U.S. patent application number 14/983121 was filed with the patent office on 2017-05-04 for characterizing responses in a drilling system.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Richard John Harmer.
Application Number | 20170122092 14/983121 |
Document ID | / |
Family ID | 58635535 |
Filed Date | 2017-05-04 |
United States Patent
Application |
20170122092 |
Kind Code |
A1 |
Harmer; Richard John |
May 4, 2017 |
CHARACTERIZING RESPONSES IN A DRILLING SYSTEM
Abstract
Computing systems, computer-readable media, and methods may
include determining at least one automated sequence to be performed
during a portion of a drilling operation by a drilling system. The
at least one automated sequence may include performing one or more
actions to cause a response in the drilling system. The method may
include performing, during the drilling operation, the at least one
automated sequence. Further, the method may include measuring,
during the performance of the at least one automated sequence, one
or more responses in the drilling system. The one or more responses
may be measured within a wellbore undergoing the drilling
operations and at a surface of the wellbore. The method may include
modifying a model of the drilling system based at least in part of
the one or more responses that were measured during the performance
of the at least one automated sequence.
Inventors: |
Harmer; Richard John;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Houston |
TX |
US |
|
|
Family ID: |
58635535 |
Appl. No.: |
14/983121 |
Filed: |
December 29, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62250970 |
Nov 4, 2015 |
|
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 44/00 20130101;
G05B 11/01 20130101; E21B 44/04 20130101; G05B 13/021 20130101;
E21B 47/06 20130101; E21B 47/07 20200501; G01V 11/002 20130101;
G05B 13/04 20130101; E21B 44/06 20130101 |
International
Class: |
E21B 44/04 20060101
E21B044/04; G05B 11/01 20060101 G05B011/01; E21B 44/06 20060101
E21B044/06; G05B 13/02 20060101 G05B013/02; G01V 11/00 20060101
G01V011/00; E21B 47/06 20060101 E21B047/06 |
Claims
1. A method, comprising: determining at least one automated
sequence to be performed during a portion of a drilling operation
by a drilling system, wherein the at least one automated sequence
comprises performing one or more actions to cause a response in the
drilling system; performing, during the drilling operation, the at
least one automated sequence; measuring, during the performance of
the at least one automated sequence, one or more responses in the
drilling system, wherein the one or more responses are measured
within a wellbore undergoing the drilling operations and at a
surface of the wellbore; and modifying a model of the drilling
system based at least in part of the one or more responses that
were measured during the performance of the at least one automated
sequence.
2. The method of claim 1, the method further comprising: altering
one or more operational parameters in the drilling operations based
at least in part on the one or more responses in the drilling
system.
3. The method of claim 2, wherein the one or more operational
parameters comprise flow rate of drilling mud, rotational speed of
a drill string, motion of a bottom hole assembly, and safety limits
of the drilling system.
4. The method of claim 1, wherein the one or more responses are
measured by sensors positioned at one or more locations comprising
a surface location of the drilling system, a location within the
wellbore, a location on a drill string, and a location in a bottom
hole assembly.
5. The method of claim 1, wherein the at least one automated
sequence comprises one or more of: a sequence of taking off, bottom
pick up, slack off, and torque references at different rates; a
sequence for shutting down flow rate and revolutions per minute
(RPM) at an end of a connection, and bringing up flow rate and RPM
at a start of a connection; a sequence of moving a block up and
down to characterize sheave friction and remove an effect from
weight on bit (WOB) and hookload calculations; a sequence of
staging up the WOB at a constant RPM to identify a point at which
the rotational system becomes unstable and enters into fully
developed stick-slip; a sequence that moves the block down at
varying rates; and a sequence that sweeps through a range of
surface RPM's off bottom to identify the locations of lateral BHA
resonances.
6. The method of claim 1, wherein the at least one automated
sequence comprises one or more of: a sequence of characterizing a
relationships between the one or more operational parameters and
bottom hole assembly (BHA) vibrations during the drilling
operations; a sequence where a slider system cycles torque to
improve weight transfer and control toolface with downhole feedback
in a form of a BHA toolface; a sequence that varies weight when
drilling with a motor and rotating and measuring pressure; and a
sequence that automatically modulates pump stroke rates.
7. The method of claim 1, wherein the at least one automated
sequence comprises one or more of: a sequence of monitoring a
change in surface hookload at a range of flow rates circulating
with rotation off bottom; a sequence that pumps drilling mud at
different flow rates; a sequence that dynamically tunes an
autodriller gain settings based upon a real-time derived bit-rock
interaction model; a sequence that varies the flow rate and
measures motor speed; a sequence that varies the flow rate and the
weight on bit (WOB) and measuring motor speed and pressure; and a
sequence that varies at least one of rotation speed or flow and
measuring temperature at along a drill string.
8. The method of claim 1, the method further comprising: storing
the one or more responses in the drilling system.
9. The method of claim 1, the method further comprising:
determining, prior to performing the at least one automated
sequence, that the at least one automated sequence requires an
update based at least partially on a change in conditions in the
drilling operation; and updating the at least one automated
sequence in response to the change in the condition in the drilling
operation.
10. A non-transitory computer readable medium storing instructions
for causing one or more processors to perform a method comprising:
determining at least one automated sequence to be performed during
a portion of a drilling operation by a drilling system, wherein the
at least one automated sequence comprises performing one or more
actions to cause a response in the drilling system; performing,
during the drilling operation, the at least one automated sequence;
measuring, during the performance of the at least one automated
sequence, one or more responses in the drilling system, wherein the
one or more responses are measured within a wellbore undergoing the
drilling operations and at a surface of the wellbore; and modifying
a model of the drilling system based at least in part of the one or
more responses that were measured during the performance of the at
least one automated sequence.
11. The non-transitory computer readable medium of claim 10, the
method further comprising: altering one or more operational
parameters in the drilling operations based at least in part on the
one or more responses in the drilling system.
12. The non-transitory computer readable medium of claim 11,
wherein the one or more operational parameters comprise flow rate
of drilling mud, rotational speed of a drill string, motion of a
bottom hole assembly, and safety limits of the drilling system.
13. The non-transitory computer readable medium of claim 10,
wherein the one or more responses are measured by sensors
positioned at one or more locations comprising a surface location
of the drilling system, a location within the wellbore, a location
on a drill string, and a location in a bottom hole assembly.
14. The non-transitory computer readable medium of claim 10,
wherein the at least one automated sequence comprises one or more
of: a sequence of taking off, bottom pick up, slack off, and torque
references at different rates; a sequence for shutting down flow
rate and revolutions per minute (RPM) at an end of a connection,
and bringing up flow rate and RPM at a start of a connection; a
sequence of moving a block up and down to characterize sheave
friction and remove an effect from weight on bit (WOB) and hookload
calculations; a sequence of staging up the WOB at a constant RPM to
identify a point at which the rotational system becomes unstable
and enters into fully developed stick-slip; a sequence that moves
the block down at varying rates; and a sequence that sweeps through
a range of surface RPM's off bottom to identify the locations of
lateral BHA resonances.
15. The non-transitory computer readable medium of claim 10,
wherein the at least one automated sequence comprises one or more
of: a sequence of characterizing a relationships between the one or
more operational parameters and bottom hole assembly (BHA)
vibrations during the drilling operations; a sequence where a
slider system cycles torque to improve weight transfer and control
toolface with downhole feedback in a form of a BHA toolface; a
sequence that varies weight when drilling with a motor and rotating
and measuring pressure; and a sequence that automatically modulates
pump stroke rates.
16. The non-transitory computer readable medium of claim 10,
wherein the at least one automated sequence comprises one or more
of: a sequence of monitoring a change in surface hookload at a
range of flow rates circulating with rotation off bottom; a
sequence that pumps drilling mud at different flow rates; a
sequence that dynamically tunes an autodriller gain settings based
upon a real-time derived bit-rock interaction model; a sequence
that varies the flow rate and measures motor speed; a sequence that
varies the flow rate and the weight on bit (WOB) and measuring
motor speed and pressure; and a sequence that varies at least one
of rotation speed or flow and measuring temperature at along a
drill string.
17. The non-transitory computer readable medium of claim 10, the
method further comprising: storing the one or more responses in the
drilling system.
18. The non-transitory computer readable medium of claim 10, the
method further comprising: determining, prior to performing the at
least one automated sequence, that the at least one automated
sequence requires an update based at least partially on a change in
conditions in the drilling operation; and updating the at least one
automated sequence in response to the change in the condition in
the drilling operation.
19. A system, comprising: one or more memory devices storing
instructions; and one or more processors coupled to the memory
devices and configured to execute the instructions to perform a
method comprising: determining at least one automated sequence to
be performed during a portion of a drilling operation by a drilling
system, wherein the at least one automated sequence comprises
performing one or more actions to cause a response in the drilling
system; performing, during the drilling operation, the at least one
automated sequence; measuring, during the performance of the at
least one automated sequence, one or more responses in the drilling
system, wherein the one or more responses are measured within a
wellbore undergoing the drilling operations and at a surface of the
wellbore; and modifying a model of the drilling system based at
least in part of the one or more responses that were measured
during the performance of the at least one automated sequence.
20. The system of claim 19, the method further comprising: altering
one or more operational parameters in the drilling operations based
at least in part on the one or more responses in the drilling
system.
21. The system of claim 20, wherein the one or more operational
parameters comprise flow rate of drilling mud, rotational speed of
a drill string, motion of a bottom hole assembly, and safety limits
of the drilling system.
22. The system of claim 19, wherein the one or more responses are
measured by sensors positioned at one or more locations comprising
a surface location of the drilling system, a location within the
wellbore, a location on a drill string, and a location in a bottom
hole assembly.
23. The system of claim 19, wherein the at least one automated
sequence comprises one or more of: a sequence of taking off, bottom
pick up, slack off, and torque references at different rates; a
sequence for shutting down flow rate and revolutions per minute
(RPM) at an end of a connection, and bringing up flow rate and RPM
at a start of a connection; a sequence of moving a block up and
down to characterize sheave friction and remove an effect from
weight on bit (WOB) and hookload calculations; a sequence of
staging up the WOB at a constant RPM to identify a point at which
the rotational system becomes unstable and enters into fully
developed stick-slip; a sequence that moves the block down at
varying rates; and a sequence that sweeps through a range of
surface RPM's off bottom to identify the locations of lateral BHA
resonances
24. The system of claim 19, wherein the at least one automated
sequence comprises one or more of: a sequence of characterizing a
relationships between the one or more operational parameters and
bottom hole assembly (BHA) vibrations during the drilling
operations; a sequence where a slider system cycles torque to
improve weight transfer and control toolface with downhole feedback
in a form of a BHA toolface; a sequence that varies weight when
drilling with a motor and rotating and measuring pressure; and a
sequence that automatically modulates pump stroke rates.
25. The system of claim 19, wherein the at least one automated
sequence comprises one or more of: a sequence of monitoring a
change in surface hookload at a range of flow rates circulating
with rotation off bottom; a sequence that pumps drilling mud at
different flow rates; a sequence that dynamically tunes an
autodriller gain settings based upon a real-time derived bit-rock
interaction model; a sequence that varies the flow rate and
measures motor speed; a sequence that varies the flow rate and the
weight on bit (WOB) and measuring motor speed and pressure; and a
sequence that varies at least one of rotation speed or flow and
measuring temperature at along a drill string.
26. The system of claim 19, the method further comprising:
determining, prior to performing the at least one automated
sequence, that the at least one automated sequence requires an
update based at least partially on a change in conditions in the
drilling operation; and updating the at least one automated
sequence in response to the change in the condition in the drilling
operation.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority to U.S. Provisional Patent
Application having Ser. No. 62/250,970, filed on Nov. 4, 2015,
entitled "Methods and Systems for Characterizing Responses in a
Drilling System." The entirety of this priority provisional patent
application is incorporated by reference herein.
BACKGROUND
[0002] In hydrocarbon exploration industries, models of physical
response of a drilling system may be used in the planning phase of
a drilling operation. Drilling operation involves three separate
mechanical operations at the surface, namely pumping mud, rotating
the pipe, and moving the travelling block. Each of the surface
mechanical operations has an associated force term: a pressure to
pump fluid, a torque to turn the drill string, and a load on the
hook from suspending the drill string in the well. Manual
operations may be undertaken during the drilling phase to
characterize the response of the drilling system. Additional, the
manual operations may be undertaken to facilitate model
calibration, which is then used for drilling parameter selection
and abnormal trend identification. Examples of manual operations
may include: manually performing a drill off test where rate of
penetration ("ROP") and downhole torque-on-bit are recorded at
different weight on bit ("WOB") and revolution per minute ("RPM")
combinations; manually circulating off bottom at different rates to
calibrate a hydraulics model; manually taking pick-up, slack off
and rotating weights as per a pre-defined sequence to calibrate a
torque and drag model.
[0003] With the advent of automated drilling, at least some of the
drilling process may be computer-controlled, e.g., "auto-driller"
operations. However, no methods or systems are available that
automatically integrate operations to characterize the response of
the drilling system during the drilling operations.
SUMMARY
[0004] Embodiments of the present disclosure may provide a method.
The method may include determining at least one automated sequence
to be performed during a portion of a drilling operation by a
drilling system. The at least one automated sequence may include
performing one or more actions to cause a response in the drilling
system. The method may also include performing, during the drilling
operation, the at least one automated sequence. Further, the method
may include measuring, during the performance of the at least one
automated sequence, one or more responses in the drilling system.
The one or more responses may be measured within a wellbore
undergoing the drilling operations and at a surface of the
wellbore. The method may include modifying a model of the drilling
system based at least in part of the one or more responses that
were measured during the performance of the at least one automated
sequence.
[0005] In an embodiment, the method may further include altering
one or more operational parameters in the drilling operations based
at least in part on the one or more responses in the drilling
system.
[0006] In an embodiment, the one or more operational parameters may
include flow rate of drilling mud, rotational speed of a drill
string, motion of a bottom hole assembly, and safety limits of the
drilling system.
[0007] In an embodiment, the one or more responses may be measured
by sensors positioned at one or more locations comprising a surface
location of the drilling system, a location within the wellbore, a
location on a drill string, and a location in a bottom hole
assembly.
[0008] In an embodiment, the at least one automated sequence
include one or more of: a sequence of taking off-bottom pick up,
slack off, and torque references at different rates; a sequence for
shutting down flow rate and revolutions per minute (RPM) at an end
of a connection, and bringing up flow rate and RPM at a start of a
connection; a sequence of moving a block up and down to
characterize sheave friction and remove an effect from weight on
bit (WOB) and hookload calculations; a sequence of characterizing a
relationships between the one or more operational parameters and
bottom hole assembly (BHA) vibrations during the drilling
operations; a sequence where a slider system cycles torque to
improve weight transfer and control toolface with downhole feedback
in a form of a BHA toolface; a sequence of monitoring a change in
surface hookload at a range of flow rates circulating with rotation
off bottom; a sequence of staging up the WOB at a constant RPM to
identify a point at which the rotational system becomes unstable
and enters into fully developed stick-slip; a sequence that sweeps
through a range of surface RPM's off bottom to identify the
locations of lateral BHA resonances; a sequence that pumps drilling
mud at different flow rates; a sequence that dynamically tunes an
autodriller gain settings based upon a real-time derived bit-rock
interaction model; a sequence that automatically modulates pump
stroke rates; a sequence that varies weight when drilling with a
motor and rotating and measuring pressure; a sequence that varies
the flow rate and measures motor speed; a sequence that varies the
flow rate and the WOB and measuring motor speed and pressure; a
sequence that varies at least one of rotation speed or flow and
measuring temperature at along a drill string; and a sequence that
moves the block down at varying rates.
[0009] In an embodiment, the method may further include storing the
one or more responses in the drilling system.
[0010] In an embodiment, the method may further include
determining, prior to performing the at least one automated
sequence, that the at least one automated sequence requires an
update based at least partially on a change in conditions in the
drilling operation. The method may also include updating the at
least one automated sequence in response to the change in the
condition in the drilling operation.
[0011] Embodiments of the present disclosure may provide a
non-transitory computer readable storage medium storing
instructions for causing one or more processors to perform a
method. The method may include determining at least one automated
sequence to be performed during a portion of a drilling operation
by a drilling system. The at least one automated sequence may
include performing one or more actions to cause a response in the
drilling system. The method may also include performing, during the
drilling operation, the at least one automated sequence. Further,
the method may include measuring, during the performance of the at
least one automated sequence, one or more responses in the drilling
system. The one or more responses may be measured within a wellbore
undergoing the drilling operations and at a surface of the
wellbore. The method may include modifying a model of the drilling
system based at least in part of the one or more responses that
were measured during the performance of the at least one automated
sequence.
[0012] Embodiments of the present disclosure may provide a system.
The system may include one or more memory devices storing
instructions. The system may also include one or more processors
coupled to the one or more memory devices and may execute the
instructions to perform a method. The method may include
determining at least one automated sequence to be performed during
a portion of a drilling operation by a drilling system. The at
least one automated sequence may include performing one or more
actions to cause a response in the drilling system. The method may
also include performing, during the drilling operation, the at
least one automated sequence. Further, the method may include
measuring, during the performance of the at least one automated
sequence, one or more responses in the drilling system. The one or
more responses may be measured within a wellbore undergoing the
drilling operations and at a surface of the wellbore. The method
may include modifying a model of the drilling system based at least
in part of the one or more responses that were measured during the
performance of the at least one automated sequence.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] The accompanying drawings, which are incorporated in and
constitute a part of this specification, illustrate embodiments of
the present teachings and together with the description, serve to
explain the principles of the present teachings. In the
figures:
[0014] FIGS. 1A and 1B illustrate a schematic view of a drilling
rig and a control system, according to an embodiment.
[0015] FIG. 2 illustrates a schematic view of a drilling rig and a
remote computing resource environment, according to an
embodiment.
[0016] FIG. 3 illustrate a flowchart of a method for characterizing
responses in drilling operations according to an embodiment.
[0017] FIGS. 4A, 4B, 4C, 4D, 4E, 4F, and 4G illustrate examples of
automated sequences according to an embodiment.
[0018] FIG. 5 illustrates a schematic view of a computing system
according to an embodiment.
DETAILED DESCRIPTION
[0019] Reference will now be made in detail to specific embodiments
illustrated in the accompanying drawings and figures. In the
following detailed description, numerous specific details are set
forth in order to provide a thorough understanding of the
invention. However, it will be apparent to one of ordinary skill in
the art that embodiments may be practiced without these specific
details. In other instances, well-known methods, procedures,
components, circuits, and networks have not been described in
detail so as not to unnecessarily obscure aspects of the
embodiments.
[0020] It will also be understood that, although the terms first,
second, etc. may be used herein to describe various elements, these
elements should not be limited by these terms. These terms are only
used to distinguish one element from another. For example, a first
object could be termed a second object or step, and, similarly, a
second object could be termed a first object or step, without
departing from the scope of the present disclosure.
[0021] The terminology used in the description of the invention
herein is for the purpose of describing particular embodiments only
and is not intended to be limiting. As used in the description of
the invention and the appended claims, the singular forms "a," "an"
and "the" are intended to include the plural forms as well, unless
the context clearly indicates otherwise. It will also be understood
that the term "and/or" as used herein refers to and encompasses any
and all possible combinations of one or more of the associated
listed items. It will be further understood that the terms
"includes," "including," "comprises" and/or "comprising," when used
in this specification, specify the presence of stated features,
integers, steps, operations, elements, and/or components, but do
not preclude the presence or addition of one or more other
features, integers, steps, operations, elements, components, and/or
groups thereof. Further, as used herein, the term "if" may be
construed to mean "when" or "upon" or "in response to determining"
or "in response to detecting," depending on the context.
[0022] FIG. 1A illustrates a conceptual, schematic view of a
control system 100 for a drilling rig 102, according to an
embodiment. The control system 100 may include a rig computing
resource environment 105, which may be located onsite at the
drilling rig 102 and, in some embodiments, may have a coordinated
control device 104. The control system 100 may also provide a
supervisory control system 107. In some embodiments, the control
system 100 may include a remote computing resource environment 106,
which may be located offsite from the drilling rig 102.
[0023] The remote computing resource environment 106 may include
computing resources locating offsite from the drilling rig 102 and
accessible over a network. A "cloud" computing environment is one
example of a remote computing resource. The cloud computing
environment may communicate with the rig computing resource
environment 105 via a network connection (e.g., a WAN or LAN
connection). In some embodiments, the remote computing resource
environment 106 may be at least partially located onsite, e.g.,
allowing control of various aspects of the drilling rig 102 onsite
through the remote computing resource environment 105 (e.g., via
mobile devices). Accordingly, "remote" should not be limited to any
particular distance away from the drilling rig 102.
[0024] Further, the drilling rig 102 may include various systems
with different sensors and equipment for performing operations of
the drilling rig 102, and may be monitored and controlled via the
control system 100, e.g., the rig computing resource environment
105. Additionally, the rig computing resource environment 105 may
provide for secured access to rig data to facilitate onsite and
offsite user devices monitoring the rig, sending control processes
to the rig, and the like.
[0025] Various example systems of the drilling rig 102 are depicted
in FIG. 1A. For example, the drilling rig 102 may include a
downhole system 110, a fluid system 112, and a central system 114.
These systems 110, 112, 114 may also be examples of "subsystems" of
the drilling rig 102, as described herein. In some embodiments, the
drilling rig 102 may include an information technology (IT) system
116. The downhole system 110 may include, for example, a bottomhole
assembly (BHA), mud motors, sensors, etc. disposed along the drill
string, and/or other drilling equipment configured to be deployed
into the wellbore. Accordingly, the downhole system 110 may refer
to tools disposed in the wellbore, e.g., as part of the drill
string used to drill the well.
[0026] The fluid system 112 may include, for example, drilling mud,
pumps, valves, cement, mud-loading equipment, mud-management
equipment, pressure-management equipment, separators, and other
fluids equipment. Accordingly, the fluid system 112 may perform
fluid operations of the drilling rig 102.
[0027] The central system 114 may include a hoisting and rotating
platform, top drive, rotary table, kelly, drawworks, pumps,
generators, tubular handling equipment, derrick, mast,
substructure, and other suitable equipment. Accordingly, the
central system 114 may perform power generation, hoisting, and
rotating operations of the drilling rig 102, and serve as a support
platform for drilling equipment and staging ground for rig
operation, such as connection make up, etc. The IT system 116 may
include software, computers, and other IT equipment for
implementing IT operations of the drilling rig 102.
[0028] The control system 100, e.g., via the coordinated control
device 104 of the rig computing resource environment 105, may
monitor sensors from multiple systems of the drilling rig 102 and
provide control commands to multiple systems of the drilling rig
102, such that sensor data from multiple systems may be used to
provide control commands to the different systems of the drilling
rig 102. For example, the system 100 may collect temporally and
depth aligned surface data and downhole data from the drilling rig
102 and store the collected data for access onsite at the drilling
rig 102 or offsite via the rig computing resource environment 105.
Thus, the system 100 may provide monitoring capability.
Additionally, the control system 100 may include supervisory
control via the supervisory control system 107.
[0029] In some embodiments, one or more of the downhole system 110,
fluid system 112, and/or central system 114 may be manufactured
and/or operated by different vendors. In such an embodiment,
certain systems may not be capable of unified control (e.g., due to
different protocols, restrictions on control permissions, safety
concerns for different control systems, etc.). An embodiment of the
control system 100 that is unified, may, however, provide control
over the drilling rig 102 and its related systems (e.g., the
downhole system 110, fluid system 112, and/or central system 114,
etc.). Further, the downhole system 110 may include one or a
plurality of downhole systems. Likewise, fluid system 112, and
central system 114 may contain one or a plurality of fluid systems
and central systems, respectively.
[0030] In addition, the coordinated control device 104 may interact
with the user device(s) (e.g., human-machine interface(s)) 118,
120. For example, the coordinated control device 104 may receive
commands from the user devices 118, 120 and may execute the
commands using two or more of the rig systems 110, 112, 114, e.g.,
such that the operation of the two or more rig systems 110, 112,
114 act in concert and/or off-design conditions in the rig systems
110, 112, 114 may be avoided.
[0031] FIG. 1B illustrates a more detailed example of the drilling
rig 102 and associated equipment that may be used during drilling
operations. As illustrated in FIG. 1B, the drilling rig 102 may be
coupled to a drill string 160. The drilling rig 102 may include
equipment to advance and rotate the drill string 160 and pump
drilling fluid or "mud" into the drill string 160, for example from
the fluid system 112. The drill string 160 may include a bottom
hole assembly (BHA) 162 coupled to the terminal end of the drill
string 160. The BHA 162 may include a drill bit 164. The drill bit
164 may remove rock from the wellbore to create the well. The drill
bit 164 may be powered by drilling fluid or "mud" pumped down the
drill string 160 by the drilling rig 102. To measure conditions
within the wellbore, one or more sensors 122 may be located within
the wellbore. For example, the drill string 160 may include one or
more of sensors 122 and the BHA 162 may include one or more sensors
122. Likewise, for example, one or more sensors 122 may be located
within the wellbore itself, e.g., located on the wall of the
wellbore, located on or within a casing of the wellbore, etc.
Additionally, one or more sensors 128 and 134 may be located on the
surface at the drilling rig 102. The sensors 122, sensors 128, and
sensors 134 may be utilized by the control system 100 to measure
and monitor operating parameters and responses of the drilling
system during drilling operations. For example, the operating
parameters and responses can include pressure in the drill string
160, pumping pressure of the drilling mud, rotational speed of the
drill bit, location of the BHA 206, length of the drill string 160,
pressure in the wellbore, temperature in the wellbore, flow rate of
the drilling mud, and the like. The sensors 122, sensors 128, and
sensors 134 may include temperature sensors, pressure sensors,
geolocation sensors, acceleration sensors, rotational sensors, flow
rate sensors, and the like.
[0032] FIG. 2 illustrates a conceptual, schematic view of the
control system 100, according to an embodiment. The rig computing
resource environment 105 may communicate with offsite devices and
systems using a network 108 (e.g., a wide area network (WAN) such
as the internet). Further, the rig computing resource environment
105 may communicate with the remote computing resource environment
106 via the network 108. FIG. 2 also depicts the aforementioned
example systems of the drilling rig 102, such as the downhole
system 110, the fluid system 112, the central system 114, and the
IT system 116. In some embodiments, one or more onsite user devices
118 may also be included on the drilling rig 102. The onsite user
devices 118 may interact with the IT system 116. The onsite user
devices 118 may include any number of user devices, for example,
stationary user devices intended to be stationed at the drilling
rig 102 and/or portable user devices. In some embodiments, the
onsite user devices 118 may include a desktop, a laptop, a
smartphone, a personal data assistant (PDA), a tablet component, a
wearable computer, or other suitable devices. In some embodiments,
the onsite user devices 118 may communicate with the rig computing
resource environment 105 of the drilling rig 102, the remote
computing resource environment 106, or both.
[0033] One or more offsite user devices 120 may also be included in
the system 100. The offsite user devices 120 may include a desktop,
a laptop, a smartphone, a personal data assistant (PDA), a tablet
component, a wearable computer, or other suitable devices. The
offsite user devices 120 may be configured to receive and/or
transmit information (e.g., monitoring functionality) from and/or
to the drilling rig 102 via communication with the rig computing
resource environment 105. In some embodiments, the offsite user
devices 120 may provide control processes for controlling operation
of the various systems of the drilling rig 102. In some
embodiments, the offsite user devices 120 may communicate with the
remote computing resource environment 106 via the network 108.
[0034] The user devices 118 and/or 120 may be examples of a
human-machine interface. These devices 118, 120 may allow feedback
from the various rig subsystems to be displayed and allow commands
to be entered by the user. In various embodiments, such
human-machine interfaces may be onsite or offsite, or both.
[0035] The systems of the drilling rig 102 may include various
sensors, actuators, and controllers (e.g., programmable logic
controllers (PLCs)), which may provide feedback for use in the rig
computing resource environment 105. For example, the downhole
system 110 may include sensors 122, actuators 124, and controllers
126. The fluid system 112 may include sensors 128, actuators 130,
and controllers 132. Additionally, the central system 114 may
include sensors 134, actuators 136, and controllers 138. The
sensors 122, 128, and 134 may include any suitable sensors for
operation of the drilling rig 102. In some embodiments, the sensors
122, 128, and 134 may include a camera, a pressure sensor, a
temperature sensor, a flow rate sensor, a vibration sensor, a
current sensor, a voltage sensor, a resistance sensor, a gesture
detection sensor or device, a voice actuated or recognition device
or sensor, or other suitable sensors.
[0036] The sensors described above may provide sensor data feedback
to the rig computing resource environment 105 (e.g., to the
coordinated control device 104). For example, downhole system
sensors 122 may provide sensor data 140, the fluid system sensors
128 may provide sensor data 142, and the central system sensors 134
may provide sensor data 144. The sensor data 140, 142, and 144 may
include, for example, equipment operation status (e.g., on or off,
up or down, set or release, etc.), drilling parameters (e.g.,
depth, hook load, torque, etc.), auxiliary parameters (e.g.,
vibration data of a pump) and other suitable data. In some
embodiments, the acquired sensor data may include or be associated
with a timestamp (e.g., a date, time or both) indicating when the
sensor data was acquired. Further, the sensor data may be aligned
with a depth or other drilling parameter.
[0037] As mentioned, the control system 100 may be used to perform
one or more workflows. A workflow may be a process that includes a
number of worksteps. A workstep may operate on data, for example,
to create new data, to update existing data, etc. As an example, a
workstep may operate on one or more inputs and create one or more
results, for example, based on one or more algorithms. As an
example, a system may include a workflow editor for creation,
editing, executing, etc. of a workflow. In such an example, the
workflow editor may provide for selection of one or more
pre-defined worksteps, one or more customized worksteps, etc. As an
example, a workflow may be a workflow implementable in the
PETREL.RTM. software, for example, that operates on seismic data,
seismic attribute(s), etc. As an example, a workflow may be a
process implementable in the OCEAN.RTM. framework. As an example, a
workflow may include one or more worksteps that access a module
such as a plug-in (e.g., external executable code, etc.).
[0038] As described above, the control system 100 may be used field
development planning and drilling operations. In embodiments, the
control system 100 may be used to simulate or model drilling one or
more wells and controlling the drilling equipment during drilling
operations. In embodiments, the control system 100 may be used to
characterize responses in the drilling system during drilling
operations. To characterize response during drilling operations,
the control system 100 may utilize one or more automated sequences.
In embodiments, the automated sequences may be a series of
operations, over a period of time, that vary one or more operating
parameters of the drilling operation while holding constant other
operational parameters of the drilling operation.
[0039] In some embodiments, for example, the automated sequences
preformed by the control system 100 may actively perturb the
drilling system or drive the drilling system in a controlled manner
through to a range of different places within its operational
envelope and collect feedback at both the surface and downhole.
Downhole may be at the BHA 162 and at multiple points along the
drill string 160. In some embodiments, for example, in the
hydraulics domain, the perturbations/sequences may be performed at
points during the drilling process where the wellbore conditions
are known. In some embodiments, for example, rather than perturbing
the drilling system, the automated sequences performed by the
control system 100 may also utilize situations present within a
normal drilling operation where the system is driven through a
range of conditions, such as the process of making a connection and
going on bottom. In some embodiments, for example, the automated
sequences performed by the control system 100 may probe where the
operational boundaries lie in a systematic manner.
[0040] Due to the physics, some properties change as the wellbore
is propagated and the lengths of the drill string and mud column
change. In some embodiments, for example, the automated sequences
may be scheduled and performed at multiple points during the
drilling operations. This may allow information to be obtained not
only by measuring the characteristics of the system at one point in
time or depth, but also by monitoring how these characteristics
change as the well construction process advances. In some
embodiments, for example, the control system 100 may be aware of
the changes taking place during drilling operations (e.g. the drill
string 160 getting longer). In response to the changes, the control
system 100 may automatically update the automated sequences in
accordance with the evolving well construction. For example, as the
drill string 160 increases in length, it may take more time for the
rotational speed to stabilize downhole after startup. In this
example, the automated sequence may be modified so a wait period
would be extended prior to taking an off bottom reference.
[0041] During performance of the automated sequences, the system
100 can measure and record the responses of the drilling system to
the automated sequences. To acquire a complete view of the
response, measurement may be acquired at the surface and downhole
within the wellbore, for example, by sensors 122, 128, and 134. The
measured and recorded responses may be used to update models of the
drilling system and modify the operational parameters of the
drilling operations. The system 100 may automatically link measured
and recorded responses back into the setup/calibration of real-time
models. In some embodiments, the measured and recorded responses
may be stored for use in future drilling operations. For example,
the measured and recorded responses may be stored as a matrix of
system response properties identified using automated
sequences/modulation in depth and time domains.
[0042] By utilizing the automated sequences, the control system 100
may achieve a level of consistency and simultaneous control of
multiple variables (pump, rotation, and block position) that is not
possible by a human driller. Not only can automation allow better
control of simultaneous parameters, the system 100 may be
automatically adjusted to fit the context and can be repeatable.
Likewise, by using the automated sequences during the drilling
operations, the system 100 may use the data collected to control
the drilling system behavior going forward in real-time--i. e, the
system 100 may be continuously learning.
[0043] FIG. 3 illustrates a flowchart of a method 300 for
characterizing responses in a drilling system. The illustrated
stages of the method are examples and any of the illustrated stages
may be removed, additional stages may be added, and the order of
the illustrated stages may be changed.
[0044] In 302, responses of the drilling system may be modeled
prior to drilling operations. In some embodiments, for example, the
model of the response in the drilling system can describe the
expected operation when drilling in a formation. The model may also
include operational parameters of the drilling operations to
deliver the expected operation. The operational parameters may
include any factors that may be controlled to operate the drilling
system. For example, drilling operations may involve three separate
mechanical operations at the surface: pumping drilling mud,
rotating the pipe, and moving the travelling block. Each of the
surface mechanical operations may an associated force term: a
pressure to pump fluid, a torque to turn the drill string, and a
load from a weight of the drill string, for example, load on the
hook from suspending the drill string in the well.
[0045] In some embodiments, for example, the drilling system
response may be modeled based on drilling operations in offset
wells and industry experience. In some embodiments, the drilling
system response may be modeled automatically by the system 100. In
some embodiment, the drilling system response can be modeled by the
system 100 with input from a user.
[0046] In 304, one or more automated sequences can be selected and
scheduled to characterize the drilling system responses during a
portion of the drilling operations. In some embodiments, for
example, the automated sequences may be a series of operations,
over a period of time, that vary one or more operating parameters
of the drilling operation while holding constant other operational
parameters of the drilling operation. In some embodiments, the
automated sequences may be integrated into the drilling process or
other aspects of the well construction process such as casing
running and cementing. For example, while standard operations rates
(flow rate, RPM and to a lesser extent weight on bit) are constant,
the dependence of the force terms on the rates of operation provide
information about the drilling system and the rock being
drilled.
[0047] In some embodiments, for example, the drilling operations
may include multiple automated sequences to be performed. For
example, a bit run may include multiple automated sequences to be
performed during the bit run. Likewise, for example, each bit run
during the drilling operations may include separate automated
sequences to be performed. In some embodiments, the automated
sequences may be selected and scheduled automatically by the system
100. In some embodiment, the automated sequences may be selected
and scheduled by the system 100 with input from a user.
[0048] In some embodiments, for example, an automated sequence may
include a programmed process of taking off-bottom pick up, slack
off and torque references at different rates. For example, the
process may include two different constant block velocities picking
up and slacking off. Additionally, for example, two different
rotational speeds for off bottom torque reference. FIG. 4A
illustrates one example of a programmed process of bottom taking
off bottom pick up, slack off and torque references at different
rates. As illustrated in FIG. 4A, the sequence may include varying,
over time, the block velocity, the pump rate, and the surface RPM.
The control system 100 may measure the responses to the sequence
performed by the drilling system, for example, using one or more of
the sensors 122, 128, and 134 located both at the surface and
downhole. For example, hookload and torque may be measured at the
surface, and pressure and equivalent circulating density (ECD) may
be measured downhole.
[0049] In some embodiments, for example, an automated sequence may
include a programmed sequence for shutting down flow rate and RPM
at the end of a connection and bringing up flow rate and RPM at the
start of a connection. The programmed sequence may allow comparison
of pumps off flow back profiles, may identify pressures required to
break mud gel strength, and may identify torsional transients. FIG.
4B illustrates one example of a programmed process for shutting
down flow rate and RPM at the end of a connection and bringing up
flow rate and RPM at the start of a connection. As illustrated in
FIG. 4B, the sequence may include varying the flow rate, for
example, the flow rate of drilling mud, over time. The control
system 100 may measure the responses to the sequence performed by
the drilling system, for example, using one or more of the sensors
122, 128, and 134 located both at the surface and downhole. For
example, flow back volume of drilling mud and pressure of the
drilling mud may be measured at the surface.
[0050] In some embodiments, for example, an automated sequence may
include a programmed sequence of flow rate and RPM (or independent)
changes. The programmed sequence may allow the drilling system to
characterize the hydraulic system response and calibrate a
hydraulics model. FIG. 4C illustrates an example of a programmed
sequence of flow rate and RPM (or independent) changes. As
illustrated in FIG. 4C, the sequence may include varying the pump
rate, for example, the pump rate of drilling mud, over time. The
sequence may also include varying the rotational speed, for
example, the rotational speed of the drill bit, over time. The
control system 100 may measure the responses to the sequence
performed by the drilling system, for example, using one or more of
the sensors 122, 128, and 134 located both at the surface and
downhole. For example, pressure of the drilling mud may be measured
at the surface, and ECD may be measured downhole.
[0051] In some embodiments, for example, an automated sequence may
include a programmed sequence of moving the block up and down to
characterize sheave friction and remove the effect from WOB and
hookload calculations. The control system 100 may measure the
responses to the sequence performed by the drilling system, for
example, using one or more of the sensors 122, 128, and 134 located
both at the surface and downhole.
[0052] In some embodiments, for example, an automated sequence may
include a programmed sequence of moving the block up and down, with
flow and RPM changes if required, to calibrate swab/surge. The
control system 100 may measure the responses to the sequence
performed by the drilling system, for example, using one or more of
the sensors 122, 128, and 134 located both at the surface and
downhole. For example, a downhole annular pressure measurement may
be utilized with this automated sequence.
[0053] In some embodiments, for example, an automated sequence may
include a programmed sequence of changing WOB while drilling, or
RPM while drilling or off bottom, to understand system response and
avoid exciting large transients. The control system 100 may measure
the responses to the sequence performed by the drilling system, for
example, using one or more of the sensors 122, 128, and 134 located
both at the surface and downhole.
[0054] In some embodiments, for example, an automated sequence may
include a programmed sequence of characterizing the relationship
between WOB, differential pressure, and toolface while drilling
with a motor. The control system 100 may measure the responses to
the sequence performed by the drilling system, for example, using
one or more of the sensors 122, 128, and 134 located both at the
surface and downhole.
[0055] In some embodiments, for example, an automated sequence may
include a programmed sequence of characterizing the relationships
between drilling parameters and BHA vibrations, while drilling or
reaming. The control system 100 may measure the responses to the
sequence performed by the drilling system, for example, using one
or more of the sensors 122, 128, and 134 located both at the
surface and downhole.
[0056] In some embodiments, for example, an automated sequence may
include a programmed sequence where a SLIDER.RTM. system cycles
torque at the surface to improve weight transfer and control
toolface with downhole feedback in the form of BHA toolface. The
surface system may be programmed to automatically execute a
sequence of operations (at defined points in the trajectory) to
facilitate learning the system response and thereby improving the
algorithms weight transfer and/or toolface control. The control
system 100 may measure the responses to the sequence performed by
the drilling system, for example, using one or more of the sensors
122, 128, and 134 located both at the surface and downhole.
[0057] In some embodiments, for example, an automated sequence may
include a programmed sequence of monitoring the change in surface
hookload at a range of flow rates circulating with rotation off
bottom (measure up-lift effect). The control system 100 may measure
the responses to the sequence performed by the drilling system, for
example, using one or more of the sensors 122, 128, and 134 located
both at the surface and downhole.
[0058] In some embodiments, for example, an automated sequence may
include a programmed sequence of staging up weight on bit at a
constant RPM to identify the point at which the rotational system
becomes unstable and enters into fully developed stick-slip
(torsional vibration mode). FIG. 4D illustrates one example of a
programmed sequence of staging up weight on bit at a constant RPM.
As illustrated in FIG. 4D, the sequence may include varying the WOB
and rotational speed, over time. The control system 100 may measure
the responses to the sequence performed by the drilling system, for
example, using one or more of the sensors 122, 128, and 134 located
both at the surface and downhole. For example, speed of the drill
bit may be measured downhole. The control system 100 may also
generate one or more additional graphs or plots to illustrate the
responses, for example, the variation in downhole speed.
[0059] In some embodiments, for example, an automated sequence may
include a programmed sequence that sweeps through a range of
surface RPM's off bottom to identify the locations of lateral BHA
resonances. FIG. 4E illustrates one example of a programmed
sequence that sweep through a range of surface RPM's off bottom. As
illustrated in FIG. 4E, the sequence may include varying the WOB
and rotational speed, over time. The control system 100 may measure
the responses to the sequence performed by the drilling system, for
example, using one or more of the sensors 122, 128, and 134 located
both at the surface and downhole. For example, lateral motion of
the drill bit may be measured downhole. The control system 100 may
also generate one or more additional graphs or plots to illustrate
the responses, for example, a three dimensional plot of the lateral
motion.
[0060] In some embodiments, for example, an automated sequence may
include a programmed sequence that pumps at different flow rates
(on or off bottom) to see if any correlation can be seen between
BHA lateral stability (lateral resonances) and mud motor nutation
frequency or RSS force actuations that generate excitations at
frequencies which are a function of flow rate. FIGS. 4F and 4G
illustrate one example of a programmed sequence that pumps at
different flow rates (on or off bottom). As illustrated in FIG. 4F,
drilling mud may be flowed into the mud motor rotor with a mud
stator, which produces acceleration in the mud motor rotor. As
illustrated in FIG. 4G, the sequence may include varying the flow
rate, for example, flow rate of drilling mud, over time. The
control system 100 may measure the responses to the sequence
performed by the drilling system, for example, using one or more of
the sensors 122, 128, and 134 located both at the surface and
downhole. For example, lateral acceleration of the mud motor or the
drill bit and the lateral shock peak may be measured downhole.
[0061] In some embodiments, for example, an automated sequence may
include a programmed sequence that dynamically "tunes" an
autodriller gain setting based upon a real-time derived bit-rock
interaction model. This may reduce or eliminate the period of time
spent searching for the right rate to move the blocks after a
formation change, e.g., as compared to proportional-integral
controllers. The control system 100 may measure the responses to
the sequence performed by the drilling system, for example, using
one or more of the sensors 122, 128, and 134 located both at the
surface and downhole.
[0062] In some embodiments, for example, an automated sequence may
include a programmed sequence that automatically modulates pump
stroke rates to identify the optimum combination of pump strokes to
maximize MWD telemetry signal to noise ration. The control system
100 may measure the responses to the sequence performed by the
drilling system, for example, using one or more of the sensors 122,
128, and 134 located both at the surface and downhole.
[0063] In some embodiments, for example, an automated sequence may
include a programmed sequence that varies weight when drilling with
a motor and rotating and measuring pressure--then use the inverse
when sliding. The control system 100 may measure the responses to
the sequence performed by the drilling system, for example, using
one or more of the sensors 122, 128, and 134 located both at the
surface and downhole.
[0064] In some embodiments, for example, an automated sequence may
include a programmed sequence that varies flow rate and measures
motor speed. The flow rate may be varied and the motor speed
measured by any equipment of the control system 100. The control
system 100 may measure the responses to the sequence performed by
the drilling system, for example, using one or more of the sensors
122, 128, and 134 located both at the surface and downhole.
[0065] In some embodiments, for example, an automated sequence may
include a programmed sequence that varies potentially both flow
rate and weight on bit and measuring motor speed and pressure to
get motor speed versus flow rate and pressure. The control system
100 may measure the responses to the sequence performed by the
drilling system, for example, using one or more of the sensors 122,
128, and 134 located both at the surface and downhole.
[0066] In some embodiments, for example, an automated sequence may
include a programmed sequence that varies rotation speed and/or
flow and measuring temperature at along the drill string 160
measurement subs. This may be used to calibrate friction models.
The control system 100 may measure the responses to the sequence
performed by the drilling system, for example, using one or more of
the sensors 122, 128, and 134 located both at the surface and
downhole.
[0067] In some embodiments, for example, an automated sequence may
include a programmed sequence that, while drilling, moves the block
down at varying rates. This may be used to examine the effect on
rate of change of weight to determine drill string 160 axial
compliance. The control system 100 may measure the responses to the
sequence performed by the drilling system, for example, using one
or more of the sensors 122, 128, and 134 located both at the
surface and downhole.
[0068] In some embodiments, for any of the automated sequences
described above, the context may be considered when selecting and
scheduling the automated sequences. For example, the context can
include a depth of the well, a trajectory of the wellbore being
drilled, a type of mud being used, a type of drill string, BHA,
and/or drill bit being employed, whether the hole is cased, and the
like. The context may be taken into account when designing and
executing the automated sequences. For example, the automated
sequences may be changed as the drill string or borehole length
increases or changes as a function of position within the planned
trajectory.
[0069] In 306, the drilling operations may be performed. In some
embodiments, the drilling operations may be performed automatically
by the control system 100. In some embodiment, the drilling
operations may be performed by the control system 100 with input
from a user.
[0070] In 308, it can be determined if an automated sequence is
scheduled to be performed. In some embodiments, for example, the
control system 100 can continuously check, during drilling
operations if an automated sequence is scheduled to be performed.
At any given time, if an automated sequence is not scheduled to be
performed, it can be determined if the drilling operation is
complete, in 310. If drilling operations are complete, the method
300 can end. If drilling operations are not complete, the method
300 can return to 306 and continue drilling operations.
[0071] In 308, if an automated sequence is scheduled to be
performed, it can be determined if the automated sequences needs to
be updated in 311 and may be updated in 312. In some embodiments,
for example, the control system 100 may be aware of the changes
taking place during drilling operations (e.g. the drill string 160
getting longer). In response to the changes, the control system 100
may automatically update the automated sequences in accordance with
the evolving well construction.
[0072] For example, in some embodiments, as the drill string 160
increases in length, it may take more time for the rotational speed
to stabilize downhole after startup. In this example, the automated
sequence may be modified so a wait period would be extended prior
to taking an off bottom reference. Likewise, for example, in the
automated sequence that includes a programmed sequence of moving
the block up and down, with flow and RPM changes if required, to
calibrate swab/surge. As the well is drilled, for example, the
automated sequence may be adjusted by altering the up and down
velocities to avoid exceeding an equivalent mud weight threshold
defined at a point in the wellbore such as the casing shoe.
[0073] Once the automated sequence is updated (if necessary), the
automated sequence can be executed and data can be collected during
the automated sequence, in 313. In embodiments, the responses of
the drilling system may be measured by sensors positioned on the
surface and within the wellbore. For example, the data can be
collected from the sensors 122, 128, and 134 of the drilling
system. As discussed above, with reference to FIGS. 4A-4G, the
control system 100 may collect the data and generate plots and
graphs that illustrate the automated sequences and the collected
data. The control system 100 may output, for example, one a
display, the plots and graphs to a user of the control system
100.
[0074] In some embodiments, the execution of the sequence and
collection of data may be performed automatically by the system
100. In some embodiment, the execution of the sequence and
collection of data may be performed by the system 100 with input
from a user.
[0075] In 314, the collected data can be collected and may be
compared to the model of the drilling system response, and the
model of the drilling system response can be calibrated. In 316, it
can be determined if a change in the model or the collected data
affect the drilling operations. If the drilling operations are
affected, the drilling processes can be altered based on the change
in the model or the collected data, in 318. In some embodiments,
for example, the collected data and/or the calibrated models may be
used to govern how the drilling system is controlled (how motion
inputs are made at surface: pumping, rotating and block movements)
to safely maximize drilling performance and efficiency. This may be
an ongoing, evolving process as the drilling process takes place.
In some embodiments, for example, the system may be able to
identify deviations from expected trends at an early stage and
alert the user or automatically implement an appropriate response
procedure. In some embodiments, for example, the system 100 may use
the calibrated models of system response to provide updated
operational boundaries to maintain the drilling system operation
within a safe/stable zone.
[0076] In 320, the collected data and the calibrated model can be
stored. In some embodiments, the collected data and/or the
calibrated models may be stored for use in future drilling
operations. For example, the collected data may be stored as a
matrix of system response properties identified using automated
sequences/modulation in depth and time domains.
[0077] In some embodiments, the methods of the present disclosure
may be executed by a computing system. FIG. 5 illustrates an
example of such a computing system 500, in accordance with some
embodiments. The computing system 500 may include a computer or
computer system 501A, which may be an individual computer system
501A or an arrangement of distributed computer systems. The
computer system 501A includes one or more analysis modules 502 that
are configured to perform various tasks according to some
embodiments, such as one or more methods disclosed herein. To
perform these various tasks, the analysis module 502 executes
independently, or in coordination with, one or more processors 504,
which is (or are) connected to one or more storage media 506. The
processor(s) 504 is (or are) also connected to a network interface
507 to allow the computer system 501A to communicate over a data
network 509 with one or more additional computer systems and/or
computing systems, such as 501B, 501C, and/or 501D (note that
computer systems 501B, 501C and/or 501D may or may not share the
same architecture as computer system 501A, and may be located in
different physical locations, e.g., computer systems 501A and 501B
may be located in a processing facility, while in communication
with one or more computer systems such as 501C and/or 501D that are
located in one or more data centers, and/or located in varying
countries on different continents).
[0078] A processor may include a microprocessor, microcontroller,
processor module or subsystem, programmable integrated circuit,
programmable gate array, or another control or computing
device.
[0079] The storage media 506 may be implemented as one or more
computer-readable or machine-readable storage media. Note that
while in the example embodiment of FIG. 5 storage media 506 is
depicted as within computer system 501A, in some embodiments,
storage media 506 may be distributed within and/or across multiple
internal and/or external enclosures of computing system 501A and/or
additional computing systems. Storage media 506 may include one or
more different forms of memory including semiconductor memory
devices such as dynamic or static random access memories (DRAMs or
SRAMs), erasable and programmable read-only memories (EPROMs),
electrically erasable and programmable read-only memories (EEPROMs)
and flash memories, magnetic disks such as fixed, floppy and
removable disks, other magnetic media including tape, optical media
such as compact disks (CDs) or digital video disks (DVDs),
BLURRY.RTM. disks, or other types of optical storage, or other
types of storage devices. Note that the instructions discussed
above may be provided on one computer-readable or machine-readable
storage medium, or alternatively, may be provided on multiple
computer-readable or machine-readable storage media distributed in
a large system having possibly plural nodes. Such computer-readable
or machine-readable storage medium or media is (are) considered to
be part of an article (or article of manufacture). An article or
article of manufacture may refer to any manufactured single
component or multiple components. The storage medium or media may
be located either in the machine running the machine-readable
instructions, or located at a remote site from which
machine-readable instructions may be downloaded over a network for
execution.
[0080] In some embodiments, the computing system 500 contains one
or more rig control module(s) 508. In the example of computing
system 500, computer system 501A includes the rig control module
508. In some embodiments, a single rig control module may be used
to perform some or all aspects of one or more embodiments of the
methods disclosed herein. In alternate embodiments, a plurality of
rig control modules may be used to perform some or all aspects of
methods herein.
[0081] It should be appreciated that computing system 500 is only
one example of a computing system, and that computing system 500
may have more or fewer components than shown, may combine
additional components not depicted in the example embodiment of
FIG. 5, and/or computing system 500 may have a different
configuration or arrangement of the components depicted in FIG. 5.
The various components shown in FIG. 5 may be implemented in
hardware, software, or a combination of both hardware and software,
including one or more signal processing and/or application specific
integrated circuits.
[0082] Further, the steps in the processing methods described
herein may be implemented by running one or more functional modules
in information processing apparatus such as general purpose
processors or application specific chips, such as ASICs, FPGAs,
PLDs, or other appropriate devices. These modules, combinations of
these modules, and/or their combination with general hardware are
all included within the scope of protection of the invention.
[0083] The foregoing description, for purpose of explanation, has
been described with reference to specific embodiments. However, the
illustrative discussions above are not intended to be exhaustive or
to limit the disclosure to the precise forms disclosed. Many
modifications and variations are possible in view of the above
teachings. Moreover, the order in which the elements of the methods
described herein are illustrate and described may be re-arranged,
and/or two or more elements may occur simultaneously. The
embodiments were chosen and described in order to explain at least
some of the principals of the disclosure and their practical
applications, to thereby enable others skilled in the art to
utilize the disclosed methods and systems and various embodiments
with various modifications as are suited to the particular use
contemplated.
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