Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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TOOL JOINT POSITIONING
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a Non-Provisional Application claiming
priority to U.S.
Provisional Patent Application No. 62/558,758, entitled "Tool Joint
Positioning", filed
September 14, 2017, which is herein incorporated by reference.
BACKGROUND
[0002] This section is intended to introduce the reader to various
aspects of art that may
be related to various aspects of the present disclosure, which are described
and/or claimed below.
This discussion is believed to be helpful in providing the reader with
background information to
facilitate a better understanding of the various aspects of the present
disclosure. Accordingly, it
should be understood that these statements are to be read in this light, and
not as admissions of
prior art.
[0002] Advances in the petroleum industry have allowed access to oil and
gas drilling
locations and reservoirs that were previously inaccessible due to
technological limitations. For
example, technological advances have allowed drilling of offshore wells at
increasing water
depths and in increasingly harsh environments, permitting oil and gas resource
owners to
successfully drill for otherwise inaccessible energy resources. Likewise,
drilling advances have
allowed for increased access to land based reservoirs.
[0003] Much of the time spent in drilling to reach these reservoirs is
wasted "non-
productive time" (NPT) that is spent in doing activities which do not increase
well depth, yet
may account for a significant portion of costs. For example, when drill pipe
is pulled out of or
lowered into a previously drilled section of well it is generally referred to
as "tripping."
Accordingly, tripping-in may include lowering drill pipe into a well (e.g.,
running in the hole or
RIH) while tripping-out may include pulling a drill pipe out of the well
(pulling out of the hole or
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POOH). Tripping operations may be performed to, for example, install new
casing, change a
drill bit as it wears out, clean and/or treat the drill pipe and/or the
wellbore to allow more
efficient drilling, run in various tools that perform specific jobs required
at certain times in the
oil well construction plan, etc. Additionally, tripping operations may require
a large number of
threaded pipe joints to be disconnected (broken-out) or connected (made-up).
Currently, this
process involves visual inspection by a human operator to locate a seam (e.g.,
a break point
between pipe segments) and may further include human fine tuning of the
position of the seam
into an appropriate location so that the tripping operation may be undertaken.
BRIEF DESCRIPTION OF DRAWINGS
[0004] FIG. 1 illustrates an example of an offshore platform having a
riser coupled to a
blowout preventer (BOP), in accordance with an embodiment;
[0005] FIG. 2 illustrates a front view a drilling rig as illustratively
presented in FIG. 1, in
accordance with an embodiment;
[0006] FIG. 2A illustrates a front view of the tripping apparatus of FIG.
2, in accordance
with an embodiment;
[0007] FIG. 3 illustrates a block diagram of a computing system of FIG.
2, in accordance
with an embodiment; and
[0008] FIG. 4 illustrates a flow chart used in conjunction with a tubular
string detection
system, in accordance with an embodiment.
[0009] FIG. 5 illustrates a front view a second drilling rig as
illustratively presented in
FIG. 1, in accordance with an embodiment;
[0010] FIG. 6 illustrates an isometric view of a movable platform of FIG.
5, in
accordance with an embodiment; and
[0011] FIG. 7 illustrates a front view of a system inclusive of the
tripping apparatus of
FIG. 5, in accordance with an embodiment.
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DETAILED DESCRIPTION
[0012] One or more specific embodiments will be described below. In an
effort to
provide a concise description of these embodiments, all features of an actual
implementation
may not be described in the specification. It should be appreciated that in
the development of
any such actual implementation, as in any engineering or design project,
numerous
implementation-specific decisions must be made to achieve the developers'
specific goals, such
as compliance with system-related and business-related constraints, which may
vary from one
implementation to another. Moreover, it should be appreciated that such a
development effort
might be complex and time consuming, but would nevertheless be a routine
undertaking of
design, fabrication, and manufacture for those of ordinary skill having the
benefit of this
disclosure.
[0013] When introducing elements of various embodiments, the articles
"a," "an," "the,"
and "said" are intended to mean that there are one or more of the elements.
The terms
"comprising," "including," and "having" are intended to be inclusive and mean
that there may be
additional elements other than the listed elements.
[0014] Present embodiments are directed to components, systems, and
techniques (e.g., a
position determination system) utilized in the detection of connection points
between individual
tubular segments, such as those used in oil and gas applications. The
detection of connection
points may be accomplished through the use of a hardware suite of one or more
sensors and
processors, as well as a suite of one or more software programs (e.g.,
instructions configured to
be executed by a processor, whereby the instructions are stored on a tangible,
non-transitory
computer-readable medium such as memory) that may operate in conjunction to
determine the
precise position of the connection point between tubular segments.
[0015] Additionally, in some embodiments, the software program(s) may be
utilized, for
example, in conjunction with hardware components (e.g., one or more processors
and sensors) to
access stored information relating to the tubulars to generate a position of a
connection point
between two tubular segments (e.g., a tool joint connection typically having a
larger diameter
than the respective tubulars and including a male pin connector of one tubular
connectable to a
female box connector on the other tubular). For example, a tool joint seam
(e.g., a location of
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the connection of the pin connector and the box connector) may be calculated
using stored
information about the tubular segments (e.g., the length of the respective
tubular segments) and
the current position of a tubular string including the tubular segments, as
determined through one
or more indirect measurements of the tubular segment positions (e.g., through
measurements of a
portion of drawworks supporting the tubular string). In some embodiments,
activation of one or
more slips to secure one of the tubular segments may be controlled based upon
the calculated
tool joint seam to allow for attachment or detachment of the tubular segments.
By calculating
the correct position of the connection point between tubular segments,
continuous tripping
procedures may be facilitated, since hunt and peck methods for the connection
point can be
avoided.
[0016] With the foregoing in mind, FIG. 1 illustrates an offshore
platform 10 as a
drillship. Although the presently illustrated embodiment of an offshore
platform 10 is a drillship
(e.g., a ship equipped with a drilling system and engaged in offshore oil and
gas exploration
and/or well maintenance or completion work including, but not limited to,
casing and tubing
installation, subsea tree installations, and well capping), other offshore
platforms 10 such as a
semi-submersible platform, a jack up drilling platform, a spar platform, a
floating production
system, or the like may be substituted for the drillship. Indeed, while the
techniques and systems
described below are described in conjunction with a drillship, the techniques
and systems are
intended to cover at least the additional offshore platforms 10 described
above. Likewise, while
an offshore platform 10 is illustrated and described in FIG. 1, the techniques
and systems
described herein may also be applied to and utilized in onshore (e.g., land
based) drilling
activities. These techniques may also apply to at least vertical drilling or
production operations
(e.g., having a rig in a primarily vertical orientation drill or produce from
a substantially vertical
well) and/or directional drilling or production operations (e.g., having a rig
in a primarily vertical
orientation drill or produce from a substantially non-vertical or slanted well
or having the rig
oriented at an angle from a vertical alignment to drill or produce from a
substantially non-
vertical or slanted well).
[0017] As illustrated in FIG. 1, the offshore platform 10 includes a
riser string 12
extending therefrom. The riser string 12 may include a pipe or a series of
pipes that connect the
offshore platform 10 to the seafloor 14 via, for example, a BOP 16 that is
coupled to a wellhead
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18 on the seafloor 14. In some embodiments, the riser string 12 may transport
produced
hydrocarbons and/or production materials between the offshore platform 10 and
the wellhead 18,
while the BOP 16 may include at least one BOP stack having at least one valve
with a sealing
element to control wellbore fluid flows. In some embodiments, the riser string
12 may pass
through an opening (e.g., a moonpool) in the offshore platform 10 and may be
coupled to drilling
equipment of the offshore platform 10. As illustrated in FIG. 1, it may be
desirable to have the
riser string 12 positioned in a vertical orientation between the wellhead 18
and the offshore
platform 10 to allow a drill string made up of drill pipes 20 to pass from the
offshore platform 10
through the BOP 16 and the wellhead 18 and into a wellbore below the wellhead
18. Also
illustrated in FIG. 1 is a drilling rig 22 (e.g., a drilling package or the
like) that may be utilized in
the drilling and/or servicing of a wellbore below the wellhead 18.
[0018] In a tripping-in operation consistent with embodiments of the
present disclosure,
as depicted in FIG. 2, a tripping apparatus 24 is positioned on drilling floor
26 in the drilling rig
22 above the wellbore 28 (e.g., the drilled hole or borehole of a well which
may be, as illustrated
in FIG. 2, proximate to the drilling floor 26 in land based drilling
operations or which may be, in
conjunction with FIG. 1, below the wellhead 18). The drilling rig 22 may
include one or more of,
for example, the tripping apparatus 24, floor slips 30 positioned in rotary
table 32, drawworks 34,
a crown block 35, a travelling block 36, a top drive 38, an elevator 40, and a
tubular handling
apparatus 42. The tripping apparatus 24 may operate to couple and decouple
tubular segments
(e.g., drill pipe 20 to and from a drill string) while the floor slips 30 may
operate to close upon
and hold a drill pipe 20 and/or the drill string passing into the wellbore 28.
The rotary table 32
may be a rotatable portion of the drilling floor 26 that may operate to impart
rotation to the drill
string either as a primary or a backup rotation system (e.g., a backup to the
top drive 38).
[0019] The drawworks 34 may be a large spool that is powered to retract
and extend
drilling line 37 (e.g., wire cable) over a crown block 35 (e.g., a vertically
stationary set of one or
more pulleys or sheaves through which the drilling line 37 is threaded) and a
travelling block
(e.g., a vertically movable set of one or more pulleys or sheaves through
which the drilling line
37 is threaded) to operate as a block and tackle system for movement of the
top drive 38, the
elevator 40, and any tubular member (e.g., drill pipe 20) coupled thereto. The
top drive 38 may
be a device that provides torque to (e.g., rotates) the drill string as an
alternative to the rotary
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table 32 and the elevator 40 may be a mechanism that may be closed around a
drill pipe 20 or
other tubular members (or similar components) to grip and hold the drill pipe
20 or other tubular
members while those members are moving vertically (e.g., while being lowered
into or raised
from the wellbore 28). The tubular handling apparatus 42 may operate to
retrieve a tubular
member from a storage location 43 (e.g., a pipe stand) and position the
tubular member during
tripping-in to assist in adding a tubular member to a tubular string.
Likewise, the tubular
handling apparatus 42 may operate to retrieve a tubular member from a tubular
string and
transfer the tubular member to a storage location 43 (e.g., a pipe stand)
during tripping-out to
remove the tubular member from the tubular string.
[0020] During a tripping-in operation, the tubular handling apparatus 42
may position a
first tubular segment 44 (e.g., a first drill pipe 20 or another tubular
member) so that the segment
44 may be grasped by the elevator 40. Elevator 40 may be lowered, for example,
via the block
and tackle system towards the tripping apparatus 24 to be coupled to a second
tubular segment
46 (e.g., a second drill pipe 20) as part of a drill string. As illustrated in
FIG. 2A, the tripping
apparatus 24 may include tripping slips 48 inclusive of slip jaws 50 that
engage and hold the
segment 46 as well as a forcing ring 52 that operates to provide force to
actuate the slip jaws 50.
The tripping slips 48 may, thus, be activated to grasp and support the
segment, and, accordingly,
an associated tubular string (e.g., drill string) when the tubular string is
disconnected from the
block and tackle system. The tripping slips 48 may be actuated hydraulically,
electrically,
pneumatically, or via any similar technique.
[0021] The tripping apparatus 24 may further include a roughneck 54 that
may operate to
selectively make-up and break-out a threaded connection between tubular
segments 44 and 46 in
a tubular string. In some embodiments, the roughneck 54 may include one or
more of fixed jaws
56, makeup/breakout jaws 58, and a spinner 60. In some embodiments, the fixed
jaws 56 may be
positioned to engage and hold the second (lower) tubular segment 46 below a
threaded joint 62
thereof. In this manner, when the first (upper) tubular segment 44 is
positioned coaxially with
the second tubular segment 46 in the tripping apparatus 24, the second tubular
segment 46 may
be held in a stationary position to allow for the connection of the first
tubular segment 44 and the
second tubular segment 46 (e.g., through connection of the threaded joint 62
of the second
tubular segment 46 and a threaded joint 64 of the first tubular segment 44).
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[0022] To facilitate this connection, the spinner 60 and the
makeup/breakout jaws 58
may provide rotational torque. For example, in making up the connection, the
spinner 60 may
engage the first tubular segment 44 and provide a relatively high-speed, low-
torque rotation to
the first tubular segment 44 to connect the first segment 44 to the second
segment 46. Likewise,
the makeup/breakout jaws 58 may engage the first segment 44 and may provide a
relatively low-
speed, high-torque rotation to the first tubular segment 44 to provide, for
example, a rigid
connection between the tubular segment 44 and 46. Furthermore, in breaking-out
the connection,
the makeup/breakout jaws 58 may engage the first tubular segment 44 and impart
a relatively
low-speed, high-torque rotation on the first tubular segment 44 to break the
rigid connection.
Thereafter, the spinner 60 may provide a relatively high-speed, low-torque
rotation to the first
tubular segment 44 to disconnect the first segment 44 from the second segment
46.
[0023] In some embodiments, the roughneck 54 may further include a mud
bucket 66
that may operate to capture drilling fluid, which might otherwise be released
during, for example,
the break-out operation. In this manner, the mud bucket 66 may operate to
prevent drilling fluid
from spilling onto drill floor 26. In some embodiments, the mud bucket 66 may
include one or
more seals that aid in fluidly sealing the mud bucket 66 as well as a drain
line that operates to
allow drilling fluid contained within mud bucket 66 to return to a drilling
fluid reservoir.
[0024] Returning to FIG. 2, the tripping apparatus 24 may be movable with
respect to the
drill floor 26 (e.g., towards and away from the drill floor 26) and, in some
embodiments, relative
to the tripping slips 48. In other embodiments, the tripping apparatus 24 can
be moved along the
direction of the rig towards and away from the drilling floor 26 in
conjunction with slanted well
operations when the rig is oriented at an angle from a vertical alignment to
respectively drill or
produce from a substantially non-vertical or slanted well. Movement of the
tripping apparatus
24 may be accomplished through the use of hydraulic pistons, jackscrews, racks
and pinions,
cable and pulley, a linear actuator, or the like along one or more support
elements 68. This
movement may be beneficial to aid in proper location of the roughneck 54
during a make-up or
break-out operation (e.g., during a tripping-in or tripping-out operation).
[0025] In some embodiments, moving of the tripping apparatus 24 into
position (whether
in conjunction with a continuous tripping operation in which the tubular
segments 44 and 46 are
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moving towards or away from the drill floor 26 while being made-up or broken-
out or in
conjunction with a static tripping operation in which the tubular segments 44
and 46 remain in a
static position relative to the drill floor 26 while being made-up or broken-
out) may require hunt
and peck techniques to find a seam between the tubular segments 44 and 46 or
the connection
point thereof so as to allow the roughneck 54 to trip the tubular segments 44
and 46. However, it
may be advantageous to instead utilize techniques and one or more systems to
determine the
location of a seam or a connection point for tubular segments 44 and 46 so
that the tripping
apparatus 24 can be moved into a correct position to facilitate a make-up or
break-out (e.g.,
tripping) operation.
[0026] To facilitate this determination of where and when to move the
tripping apparatus
24 into position (e.g., tool joint recognition), a computing system 70 may be
present and may
operate to control the timing when the tripping apparatus 24 moves into
position to perform a
tripping operation based on, for example, a determined or calculated location
of a seam or a
connection point for tubular segments 44 and 46. In some embodiments, the
computing system
70 may be communicatively coupled to a separate main control system 72, for
example, a control
system in a driller's cabin that may provide a centralized control system for
drilling controls,
automated pipe handling controls, and the like. In other embodiments, the
computing system
may be a portion of the main control system 72 (e.g., the control system
present in the driller's
cabin).
[0027] FIG. 3 illustrates the computing system 70. It should be noted
that the computing
system 70 may be a standalone unit (e.g., a control monitor) that operates in
conjunction with
one or more sensors (e.g., to form a control system) that may operate to
provide inputs used, for
example, by the computing system to determine a position of a seam or a
connection point for
tubular segments 44 and 46. Likewise, the computing system 70 may be
configured to operate in
conjunction with one or more of the tripping apparatus 24 and/or the tubular
handling apparatus
42.
[0028] The computing system 70 may be a general purpose or a special
purpose
computer that includes a processing device 74, such as one or more application
specific
integrated circuits (ASICs), one or more processors, or another processing
device that interacts
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with one or more tangible, non-transitory, machine-readable media (e.g.,
memory 76) of the
computing system 70, which may operate to collectively store instructions
executable by the
processing device 74 to perform the methods and actions described herein. By
way of example,
such machine-readable media can comprise RAM, ROM, EPROM, EEPROM, CD-ROM or
other optical disk storage, magnetic disk storage or other magnetic storage
devices, or any other
medium which can be used to carry or store desired program code in the form of
machine
executable instructions or data structures and which can be accessed by the
processing device 74.
In some embodiment, the instructions executable by the processing device 74
are used to
generate, for example, control signals to be transmitted to, for example, one
or more of the
tripping apparatus 24 (e.g., the roughneck 54 and/or one or more of the fixed
jaws 56, the
makeup/breakout jaws 58, and the spinner 60), the tubular handling apparatus
42, and/or the
main control system 72 (e.g., to be utilized in the control of the tripping
apparatus 24, the
roughneck 54, the fixed jaws 56, the makeup/breakout jaws 58, the spinner 60,
and/or the tubular
handling apparatus 42) to operate in a manner described herein.
[0029] The computing system 70 may operate in conjunction with software
systems
implemented as computer executable instructions stored in a non-transitory
machine readable
medium of computing system 70, such as memory 76, a hard disk drive, or other
short term
and/or long term storage. Particularly, the processing device 74 may operate
in conjunction with
software systems implemented as computer executable instructions (e.g., code)
stored in a non-
transitory machine readable medium of computing system 70, such as memory 76,
that may be
executed to receive information (e.g., signals or data) related to one or more
of tubular
characteristics (e.g., lengths or similar measurements) as well as receive
tubular locations or
positions when involved in a tripping operation, attributes of a portion of
the drawworks 34,
operational parameters of the drawworks 34, and/or location and/or position
information of the
travelling block 36, the top drive 38, and/or the elevator 40. This
information can be used by the
computing system 70 (e.g., by the processing device 74 executing computer
executable
instructions stored in memory 76) to generate or otherwise calculate a
determined position of a
seam or a connection point for tubular segments 44 and 46. Additionally, this
determined
position can be used to initiate or control movement of the tripping apparatus
24 into position to
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facilitate a make-up or break-out (e.g., tripping) operation by the computing
system 70, the main
control system 72, or by another local controller of the tripping apparatus
24.
[0030] In some embodiments, the computing system 70 may also include one
or more
input structures 78 (e.g., one or more of a keypad, mouse, touchpad,
touchscreen, one or more
switches, buttons, or the like) to allow a user to interact with the computing
system 70, for
example, to start, control, or operate a graphical user interface (GUI) or
applications running on
the computing system 70 and/or to start, control, or operate the tripping
apparatus 24 (e.g., the
roughneck 54 and/or one or more of the fixed jaws 56, the makeup/breakout jaws
58, and the
spinner 60), the tubular handling apparatus 42, or additional systems of the
drilling rig 22.
Additionally, the computing system 70 may include a display 80 that may be a
liquid crystal
display (LCD) or another type of display that allows users to view images
generated by the
computing system 70. The display 80 may include a touch screen, which may
allow users to
interact with the GUI of the computing system 70. Likewise, the computing
system 70 may
additionally and/or alternatively transmit images to a display of the main
control system 72,
which itself may also include a processing device 74, a non-transitory machine
readable medium,
such as memory 76, one or more input structures 78, a display 80, and/or a
network interface 82.
[0031] Returning to the computing system 70, as may be appreciated, the
GUI may be a
type of user interface that allows a user to interact with the computer system
70 and/or the
computer system 70 and one or more sensors that transmit data to the computing
system through,
for example, graphical icons, visual indicators, and the like. Additionally,
the computer system
70 may include network interface 82 to allow the computer system 70 to
interface with various
other devices (e.g., electronic devices). The network interface 82 may include
one or more of a
Bluetooth interface, a local area network (LAN) or wireless local area network
(WLAN)
interface, an Ethernet or Ethernet based interface (e.g., a Modbus TCP,
EtherCAT, and/or
ProfiNET interface), a field bus communication interface (e.g., Profibus),
a/or other industrial
protocol interfaces that may be coupled to a wireless network, a wired
network, or a combination
thereof that may use, for example, a multi-drop and/or a star topology with
each network spur
being multi-dropped to a reduced number of nodes.
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[0032] In some embodiments, one or more of the tripping apparatus 24
(and/or a
controller or control system associated therewith), the tubular handling
apparatus 42 (and/or a
controller or control system associated therewith), sensors of the drilling
rig 22, and/or the main
control system 72 may each be a device that can be coupled to the network
interface 82. In some
embodiments, the network formed via the interconnection of one or more of the
aforementioned
devices should operate to provide sufficient bandwidth as well as low enough
latency to
exchange all required data within time periods consistent with any dynamic
response
requirements of all control sequences and closed-loop control functions of the
network and/or
associated devices therein. It may also be advantageous for the network to
allow for sequence
response times and closed-loop performances to be ascertained, the network
components should
allow for use in oilfield/drillship environments (e.g., should allow for
rugged physical and
electrical characteristics consistent with their respective environment of
operation inclusive of
but not limited to withstanding electrostatic discharge (ESD) events and other
threats as well as
meeting any electromagnetic compatibility (EMC) requirements for the
respective environment
in which the network components are disposed). The network utilized may also
provide
adequate data protection and/or data redundancy to ensure operation of the
network is not
compromised, for example, by data corruption (e.g., through the use of error
detection and
correction or error control techniques to obviate or reduce errors in
transmitted network signals
and/or data).
[0033] Returning to FIG. 2, one or more sensors 84 and 86 may be provided
in
conjunction with the drilling rig 22. In some embodiments, the one or more
sensors 84 or 86
may be utilized in conjunction with a make-up (e.g., a tripping-in) and a
break-out (e.g., a
tripping-out) operation. Alternatively, both sets of sensors 84 and 86 may be
utilized together in
conjunction with either or both tripping operations. In one embodiment, the
sensors 84 and 86
may include, but are not limited to, cameras (e.g., high frame rate cameras),
lasers (e.g., multi-
dimensional lasers), transducers (e.g., ultrasound transducers), electrical
and or magnetic
characteristic sensors (e.g., sensors that can measure/infer capacitance,
inductance, magnetism,
or the like), chemical sensors, metallurgical detection sensors, or the like.
In some embodiments,
the one or more sensors 84 may be proximity sensors (e.g., inductive,
magnetic, optical,
ultrasonic, etc.) to detect the presence of an object (e.g., a drill pipe 20,
the top drive 38, the
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elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint
64 of a drill pipe 20)
without physical contact with the object. This may be accomplished via
emission of an
electromagnetic signal as well as monitoring for a return signal or emitting
an electromagnetic
field and monitoring for changes in the electronic field. As illustrated, the
sensors 84 may be
disposed on a derrick 87 of the drilling rig 22 while the sensors 86 may be
disposed internal to or
adjacent to the drawworks 34. However, alternative locations on the drilling
rig 22 may be
employed.
[0034] In some embodiments, a sensor 84 may generate a signal indicative
of the
detection of the object (e.g., a drill pipe 20, the top drive 38, the elevator
40, the threaded joint
62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as the
object passes the sensor 84
and the sensor 84 may transmit (wirelessly or via a physical connection) the
signal indicative of
the detection of the object to the computer system 70. This signal may be used
to determine the
location of the object by the computer system 70, as the location of the
sensor 84 may be stored
in the computer system 70 and the location of the object may be calculated
based on its being
detected.
[0035] One or more additional sensors 84 may generate respective signals
indicative of
the detection of the object (e.g., a drill pipe 20, the top drive 38, the
elevator 40, the threaded
joint 62 of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as
the one or more additional
sensors 84 is passed by the object. The one or more additional sensors 84 may
each transmit
(wirelessly or via a physical connection) a respective signal indicative of
the detection of the
object to the computer system 70. This signal may be used to determine the
location of the
object by the computer system 70, as the location of the sensor 84
transmitting the signal may be
stored in the computer system 70 and the location of the object may be
calculated based on its
being detected (e.g., based on the received signal from a particular sensor
84). Additionally, the
computer system 70 may be able to calculate the velocity of the object based
on the one or more
location calculations as related to time (e.g., the computer system 70 may be
able to calculate
velocity of the object based on its calculated location at a first time and
its calculated location at
a second time).
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[0036] In
some embodiments, one or more sensors 86 may also be proximity sensors
(e.g., a rotational sensor such as an optical encoder, magnetic speed sensor,
a reflective sensor, or
a hall effect sensor) to detect operational characteristics of the drawworks
34 (e.g., rotation of a
drum, speed of a drum or the like). In some embodiments, the one or more
sensors 86 may
generate a signal indicative of operational characteristics of the drawworks
34 and may transmit
(wirelessly or via a physical connection) the signal indicative of operational
characteristic of the
drawworks 34 to the computer system 70. This signal may be used to determine
the location of
an object (e.g., a drill pipe 20, the top drive 38, the elevator 40, the
threaded joint 62 of a drill
pipe 20, or the threaded joint 64 of a drill pipe 20) by the computer system
70, as the location of
an object may be directly related to the operation of the drawworks 34 (e.g.,
an amount of
rotation of a drum causing drilling line 37 to be extended from the drawworks
34, which defines
the location of the object suspended from the block and tackle system). The
determined location
of an object may be useful, for example, to determine and/or control where and
when to move
the tripping apparatus 24 into position (e.g., tool joint recognition) to
perform a tripping
operation based on, for example, a determined or calculated location of a seam
or a connection
point for tubular segments 44 and 46.
[0037] FIG.
4 illustrates a flow chart 88 detailing the operation of a detection system,
which may include the use of the computing system 70 operating in conjunction
with one or
more of the sensors 84 and 86. It will be noted that the operation will be
discussed as utilizing
one or more sensors 84. However, this operation may instead utilize one or
more sensors 84 and
86 or one or more sensors 86 depending on, for example, a tripping operation
being undertaken,
the type of deviation in the tubular string to be detected, and/or based on
additional factors.
[0038] In
step 90, initial information may be received and/or calculated regarding the
tubular members (e.g., drill pipes 20) to be used in formation of a tubular
string (e.g., a drill
string). This initial information may include tubular member characteristics,
such as
measurements of an overall length of each respective tubular member, a
measurement of the
length of a pin connector and/or a box connector of each respective tubular
member, and/or an
order in which the respective tubular members are to be connected and/or
disconnected to form
or break down the tubular string. In some embodiments, the initial information
regarding the
tubular members may be calculated by the computing system 70 based upon inputs
(received
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signals) from one or more sensors (e.g., optical sensor or the like) adjacent
to the storage location
43 (e.g., a pipe stand) transmitted to the computing system 70. In other
embodiments, the
measurements and/or order of the tubular members may be directly input to the
computing
system. The initial information may also include information related to a
distance between a
bottom portion of, for example, the elevator 40 and a connection portion of a
tubular segment
(e.g., tubular segment 44 or 46).
[0039] In step 92, the one or more sensors 84 may generate a signal
indicative of
detection of an object (e.g., a drill pipe 20, the top drive 38, the elevator
40, the threaded joint 62
of a drill pipe 20, or the threaded joint 64 of a drill pipe 20) as the object
passes the one or more
sensors 84 and the one or more sensors 84 may transmit the signal indicative
of the detection of
the object for receipt by the computer system 70. Additionally or
alternatively in step 92, one or
more sensors 86 may generate a signal indicative of operational
characteristics of the drawworks
34 (e.g., an amount of rotation of a drum causing drilling line 37 to be
extended from the
drawworks 34) and may transmit the signal indicative of operational
characteristic of the
drawworks 34 for receipt by the computer system 70.
[0040] In step 94, the signal(s) received in step 92 may be utilized in
conjunction with
the initial information from step 90 to calculate a location of a seam (e.g.,
a tool joint seam) or a
connection point for tubular segments 44 and 46. For example, the signal(s)
received in step 92
may be used to determine the location of an object (e.g., a drill pipe 20, the
top drive 38, the
elevator 40, the threaded joint 62 of a drill pipe 20, or the threaded joint
64 of a drill pipe 20) by
the computer system 70 based upon location information of the sensor 84 used
to generate the
signal and/or based upon operational information of the drawworks 34 (e.g., an
amount of
rotation of a drum causing drilling line 37 to be extended from the drawworks
34, which defines
the location of the object suspended from the block and tackle system). For
the purposes of
discussion, the object will be the elevator 40, but it is appreciated that the
object could be any
one of a drill pipe 20, the top drive 38, the elevator 40, the threaded joint
62 of a drill pipe 20, the
threaded joint 64 of a drill pipe 20, or other related physical
characteristics of the tubular
members or their associated positioning equipment.
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[0041] In step 94, the computer system 70 (e.g., the processing device 74
or the
processing device 74 operating in conjunction with software systems
implemented as computer
executable instructions stored in a non-transitory machine readable medium of
computing system
70, such as memory 76, that may be executed) may apply the initial information
related to one or
more of tubular characteristics (e.g., lengths or similar measurements) with
the location of the
elevator 40. In some embodiments, the lengths of the tubular members (e.g.,
tubular segments
44 and 46) and/or the lengths of the connection portions of the tubular
members (e.g., the lengths
of a pin connector and/or a box connector of each respective tubular member
and, thus, the
location of the tool joint and its respective seam) may vary. The processing
device 74 or the
processing device 74 operating in conjunction with a software system may
retrieve a known
physical attribute (e.g., a measured characteristic such as a length) of the
tubular member (e.g.,
tubular segment 44) being supported by the elevator 40, based upon its order
to be
attached/detached from the tubular string. The processing device 74 or the
processing device 74
operating in conjunction with a software system may also retrieve and/or
calculate the location of
an object (e.g., the elevator 40) based upon information received in step 92.
In this manner, the
processing device 74 or the processing device 74 operating in conjunction with
a software
system may utilize the location of the object (e.g., the elevator 40) in
conjunction with the
physical attribute to determine a precise location of a connection point
(e.g., a seam of a tool
joint or a connection point for a tubular member such as tubular segment 44)
without direct
measurement or sensing of the connection point.
[0042] In step 96, the determined location of a connection point (e.g., a
seam of a tool
joint or a connection point for a tubular member such as tubular segment 44)
may be utilized to
generate an output signal from the computer system 70. In some embodiments,
this output signal
may be an indication of the location of the connection point to be used by a
controller external to
the computing system 70 and may be used to determine and/or control where and
when to move
the tripping apparatus 24 into position (e.g., tool joint recognition) to
perform a tripping
operation. Additionally or alternatively, the generated output signal may be
utilized as a control
signal for the activation of one or more slips 30 and/or 48 to secure one of
the tubular segments
(e.g., tubular segment 44) so that a calculated tool joint seam location
thereof will be at an
appropriate height for the tripping apparatus 24 to operate on. In some
embodiments, the output
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signal generated may cause display of an image, for example, on display 80 in
conjunction with
and/or separate from activation of one or more slips 30 and/or 48 and/or
determining and/or
controlling where and when to move the tripping apparatus 24 into position for
a tripping
operation.
[0043] In step 98, the output signal generated by the computer system 70
may be applied
by the computer system 70. For example, the computer system 70 (e.g., the
processing device 74
or the processing device 74 operating in conjunction with software systems
implemented as
computer executable instructions stored in a non-transitory machine readable
medium of
computing system 70, such as memory 76, that may be executed) may operate as a
control
system itself so as to transmit a control signal based upon the output signal
of step 96 or as the
output signal of step 96 to control where and when to move the tripping
apparatus 24 into
position (e.g., tool joint recognition) to perform a tripping operation.
Additionally or
alternatively, the computer system 70 may operate as a control system itself
so as to transmit a
control signal based upon the output signal of step 96 or as the output signal
of step 96 to control
the activation of one or more slips 30 and/or 48 to secure one of the tubular
segments (e.g.,
tubular segment 44) so that a calculated tool joint seam location thereof will
be at an appropriate
height for the tripping apparatus 24 to perform a tripping operation.
Likewise, external control
systems may instead receive the output signal of step 96 from the computer
system 70 and use
the output signal to control where and when to move the tripping apparatus 24
into position (e.g.,
tool joint recognition) to perform a tripping operation and/or control the
activation of one or
more slips 30 and/or 48 to secure one of the tubular segments (e.g., tubular
segment 44) so that a
calculated tool joint seam location thereof will be at an appropriate height
for the tripping
apparatus 24 to perform a tripping operation.
[0044] FIG. 5 illustrates another embodiment of a drilling rig 100 that
may be utilized in
a tripping operation consistent with embodiments of the present disclosure. As
illustrated, the
tripping apparatus 24 is illustrated as being positioned above drill floor 26
in the drilling rig 100
above the wellbore (e.g., the drilled hole or borehole of a well which may be
proximate to the
drill floor 26 or which may be, in conjunction with FIG. 1, below the wellhead
18). However, as
will be discussed in greater detail below, the tripping apparatus 24 may be
moved towards and
away from the drill floor 26 during a tripping operation. As illustrated, the
drilling rig 100 may
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include one or more of, for example, the tripping apparatus 24, a movable
platform 102 (that
may include floor slips 30 positioned in rotary table 32, as illustrated in
FIG. 6), drawworks 34, a
crown block 35, a travelling block 36, a top drive 38, an elevator 40, and a
tubular handling
apparatus 42. The tripping apparatus 24 may operate to couple and decouple
tubular segments
44 and 46 (e.g., couple and decouple drill pipe 20 to and from a drill string)
while the floor slips
30 may operate to close upon and hold a drill pipe 20 and/or the drill string
passing into the
wellbore. The rotary table 32 may be a rotatable portion that can be locked
into positon co-
planar with the drill floor 26 and/or above the drill floor 26. The rotary
table 32 can, for example,
operate to impart rotation to the drill string either as a primary or a backup
rotation system (e.g.,
a backup to the top drive 38) as well as utilize its floor slips 30 to support
tubular segments (e.g.,
tubular segment 46), for example, during a tripping operation.
[0045] The drawworks 34 may be a large spool that is powered to retract
and extend
drilling line 37 (e.g., wire cable) over a crown block 35 (e.g., a vertically
stationary set of one or
more pulleys or sheaves through which the drilling line 37 is threaded) and a
travelling block
(e.g., a vertically movable set of one or more pulleys or sheaves through
which the drilling line
37 is threaded) to operate as a block and tackle system for movement of the
top drive 38, the
elevator 40, and any tubular segment (e.g., drill pipe 20) coupled thereto. In
some embodiments,
the top drive 38 and/or the elevator 40 may be referred to as a tubular
support system or the
tubular support system may also include the block and tackle system described
above.
[0046] The top drive 38 may be a device that provides torque to (e.g.,
rotates) the drill
string as an alternative to the rotary table 32 and the elevator 40 may be a
mechanism that may
be closed around a drill pipe 20 or other tubular segments 44 and 46 (or
similar components) to
grip and hold the drill pipe 20 or other tubular segments 44 and 46 while
those segments are
moving vertically (e.g., while being lowered into or raised from a wellbore)
or directionally (e.g.,
during slant drilling). The tubular handling apparatus 42 may operate to
retrieve a tubular
segment 44 from a storage location 43 (e.g., a pipe stand) and position the
tubular segment 44
during tripping-in to assist in adding a tubular segment 44 to a tubular
string. Likewise, the
tubular handling apparatus 42 may operate to retrieve a tubular segment 44
from a tubular string
and transfer the tubular segment 44 to a storage location (e.g., a pipe stand)
during tripping-out
to remove the tubular segment 44 from the tubular string.
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[0047] During a tripping-in operation, the tubular handling apparatus 42
may position a
tubular segment 44 (e.g., a drill pipe 20) so that the segment 44 may be
grasped by the elevator
40. Elevator 40 may be lowered, for example, via the block and tackle system
towards the
tripping apparatus 24 to be coupled to tubular segment 46 (e.g., a drill pipe
20) as part of a drill
string. In some embodiments, the tripping apparatus 24 may operate as
discussed in conjunction
with FIG. 2A above during a tripping operation. However, in addition to the
operation of the
tripping apparatus 24, continuous tripping operations (tripping tubular
segments 44 and 46
without halting the movement of the tubular string at a fixed position) may be
facilitated and/or
accelerated through the inclusion of the movable platform 102.
[0048] The movable platform 102, may be raised and lowered with a cable
and sheave
arrangement (e.g., similar to the block and tackle system for movement of the
top drive 38) that
may include a winch or other drawworks element positioned on the drill floor
26 or elsewhere on
the offshore platform 10 or the drilling rig 22. The winch or other drawworks
element may be a
spool that is powered to retract and extend a line (e.g., a wire cable) over a
crown block (e.g., a
stationary set of one or more pulleys or sheaves through which the line 37 is
threaded) and a
travelling block (e.g., a movable set of one or more pulleys or sheaves
through which the line 37
is threaded) to operate as a block and tackle system for movement of the
movable platform 102
and, thus the rotary table 32 therein and the tripping apparatus 24 thereon.
Additionally and/or
alternatively, direct acting cylinders, a suspended winch and cable system
mechanism disposed
such that the movable platform 102 is between the suspended winch and cable
system and the
drill floor 26, or similar internal or external actuation systems may be used
to move the movable
platform 102 along support element 68.
[0049] In some embodiments, the support element 68 may be one or more
guide
mechanisms (e.g., guide tracks, such as top drive dolly tracks) that provide
support (e.g., lateral
support) to the movable platform 102 while allowing for movement towards and
away from the
drill floor 26. Additionally, as illustrated in FIG. 6, one or more lateral
supports 104 may be
used to couple the movable platform 102 to the support element 68. For
example, the lateral
supports 104 may be, for example, pads that may be made of Teflon-graphite
material or another
low-friction material (e.g., a composite material) that allows for motion of
the movable platform
102 relative to drill floor 26 and/or the tubular segment support system with
reduced friction
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characteristics. In addition to, or in place of the aforementioned pads, other
lateral supports 104
including bearing or roller type supports (e.g., steel or other metallic or
composite rollers and/or
bearings) may be utilized. The lateral supports 104 may allow the movable
platform 102 to
interface with a support element 68 (e.g., guide tracks, such as top drive
dolly tracks) so that the
movable platform 102 is movably coupled to the support element 68.
Accordingly, the movable
platform 102 may be movably coupled to a support element 68 to allow for
movement of the
movable platform 102 (e.g., towards and away from the drill floor 26 and/or
the tubular segment
support system while maintaining contact with the guide tracks or other
support element 68)
during a tripping operation (e.g., a continuous tripping operation).
[0050] As further illustrated in FIG. 6, the movable platform 102 may
have guide pins
106 or similar devices to provide coarse and fine alignment when moving in and
out of the drill
floor 26 (e.g., into a planar position with the drill floor 26 or raised above
the drill floor 26).
Additionally, one or more locking mechanisms 108 may be employed to affix the
movable
platform 102 into a desired position with respect to the drill floor 26, for
example, when a
tripping operation is complete or not necessary. In this fixed position, the
rotary table 32 may
operate in conjunction with the top drive 38 and/or as a backup system to the
top drive 38. The
locking mechanisms 108 may be automatic (e.g., controllable) such that they
can be actuated
without human contact (e.g., a control signal may cause pins or other locking
mechanisms to
engage an aperture between the drill floor 26 and the movable platform 102).
It is envisioned
that the locking mechanisms will interface with the drill floor 26 or an
element beneath the drill
floor (if the movable platform 102 is to be locked in a position planar with
the drill floor 26).
[0051] Returning to FIG. 5, a computing system 70 may be present and may
operate in
conjunction with one or more of the tripping apparatus 24, the movable
platform 102, an
actuating system used to move the tripping apparatus 24, and/or an actuating
system used to
move the movable platform 102. This computing system 70 may also operate to
control one or
more of the tubular segment support system and/or the tubular handling
apparatus 42. It should
be noted that the computing system 70 may be similar to the computing system
of FIG. 3 and
may operate in a manner disclosed with respect to FIG. 4, with the added
aspects of control of
the movable platform 102 and/or the floor slips 30 of the movable platform 102
in conjunction
with steps 96 and 98 therein.
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[0052] Additionally, tripping operations involving singular tubular
members (e.g., drill
pipe 20) has been discussed with respect to FIGS. 2-6. However, as illustrated
in FIG. 7, it is
envisioned that a stand 110 of tubular segments 44 (e.g., two, three, or more
tubular segments 44
coupled together) may be the tubular segments 44 being tripped-in or tripped-
out. The operation
including the steps described in FIG. 4 may apply to tripping stands 110 as
illustrated in FIG. 7.
For example, when applying step 90 to the system of FIG. 7, initial
information may be received
and/or calculated regarding the tubular segments 44 (e.g., drill pipes 20) to
be used in formation
of a tubular string (e.g., a drill string). This initial information may
include tubular segment 44
characteristics of the stand 110, such as measurements of an overall length of
each respective
tubular segment 44, a measurement of the length of a pin connector and/or a
box connector of
each respective tubular segment 44, and/or an order in which the respective
tubular segment 44
are to be connected and/or disconnected to form or break down the tubular
string, measurements
of an overall length of the stand 110, a measurement of the length of a pin
connector and/or a
box connector of each respective tubular segment 44 at a terminal end of the
stand 110 (e.g.,
where a connection between stands 110 is made), and/or an order in which the
respective stands
110 are to be connected and/or disconnected to form or break down the tubular
string. In some
embodiments, the initial information regarding the tubular segments 44 of the
stand 110 and/or
the stand 110 may be calculated by the computing system 70 based upon inputs
(received
signals) from one or more sensors (e.g., optical sensor or the like) adjacent
to the storage location
43 (e.g., a pipe stand) transmitted to the computing system 70. In other
embodiments, the
measurements and/or order of the tubular segments 44 of the stand 110 and/or
the stand 110 may
be directly input to the computing system. The initial information may also
include information
related to a distance between a bottom portion of, for example, the elevator
40 and a connection
portion of an uppermost and/or lowermost tubular segment 44 of the stand 110.
[0053] Likewise when applying step 94 to the system of FIG. 7, the
signal(s) received in
step 92 may be utilized in conjunction with the initial information from step
90 to calculate a
location of a seam (e.g., a tool joint seam) or a connection point for tubular
stands 110. For
example, the signal(s) received in step 92 may be used to determine the
location of an object
(e.g., a drill pipe 20, the top drive 38, the elevator 40, the threaded joint
62 of a drill pipe 20, or
the threaded joint 64 of a drill pipe 20) by the computer system 70 based upon
location
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information of the sensor 84 used to generate the signal and/or based upon
operational
information of the drawworks 34 (e.g., an amount of rotation of a drum causing
drilling line 37
to be extended from the drawworks 34, which defines the location of the object
suspended from
the block and tackle system). For the purposes of discussion, the object will
be the elevator 40,
but it is appreciated that the object could be any one of a drill pipe 20, the
top drive 38, the
elevator 40, the threaded joint 62 of a drill pipe 20, the threaded joint 64
of a drill pipe 20, or
other related physical characteristics of the tubular stands 110 or their
associated positioning
equipment.
[0054] When further applying step 94 to the system of FIG. 7, the
computer system 70
(e.g., the processing device 74 or the processing device 74 operating in
conjunction with
software systems implemented as computer executable instructions stored in a
non-transitory
machine readable medium of computing system 70, such as memory 76, that may be
executed)
may apply the initial information related to one or more of tubular
characteristics (e.g., lengths or
similar measurements) with the location of the elevator 40. In some
embodiments, the lengths of
the tubular members (e.g., tubular segments 44) or tubular stands 110 and/or
the lengths of the
connection portions of the tubular segments 44 of the tubular stands 110
(e.g., the lengths of a
pin connector and/or a box connector of each respective tubular segment 44 of
the stand 110 and,
thus, the tool joint and its respective seam between stands 110) may vary. The
processing device
74 or the processing device 74 operating in conjunction with a software system
may retrieve a
known physical attribute (e.g., a measured characteristic such as a length) of
the tubular member
(e.g., tubular segment 44) or stand 110 being supported by the elevator 40,
based upon its order
to be attached/detached from the tubular string. The processing device 74 or
the processing
device 74 operating in conjunction with a software system may also retrieve
and/or calculate the
location of an object (e.g., the elevator 40) based upon information received
in step 92. In this
manner, the processing device 74 or the processing device 74 operating in
conjunction with a
software system may utilize the location of the object (e.g., the elevator 40)
in conjunction with
the physical attribute to determine a precise location of a connection point
(e.g., a seam of a tool
joint or a connection point for an upper and/or lower tubular segment 44 of
the tubular stand
110) without direct measurement or sensing of the connection point.
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[0055] When applying step 96 to the system of FIG. 7, the determined
location of a
connection point (e.g., a seam of a tool joint or a connection point for a
respective tubular
segment 44 of the stand 110 and/or between two stands 110) may be utilized to
generate an
output signal from the computer system 70. In some embodiments, this output
signal may be an
indication of the location of the connection point to be used by a controller
external to the
computing system 70 and may be used to determine and/or control where and when
to move the
tripping apparatus 24 into position (e.g., tool joint recognition) to perform
a tripping operation
between stands 110. Additionally or alternatively, the generated output signal
may be utilized as
a control signal for the activation of one or more slips 30 and/or 48 to
secure one of the stands
110 so that a calculated tool joint seam location thereof will be at an
appropriate height for the
tripping apparatus 24 to operate on. In some embodiments, the output signal
generated may
cause display of an image, for example, on display 80 in conjunction with
and/or separate from
activation of one or more slips 30 and/or 48 and/or determining and/or
controlling where and
when to move the tripping apparatus 24 into position for a tripping operation.
[0056] In applying step 98 to the system of FIG. 7, the output signal
generated by the
computer system 70 may be applied by the computer system 70. For example, the
computer
system 70 (e.g., the processing device 74 or the processing device 74
operating in conjunction
with software systems implemented as computer executable instructions stored
in a non-
transitory machine readable medium of computing system 70, such as memory 76,
that may be
executed) may operate as a control system itself so as to transmit a control
signal based upon the
output signal of step 96 or as the output signal of step 96 to control where
and when to move the
tripping apparatus 24 into position (e.g., tool joint recognition) to perform
a tripping operation.
Additionally or alternatively, the computer system 70 may operate as a control
system itself so as
to transmit a control signal based upon the output signal of step 96 or as the
output signal of step
96 to control the activation of one or more slips 30 and/or 48 to secure one
of the stands 110 so
that a calculated tool joint seam location thereof will be at an appropriate
height for the tripping
apparatus 24 to perform a tripping operation. Likewise, external control
systems may instead
receive the output signal of step 96 from the computer system 70 and use the
output signal to
control where and when to move the tripping apparatus 24 into position (e.g.,
tool joint
recognition) to perform a tripping operation and/or control the activation of
one or more slips 30
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and/or 48 to secure one of the stands 110 so that a calculated tool joint seam
location thereof will
be at an appropriate height for the tripping apparatus 24 to perform a
tripping operation.
[0057] This written description uses examples to disclose the above
description to enable
any person skilled in the art to practice the disclosure, including making and
using any devices or
systems and performing any incorporated methods. The patentable scope of the
disclosure is
defined by the claims, and may include other examples that occur to those
skilled in the art.
Such other examples are intended to be within the scope of the claims if they
have structural
elements that do not differ from the literal language of the claims, or if
they include equivalent
structural elements with insubstantial differences from the literal languages
of the claims.
Accordingly, while the above disclosed embodiments may be susceptible to
various
modifications and alternative forms, specific embodiments have been shown by
way of example
in the drawings and have been described in detail herein. However, it should
be understood that
the embodiments are not intended to be limited to the particular forms
disclosed. Rather, the
disclosed embodiment are to cover all modifications, equivalents, and
alternatives falling within
the spirit and scope of the embodiments as defined by the following appended
claims.
23
