown, the actuators 152 are
hydraulically operated and may be driven by a hydraulic system (not shown),
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although any suitable means for actuating the cutting tools 248 may be used
such as
pneumatic, electric, and the like.
Continued movement of the piston 56 moves each of the cutting tools 248
along the guideway 50. The cutting tool 248 follows the guideway 50 as a point
(or
tip or piercing point) 200 on each cutting tool 248 engages and then pierces
the
tubular string 118. Continued movement of the piston 56 severs the tubular
string
118 completely as the cutting tools 248 converge toward a center axis z of the
tubular
string 118.
Figure 3 shows a schematic top view of the tubular severing system 150 in the
BOP 108. The tubular severing system 150 may include a plurality of cutting
tools
248 positioned radially about the central axis of the bore 32. In this figure,
the
cutting tools 248 are depicted in the fully actuated position whereby the
cutting tools
248 are converged to the central axis of the bore 32 of the BOP 108. As
depicted in
this figure, the cutting tools 248 may converge at a central or off-center
location
within the bore 32 for engagement with the tubular 118.
Figures 4A and 4B show a portion of the tubular cutting system 150 in greater
detail with the rubber elements removed. As shown in these figures, the
tubular
cutting system 150 includes the cutting tools 248 positioned adjacent to each
other in
a dome-shaped configuration. The cutting tools 248 may be positioned in a
tight or
loose configuration radially about the tubular. The cutting tools 248 may be
arranged
so that, upon activation, the cutting tools 248 converge about the tubular
118.
Each of the cutting tools 248 has a cutting head 400, a body 402 and a base
404. The cutting head has a tip at an end thereof. The tip has a piercing
point 200 for
piercing the tubular 118, and angled cutting surfaces 406 extending from the
piercing
point 200. The angled cutting surfaces 406 taper away from the piercing point
200
and toward the body 402.
Figure 4A shows the portion of the tubular cutting system 150 without the
BOP 108 and/or the tubular 118 (as shown in Figure 1). This view shows the
plurality of cutting tools 248 in greater detail in the actuated position. As
shown, the
cutting heads 400 have converged together where the central bore 32 (as shown
in
Figure 2) would have been. The cutting tools 248 are positioned so that, upon
activation, the points 200 of each of the cutting heads 400 converge.
Figure 4B shows the plurality of cutting tools 248 in the actuated position
with a tubular 118 therein as it is severed by the cutting tools 248. The
piercing point
200 of each of the cutting heads 400 has pierced a hole into the tubular. The
cutting
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heads 400 form a plurality of holes in a ring around the tubular 118. The
cutting
surfaces 406 of each of the cutting heads 400 advance through the pierced
holes to
expand the holes until the tubular 118 is severed.
The cutting tools 248 may have any form suitable for traveling in the
guideway 50 and severing the tubular string 118. Figures 5A and 5B show one of
the
cutting tools 248 in greater detail. Figures 5A and 5B shows perspective side
and
bottom views of the cutting tool 248. The cutting tool 248, as shown, has the
cutting
head 400, the body 402 and the base 404. The cutting head 400 may have the
point
200, one or more cutting surfaces 406 and a guide surface 525. The point 200
may
be configured to be the first point of contact for the cutting tool 248 and
the tubular
string 118.
The point 200 may have any structure suitable for puncturing, cutting,
shearing and/or rupturing the tubular string 118. For example, the point 200
may be
a cone, a blade, a pick type surface and the like. As shown in Figures 5A and
5B, the
point 200 is a wedge shaped blade. The point 200 may have a leading edge or
terminate at a point. The tip 401 as shown in Figures 5A and 5B has multiple,
flat
cutting surfaces 406 extending from the point 200. The cutting surfaces 406
may cut,
shear, sever and/or destroy the wall of the tubular string 118 as the cutting
tool 248
continues to move into the tubular string 118. Further, the cutting surfaces
406 may
act as a wedge to spread the wall of the tubular string 118 apart as the
cutting tool
248 cuts. The cutting surfaces 406 taper away from the point 200 at a leading
end of
the cutting tool 248. The cutting surfaces 406 are depicted as flat, polygonal
surfaces
that extend at an angle away from the piercing point 200. The angles and
shapes of
the cutting surfaces 406 and/or piercing point 200 may be selected to
facilitate entry
into the tubular, expansion of the holes formed by the piercing points 200
and/or
severing of the tubular 118.
The guide surface 525 of the cutting tool 248 may be configured to guide the
cutting tool 248 along the guideway 50 as the actuator 152 motivates the
cutting tool
248 toward the tubular string 118 (as shown in Figure 2). The guide surface
525 of
the cutting tool 248 may conform to the shape of the guide 50 for slidable
movement
therealong. The guide surface 525 may terminate at one end at the cutting
surfaces
406, and at an opposite end at the body 402.
The base 404 may be configured to couple the cutting tool 248 to the cutting
tool carrier 202 and/or actuator 152 (as shown in Figure 2). As the cutting
tool carrier
202 is engaged by the actuator 152, the cutting tool carrier 202 moves the
base 404
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and thereby the cutting tool 248. The base 404 may also have an actuation
surface
527 for actuatable engagement with the actuator 152. The base 404 may be any
suitable shape for securing to and/or engaging the cutting tool carrier 202
and/or
actuator 152.
The body 402 may be configured to be a support between the base 404 and
the cutting head 400. The body 402 may be any suitable shape for supporting
the
cutting head 400. Further, the body 402 may be absent and the cutting head 400
may
extend to the base 404 and/or form the base 404. The body 402 may have a
narrower
width than the base 404 and the cutting head 400 for placement and flow of the
elastomeric elements 52 and 54 between adjacent cutting tools 248.
The cutting tools 248, and/or portions thereof, may be constructed of any
suitable material for cutting the tubular string 118, such as steel. Further,
the cutting
tools 248 may have portions, such as the points 200, the cutting head 400,
and/or the
cutting surfaces 406, provided with a hardened material 550 (as shown in
Figure 5A)
and/or coated in order to prevent wear of the cutting tools 248. This
hardening and/or
coating may be achieved by any suitable method such as, hard facing, heat
treating,
hardening, changing the material, and/or inserting hardened material such as
polydiamond carbonate, NCONELTM and the like.
Figures 6A-6C show perspective views of a cutting tool 248'usable as the
cutting tool 248, and having a replaceable tip 600. The cutting tool 248' of
these
figures may be the same as the cutting tool 248' previously described, except
that a
portion of the cutting head 400 comprises the replaceable tip 600. The
replaceable
tips 600 may be shaped like any of the tips 401 described herein. The
replaceable
tips 600 may be constructed with the same material as the cutting tool 248
and/or any
of the hardening and/or coating materials and/or methods described herein.
The replaceable tips 600 and cutting head 400 may be connectable by any
means. The replaceable tips 600 and/or the cutting head 400, the body 402, or
the
base 404 may have one or more connector holes 602, as shown in FIG. 6C for
receivably coupling with the replaceable tips 600 to the cutting tool 248'.
The
connector holes 602 may be configured to receive a connector 704 on the
replaceable
tip 600 as shown in FIG. 7. The replaceable tips 600 may allow the operator to
easily
replace the tips during maintenance. Further, the replaceable tips 600 may be
configured to easily break off in order to allow the cutting tool carrier 202
(as shown
in Figure 2) to seal the bores 32. Such 'frangible' tips 600 may be made of
material
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that is sufficient to puncture and/or cut the tubular, but breaks away from
the tubular
severing system 150.
Figure 8 depicts a method 800 of severing a tubular. The method involves
positioning (880) a BOP about the tubular, positioning (882) a plurality of
cutting
tools in the housing, and selectively (884) moving the plurality of cutting
tools to an
actuated position with the actuator such that the cutting head passes through
the
tubular by piercing the tubular with the tip of the cutting head and cutting
through the
tubular with the cutting surface of the cutting head.
The method may also involve guiding the plurality of cutting tools along a
guide of the housing, sealing a bore of the housing with a seal, breaking off
a portion
of the cutting head, and/or replacing a portion of the cutting head. The steps
may be
performed in any order, and repeated as desired.
In operation, the severing action of tubular severing system 150 may pierce,
shear, and/or cut the tubular string 118 (see, e.g., FIG. 2). After the
tubular string 118
is severed, a lower portion of the tubular string 118 may drop into the
wellbore 116
(not shown) below the blowout preventer 108. Optionally (as is true for any
method
according to the present invention) the tubular string 118 may be hung off the
BOP
after being severed. The BOP 108, the cutting tool carrier 202, seal 250,
elastomeric
members 52, 54, and/or another piece of equipment may then seal the bore hole
32 in
order to prevent an oil leak, and/or explosion. The sealing using a spherical
BOP is
described, for example, in US Patent Nos. 5588491 and 5662171.
It will be appreciated by those skilled in the art that the techniques
disclosed
herein can be implemented for automated/autonomous applications via software
configured with algorithms to perform the desired functions. These aspects can
be
implemented by programming one or more suitable general-purpose computers
having appropriate hardware. The programming may be accomplished through the
use of one or more program storage devices readable by the processor(s) and
encoding one or more programs of instructions executable by the computer for
performing the operations described herein. The program storage device may
take
the form of, e.g., one or more floppy disks; a CD ROM or other optical disk; a
read-
only memory chip (ROM); and other forms of the kind well known in the art or
subsequently developed. The program of instructions may be "object code,"
i.e., in
binary form that is executable more-or-less directly by the computer; in
"source
code" that requires compilation or interpretation before execution; or in some
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intermediate form such as partially compiled code. The precise forms of the
program
storage device and of the encoding of instructions are immaterial here.
Aspects of
the invention may also be configured to perform the described functions (via
appropriate hardware/software) solely on site and/or remotely controlled via
an
extended communication (e.g., wireless, internet, satellite, etc.) network.
While the embodiments are described with reference to various
implementations and exploitations, it will be understood that these
embodiments are
illustrative and that the scope of the inventive subject matter is not limited
to them.
Many variations, modifications, additions and improvements are possible. For
example, any number of the cutting tools at various positions may be moved
into
engagement with the tubular at various times.
Plural instances may be provided for components, operations or structures
described herein as a single instance. In general, structures and
functionality
presented as separate components in the exemplary configurations may be
implemented as a combined structure or component. Similarly, structures and
functionality presented as a single component may be implemented as separate
components. These and other variations, modifications, additions, and
improvements
may fall within the scope of the inventive subject matter.
