U.S. patent application number 15/997414 was filed with the patent office on 2019-12-05 for blowout preventer control.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Anstein Jorud.
Application Number | 20190368299 15/997414 |
Document ID | / |
Family ID | 68694507 |
Filed Date | 2019-12-05 |
United States Patent
Application |
20190368299 |
Kind Code |
A1 |
Jorud; Anstein |
December 5, 2019 |
Blowout Preventer Control
Abstract
An apparatus and method for blowout preventer (BOP) control. The
apparatus may include a first control station communicatively
connected with and operable to control BOP equipment for
controlling pressure within a wellbore at an oil and gas wellsite,
and a second control station communicatively connected with and
operable to control drilling rig equipment for drilling the
wellbore within a subterranean formation at the oil and gas
wellsite. The second control station may be communicatively
connected with the first control station and operable to control
the BOP equipment via the first control station.
Inventors: |
Jorud; Anstein;
(Kristiansand, NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
68694507 |
Appl. No.: |
15/997414 |
Filed: |
June 4, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 34/066 20130101;
E21B 2200/04 20200501; E21B 33/063 20130101; E21B 41/00 20130101;
E21B 34/16 20130101; E21B 44/00 20130101 |
International
Class: |
E21B 33/06 20060101
E21B033/06; E21B 34/06 20060101 E21B034/06; E21B 34/16 20060101
E21B034/16; E21B 44/00 20060101 E21B044/00 |
Claims
1. An apparatus comprising: a first control station communicatively
connected with and operable to control blowout preventer (BOP)
equipment for controlling pressure within a wellbore at an oil and
gas wellsite; and a second control station communicatively
connected with and operable to control drilling rig equipment for
drilling the wellbore within a subterranean formation at the oil
and gas wellsite, wherein the second control station is
communicatively connected with the first control station and
operable to control the BOP equipment via the first control
station.
2. The apparatus of claim 1 wherein each of the first and second
control stations comprises or is communicatively connected with a
corresponding processor and a memory storing a computer program
code.
3. The apparatus of claim 1 wherein the drilling rig equipment
comprises one or more of: a drill pipe handling system operable to
move drill pipe at the oil/gas wellsite; a drill string hoisting
system operable to move a drill string within the wellbore; a drill
string rotation system operable to rotate the drill string within
the wellbore; and a fluid control system operable to pump drilling
fluid into the drill string.
4. The apparatus of claim 1 wherein the BOP equipment is or
comprises a BOP stack and/or a BOP control hydraulic power unit for
actuating the BOP stack.
5. The apparatus of claim 1 wherein the second control station is
operable to: receive first information from the BOP equipment via
the first control station; receive second information from the
drilling rig equipment; and transmit control commands to the
drilling rig equipment.
6. The apparatus of claim 5 wherein the control commands are based,
at least in part, on the first and/or second information.
7. The apparatus of claim 5 wherein the control commands are first
control commands, and wherein the second control station is
operable to transmit second control commands to the BOP equipment
via the first control station.
8. The apparatus of claim 7 wherein the second control commands are
based, at least in part, on the first and/or second
information.
9. The apparatus of claim 1 wherein the second control station is
operable to: receive first information indicative of operational
status of the BOP equipment from the first control station; receive
second information indicative of operational status of the drilling
rig equipment from the drilling rig equipment; and transmit control
commands to the drilling rig equipment to control the drilling rig
equipment.
10. The apparatus of claim 9 wherein the control commands are
based, at least in part, on the first and/or second
information.
11. The apparatus of claim 9 wherein the control commands are first
control commands, and wherein the second control station is
operable to transmit second control commands to the first control
station to control the BOP equipment.
12. The apparatus of claim 11 wherein the second control commands
are based, at least in part, on the first and/or second
information.
13. The apparatus of claim 11 wherein: the first information is
generated by first sensors disposed in association with or forming
at least a portion of the BOP equipment; the second information is
generated by second sensors disposed in association with or forming
at least a portion of the drilling rig equipment; the second
control commands are transmitted to first actuators disposed in
association with or forming at least a portion of the BOP
equipment; and the first control commands are transmitted to second
actuators disposed in association with or forming at least a
portion of the drilling rig equipment.
14. The apparatus of claim 9 wherein the second control station
comprises a video output device operable to display the first and
second information.
15. The apparatus of claim 9 wherein the first control station
comprises a first video output device operable to display the first
information, and wherein the second control station comprises a
second video output device operable to display the first and second
information.
16. The apparatus of claim 1 wherein: the first control station is
operable to: receive first information indicative of operational
status of the BOP equipment from the BOP equipment; and transmit
first control commands to the BOP equipment to control the BOP
equipment; and the second control station is operable to: receive
the first information from the first control station; receive
second information indicative of operational status of the drilling
rig equipment from the drilling rig equipment; receive the first
control commands from a human wellsite operator; receive second
control commands from the human wellsite operator; transmit the
first control commands to the first control station to control the
BOP equipment; and transmit the second control commands to the
drilling rig equipment to control the drilling rig equipment.
17. The apparatus of claim 16 wherein the first control commands
are based, at least in part, on the first and/or second
information.
18. The apparatus of claim 16 wherein the second control station
comprises: an input device operable to receive the first and second
control commands from the human wellsite operator; and a video
output device operable to display the first and second
information.
19. The apparatus of claim 1 wherein: the first control station is
operable to: receive information indicative of operational status
of the BOP equipment from the BOP equipment; and transmit control
commands to the BOP equipment to control the BOP equipment; and the
second control station comprises a processor and a memory storing a
computer program code, wherein the second control station is
operable to: receive the information from the first control
station; generate the control commands based on the computer
program code and the information; and transmit the control commands
to the first control station.
20. The apparatus of claim 1 wherein the first and second control
stations are disposed within or form at least a portion of a
wellsite control center.
21. The apparatus of claim 20 wherein the first control station
comprises a touchscreen operable by a human wellsite operator
sitting in a driller's chair within the wellsite control center to
control the BOP equipment and the rig equipment.
22. The apparatus of claim 21 wherein the touchscreen is mounted to
and/or otherwise carried with the driller's chair.
23. An apparatus comprising: a first control station
communicatively connected with blowout preventer (BOP) equipment
for controlling pressure within a wellbore at an oil and gas
wellsite, wherein the first control station is operable to: receive
information indicative of operational status of the BOP equipment
from the BOP equipment; and control the BOP equipment to control
the pressure within the wellbore; and a second control station
communicatively connected with the first control station and
operable to: receive the information from the first control
station; receive control commands from a human wellsite operator;
and transmit the control commands to the first control station for
transmission by the first control station to the BOP equipment to
control the BOP equipment.
24. The apparatus of claim 23 wherein each of the first and second
control stations comprises or is communicatively connected with a
corresponding processor and a memory storing a computer program
code.
25. The apparatus of claim 23 wherein the BOP equipment is or
comprises a BOP stack and/or a BOP control hydraulic power unit for
actuating the BOP stack.
26. The apparatus of claim 23 wherein the second control station is
communicatively connected with drilling rig equipment for drilling
the wellbore within a subterranean formation at the oil and gas
wellsite.
27. The apparatus of claim 26 wherein the drilling rig equipment
comprises one or more of: a drill pipe handling system operable to
move drill pipe at the oil/gas wellsite; a drill string hoisting
system operable to move a drill string within the wellbore; a drill
string rotation system operable to rotate the drill string within
the wellbore; and a fluid control system operable to pump drilling
fluid into the drill string.
28. The apparatus of claim 26 wherein the information is first
information, and wherein the second control station is operable to
receive second information indicative of operational status of the
drilling rig equipment from the drilling rig equipment.
29. The apparatus of claim 28 wherein the control commands are
based, at least in part, on the first and/or second
information.
30. The apparatus of claim 28 wherein the second control station
comprises a video output device operable to display the first and
second information.
31. The apparatus of claim 28 wherein the first control station
comprises a first video output device operable to display the first
information, and wherein the second control station comprises a
second video output device operable to display the first and second
information.
32. The apparatus of claim 28 wherein the control commands are
first control commands, and wherein the second control station is
further operable to transmit second control commands to the
drilling rig equipment to control the drilling rig equipment.
33. The apparatus of claim 32 wherein the second control commands
are based, at least in part, on the first and/or second
information.
34. The apparatus of claim 32 wherein: the first information is
generated by first sensors disposed in association with or forming
at least a portion of the BOP equipment; the second information is
generated by second sensors disposed in association with or forming
at least a portion of the drilling rig equipment; the first control
commands are transmitted to first actuators disposed in association
with or forming at least a portion of the BOP equipment; and the
second control commands are transmitted to second actuators
disposed in association with or forming at least a portion of the
drilling rig equipment.
35. The apparatus of claim 32 the second control station is further
operable to receive the first and second control commands from the
human wellsite operator.
36. The apparatus of claim 35 wherein the second control commands
are based, at least in part, on the first and/or second
information.
37. The apparatus of claim 35 wherein the second control station
comprises: an input device operable to receive the first and second
control commands from the human wellsite operator; and a video
output device operable to display the first and second
information.
38. The apparatus of claim 23 wherein the second control station
comprises a processor and a memory storing a computer program code,
and wherein the second control station is operable to generate the
control commands based on the computer program code and the
information.
39. The apparatus of claim 23 wherein the first and second control
stations are disposed within or form at least a portion of a
wellsite control center.
40. The apparatus of claim 39 wherein the first control station
comprises a touchscreen operable by the human wellsite operator
sitting in a driller's chair within the wellsite control center to
control the BOP equipment and the rig equipment.
41. The apparatus of claim 40 wherein the touchscreen is mounted to
and/or otherwise carried with the driller's chair.
42. A method comprising: receiving, by a first control station at
an oil and gas wellsite, first information indicative of
operational status of drilling rig equipment at an oil and gas
wellsite, wherein the first control station is manually and/or
automatically operable to control the drilling rig equipment;
receiving, by the first control station, second information
indicative of operational status of blowout preventer (BOP)
equipment at the oil and gas wellsite, wherein: the drilling rig
equipment does not include the BOP equipment; the second
information is received from a second control station at the oil
and gas wellsite; and the second control station is operable to
control the BOP equipment but not the drilling rig equipment;
transmitting first control commands from the first control station
to the second control station for transmission to the BOP equipment
to control the BOP equipment; and transmitting second control
commands from the first control station to the drilling rig
equipment to control the drilling rig equipment to drill a wellbore
within a subterranean formation at the oil and gas wellsite.
43. The method of claim 42 wherein the drilling rig equipment
comprises one or more of: a drill pipe handling system operable to
move drill pipe at the oil/gas wellsite; a drill string hoisting
system operable to move a drill string within the wellbore; a drill
string rotation system operable to rotate the drill string within
the wellbore; and a fluid control system operable to pump drilling
fluid into the drill string.
44. The method of claim 42 wherein the BOP equipment is or
comprises a BOP stack and/or a BOP control hydraulic power unit for
actuating the BOP stack.
45. The method of claim 42 further comprising transmitting from the
second control station to the BOP equipment the first control
commands to control the BOP equipment.
46. The method of claim 42 wherein the first control commands are
based, at least in part, on the first and/or second
information.
47. The method of claim 42 wherein the second control commands are
based, at least in part, on the first and/or second
information.
48. The method of claim 42 wherein: the first information is
generated by first sensors disposed in association with or forming
at least a portion of the drilling rig equipment; the second
information is generated by second sensors disposed in association
with or forming at least a portion of the BOP equipment; the second
control commands are transmitted to first actuators disposed in
association with or forming at least a portion of the drilling rig
equipment; and the first control commands are transmitted to second
actuators disposed in association with or forming at least a
portion of the BOP equipment.
49. The method of claim 42 further comprising displaying the first
and second information on a video output device of the first
control station.
50. The method of claim 42 further comprising: displaying the first
and second information on a first video output device of the first
control station; and displaying the second information on a second
video output device of the second control station.
51. The method of claim 42 further comprising receiving by the
first control station the first and second control commands from a
human wellsite operator.
52. The method of claim 51 wherein the second control commands are
based, at least in part, on the first and/or second
information.
53. The method of claim 42 further comprising automatically
generating by the second control station the second control
commands based, at least in part, on the first and/or second
information.
54. The method of claim 42 wherein the first and second control
stations are disposed within or forming at least a portion of a
wellsite control center.
55. The method of claim 54 wherein the first control station
comprises a touchscreen, and wherein the method further comprises
operating the touchscreen by a human wellsite operator sitting in a
driller's chair within the wellsite control center to enter the
first and second commands.
56. The method of claim 55 wherein the touchscreen is mounted to
and/or otherwise carried with the driller's chair.
57. A method comprising: controlling drilling rig equipment by
operating a first control station in response to receipt, by the
first control station, of first information indicative of
operational status of the drilling rig equipment; and controlling
blowout preventer (BOP) equipment by operating the first control
station in response to receipt, by the first control station, of
second information indicative of operational status of the BOP
equipment, wherein the second information is received by the first
control station from a second control station that is operable to
control the BOP equipment but not the drilling rig equipment.
58. The method of claim 57 wherein controlling the drilling rig
equipment causes the rig equipment to drill a wellbore within a
subterranean formation at an oil and gas wellsite, and wherein
controlling the BOP equipment causes the BOP equipment to control
pressure within the wellbore at the oil and gas wellsite.
59. The method of claim 57 wherein the drilling rig equipment
comprises one or more of: a drill pipe handling system operable to
move drill pipe at the oil/gas wellsite; a drill string hoisting
system operable to move a drill string within the wellbore; a drill
string rotation system operable to rotate the drill string within
the wellbore; and a fluid control system operable to pump drilling
fluid into the drill string.
60. The method of claim 57 wherein the BOP equipment is or
comprises a BOP stack and/or a BOP control hydraulic power unit for
actuating the BOP stack.
61. The method of claim 57 wherein: controlling the BOP equipment
by operating the first control station further comprises
transmitting first control commands from the first control station
to the second control station; controlling the drilling rig
equipment by operating a first control station further comprises
transmitting second control commands from the first control station
to the drilling rig equipment to control the drilling rig equipment
to drill a wellbore within a subterranean formation at the oil and
gas wellsite; and the method further comprises transmitting the
first control commands from the second control station to the BOP
equipment to control the BOP equipment.
62. The method of claim 57 wherein the first control commands are
based, at least in part, on the first and/or second
information.
63. The method of claim 57 wherein the second control commands are
based, at least in part, on the first and/or second
information.
64. The method of claim 57 wherein: the first information is
generated by first sensors disposed in association with or forming
at least a portion of the drilling rig equipment; the second
information is generated by second sensors disposed in association
with or forming at least a portion of the BOP equipment; the second
control commands are transmitted to first actuators disposed in
association with or forming at least a portion of the drilling rig
equipment; and the first control commands are transmitted to second
actuators disposed in association with or forming at least a
portion of the BOP equipment.
65. The method of claim 57 further comprising receiving by the
first control station the first and second control commands from a
human wellsite operator.
66. The method of claim 61 wherein the second control commands are
based, at least in part, on the first and/or second
information.
67. The method of claim 61 further comprising automatically
generating by the second control station the second control
commands based, at least in part, on the first and/or second
information.
68. The method of claim 61 wherein the first and second control
stations are disposed within or forming at least a portion of a
wellsite control center.
69. The method of claim 68 wherein the first control station
comprises a touchscreen, and wherein the method further comprises
operating the touchscreen by the human wellsite operator sitting in
a driller's chair within the wellsite control center to enter the
first and second commands.
70. The method of claim 69 wherein the touchscreen is mounted to
and/or otherwise carried with the driller's chair.
71. The method of claim 57 further comprising displaying the first
and second information on a video output device of the first
control station.
72. The method of claim 57 further comprising: displaying the first
and second information on a first video output device of the first
control station; and displaying the second information on a second
video output device of the second control station.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Wells are generally drilled into the ground or ocean bed to
recover natural deposits of oil, gas, and other materials that are
trapped in subterranean formations. Such wells are drilled into the
subterranean formations at wellsites utilizing a well construction
system having various surface and subterranean wellsite equipment
operating in a coordinated manner. The wellsite equipment may be
grouped into various subsystems, wherein each subsystem performs a
different operation controlled by a corresponding controller and/or
a central controller operable to execute processes associated with
the corresponding subsystem(s). The subsystems may include a rig
control system, a fluid control system, a managed pressure drilling
control system, a gas monitoring system, a closed-circuit
television system, a choke pressure control system, and a well
pressure control system, among other examples.
[0002] The wellsite equipment is monitored and controlled from a
control center located at the wellsite. A typical control center
contains a wellsite control station utilized by a human wellsite
operator to monitor and control the various subsystems of the well
construction system. However, safety regulations specify that
certain subsystems are to be controlled by a designated control
station constructed pursuant to corresponding safety standards. For
example, safety regulations specify that blowout preventer (BOP)
equipment of the well pressure control system is to be controlled
by a designated BOP control station constructed pursuant to safety
standards for use in designated areas or zones of the wellsite.
Safety regulations further specify that the BOP control station is
to be enclosed within an intrinsically safe, weatherproof,
waterproof, or another cabinet or enclosure, such as may permit the
control station to be utilized within safe areas, hazardous areas,
or other areas or zones of the wellsite.
[0003] Because the well pressure control system comprises a
designated BOP control station, the wellsite control station may
not be utilized by the wellsite operator (e.g., driller) to monitor
and control the BOP equipment of the well pressure control system,
requiring the wellsite operator to walk or otherwise move about the
control center between the wellsite and BOP control stations to
control the BOP equipment and other subsystems of the well
construction system, such as the rig control system. Furthermore,
because there is no communication between the wellsite and BOP
control stations, interactions or coordination between the BOP
equipment of the well pressure control system and other subsystems
are typically initiated by the wellsite operators. For example, the
wellsite operators may monitor the subsystems to identify
operational and safety events and manually initiate processes to
counteract such events. Accordingly, a typical control center may
be manned by multiple wellsite operators who monitor and control
the BOP equipment and other wellsite equipment. Utilizing multiple
workstations and relying on multiple wellsite operators to perform
such operations increases cost and limits speed, efficiency, and
safety of well construction operations.
SUMMARY OF THE DISCLOSURE
[0004] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify indispensable
features of the claimed subject matter, nor is it intended for use
as an aid in limiting the scope of the claimed subject matter.
[0005] Some embodiments herein relate to an apparatus including a
first control station communicatively connected with and operable
to control blowout preventer (BOP) equipment for controlling
pressure within a wellbore at an oil and gas wellsite; and a second
control station communicatively connected with and operable to
control drilling rig equipment for drilling the wellbore within a
subterranean formation at the oil and gas wellsite, wherein the
second control station is communicatively connected with the first
control station and operable to control the BOP equipment via the
first control station.
[0006] Some embodiments herein relate to a method including
receiving, by a first control station at an oil and gas wellsite,
first information indicative of operational status of drilling rig
equipment at an oil and gas wellsite, wherein the first control
station is manually and/or automatically operable to control the
drilling rig equipment; receiving, by the first control station,
second information indicative of operational status of blowout
preventer (BOP) equipment at the oil and gas wellsite, wherein the
drilling rig equipment does not include the BOP equipment; the
second information is received from a second control station at the
oil and gas wellsite; and the second control station is operable to
control the BOP equipment but not the drilling rig equipment;
transmitting first control commands from the first control station
to the second control station for transmission to the BOP equipment
to control the BOP equipment; and transmitting second control
commands from the first control station to the drilling rig
equipment to control the drilling rig equipment to drill a wellbore
within a subterranean formation at the oil and gas wellsite.
[0007] These and additional aspects of the present disclosure are
set forth in the description that follows, and/or may be learned by
a person having ordinary skill in the art by reading the materials
herein and/or practicing the principles described herein. At least
some aspects of the present disclosure may be achieved via means
recited in the attached claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The present disclosure is best understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0009] FIG. 1 is a schematic side view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0010] FIG. 2 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0011] FIG. 3 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0012] FIG. 4 is a perspective view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0013] FIG. 5 is a perspective sectional view of the apparatus
shown in FIG. 4 according to one or more aspects of the present
disclosure.
[0014] FIG. 6 is a top view of a portion of an example
implementation of the apparatus shown in FIG. 5 according to one or
more aspects of the present disclosure.
[0015] FIGS. 7-9 are views of example implementations of software
controls displayed by the apparatus shown in FIG. 6 according to
one or more aspects of the present disclosure.
[0016] FIGS. 10 and 11 are views of example implementations of
control menus displayed by the apparatus shown in FIG. 6 according
to one or more aspects of the present disclosure.
[0017] FIG. 12 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0018] FIG. 13 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
DETAILED DESCRIPTION
[0019] It is to be understood that the following disclosure
describes many example implementations for different aspects
introduced herein. Specific examples of components and arrangements
are described below to simplify the present disclosure. These are
merely examples, and are not intended to be limiting. In addition,
the present disclosure may repeat reference numerals and/or letters
in the various examples. This repetition is for simplicity and
clarity, and does not in itself dictate a relationship between the
various implementations described herein. Moreover, the formation
of a first feature over or on a second feature in the description
that follows may include implementations in which the first and
second features are formed in direct contact, and may also include
implementations in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
[0020] FIG. 1 is a schematic view of at least a portion of an
example implementation of a well construction system 100 according
to one or more aspects of the present disclosure. The well
construction system 100 represents an example environment in which
one or more aspects described below may be implemented. Although
the well construction system 100 is depicted as an onshore
implementation, the aspects described below are also applicable to
offshore and inshore implementations.
[0021] The well construction system 100 is depicted in relation to
a wellbore 102 formed by rotary and/or directional drilling from a
wellsite surface 104 and extending into a subterranean formation
106. The well construction system 100 includes surface equipment
110 located at the wellsite surface 104 and a drill string 120
suspended within the wellbore 102. The surface equipment 110 may
include a mast, a derrick, and/or another wellsite structure 112
disposed over a rig floor 114. The drill string 120 may be
suspended within the wellbore 102 from the wellsite structure 112.
The wellsite structure 112 and the rig floor 114 are collectively
supported over the wellbore 102 by legs and/or other support
structures 113.
[0022] The drill string 120 may comprise a bottom-hole assembly
(BHA) 124 and means 122 for conveying the BHA 124 within the
wellbore 102. The conveyance means 122 may comprise drill pipe,
heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough
logging condition (TLC) pipe, coiled tubing, and/or other means for
conveying the BHA 124 within the wellbore 102. A downhole end of
the BHA 124 may include or be coupled to a drill bit 126. Rotation
of the drill bit 126 and the weight of the drill string 120
collectively operate to form the wellbore 102. The drill bit 126
may be rotated from the wellsite surface 104 and/or via a downhole
mud motor (not shown) connected with the drill bit 126.
[0023] The BHA 124 may also include various downhole tools 180,
182, 184. One or more of such downhole tools 180, 182, 184 may be
or comprise an acoustic tool, a density tool, a directional
drilling tool, an electromagnetic (EM) tool, a formation sampling
tool, a formation testing tool, a gravity tool, a monitoring tool,
a neutron tool, a nuclear tool, a photoelectric factor tool, a
porosity tool, a reservoir characterization tool, a resistivity
tool, a sampling while drilling (SWD) tool, a seismic tool, a
surveying tool, and/or other measuring-while-drilling (MWD) or
logging-while-drilling (LWD) tools.
[0024] One or more of the downhole tools 180, 182, 184 may be or
comprise an MWD or LWD tool comprising a sensor package 186
operable for the acquisition of measurement data pertaining to the
BHA 124, the wellbore 102, and/or the formation 106. One or more of
the downhole tools 180, 182, 184 and/or another portion of the BHA
124 may also comprise a telemetry device 187 operable for
communication with the surface equipment 110, such as via mud-pulse
telemetry. One or more of the downhole tools 180, 182, 184 and/or
another portion of the BHA 124 may also comprise a downhole
processing device 188 operable to receive, process, and/or store
information received from the surface equipment 110, the sensor
package 186, and/or other portions of the BHA 124. The processing
device 188 may also store executable programs and/or instructions,
including for implementing one or more aspects of the operations
described herein.
[0025] The wellsite structure 112 may support a top drive 116
operable to connect (perhaps indirectly) with an uphole end of the
conveyance means 122, and to impart rotary motion 117 and vertical
motion 135 to the drill string 120 and the drill bit 126. However,
a kelly and rotary table (neither shown) may be utilized instead of
or in addition to the top drive 116 to impart the rotary motion
117. The top drive 116 and the connected drill string 120 may be
suspended from the wellsite structure 112 via hoisting equipment,
which may include a traveling block 118, a crown block (not shown),
and a drawworks 119 storing a support cable or line 123. The crown
block may be connected to or otherwise supported by the wellsite
structure 112, and the traveling block 118 may be coupled with the
top drive 116, such as via a hook. The drawworks 119 may be mounted
on or otherwise supported by the rig floor 114. The crown block and
traveling block 118 comprise pulleys or sheaves around which the
support line 123 is reeved to operatively connect the crown block,
the traveling block 118, and the drawworks 119 (and perhaps an
anchor). The drawworks 119 may thus selectively impart tension to
the support line 123 to lift and lower the top drive 116, resulting
in the vertical motion 135. The drawworks 119 may comprise a drum,
a frame, and a prime mover (e.g., an engine or motor) (not shown)
operable to drive the drum to rotate and reel in the support line
123, causing the traveling block 118 and the top drive 116 to move
upward. The drawworks 119 may be operable to release the support
line 123 via a controlled rotation of the drum, causing the
traveling block 118 and the top drive 116 to move downward.
[0026] The top drive 116 may comprise a grabber, a swivel (neither
shown), a tubular handling assembly 127 terminating with an
elevator 129, and a drive shaft 125 operatively connected with a
prime mover (not shown), such as via a gear box or transmission
(not shown). The drill string 120 may be mechanically coupled to
the drive shaft 125 with or without a sub saver between the drill
string 120 and the drive shaft 125. The prime mover may be
selectively operated to rotate the drive shaft 125 and the drill
string 120 coupled with the drive shaft 125. Hence, during drilling
operations, the top drive 116 in conjunction with operation of the
drawworks 119 may advance the drill string 120 into the formation
106 and form the wellbore 102. The tubular handling assembly 127
and the elevator 129 of the top drive 116 may handle tubulars
(e.g., drill pipes, drill collars, casing joints, and the like)
that are not mechanically coupled to the drive shaft 125. For
example, when the drill string 120 is being tripped into or out of
the wellbore 102, the elevator 129 may grasp the tubulars of the
drill string 120 such that the tubulars may be raised and/or
lowered via the hoisting equipment mechanically coupled to the top
drive 116. The grabber may include a clamp that clamps onto a
tubular when making up and/or breaking out a connection of a
tubular with the drive shaft 125. The top drive 116 may have a
guide system (not shown), such as rollers that track up and down a
guide rail on the wellsite structure 112. The guide system may aid
in keeping the top drive 116 aligned with the wellbore 102, and in
preventing the top drive 116 from rotating during drilling by
transferring reactive torque to the wellsite structure 112.
[0027] The well construction system 100 may further include a well
control system for maintaining well pressure control. For example,
the drill string 120 may be conveyed within the wellbore 102
through various blowout preventer (BOP) equipment disposed at the
wellsite surface 104 on top of the wellbore 102 and perhaps below
the rig floor 114. The BOP equipment may be operable to control
pressure within the wellbore 102 via a series of pressure barriers
(e.g., rams) between the wellbore 102 and the wellsite surface 104.
The BOP equipment may include a BOP stack 130 and an annular fluid
control device 132 (e.g., an annular preventer and/or a rotating
control device (RCD)). The BOP equipment 130, 132 may be mounted on
top of a wellhead 134. The well control system may further include
a BOP control unit 137 (i.e., a BOP closing unit) operatively
connected with the BOP equipment 130, 132 and operable to actuate,
drive, or otherwise operate the BOP equipment 130, 132 to control
the BOP equipment 130, 132. The BOP control unit 137 may be or
comprise a hydraulic fluid power unit fluidly connected with the
BOP equipment 130, 132 and selectively operable to hydraulically
drive various portions (e.g., rams, valves) of the BOP equipment
130, 132. The well control system may further include a BOP control
station (e.g., a BOP control station 370 shown in FIG. 5) for
controlling the BOP control unit 137 and the BOP equipment 130,
132.
[0028] The well construction system 100 may further include a
drilling fluid circulation system operable to circulate fluids
between the surface equipment 110 and the drill bit 126 during
drilling and other operations. For example, the drilling fluid
circulation system may be operable to inject a drilling fluid from
the wellsite surface 104 into the wellbore 102 via an internal
fluid passage 121 extending longitudinally through the drill string
120. The drilling fluid circulation system may comprise a pit, a
tank, and/or other fluid container 142 holding drilling fluid 140,
and a pump 144 operable to move the drilling fluid 140 from the
container 142 into the fluid passage 121 of the drill string 120
via a fluid conduit 146 extending from the pump 144 to the top
drive 116 and an internal passage extending through the top drive
116. The fluid conduit 146 may comprise one or more of a pump
discharge line, a stand pipe, a rotary hose, and a gooseneck (not
shown) connected with a fluid inlet of the top drive 116. The pump
144 and the container 142 may be fluidly connected by a fluid
conduit 148, such as a suction line.
[0029] A flow rate sensor 150 may be operatively connected along
the fluid conduit 146 to measure flow rate of the drilling fluid
140 being pumped downhole. The flow rate sensor 150 may be operable
to measure volumetric and/or mass flow rate of the drilling fluid
140. The flow rate sensor 150 may be an electrical flow rate sensor
operable to generate an electrical signal and/or information
indicative of the measured flow rate. The flow rate sensor 150 may
be a Coriolis flowmeter, a turbine flowmeter, or an acoustic
flowmeter, among other examples.
[0030] A fluid level sensor 152 may be mounted or otherwise
disposed in association with the container 142, and may be operable
to measure the level of the drilling fluid 140 within the container
142. The fluid level sensor 152 may be an electrical fluid level
sensor operable to generate signals or information indicative of
the amount (e.g., level, volume) of drilling fluid 140 within the
container 142. The fluid level sensor 152 may comprise conductive,
capacitive, vibrating, electromechanical, ultrasonic, microwave,
nucleonic, and/or other example sensors. A flow check valve 154 may
be connected downstream from the pump 144 to prevent the drilling
or other fluids from backing up through the pump 144.
[0031] A pressure sensor 156 may be connected along the fluid
conduit 146, such as to measure the pressure of the drilling fluid
140 being pumped downhole. The pressure sensor 156 may be connected
close to the top drive 116, such as may permit the pressure sensor
156 to measure the pressure within the drill string 120 at the top
of the internal passage 121 or otherwise proximate the wellsite
surface 104. The pressure sensor 156 may be an electrical sensor
operable to generate electric signals and/or other information
indicative of the measured pressure.
[0032] During drilling operations, the drilling fluid may continue
to flow downhole through the internal passage 121 of the drill
string 120, as indicated in FIG. 1 by directional arrow 158. The
drilling fluid may exit the BHA 124 via ports 128 in the drill bit
126 and then circulate uphole through an annular space ("annulus")
108 of the wellbore 102 defined between an exterior of the drill
string 120 and the wall of the wellbore 102, such flow being
indicated in FIG. 1 by directional arrows 159. In this manner, the
drilling fluid 140 lubricates the drill bit 126 and carries
formation cuttings uphole to the wellsite surface 104. The
returning drilling fluid may exit the annulus 108 via a wing valve,
a bell nipple, or another ported adapter 136. The ported adapter
136 may be disposed below the annular fluid control device 132,
above the BOP stack 130, or at another location along the BOP
equipment permitting ported access or fluid connection with the
annulus 108.
[0033] The drilling fluid exiting the annulus 108 via the ported
adapter 136 may be directed into a fluid conduit 160, and may pass
through various equipment fluidly connected along the conduit 160
prior to being returned to the container 142 for recirculation. For
example, the drilling fluid may pass through a choke manifold 162
connected along the conduit 160. The choke manifold 162 may include
at least one choke and a plurality of fluid valves (neither shown)
collectively operable to control the flow through and out of the
choke manifold 162. Backpressure may be applied to the annulus 108
by variably restricting flow of the drilling fluid or other fluids
flowing through the choke manifold 162. The greater the restriction
to flow through the choke manifold 162, the greater the
backpressure applied to the annulus 108. Thus, downhole pressure
(e.g., pressure at the bottom of the wellbore 102 around the BHA
124 or at a selected depth along the wellbore 102) may be regulated
by varying the backpressure at an upper (i.e., uphole) end (e.g.,
within an upper portion) of the annulus 108 proximate the wellsite
surface 104. Pressure maintained at the upper end of the annulus
108 may be measured via a pressure sensor 164 connected along the
conduit 160 between the ported adapter 136 and the choke manifold
162. A fluid valve 166 may be connected along the conduit 160 to
selectively fluidly isolate the annulus 108 from the choke manifold
162 and/or other surface equipment 110 fluidly connected with the
conduit 160. The fluid valve 166 may be or comprise one or more
fluid shut-off valves, such as ball valves, globe valves, and/or
other types of fluid valves, which may be selectively opened and
closed to permit and prevent fluid flow therethrough. The fluid
valve 166 may be actuated remotely by a corresponding actuator
operatively coupled with the fluid valve 166. The actuator may be
or comprise an electric actuator, such as a solenoid or motor, or a
fluid actuator, such as pneumatic or hydraulic cylinder or rotary
actuator. The fluid valve 166 may also or instead be actuated
manually, such as by a corresponding lever. A flow rate sensor 168
may be connected along the fluid conduit 160 to monitor the flow
rate of the returning drilling fluid or another fluid being
discharged from the wellbore 102.
[0034] Before being returned to the container 142, the drilling
fluid may be cleaned and/or reconditioned by solids and gas control
equipment 170, which may include one or more of shakers,
separators, centrifuges, and other drilling fluid cleaning devices.
The solids control equipment 170 may be operable for separating and
removing solid particles 141 (e.g., drill cuttings) from the
drilling fluid returning to the surface 104. The solids and gas
control equipment 170 may also comprise fluid reconditioning
equipment, such as may remove gas and/or finer formation cuttings
143 from the drilling fluid. The fluid reconditioning equipment may
include a desilter, a desander, a degasser 172, and/or the like.
The degasser 172 may form or be mounted in association with one or
more portions of the solids and gas control equipment 170. The
degasser 172 may be operable for releasing and/or capturing
formation gasses entrained in the drilling fluid discharged from
the wellbore 102. Intermediate tanks/containers (not shown) may be
utilized to hold the drilling fluid 140 between the various
portions of the solids and gas control equipment 170.
[0035] The degasser 172 may be fluidly connected with one or more
gas sensors 174 (e.g., gas detectors and/or analyzers) via a
conduit 176, such as may permit the formation gasses released
and/or captured by the degasser 172 to be directed to and analyzed
by the gas sensors 174. The gas sensors 174 may be operable for
generating signals or information indicative of the presence and/or
quantity of formation gasses released and/or captured by the
degasser 172. The gas sensors 174 may be or comprise qualitative
gas analyzers, which may be utilized for safety purposes, such as
to detect presence of hazardous gases entrained within the
returning drilling fluid. The gas sensors 174 may also or instead
be or comprise quantitative gas analyzers, which may be utilized to
detect levels or quantities of certain formation gasses, such as to
perform formation evaluation.
[0036] The cleaned/reconditioned drilling fluid may be transferred
to the fluid container 142, and the solid particles 141 removed
from the fluid may be transferred to a solids container 143 (e.g.,
a reserve pit). The container 142 may include an agitator (not
shown) to maintain uniformity of the drilling fluid 140 therein. A
hopper (not shown) may be connected with or along the fluid conduit
148 to introduce chemical additives, such as caustic soda, into the
drilling fluid 140 being pumped into the wellbore 102.
[0037] The surface equipment 110 may include tubular handling
equipment operable to store, move, connect, and disconnect tubulars
to assemble and disassemble the conveyance means 122 of the drill
string 120 during drilling operations. For example, a catwalk 131
may be utilized to convey tubulars from a ground level, such as
along the wellsite surface 104, to the rig floor 114, permitting
the tubular handling assembly 127 to grab and lift the tubulars
above the wellbore 102 for connection with previously deployed
tubulars. The catwalk 131 may have a horizontal portion and an
inclined portion that extends between the horizontal portion and
the rig floor 114. The catwalk 131 may comprise a skate 133 movable
along a groove (not shown) extending longitudinally along the
horizontal and inclined portions of the catwalk 131. The skate 133
may be operable to convey (e.g., push) the tubulars along the
catwalk 131 to the rig floor 114. The skate 133 may be driven along
the groove by a drive system (not shown), such as a pulley system
or a hydraulic system, among other examples. Additionally, one or
more racks (not shown) may adjoin the horizontal portion of the
catwalk 131. The racks may have a spinner unit for transferring
tubulars to the groove of the catwalk 131.
[0038] An iron roughneck 151 may be positioned on the rig floor
114. The iron roughneck 151 may comprise a torqueing portion 153,
such as may include a spinner and a torque wrench comprising a
lower tong and an upper tong. The torqueing portion 153 of the iron
roughneck 151 may be moveable toward and at least partially around
the drill string 120, such as may permit the iron roughneck 151 to
make up and break out connections of the drill string 120. The
torqueing portion 153 may also be moveable away from the drill
string 120, such as may permit the iron roughneck 151 to move clear
of the drill string 120 during drilling operations. The spinner of
the iron roughneck 151 may be utilized to apply low torque to make
up and break out threaded connections between tubulars of the drill
string 120, and the torque wrench may be utilized to apply a higher
torque to tighten and loosen the threaded connections.
[0039] A reciprocating slip 161 may be located on the rig floor
114, such as may accommodate therethrough the conveyance means 122
during make up and break out operations and during the drilling
operations. The reciprocating slip 161 may be in an open position
during drilling operations to permit advancement of the drill
string 120 therethrough, and in a closed position to clamp an upper
end of the conveyance means 122 (e.g., assembled tubulars) to
thereby suspend and prevent advancement of the drill string 120
within the wellbore 102, such as during the make up and break out
operations.
[0040] During drilling operations, the hoisting equipment lowers
the drill string 120 while the top drive 116 rotates the drill
string 120 to advance the drill string 120 downward within the
wellbore 102 and into the formation 106. During the advancement of
the drill string 120, the reciprocating slip 161 is in an open
position, and the iron roughneck 151 is moved away or is otherwise
clear of the drill string 120. When the upper portion of the
tubular in the drill string 120 that is made up to the drive shaft
125 is near the reciprocating slip 161 and/or the rig floor 114,
the top drive 116 ceases rotating and the reciprocating slip 161
closes to clamp the tubular made up to the drive shaft 125. The
grabber of the top drive 116 then clamps the upper portion of the
tubular made up to the drive shaft 125, and the drive shaft 125
rotates in a direction reverse from the drilling rotation to break
out the connection between the drive shaft 125 and the made up
tubular. The grabber of the top drive 116 may then release the
tubular of the drill string 120.
[0041] Multiple tubulars may be loaded on the rack of the catwalk
131 and individual tubulars (or stands of two or three tubulars)
may be transferred from the rack to the groove in the catwalk 131,
such as by the spinner unit. The tubular positioned in the groove
may be conveyed along the groove by the skate 133 until an end of
the tubular projects above the rig floor 114. The elevator 129 of
the top drive 116 then grasps the protruding end, and the drawworks
119 is operated to lift the top drive 116, the elevator 129, and
the new tubular.
[0042] The hoisting equipment then raises the top drive 116, the
elevator 129, and the tubular until the tubular is aligned with the
upper portion of the drill string 120 clamped by the slip 161. The
iron roughneck 151 is moved toward the drill string 120, and the
lower tong of the torqueing portion 153 clamps onto the upper
portion of the drill string 120. The spinning system rotates the
new tubular (e.g., a threaded male end) into the upper portion of
the drill string 120 (e.g., a threaded female end). The upper tong
then clamps onto the new tubular and rotates with high torque to
complete making up the connection with the drill string 120. In
this manner, the new tubular becomes part of the drill string 120.
The iron roughneck 151 then releases and moves clear of the drill
string 120.
[0043] The grabber of the top drive 116 may then clamp onto the
drill string 120. The drive shaft 125 (e.g., a threaded male end)
is brought into contact with the drill string 120 (e.g., a threaded
female end) and rotated to make up a connection between the drill
string 120 and the drive shaft 125. The grabber then releases the
drill string 120, and the reciprocating slip 161 is moved to the
open position. The drilling operations may then resume.
[0044] The tubular handling equipment may further include a tubular
handling manipulator (PHM) 163 disposed in association with a
fingerboard 165. Although the PHM 163 and the fingerboard 165 are
shown supported on the rig floor 114, one or both of the PHM 163
and fingerboard 165 may be located on the wellsite surface 104 or
another area of the well construction system 100. The fingerboard
165 provides storage (e.g., temporary storage) of tubulars (or
stands of two or three tubulars) 111 during various operations,
such as during and between tripping out and tripping in the drill
string 120. The PHM 163 may be operable to transfer the tubulars
111 between the fingerboard 165 and the drill string 120 (i.e.,
space above the suspended drill string 120). For example, the PHM
163 may include arms 167 terminating with clamps 169, such as may
be operable to grasp and/or clamp onto one of the tubulars 111. The
arms 167 of the PHM 163 may extend and retract, and/or at least a
portion of the PHM 163 may be rotatable and/or movable toward and
away from the drill string 120, such as may permit the PHM 163 to
transfer the tubular 111 between the fingerboard 165 and the drill
string 120.
[0045] To trip out the drill string 120, the top drive 116 is
raised, the reciprocating slip 161 is closed around the drill
string 120, and the elevator 129 is closed around the drill string
120. The grabber of the top drive 116 clamps the upper portion of
the tubular made up to the drive shaft 125. The drive shaft 125
then rotates in a direction reverse from the drilling rotation to
break out the connection between the drive shaft 125 and the drill
string 120. The grabber of the top drive 116 then releases the
tubular of the drill string 120, and the drill string 120 is
suspended by (at least in part) the elevator 129. The iron
roughneck 151 is moved toward the drill string 120. The lower tong
clamps onto a lower tubular below a connection of the drill string
120, and the upper tong clamps onto an upper tubular above that
connection. The upper tong then rotates the upper tubular to
provide a high torque to break out the connection between the upper
and lower tubulars. The spinning system then rotates the upper
tubular to separate the upper and lower tubulars, such that the
upper tubular is suspended above the rig floor 114 by the elevator
129. The iron roughneck 151 then releases the drill string 120 and
moves clear of the drill string 120.
[0046] The PHM 163 may then move toward the tool string 120 to
grasp the tubular suspended from the elevator 129. The elevator 129
then opens to release the tubular. The PHM 163 then moves away from
the tool string 120 while grasping the tubular with the clamps 169,
places the tubular in the fingerboard 165, and releases the tubular
for storage in the fingerboard 165. This process is repeated until
the intended length of drill string 120 is removed from the
wellbore 102.
[0047] The well construction system 100 may also comprise a
plurality of fire and gas sensors 178 located at different
locations (e.g., the rig floor 114, the wellsite structure 112) of
the well construction system 100. The fire and gas sensors 178 may
each be operable to generate signals indicative of fire and/or
smoke. The fire and gas sensors 178 may also be or comprise
qualitative gas analyzers operable to generate signals indicative
of flammable and/or other hazardous gasses being released from the
wellbore 102 or otherwise present at the well construction system
100.
[0048] The surface equipment 110 of the well construction system
100 may also comprise a control center 190 from which various
portions of the well construction system 100, such as the top drive
116, the hoisting system, the tubular handling system, the drilling
fluid circulation system, the well control system, the BHA 124, and
the fire and gas sensors 178, among other examples, may be
monitored and controlled. The control center 190 may be located on
the rig floor 114 or another location of the well construction
system 100, such as the wellsite surface 104. The control center
190 may comprise a facility 191 (e.g., a room, a cabin, a trailer,
etc.) containing a control workstation 197, which may be operated
by a human wellsite operator 195 to monitor and control various
wellsite equipment or portions of the well construction system 100.
The control workstation 197 may comprise or be communicatively
connected with a processing device 192 (e.g., a controller, a
computer, etc.), such as may be operable to receive, process, and
output information to monitor operations of and provide control to
one or more portions of the well construction system 100. For
example, the processing device 192 may be communicatively connected
with the various surface and downhole equipment described herein,
and may be operable to receive signals from and transmit signals to
such equipment to perform various operations described herein. The
processing device 192 may store executable programs, instructions,
and/or operational parameters or set-points, including for
implementing one or more aspects of the operations described
herein. The processing device 192 may be located within and/or
outside of the facility 191.
[0049] The control workstation 197 may be operable for entering or
otherwise communicating commands to the processing device 192 by
the wellsite operator 195, and for displaying or otherwise
communicating information from the processing device 192 to the
wellsite operator 195. The control workstation 197 may comprise a
plurality of human-machine interface (HMI) devices, including one
or more input devices 194 (e.g., a keyboard, a mouse, a joystick, a
touchscreen, etc.) and one or more output devices 196 (e.g., a
video monitor, a printer, audio speakers, etc.). Communication
between the control center 190, the processing device 192, the
input and output devices 194, 196, and the various wellsite
equipment may be via wired and/or wireless communication means.
However, for clarity and ease of understanding, such communication
means are not depicted, and a person having ordinary skill in the
art will appreciate that such communication means are within the
scope of the present disclosure.
[0050] The well construction system 100 also includes stationary
and/or mobile video cameras 198 disposed or utilized at various
locations within the well construction system 100. The video
cameras 198 capture videos of various portions, equipment, or
subsystems of the well construction system 100, and perhaps the
wellsite operators 195 and the actions they perform, during or
otherwise in association with the wellsite operations, including
while performing repairs to the well construction system 100 during
a breakdown. For example, the video cameras 198 may capture videos
of the entire well construction system 100 and/or specific portions
of the well construction system 100, such as the top drive 116, the
iron roughneck 151, the PHM 163, the fingerboard 165, and/or the
catwalk 131, among other examples. The video cameras 198 generate
corresponding video signals (i.e., video feeds) comprising or
otherwise indicative of the captured videos. The video cameras 198
may be in signal communication with the processing device 192, such
as may permit the video signals to be processed and transmitted to
the control workstation 197 and, thus, permit the wellsite
operators 195 to view various portions or components of the well
construction system 100 on one or more of the output devices 196.
The processing device 192 or another portion of the control
workstation 197 may be operable to record the video signals
generated by the video cameras 198.
[0051] Well construction systems within the scope of the present
disclosure may include more or fewer components than as described
above and depicted in FIG. 1. Additionally, various equipment
and/or subsystems of the well construction system 100 shown in FIG.
1 may include more or fewer components than as described above and
depicted in FIG. 1. For example, various engines, motors,
hydraulics, actuators, valves, and/or other components not
explicitly described herein may be included in the well
construction system 100, and are within the scope of the present
disclosure.
[0052] FIG. 2 is a schematic view of at least a portion of an
example implementation of a control system 200 for the well
construction system 100 according to one or more aspects of the
present disclosure. The following description refers to FIGS. 1 and
2, collectively.
[0053] The control system 200 may be utilized to monitor and
control various portions, components, and equipment of the well
construction system 100 described herein, which may be grouped into
several subsystems, each operable to perform a corresponding
operation and/or a portion of the well construction operations
described herein. The subsystems may include a rig control (RC)
system 211, a fluid control (FC) system 212, a managed pressure
drilling control (MPDC) system 213, a fire and gas monitoring (FGM)
system 214, a closed-circuit television (CCTV) system 215, a choke
pressure control (CPC) system 216, and a well pressure control (WC)
system 217. The control workstation 197 may be utilized to monitor,
configure, control, and/or otherwise operate one or more of the
subsystems 211-217.
[0054] The RC system 211 may include the wellsite structure 112,
the drill string hoisting system or equipment (e.g., the drawworks
119 and the top drive 116), drill string rotation system or
equipment (e.g., the top drive 116 and/or the rotary table and
kelly), the reciprocating slip 161, the drill pipe handling system
or equipment (e.g., the catwalk 131, the PHM 163, the fingerboard
165, and the iron roughneck 151), electrical generators, and other
equipment. Accordingly, the RC system 211 may perform power
generation and drill pipe handling, hoisting, and rotation
operations. The RC system 211 may also serve as a support platform
for drilling equipment and staging ground for rig operations, such
as connection make up and break out operations described above. The
FC system 212 may include the drilling fluid 140, the pumps 144,
valves 166, drilling fluid loading equipment, the solids and gas
treatment equipment 170, and/or other fluid control equipment.
Accordingly, the FC system 212 may perform fluid operations of the
well construction system 100. The MPDC system 213 may include the
choke manifold 162, the downhole pressure sensors 186, and/or other
equipment. The FGM system 214 may comprise the gas sensors 174, the
fire and gas sensors 178, and/or other equipment. The CCTV system
215 may include the video cameras 198, one or more other input
devices 194 (e.g., a keyboard, a touchscreen, etc.), one or more
video output devices 196 (e.g., video monitors), various
communication equipment (e.g., modems, network interface cards,
etc.), and/or other equipment. The CCTV system 215 may be utilized
to capture real-time video of various portions or subsystems
211-217 of the well construction system 100 and display video
signals from the video cameras 198 on the video output devices to
display in real-time the various portions or subsystems 211-217 of
the well construction system 100. The CPC system 216 may comprise
the choke manifold 162 and/or other equipment, and the WC system
217 may comprise the BOP equipment 130, 132, the BOP control unit
137, and the BOP control station (e.g., BOP control station 370
shown in FIG. 5) for controlling the BOP control unit 137 and the
BOP equipment 130, 132.
[0055] The control system 200 may include a wellsite computing
resource environment 205, which may be located at the wellsite 104
as part of the well construction system 100, and a remote computing
resource environment 206, which may be located offsite (i.e., not
at the wellsite 104). The control system 200 may also include
various local controllers (e.g., controllers 241-247 shown in FIG.
3) associated with the subsystems 211-217 and/or individual
components or equipment of the well construction system 100. As
described above, each subsystem 211-217 of the well construction
system 100 may include actuators (e.g., actuators 231-237 shown in
FIG. 3) and sensors (e.g., sensors 221-227 shown in FIG. 3) for
performing operations of the well construction system 100. These
actuators and sensors may be monitored and/or controlled via the
wellsite computing resource environment 205, the remote computing
resource environment 206, and/or the corresponding local
controllers. For example, the wellsite computing resource
environment 205 and/or the local controllers may be operable to
monitor the sensors of the wellsite subsystems 211-217 in
real-time, and to provide real-time control commands to the
subsystems 211-217 based on the received sensor data. Data may be
generated by both sensors and computation, and may be utilized for
coordinated control among two or more of the subsystems
211-217.
[0056] The control system 200 may be in real-time communication
with the various components of the well construction system 100.
For example, the local controllers may be in communication with
various sensors and actuators of the corresponding subsystems
211-217 via local communication networks (not shown) and the
wellsite computing resource environment 205 may be in communication
with the subsystems 211-217 via a data bus or network 209. As
described below, data or sensor signals generated by the sensors of
the subsystems 211-217 may be made available for use by processes
(e.g., processes 274, 275 shown in FIG. 3) and/or devices of the
wellsite computing resource environment 205. Similarly, data or
control signals generated by the processes and/or devices of the
wellsite computing resource environment 205 may be automatically
communicated to various actuators of the subsystems 211-217,
perhaps pursuant to predetermined programming, such as to
facilitate well construction operations and/or other operations
described herein.
[0057] The remote computing resource environment 206, the wellsite
computing resource environment 205, and the subsystems 211-217 of
the well construction system 100 may be communicatively connected
with each other via a network connection, such as via a
wide-area-network (WAN), a local-area-network (LAN), and/or other
networks also within the scope of the present disclosure. A "cloud"
computing environment is one example of a remote computing resource
environment 206. The wellsite computing resource environment 205
may be or form at least a portion of the processing device 192 and,
thus, may form a portion of or be communicatively connected with
the control workstation 197.
[0058] FIG. 3 is a schematic view of an example implementation of
the control system 200 shown in FIG. 2 communicatively connected
with the subsystems 211-217 of the well construction system 100,
including the RC system 211, the FC system 212, the MPDC system
213, the FGM system 214, the CCTV system 215, the CPC system 216,
and the WC system 217. The following description refers to FIGS.
1-3, collectively.
[0059] An example implementation of the well construction system
100 may include one or more onsite user devices 202 communicatively
connected with the wellsite computing resource environment 205. The
onsite user devices 202 may be or comprise stationary user devices
intended to be stationed at the well construction system 100 and/or
portable user devices. For example, the onsite user devices 202 may
include a desktop, a laptop, a smartphone, a personal digital
assistant (PDA), a tablet component, a wearable computer, or other
suitable devices. The onsite user devices 202 may be operable to
communicate with the wellsite computing resource environment 205 of
the well construction system 100 and/or the remote computing
resource environment 206. The onsite user device 202 may be or
comprise at least a portion of the control workstation 197 shown in
FIG. 1 and described above. The onsite user device 202 may be
located within the facility 191.
[0060] The wellsite computing resource environment 205 and/or other
portions of the well construction system 100 may further comprise
an information technology (IT) system 219 operable to
communicatively connect various portions of the wellsite computing
resource environment 205 and/or communicatively connect the
wellsite computing resource environment 205 with other portions of
the well construction system 100. The IT system 219 may include
communication conduits, software, computers, and other IT equipment
facilitating communication between one or more portions of the
wellsite computing resource environment 205 and/or between the
wellsite computing resource environment 205 and another portion of
the well construction system 100, such as the remote computing
resource environment 206, the onsite user device 202, and the
subsystems 211-217.
[0061] The control system 200 may include (or otherwise be utilized
in conjunction with) one or more offsite user devices 203. The
offsite user devices 203 may be or comprise a desktop computer, a
laptop computer, a smartphone and/or other portable smart device, a
PDA, a tablet/touchscreen computer, a wearable computer, and/or
other devices. The offsite user devices 203 may be operable to
receive and/or transmit information (e.g., for monitoring
functionality) from and/or to the well construction system 100,
such as by communication with the wellsite computing resource
environment 205 via the network 208. The offsite user devices 203
may be utilized for monitoring functions, but may also provide
control processes for controlling operation of the various
subsystems 211-217 of the well construction system 100. The offsite
user devices 203 and/or the wellsite computing resource environment
205 may also be operable to communicate with the remote computing
resource environment 206 via the network 208. The network 208 may
be a WAN, such as the internet, a cellular network, a satellite
network, other WANs, and/or combinations thereof.
[0062] The subsystems 211-217 of the well construction system 100
may include sensors 221-227, actuators 231-237, and local
controllers 241-247. The controllers 241-247 may be programmable
logic controllers (PLCs) and/or other controllers having aspects
similar to the example processing device 700 shown in FIG. 13. The
RC system 211 may include one or more sensors 221, one or more
actuators 231, and one or more controllers 241. The FC system 212
may include one or more sensors 222, one or more actuators 232, and
one or more controllers 242. The MPDC system 213 may include one or
more sensors 223, one or more actuators 233, and one or more
controllers 243. The FGM system 214 may include one or more sensors
224, one or more actuators 234, and one or more controllers 244.
The CCTV system 215 may include one or more sensors 225, one or
more actuators 235, and one or more controllers 245. The CPC system
216 may include one or more sensors 226, one or more actuators 236,
and one or more controllers 246. The WC system 217 may include one
or more sensors 227, one or more actuators 237, and one or more
controllers 247 (e.g., a BOP control station 370 shown in FIG.
5).
[0063] The sensors 221-227 may include sensors utilized for
operation of the various subsystems 211-217 of the well
construction system 100. For example, the sensors 221-227 may
include cameras, position sensors, pressure sensors, temperature
sensors, flow rate sensors, vibration sensors, current sensors,
voltage sensors, resistance sensors, gesture detection sensors or
devices, voice actuated or recognition devices or sensors, and/or
other examples.
[0064] The sensors 221-227 may be operable to provide sensor data
to the wellsite computing resource environment 205, such as to the
coordinated control device 204. For example, the sensors 221-227
may provide sensor data 251-257, respectively. The sensor data
251-257 may include signals or information indicative of 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), flow rate,
temperature, operational speed, position, and pressure, among other
examples. The acquired sensor data 251-257 may include or be
associated with a timestamp (e.g., date and/or time) indicative of
when the sensor data 251-257 was acquired. The sensor data 251-257
may also or instead be aligned with a depth or other drilling
parameter.
[0065] Acquiring the sensor data 251-257 at the coordinated control
device 204 may facilitate measurement of the same physical
properties at different locations of the well construction system
100, wherein the sensor data 251-257 may be utilized for
measurement redundancy to permit continued well construction
operations. Measurements of the same physical properties at
different locations may also be utilized for detecting equipment
conditions among different physical locations at the wellsite
surface 104 or within the wellbore 102. Variation in measurements
at different wellsite locations over time may be utilized to
determine equipment performance, system performance, scheduled
maintenance due dates, and the like. For example, slip status
(e.g., set or unset) may be acquired from the sensors 221 and
communicated to the wellsite computing resource environment 205.
Acquisition of fluid samples may be measured by a sensor, such as
the sensors 186, 223, and related with bit depth and time measured
by other sensors. Acquisition of data from the video cameras 198,
225 may facilitate detection of arrival and/or installation of
materials or equipment at the well construction system 100. The
time of arrival and/or installation of materials or equipment may
be utilized to evaluate degradation of material, scheduled
maintenance of equipment, and other evaluations.
[0066] The coordinated control device 204 may facilitate control of
one or more of the subsystems 211-217 at the level of each
individual subsystem 211-217. For example, in the FC system 212,
sensor data 252 may be fed into the controller 242, which may
respond to control the actuators 232. However, for control
operations that involve multiple systems, the control may be
coordinated through the coordinated control device 204. For
example, coordinated control operations may include the control of
downhole pressure during tripping. The downhole pressure may be
affected by both the FC system 212 (e.g., pump rate), the MPDC 213
(e.g., choke position of the MPDC), and the RC system 211 (e.g.,
tripping speed). Thus, when it is intended to maintain certain
downhole pressure during tripping, the coordinated control device
204 may be utilized to direct the appropriate control commands to
two or more (or each) of the participating subsystems.
[0067] Control of the subsystems 211-217 of the well construction
system 100 may be provided via a three-tier control system that
includes a first tier of the local controllers 241-247, a second
tier of the coordinated control device 204, and a third tier of the
supervisory control system 207. Coordinated control may also be
provided by one or more controllers 241-247 of one or more of the
subsystems 211-217 without the use of a coordinated control device
204. In such implementations of the control system 200, the
wellsite computing resource environment 205 may provide control
processes directly to these controllers 241-247 for coordinated
control.
[0068] The sensor data 251-257 may be received by the coordinated
control device 204 and utilized for control of the subsystems
211-217. The sensor data 251-257 may be encrypted to produce
encrypted sensor data 271. For example, the wellsite computing
resource environment 205 may encrypt sensor data from different
types of sensors and systems to produce a set of encrypted sensor
data 271. Thus, the encrypted sensor data 271 may not be viewable
by unauthorized user devices (either offsite user devices 203 or
onsite user devices 202) if such devices gain access to one or more
networks of the well construction system 100. The encrypted sensor
data 271 may include a timestamp and an aligned drilling parameter
(e.g., depth), as described above. The encrypted sensor data 271
may be communicated to the remote computing resource environment
206 via the network 208 and stored as encrypted sensor data
272.
[0069] The wellsite computing resource environment 205 may provide
the encrypted sensor data 271, 272 available for viewing and
processing offsite, such as via the offsite user devices 203.
Access to the encrypted sensor data 271, 272 may be restricted via
access control implemented in the wellsite computing resource
environment 205. The encrypted sensor data 271, 272 may be provided
in real-time to offsite user devices 203 such that offsite
personnel may view real-time status of the well construction system
100 and provide feedback based on the real-time sensor data. For
example, different portions of the encrypted sensor data 271, 272
may be sent to the offsite user devices 203. The encrypted sensor
data 271, 272 may be decrypted by the wellsite computing resource
environment 205 before transmission, and/or decrypted on the
offsite user device 203 after encrypted sensor data is received.
The offsite user device 203 may include a thin client (not shown)
configured to display data received from the wellsite computing
resource environment 205 and/or the remote computing resource
environment 206. For example, multiple types of thin clients (e.g.,
devices with display capability and minimal processing capability)
may be utilized for certain functions or for viewing various sensor
data 251-257.
[0070] The wellsite computing resource environment 205 may include
various computing resources utilized for monitoring and controlling
operations, such as one or more computers having a processor and a
memory. For example, the coordinated control device 204 may include
a processing device (e.g., processing device 700 shown in FIG. 13),
having a processor and memory for processing the sensor data,
storing the sensor data, and issuing control commands responsive to
the sensor data. As described above, the coordinated control device
204 may control various operations of the subsystems 211-217 via
analysis of sensor data 251-257 from one or more of the wellsite
subsystems 211-217 to facilitate coordinated control between the
subsystems 211-217. The coordinated control device 204 may generate
control data 273 (e.g., signals, commands, coded instructions) to
execute control of the subsystems 211-217. The coordinated control
device 204 may transmit the control data 273 to one or more
subsystems 211-217. For example, control data 261 may be sent to
the RC system 211, control data 262 may be sent to the FC system
212, control data 263 may be sent to the MPDC system 213, control
data 264 may be sent to the FGM system 214, control data 265 may be
sent to the CCTV system 215, control data 266 may be sent to the
CPC system 216, and control data 267 may be sent to the WC system
217. The control data 261-267 may include, for example, wellsite
operator commands (e.g., turn on or off a pump, switch on or off a
valve, update a physical property set-point, etc.). The coordinated
control device 204 may include a fast control loop that directly
obtains sensor data 251-257 and executes, for example, a control
algorithm. The coordinated control device 204 may include a slow
control loop that obtains data via the wellsite computing resource
environment 205 to generate control commands.
[0071] The coordinated control device 204 may intermediate between
the supervisory control system 207 and the local controllers
241-247 of the subsystems 211-217, such as may permit the
supervisory control system 207 to control the subsystems 211-217.
The supervisory control system 207 may include, for example,
devices for entering control commands to perform operations of the
subsystems 211-217. The coordinated control device 204 may receive
commands from the supervisory control system 207, process such
commands according to a rule (e.g., an algorithm based upon the
laws of physics for drilling operations), and provide control data
to one or more subsystems 211-217. The supervisory control system
207 may be provided by the wellsite operator 195 and/or process
monitoring and control program. In such implementations, the
coordinated control device 204 may coordinate control between
discrete supervisory control systems and the subsystems 211-217
while utilizing control data 261-267 that may be generated based on
the sensor data 251-257 received from the subsystems 211-217 and
analyzed via the wellsite computing resource environment 205. The
coordinated control device 204 may receive the control data 251-257
and then dispatch control data 261, including interlock commands,
to each subsystem 211-217. The coordinated control device 204 may
also or instead just listen to the control data 251-257 being
dispatched to each subsystem 221-227 and then initiate the machine
interlock commands to the relevant local controller 241-247.
[0072] The coordinated control device 204 may run with different
levels of autonomy. For example, the coordinated control device 204
may operate in an advice mode to inform the wellsite operators 195
to perform a specific task or take specific corrective action based
on sensor data 251-257 received from the various subsystems
211-217. While in the advice mode, the coordinated control device
204 may, for example, advise or instruct the wellsite operator 195
to perform a standard work sequence when gas is detected on the rig
floor 114, such as to close the annular BOP 132. Furthermore, if
the wellbore 102 is gaining or losing drilling fluid 140, the
coordinated control device 204 may, for example, advise or instruct
the wellsite operator 195 to modify the density of the drilling
fluid 140, modify the pumping rate of the drilling fluid 140,
and/or modify the pressure of the drilling fluid within the
wellbore 102.
[0073] The coordinated control device 204 may also operate in a
system/equipment interlock mode, whereby certain operations or
operational sequences are prevented based on the received sensor
data 251-257. While operating in the interlock mode, the
coordinated control device 204 may manage interlock operations
among the various equipment of the subsystems 211-217. For example,
if a pipe ram of the BOP stack 130 is activated, the coordinated
control device 204 may issue an interlock command to the RC system
controller 241 to stop the drawworks 119 from moving the drill
string 120. However, if a shear ram of the BOP stack 130 is
activated, the coordinated control device 204 may issue an
interlock command to the controller 241 to operate the drawworks
119 to adjust the position of the drill string 120 within the BOP
stack 130 before activating the shear ram, so that the shear ram
does not align with a shoulder of the tubulars forming the drill
string 120.
[0074] The coordinated control device 204 may also operate in an
automated sequence mode, whereby certain operations or operational
sequences are automatically performed based on the received sensor
data 251-257. For example, the coordinated control device 204 may
activate an alarm and/or stop or reduce operating speed of the pipe
handling equipment when a wellsite operator 195 is detected close
to a moving iron roughneck 151, the PHM 163, or the catwalk 131. As
another example, if the wellbore pressure increases rapidly, the
coordinated control device 204 may close the annular BOP 132, close
one or more rams of the BOP stack 130, and/or adjust the choke
manifold 162.
[0075] The wellsite computing resource environment 205 may comprise
or execute a monitoring process 274 (e.g., an event detection
process) that may utilize the sensor data 251-257 to determine
information about status of the well construction system 100 and
automatically initiate an operational action, a process, and/or a
sequence of one or more of the subsystems 211-217. The monitoring
process 274 may initiate the operational action to be caused by the
coordinated control device 204. Depending on the type and range of
the sensor data 251-257 received, the operational actions may be
executed in the advice mode, the interlock mode, or the automated
sequence mode.
[0076] For example, the monitoring process 274 may determine a
drilling state, equipment health, system health, a maintenance
schedule, or combination thereof, and initiate an advice to be
generated. The monitoring process 274 may also detect abnormal
drilling events, such as a wellbore fluid loss and gain, a wellbore
washout, a fluid quality issue, or an equipment event based on job
design and execution parameters (e.g., wellbore, drilling fluid,
and drill string parameters), current drilling state, and real-time
sensor information from the surface equipment 110 (e.g., presence
of hazardous gas at the rig floor, presence of wellsite operators
in close proximity to moving pipe handling equipment, etc.) and the
BHA 124, initiating an operational action in the automated mode.
The monitoring process 274 may be connected to the real-time
communication network 209. The coordinated control device 204 may
initiate a counteractive measure (e.g., a predetermined action,
process, or operation) based on the events detected by the
monitoring process 274.
[0077] The term "event" as used herein may include, but not be
limited to, an operational and safety related event described
herein and/or another operational and safety related event that can
take place at a well construction system. The events described
herein may be detected by the monitoring process 274 based on the
sensor data 251-257 (e.g., sensor signals or information) received
and analyzed by the monitoring process 274.
[0078] The wellsite computing resource environment 205 may also
comprise or execute a control process 275 that may utilize the
sensor data 251-257 to optimize drilling operations, such as the
control of drilling equipment to improve drilling efficiency,
equipment reliability, and the like. For example, the acquired
sensor data 252 may be utilized to derive a noise cancellation
scheme to improve electromagnetic and mud pulse telemetry signal
processing. The remote computing resource environment 206 may
comprise or execute a control process 276 substantially similar to
the control process 275 that may be provided to the wellsite
computing resource environment 205. The monitoring and control
processes 274, 275, 276 may be implemented via, for example, a
control algorithm, a computer program, firmware, or other hardware
and/or software.
[0079] The wellsite computing resource environment 205 may include
various computing resources, such as a single computer or multiple
computers. The wellsite computing resource environment 205 may
further include a virtual computer system and a virtual database or
other virtual structure for collected data, such as may include one
or more resource interfaces (e.g., web interfaces) that facilitate
the submission of application programming interface (API) calls to
the various resources through a request. In addition, each of the
resources may include one or more resource interfaces that
facilitate the resources to access each other (e.g., to facilitate
a virtual computer system of the computing resource environment to
store data in or retrieve data from the database or other structure
for collected data). The virtual computer system may include a
collection of computing resources configured to instantiate virtual
machine instances. A wellsite operator 195 may interface with the
virtual computer system via the offsite user device 203 or the
onsite user device 202. Other computer systems or computer system
services may be utilized in the wellsite computing resource
environment 205, such as a computer system or computer system
service that provides computing resources on dedicated or shared
computers/servers and/or other physical devices. The wellsite
computing resource environment 205 may include a single server (in
a discrete hardware component or as a virtual server) or multiple
servers (e.g., web servers, application servers, or other servers).
The servers may be, for example, computers arranged in physical
and/or virtual configuration.
[0080] The wellsite computing resource environment 205 may also
include a database that may be or comprise a collection of
computing resources that run one or more data collections. Such
data collections may be operated and managed by utilizing API
calls. The data collections, such as the sensor data 251-257, may
be made available to other resources in the wellsite computing
resource environment 205, or to user devices (e.g., onsite user
device 202 and/or offsite user device 203) accessing the wellsite
computing resource environment 205. The remote computing resource
environment 206 may include computing resources similar to those
described above, such as a single computer or multiple computers
(in discrete hardware components or virtual computer systems).
[0081] FIGS. 4 and 5 are perspective and sectional views of at
least a portion of an example implementation of a control center
300 according to one or more aspects of the present disclosure. The
control center 300 may be or form at least a portion of the control
center 190 shown in FIG. 1. The following description refers to
FIGS. 1, 4, and 5, collectively.
[0082] The control center 300 comprises a facility 305 (e.g., a
room, a cabin, a trailer, etc.) containing various control devices
for monitoring and controlling the subsystems 211-217 and other
portions of the well construction system 100. The facility 305 may
comprise a front side 301, which may be directed toward or located
closest to the drill string 120 being constructed by the well
construction system 100 and a rear side 303, which may be directed
away from the drill string 120. The facility 305 may comprise a
floor 302, a front wall 304, a left wall 306, a right wall 308, a
rear wall 310, and a roof 312. The facility 305 may also have a
side door 314, a rear door 316, and a plurality of windows 321-328
in one or more of the walls 304, 306, 308, 310 and/or the roof 312.
Each of the windows 321-328 may be surrounded by structural framing
330 connected with the walls and supporting window safety guards
332 (e.g., bars, grills) in front of or along the windows
321-328.
[0083] The facility 305 may have an observation area 340 at the
front side 301 of the facility 305 from which a wellsite operator
195 will have an optimal or otherwise improved view of the drill
string 120, the rig floor 114, and/or other portions of the well
construction system 100. The observation area 340 may be surrounded
or defined by windows 323-328 on several sides to increase wellsite
operator's 195 horizontal and vertical angle of view of the well
constriction system 100. A portion 342 of the observation area 340
(e.g., windows 323-327) may protrude or extend out past other
portions of the facility 305 (e.g., front wall 304) to facilitate
the optimal view of the well construction system 100 by the
wellsite operators 195. The observation area 340 may be located on
a side of the facility 305. The observation area 318 may be
surrounded by or at least partially defined by a front window 324
permitting the wellsite operator 195 to look forward, two side
windows 323, 325 permitting the wellsite operator 195 to look
sideways (i.e., left and right), a lower window 326 permitting the
wellsite operator 195 to look downwards, and one or more upper
windows 327, 328 permitting the wellsite operator 195 to look
upwards. The lower window 326 and/or at least one upper window 327
may extend diagonally with respect to the front window 324.
[0084] The control center 300 may comprise one or more wellsite
operator control workstations within the facility 305. The
workstations may be utilized by the wellsite operators 195 to
monitor and control the subsystems 211-217 and other portions of
the well construction system 100. For example, the observation area
340 may contain a first control workstation 350 located adjacent
the windows 323, 324, 325, 326, 328 and at least partially within
the extended portion 342 of the observation area 340, such as may
permit the wellsite operator 195 utilizing the control workstation
350 to have an unobstructed or otherwise optimal view of the drill
string 120, the rig floor 114, and/or other portions of the well
construction system 100. The observation area 340 may also contain
a second control workstation 352 located adjacent (e.g., behind)
the first control workstation 350 and adjacent the window 325, but
not within the extended portion 342 of the observation area 340.
The control workstation 352 may be elevated at least partially
above the control workstation 350 to reduce the obstruction of view
caused by the control workstation 350 and, thus, permit the
wellsite operator 195 utilizing the control workstation 352 to view
the drill string 120, the rig floor 114, and/or other portions of
the well construction system 100 over the control workstation 350
via the front window 324. The control center 300 may also comprise
a third control workstation 354 located adjacent the control
workstations 350, 352 and adjacent the windows 321, 322, but not
within the observation area 340.
[0085] The control center 300 may further comprise a processing
device 356 (e.g., a controller, a computer, a server, etc.)
operable to provide control to one or more portions of the well
construction system 100 and/or operable to monitor operations of
one or more portions of the well construction system 100. For
example, the processing device 356 may be communicatively connected
with the various surface and downhole equipment described herein
and operable to receive signals from and transmit signals to such
equipment to perform various operations described herein. The
processing device 356 may store executable programs, instructions,
and/or operational parameters or set-points, including for
implementing one or more aspects of the operations described
herein. The processing device 356 may be communicatively connected
with the control workstations 350, 352, 354. Although the
processing device 356 is shown located within the facility 305, the
processing device 356 may be located outside of the facility 305.
Furthermore, although the processing device 356 is shown as a
single device that is separate and distinct from the control
workstations 350, 352, 354, one or more of the control workstation
350, 352, 354 may comprise a corresponding processing device 356
disposed in association with or forming at least a portion of such
corresponding processing device 356.
[0086] The control workstations 350, 352, 354 may be operable to
enter or otherwise communicate commands to the processing device
356 by the wellsite operator 195 and to display or otherwise
communicate information from the processing device 356 to the
wellsite operator 195. One or more of the control workstations 350,
352, 354 may comprise an operator chair 360 and an HMI system
comprising one or more input devices 362 (e.g., a keyboard, a
mouse, a joystick, a touchscreen, a microphone, etc.) and one or
more output devices 364 (e.g., a video monitor, a printer, audio
speakers, a touchscreen, etc.). The input and output devices 362,
364 may be disposed in association with and/or integrated with the
operator chair 360 to permit the wellsite operator 195 to enter
commands or other information to the processing device 356 and
receive information from the processing device 356 and other
portions of the well construction system 100. One or more of the
control workstations 350, 352, 354 may be or form at least a
portion of the control workstation 197 shown in FIG. 1, and the
processing device 356 may be or form at least a portion of the
processing device 192 shown in FIG. 1.
[0087] The control center 300 may further contain a BOP control
station 370 (e.g., control panel) of the WC system 217 operable to
monitor and control one or more portions of the WC system 217. For
example, the BOP control station 370 may be communicatively
connected with the BOP control unit 137 and the BOP equipment 130,
132, and operable to monitor and control operations of the BOP
control unit 137 and the BOP equipment 130, 132.
[0088] The BOP control station 370 may be operable communicate to
the BOP control unit 137 control commands entered by the wellsite
operator 195 for controlling the BOP equipment 130, 132 and to
display or otherwise communicate information indicative of
operational status of the BOP equipment 130, 132 and the BOP
control unit 137 to the wellsite operator 195. The BOP control
station 370 may comprise a processing device (e.g., processing
device 700 shown in FIG. 13) operable to store executable programs,
instructions, and/or operational parameters or set-points,
including for implementing one or more BOP operations described
herein. The BOP control station 370 may further comprise an HMI
system comprising one or more input devices 372 (e.g., buttons,
keys, a touchscreen, etc.) and one or more output devices 374
(e.g., a video monitor, gauges, audio speakers, a touchscreen,
etc.). The input and output devices 372, 374 may be disposed in
association with and/or integrated with a housing or enclosure of
the BOP control station 370 to permit the wellsite operator 195 to
enter commands or other information to the BOP control station 370
to control the BOP equipment 130, 132 and receive information from
the BOP control station 370 to monitor operational status of the
BOP equipment 130, 132.
[0089] The BOP control station 370 and the BOP control unit 137 may
be operatively connected via electrical, pneumatic, and/or
hydraulic means. For example, control commands entered by the
wellsite operator 195 via the input devices 372 may be transmitted
from the BOP control station 370 in the form of electrical,
pneumatic, and/or hydraulic control signals to operate various
portions (e.g., valves) of the BOP control unit 137 to control the
BOP equipment 130, 132. Feedback information indicative of
operational status of the BOP control unit 137 and the BOP
equipment 130, 132 may be transmitted in the form of electrical,
pneumatic, and/or hydraulic feedback signals from various sensors
of the BOP control unit 137 and the BOP equipment 130, 132. The
feedback information may be displayed to the wellsite operator 195
via the output devices 374 of the BOP control station 370. The BOP
control station 370 may comprise an intrinsically safe
construction, an explosion proof construction (e.g., Class 1
rating), a weatherproof construction, a dust and/or water proof
construction (e.g., IP66 rating, IP55 rating), and/or may be
certified for use in Zone 1, Zone 2, hazardous, and/or safe areas
of the wellsite. Although the BOP control station 370 is shown
located within the facility 305, the BOP control station 370 may be
located outside of the facility 305, such as on the rig floor 114
or the wellsite surface 104.
[0090] The BOP control unit 370 may be communicatively connected
with one or more of the control workstations 350, 352, 354, such as
may permit monitoring and control of one or more portions of the WC
system 217 via the control workstations 350, 352, 354. For example,
one or more of the control workstations 350, 352, 354 or the
processing device 356 may be communicatively connected directly
with the processing device of the BOP control station 370 or
indirectly, such as via the input and output devices 372, 374 of
the BOP control station 370. Such connection may permit the control
workstations 350, 352, 354 to receive information indicative of
operational status of the BOP control unit 137 and the BOP
equipment 130, 132 via the BOP control station 370. Such connection
may further permit the control workstations 350, 352, 354 to
transmit control commands to the BOP control unit 137 and the BOP
equipment 130, 132 via the BOP control station 370. Such connection
may also or instead facilitate control of the BOP control station
370 via the control workstations 350, 352, 354, such as may cause
the BOP control station 370 to control the BOP control unit 137 and
the BOP equipment 130, 132 as directed by or from the control
workstations 350, 352, 354.
[0091] The control workstations 350, 352, 354 may be operable to
display the information indicative of operational status of the BOP
control unit 137 and the BOP equipment 130, 132 to the wellsite
operator 195 via the output devices 364 to permit the wellsite
operator to monitor the operational status of the BOP control unit
137 and the BOP equipment 130, 132 while sitting in the
corresponding operator chair 360. The control workstations 350,
352, 354 may be further operable to receive the control commands
from the wellsite operator 195 via the input devices 362 while
sitting in the corresponding operator chair 360 for transmission to
the BOP control station 370 to control the BOP control unit 137 and
the BOP equipment 130, 132.
[0092] FIG. 6 is a top view of a portion of an example
implementation of a wellsite operator control workstation 400
communicatively connected with the processing device 192 and/or
other portions of the well construction system 100 according to one
or more aspects of the present disclosure. The control workstation
400 may facilitate display or output means showing various
information, such as sensor data, control data, processes taking
place, events being detected, and operational status of various
equipment of the subsystems 211-217 of the well construction system
100. The following description refers to FIGS. 1-6,
collectively.
[0093] The control workstation 400 comprises an operator chair 402
(e.g., driller's chair) and an HMI system comprising a plurality of
input and output devices integrated with, supported by, or
otherwise disposed in association with the operator chair 402. The
input devices permit the wellsite operator 195 to enter commands or
other information to the processing device 192, such as to control
the actuators of a selected one of the wellsite equipment of the
well construction system 100, and the output devices permit the
wellsite operator to receive information from the processing device
192 and other wellsite equipment. The operator chair 402 may
include a seat 404, a left armrest 406, and a right armrest
408.
[0094] The input devices of the control workstation 400 may include
a plurality of physical controls, such as a left joystick 410, a
right joystick 412, and/or other physical controls 414, 415, 416,
418, 420, such as buttons, switches, knobs, dials, slider bars, a
mouse, a keyboard, and a microphone. One or more of the joysticks
410, 412 and/or the physical controls 414, 415, 416 may be
integrated into or otherwise supported by the corresponding
armrests 406, 408 of the operator chair 402 to permit the wellsite
operator 195 to operate these input devices from the operator chair
404. Furthermore, one or more of the physical controls 418, 420 may
be integrated into the corresponding joysticks 410, 412 to permit
the wellsite operator 195 to operate these physical controls 418,
420 while operating the joysticks 410, 412. The physical controls
may comprise emergency stop (E-stop) buttons 415, which may be
electrically connected to E-stop relays of one or more pieces of
wellsite equipment (e.g., the iron roughneck 151, the PHM 163, the
drawworks 119, the top drive 116, etc.), such that the wellsite
operator 195 can shut down the wellsite equipment during
emergencies and other situations.
[0095] The output devices of the control workstation 400 may
include one or more video output devices 426 (e.g., video
monitors), printers, speakers, and other output devices disposed in
association with the operator chair 404 and operable to display to
the wellsite operator 195 information from the processing device
192 and other portions of the well construction system 100. The
video output devices may be implemented as one or more LCD
displays, LED displays, plasma displays, cathode ray tube (CRT)
displays, and/or other types of displays.
[0096] The video output devices 426 may be disposed in front of or
otherwise adjacent the operator chair 402. The video output devices
426 may include a plurality of video output devices 432, 434, 436,
each dedicated to displaying predetermined information in a
predetermined (e.g., programmed) manner. Although the video output
devices 426 are shown comprising three video output devices 432,
434, 436, the video output devices 426 may be or comprise one, two,
four, or more video output devices. As described below, different
portions of the video output devices 432, 434, 436 may be dedicated
to displaying predetermined information in a predetermined
manner.
[0097] One or more of the video output devices 426 may be operated
as both input and output devices. For example, the video output
devices 434, 436 may display information related to the control and
monitoring of the various subsystems 211-217 of the well
construction system 100. The video output devices 434, 436 may
further display sensor signals or information 440 generated by the
various sensors 221-227 of the well construction system 100 to
permit the wellsite operator 195 to monitor operational status of
the subsystems 211-217. The video output devices 434, 436 may also
display a plurality of software (e.g., virtual, computer generated)
buttons, icons, selection menus, switches, knobs, slide bars,
dials, or other software controls 442 displayed on the video output
devices 434, 436 to permit the wellsite operator 195 to control the
various actuators 231-237 or other portions of the subsystems
211-217. The software controls 442 may be operated by the physical
controls 414, 416, the joysticks 410, 412, or other input devices
of the control workstation 400.
[0098] One or more of the video output devices 426 may be
configured to display the video signals (i.e., video feeds)
generated by one or more of the video cameras 198. For example, the
video output device 432 may operate purely as an output device
dedicated for displaying the video signals generated by one or more
of the video cameras 198. When displaying the video signals from
multiple video cameras 198, the display screen of the video output
device 432 may be divided into or comprise multiple video windows,
each displaying a corresponding video signal. One or more of the
other video output devices 434, 436 may display an integrated
display screen displaying the sensor information 440, the software
controls 442, and the video signals from one or more of the video
cameras 198. For example, one or both of the display screens of the
video output devices 434, 436 may include one or more
picture-in-picture (PIP) video windows 444, each displaying a video
signal from a corresponding one of the video cameras 198. The PIP
video windows 444 may be embedded or inset on the corresponding
display screens along or adjacent the sensor information 440 and
the software controls 442. Sourcing (i.e., selection) of the video
cameras 198 whose video signals are to be displayed on the display
screens may be automated based on operational events (e.g.,
drilling events, drilling operation processes, etc.) at the well
construction system 100, such that video signals relevant to an
event currently taking place are displayed.
[0099] The control workstation 400 may further comprise combination
devices operable as both input and output devices to display
information to the wellsite operator 195 and receive commands or
information from the wellsite operator 195. Such devices may be or
comprise touchscreens 422, 424 (i.e., touchpads) operable to
display a plurality of software buttons, switches, knobs, dials,
icons, and/or other software controls 428, 430 permitting the
wellsite operator 195 to operate (e.g., click, selected, move) the
software controls 428, 430 via finger contact with the touchscreens
422, 424. The software controls 428, 430 and/or other features
displayed on the touchscreens 422, 424 may also display operational
settings, set-points, and/or status of selected subsystems 211-217
for viewing by the wellsite operator 195. For example, the software
controls 428, 430 may change color, move in position or direction,
and/or display the set-points or operational values (e.g.,
temperature, pressure, position). The touchscreens 422, 424 may be
disposed on or integrated into the armrests 406, 408 or other parts
of the operator chair 404 to permit the wellsite operator 195 to
operate the software controls 428, 430 displayed on the
touchscreens 422, 424 from the operator chair 404.
[0100] Selected sensor data may be shown to the wellsite operator
195 via multiple display screens (i.e., an integrated display
system) displayed on the video output devices 426 and/or the
touchscreens 422, 424. Each display screen may display information
related to one or more of the subsystems 211-217. Each display
screen may integrate the software controls 428, 430, 442, selected
sensor data 251-257, 440 from the corresponding subsystems 211-217,
and information from the monitoring process 274, the control
process 275, and/or the control data 261-267, 273 generated by the
processing devices/controllers 192, 205, 241-247 for the wellsite
operator 195. Accordingly, each display screen may be utilized to
control operation of the subsystems 211-217 associated with the
display screen. The display screens may be shown or displayed
alternately on one or more of the video output devices 426 and/or
the touchscreens 422, 424 or simultaneously on one or more of these
devices. The display screens intended to be displayed on the video
output devices 426 and/or the touchscreens 422, 424 may be selected
by the wellsite operator 195 via the physical 414, 416, 418, 420
and/or software controls 428, 430, 442. The display screen intended
to be displayed on the video output devices 426 and/or the
touchscreens 422, 424 may also or instead be selected automatically
by the monitoring process 274 based on operational events detected
or planned at the well construction system 100 (e.g., a drilling
process or event), such that information relevant to an event
currently taking place is displayed.
[0101] The control workstation 400 may also be utilized by the
wellsite operator 195 to control the subsystems 211-217 or other
wellsite equipment of the well construction system 100. For
example, the control workstation 400 may display on one or more of
the video output devices 426 and/or the touchscreens 422, 424 one
or more configuration display screens or menus (i.e., computer
programs), which may be utilized to set, adjust, configure or
otherwise control the subsystems 211-217 or other wellsite
equipment. The configuration display screens or menus may be
displayed on the touchscreens 422, 424 to permit the wellsite
operator 195 to operate the displayed software controls 428, 430
via finger contact with the touchscreens 422, 424 from the operator
chair 404.
[0102] FIGS. 7-9 are example implementations of software controls
452, 454, 456 that may be displayed on the video output devices 426
and/or the touchscreens 422, 424 and operated by the wellsite
operator 195 to configure or otherwise control various portions of
the well construction system 100, including the subsystems 211-217.
The software controls 452, 454, 456 may be pressed, clicked,
selected, or otherwise operated via the physical controls 414, 416
and/or, when displayed on the touchscreens 422, 424, via finger
contact by the wellsite operator 195 to increase, decrease, change,
or otherwise enter operational parameters, set-points, and/or
instructions for controlling one or more portions of the well
construction system 100 associated with the software controls 452,
454, 456. The software controls 452, 454, 456 may also display the
entered and/or current operational parameters on or in association
with the software controls 452, 454, 456 for viewing by the
wellsite operator 195. The operational parameters, set-points,
and/or instructions associated with the software controls 452, 454,
456 may include equipment operational status (e.g., on or off, up
or down, set or release, position, speed, temperature, etc.),
drilling parameters (e.g., depth, hook load, torque, etc.),
auxiliary parameters (e.g., vibration data of a pump), and fluid
parameters (e.g., flow rate, pressure, temperature, etc.), among
other examples.
[0103] The software controls 452 may be or comprise software
buttons, which may be operated to increase, decrease, change, or
otherwise enter different operational parameters, set-points,
and/or instructions for controlling one or more portions of the
well construction system 100 associated with the software controls
452. The software controls 454 may be or comprise a list or menu of
items (e.g., equipment, processes, operational stages, equipment
subsystems, etc.) related to one or more aspects of the well
construction system 100, which may be operated to select one or
more items on the list. The selected items may be highlighted,
differently colored, or otherwise indicated, such as via a
checkmark, a circle, or a dot appearing in association with the
selected item. The software controls 456 may be or comprise a
combination of different software controls, which may be operated
to increase, decrease, change, or otherwise enter different
operational parameters, set-points, and/or instructions for
controlling one or more portions of the well construction system
100 associated with the software controls 456, such as a pump of
the well construction system 100. The software controls 456 may
include a slider bar 453, which may be moved or otherwise operated
to increase, decrease, or otherwise change pump speed or another
operational parameter associated with the slider bar 453. The
entered pump speed may be shown in a display window 455. The
software controls 456 may also include software buttons 457, such
as may be operated to start, pause, and stop operation of the pump
or another portion of the well construction system 100 associated
with the software buttons 457.
[0104] FIGS. 10 and 11 are views of example implementations of
display screens 502, 504 generated by the processing device 356
(e.g., wellsite computing resource environment 205) and displayed
on one or more of the video output devices 426 according to one or
more aspects of the present disclosure. The example display screen
502 displays various sensor information and software controls
related to the control and monitoring of the WC system 217, such as
the BOP equipment 130, 132 and the BOP control unit 137, and other
sensor information and software controls related to operational
status of the drilling operations. The example display screen 504
displays various sensor information and software controls related
to the control and monitoring of the CPC system 216, and other
sensor information and software controls related to operational
status of the drilling operations.
[0105] The display screens, including the display screens 502, 504,
may comprise a wellsite subsystem selector/indicator window or area
506, which may be utilized to switch between or select which one or
more of the display screens are being displayed on the video output
device. The selector/indicator area 506 may be continuously
displayed regardless of which display screen is being shown on the
video output device. The area 506 may comprise a subsystem
selection menu 508, such as a plurality of indicator bars, tabs, or
buttons, each listing a subsystem 211-217 of the well construction
system 100. The wellsite operator 195 may operate (e.g., click on,
touch, highlight, and/or otherwise select) one of the buttons to
select and view the display screen and the associated subsystem
information. The button associated with the selected subsystem
211-217 may light up, change color, and/or otherwise indicate which
display screen and, thus, subsystem 211-217, is being shown. The
selector/indicator area 506 may also include a SAFETY button, which
may be selected to show the display screen with status of various
safety equipment of the well construction system 100. Although the
subsystem selection menu 508 is shown as a list that is permanently
maintained on the display screens 502, 504, the subsystem selection
menu 508 may be implemented as a dropdown or pop-up menu,
displaying a list of subsystems 211-217 when clicked on or
otherwise operated.
[0106] The selector/indicator area 506 may also include a plurality
of alarms or event indicators 510 (e.g., lights), each associated
with a corresponding subsystem selection button. The monitoring
process 274 may activate (e.g., light up, change color, etc.) one
or more of the event indicators 510 to show or alarm the wellsite
operator 195 of an operational event at or associated with a
corresponding subsystem 211-217 that may be associated with a
predetermined corrective action or another action by the wellsite
operator 195. Responsive to the event indicator 510 being
activated, the wellsite operator 195 may switch to a display screen
corresponding to the activated event indicator to assess the event
and/or implement appropriate counteractive measures or actions.
Instead of manually changing between the display screens, the
processing device 192 may automatically change the display screen
to show the display screen corresponding to a subsystem 211-217
experiencing the event.
[0107] The display screens, including the display screens 502, 504,
may further comprise a driller information window or area 512
displaying selected sensor data 251-257 or information related to
status of drilling operations. For example, the area 512 may
include selected sensor data 251 from the RC system 211, selected
sensor data 252 from the FC system 212, and/or selected sensor data
from the WC system 217. The area 512 may display information such
as hook load, traveling block position, drill bit depth, wellbore
depth, number of stands or tubulars in the wellbore, standpipe
pressure, top drive dolly location, inside BOP position, top drive
pipe connection status, elevator status, stickup connection status,
and slips status. The area 512 may be continuously displayed
regardless of which display screen is being shown on the video
output device.
[0108] Each display screen, including the display screens 502, 504,
may further comprise a corresponding subsystem information window
or area 514, 518, respectively, displaying selected sensor data
251-257 or information related to a subsystem 211-217 being shown
on the display screen. The information displayed in the area 514,
518 may switch when the wellsite operator 195 or the processing
device 192 switches between the display screens of the integrated
display.
[0109] As described above, the control station 370 may be
communicatively connected with and operable to control the BOP
control unit 137 and the BOP equipment 130, 132. The operator
control workstation 400 may be communicatively connected with the
BOP control station 370, such as may permit the operator control
workstation 400 to receive information from and transmit control
commands to the BOP control station 370, which in turn receives
information from and transmits corresponding control commands to
the BOP control unit 137 and the BOP equipment 130, 132,
facilitating control of the BOP control unit 137 and the BOP
equipment 130, 132 from the operator control workstation 400.
[0110] For example, when the wellsite operator 195 operates in the
subsystem selection menu 508 a software button marked with "WC"
associated with the WC system 217, the subsystem information area
514 may display selected information related to the WC system 217.
The information area 514 may display a schematic view 515 of the
BOP equipment 130, 132 and a plurality of status bars 516
indicative of status of corresponding portions of the BOP equipment
130, 132. The status bars 516 may display sensor data 257 showing
operational parameters of the BOP equipment 130, 132, such as
pressure, temperature, and position (e.g., open, closed). The
information area 514 may further show the sensor data 257 of the WC
system 217 in table or list form. One or more operational
parameters (e.g., preventer position) of the WC system 217 may be
changed, for example, by entering in the status bars 516 or on the
list 257 the intended values of the one or more operational
parameters, causing the processing device 356 to transmit
corresponding control data 267 to the BOP control station 370
(e.g., controller 247) of the WC system 217 to change the
operational parameters as intended. The sensor data 257 generated
by the BOP control unit 137 and the BOP equipment 130, 132 may be
transmitted from the BOP control station 370 to the operator
control workstation 400 for display on the display screen 502.
[0111] The operator control workstation 400 may be further operable
to receive and display different information from the BOP control
station 370 or display different display screens (not shown)
containing different information from the BOP control station 370,
such as may permit the wellsite operator 154 to monitor and control
other aspects of the WC system 217. For example, the operator
control workstation 400 may display in the subsystem information
area 514 different information related to the WC system 217, such
as information related to a riser/diverter, pod controls, pod
regulators, analog sensor values, BOP event alarm signals, and
inclination sensors of the WC system 217. The operator control
workstation 400 may be further operable to receive and display on
one or more of the video output devices 426 or the touchscreens
422, 424 the same information displayed on the output devices 374
of the BOP control station 370. The operator control workstation
400 may also or instead be operable to mirror or otherwise
duplicate on one or more of the video output devices 426 or the
touchscreens 422, 424 the actual display screen(s) displayed on the
output devices 374 of the BOP control station 370.
[0112] When the wellsite operator 195 operates in the subsystem
selection menu 508 a software button marked with "CPC" associated
with the CPC system 216, the subsystem information area 518 may
display selected information related to the CPC system 216. The
subsystem information area 518 may display a schematic view 519 of
the choke manifold 162 and a plurality of status bars 520
indicative of status of corresponding portions of the choke
manifold 162. The status bars 520 may display sensor data 256
showing operational parameters of the CPC system 216, such as flow,
pressure, temperature, and position. The area 518 may further show
the sensor data 256 of the CPC system 216 in table or list form.
One or more operational parameters of the CPC system 216 may be
changed, for example, by entering in the status bars 520 or on the
list the intended values of the one or more operational parameters,
causing the coordinated control device 204 to transmit
corresponding control data 266 to the controller 246 of the CPC
system 216 to change the operational parameters as intended.
[0113] Each display screen, including the display screens 502, 504,
may further include one or more PIP video windows 522, each
displaying in real-time a video signal from a predetermined video
camera 198 to display a predetermined portion of the well
construction system 100, a predetermined one of the subsystems
211-217, and/or predetermined wellsite equipment associated with
the subsystem 211-217 selected in the subsystem selection menu 508
and/or associated with the information shown in the subsystem
information area 514, 518. The PIP video windows 522 may be
embedded or inset on the corresponding display screens 502, 504
along or adjacent the sensor information and the software controls
displayed on the display screens 502, 504. The view shown in the
PIP video window 522 may be switched between different video
cameras 198. For example, the PIP video window 522 of the display
screen 502 may show a real-time view of the BOP stack 130 and the
PIP video window 522 of the display screen 504 may show a real-time
view of the choke manifold 162.
[0114] Each display screen, including the display screens 502, 504,
may also comprise an event description window or area 524 listing
and/or describing one or more operational events taking place at
the well construction system 100. The event description area 524
may also list and/or describe one or more counteractive measures
(e.g., corrective actions, operational sequences) related to the
event that may be performed or otherwise implemented in response to
the event. Depending on the event and/or mode (e.g., advice,
interlock, automated) in which the coordinated control device 204
is operating, the processing device 192 may just describe the
corrective action within the event description area 524, and the
wellsite operator 195 may implement such corrective action.
However, the processing device 192 may automatically implement the
corrective action, or cause the corrective action to be
automatically implemented, such as by transmitting predetermined
control data 261-267 to the controller 241-247 of the corresponding
subsystem 211-217.
[0115] The information displayed in the area 524 may just display
events and/or corrective actions related to the display screen and
the subsystem 211-217 being viewed and, thus, change when switching
between the display screens of the integrated display. However, the
information displayed in the area 524 may not change when switching
between the display screens, and may list events and/or corrective
actions related to each subsystem 211-217, such as in chronological
order or in the order of importance. As described above, the
coordinated control device 204 or another portion of the processing
device 192 may automatically change the display screen to show the
subsystem 211-217 experiencing the event and the corresponding
description and/or corrective action related to the event.
[0116] Each display screen, including the display screens 502, 504,
may be adjusted or otherwise configured by the wellsite operator
195 to display one or more of the various information windows or
areas in an intended position on each display screen. For example,
the selector/indicator area 506 may be displayed at the bottom of
the display screens 502, 504, the event description area 524 may be
displayed at the top of the display screens 502, 504, and the
driller information area 512 may be displayed on the left side of
the display screens 502, 504. Furthermore, the location and/or size
(i.e., dimensions) of the PIP video windows 522 displayed on each
display screen, including the display screens 502, 504, may also be
adjusted or otherwise selected. The placement of the various
information windows or areas and the PIP video windows 522 on the
display screens may be moved or selected, for example, via one or
more of the physical controls physical controls 414, 416, 418, 420,
such as by entering an intended location of the information areas
and PIP video windows 522 or by dragging the information areas and
PIP video windows 522 to an intended location on the display
screens.
[0117] FIG. 12 is a schematic view of at least a portion of an
example implementation of a wellsite control system 600 for
controlling the well construction system 100 according to one or
more aspects of the present disclosure. The control system 600 may
comprise at least a portion of one or more implementations of one
or more instances of the apparatus shown in one or more of FIGS.
1-11 and/or otherwise within the scope of the present disclosure.
Accordingly, the following description refers to FIGS. 1-12,
collectively.
[0118] The wellsite control system 600 may comprise a wellsite
control station 602 (e.g., operator control workstation 197, 350,
352, 354, 400) communicatively connected with and operable to
control drilling rig equipment 604 (e.g., subsystems 211-216) of
the wellsite construction system 100 to drill a wellbore 102 within
a subterranean formation 106 at an oil and gas wellsite 104. The
wellsite control station 602 may be in communication with various
sensors (e.g., sensors 221-226), actuators (e.g., actuators
231-236), controllers (e.g., local controllers 241-246), and other
devices of the subsystems 211-216 to control operations associated
with the subsystems 211-216.
[0119] The wellsite control station 602 may be communicatively
connected with one or more portions of the WC system 217 to
facilitate control of the WC system 217 via the wellsite control
station 602. The WC system 217 may comprise a BOP control station
606 (e.g., BOP control station 370) communicatively connected with
and operable to control other portions of the WC system 217,
including a BOP control unit 608 (e.g., BOP control unit 137) and
BOP equipment 610 (e.g., BOP equipment 130, 132) for controlling
pressure within the wellbore 102. The BOP control unit 608 may be
operatively (e.g., fluidly) connected with the BOP equipment 610,
such as may permit the BOP control unit 608 to selectively actuate,
drive, or otherwise power various portions of the BOP equipment
610. The BOP control station 606 may be in communication with
various sensors (e.g., sensors 227), actuators (e.g., actuators
237), controllers (e.g., controllers 247), and other devices of the
WC system 217 to monitor operational status of the WC system 217.
For example, the BOP control station 606 may be communicatively
connected with various actuators (e.g., valves) of the BOP control
unit 608 to actuate or otherwise operate various actuators (e.g.,
hydraulic cylinders) of the BOP equipment 610 and, thus, control
the BOP equipment 610. The BOP control station 606 may also be
communicatively connected with various sensors of the BOP control
unit 608 and the BOP equipment 610 to receive information
indicative of operational status (e.g., position, pressure) of the
BOP control unit 608 and the BOP equipment 610.
[0120] The wellsite control station 602 and the BOP control station
606 may be communicatively connected together, such as may permit
the wellsite control station 602 to control the BOP control station
606 to control the BOP control unit 608 and BOP equipment 610. Such
communicative connection may also or instead permit the wellsite
control station 602 to communicate with and control the BOP control
unit 608 and BOP equipment 610 via the BOP control station 606.
Accordingly, the wellsite control station 602 may be operated by a
wellsite operator 195 to control the drilling rig equipment 604 and
the BOP equipment 610.
[0121] The wellsite control station 602 may be operable to receive
sensor signals or information (e.g., sensor data 257) indicative of
operational status of the BOP equipment 610 and BOP control unit
608 via the BOP control station 606 to monitor the BOP equipment
610 and BOP control unit 608, and to receive sensor signals or
information (e.g., sensor data 251-256) indicative of operational
status of the drilling rig equipment 604 to monitor the drilling
rig equipment 604. The wellsite control station 602 may be further
operable to transmit control commands (e.g., control data 267) to
the BOP equipment 610 and BOP control unit 608 via the BOP control
station 606 to control the BOP equipment 610 and BOP control unit
608, and transmit control commands (e.g., control data 261-266) to
the drilling rig equipment 604 to control the drilling rig
equipment 604.
[0122] The control commands transmitted to the BOP control unit 608
and the BOP equipment 610 via the BOP control station 606 may be
based, at least in part, on the sensor signals or information
indicative of operational status (e.g., events described above in
association with FIG. 3) of the BOP equipment 610 and BOP control
unit 608 and/or on the sensor signals or information indicative of
operational status (e.g., events) of the drilling rig equipment
604. Similarly, the control commands transmitted to the drilling
rig equipment 604 may be based, at least in part, on the sensor
signals or information indicative of operational status of the BOP
equipment 610 and BOP control unit 608 and/or on the sensor signals
or information indicative of operational status of the drilling rig
equipment 604. Example control commands for controlling the BOP
equipment 610 and/or the drilling rig equipment 604 based on sensor
signals or information are described above in association with FIG.
3.
[0123] The BOP control station 606 may comprise one or more input
devices 612 (e.g., input devices 372), such as may be utilized by
the wellsite operator 195 to enter the control commands for
controlling the BOP control unit 608 and the BOP equipment 610. The
BOP control station 605 may further comprise one or more output
devices 614 (e.g., output devices 374), such as may be operable to
display to the wellsite operator 195 the sensor signals or
information indicative of the operational status of the BOP control
unit 608 and the BOP equipment 610.
[0124] The wellsite control station 602 may comprise one or more
input devices 616 (e.g., input devices 194, 414, 416, 418, 422,
424), such as may be utilized by the wellsite operator 195 to enter
the control commands for controlling the drilling rig equipment
604, the BOP control unit 608, and/or the BOP equipment 610. The
wellsite control station 602 may further comprise one or more
output devices 618 (e.g., output devices 196, 422, 424, 426), such
as may be operable to display to the wellsite operator 195 the
sensor signals or information indicative of the operational status
of the drilling rig equipment 604, the BOP control unit 608, and/or
the BOP equipment 610. The wellsite control station 602 may be
operable to receive and display on the output device 618 the sensor
signals or information displayed by the BOP control station 606 on
the output device 612. The control commands for controlling the BOP
control unit 608, the BOP equipment 610, and drilling rig equipment
604 may be entered into the well site control station 602 by the
wellsite operator 195, for example, while operating the coordinated
control device 204 of the wellsite control station 602 in the
advice mode, as described above in association with FIG. 3.
[0125] Instead of or in addition to receiving control commands from
the wellsite operator 195 to control the drilling rig equipment
604, the BOP control unit 608, and/or the BOP equipment 610, the
wellsite control station 602 may be operable to automatically
generate control commands based on computer program code and the
sensor signals or information indicative of the operational status
of the drilling rig equipment 604, the BOP control unit 608, and/or
the BOP equipment 610 to automatically control operations of one or
more of the drilling rig equipment 604, the BOP control unit 608,
and/or the BOP equipment 610. The control commands for controlling
the BOP control unit 608, the BOP equipment 610, and drilling rig
equipment 604 may be generated automatically by the wellsite
control station 602, for example, while operating the coordinated
control device 204 in the interlock mode or automated sequence
mode, as described above in association with FIG. 3.
[0126] The wellsite and BOP control stations 602, 606 may be
disposed within or form at least a portion of a wellsite control
center (e.g., control center 190, 300). The input and output
devices 616, 618 of the wellsite control station 602 may be or
comprise one or more touchscreens (e.g., touchscreens 422, 424)
mounted to, carried by, or otherwise disposed in association with a
driller's chair (e.g., chair 402) within the control center, such
as may permit the wellsite operator 195 to control the drilling rig
equipment 604, the BOP control unit 608, and/or the BOP equipment
610 while sitting in the driller's chair.
[0127] FIG. 13 is a schematic view of at least a portion of an
example implementation of a processing device 700 according to one
or more aspects of the present disclosure. The processing device
700 may form at least a portion of one or more electronic devices
utilized at the well construction system 100. For example, the
processing device 700 may be or form at least a portion of the
processing devices 188, 192, 356, the BOP control station 370, and
the control workstations 350, 352, 354, 400. The processing device
700 may form at least a portion of the control system 200,
including the wellsite computing resource environment 205, the
coordinated control device 204, the supervisory control system 207,
the local controllers 241-247, the onsite user devices 202, and the
offsite user devices 203. The processing device 700 may form at
least a portion of the control system 600, including the wellsite
and BOP control stations 602, 606.
[0128] The processing device 700 may be in communication with
various sensors, actuators, controllers, and other devices of the
subsystems 211-217 and/or other portions of the well construction
system 100. The processing device 700 may be operable to receive
coded instructions 742 from the wellsite operators 195 via the
wellsite control station 602 and the sensor data 251-257 generated
by the sensors 221-227, process the coded instructions 742 and the
sensor data 251-257, and communicate the control data 261-267 to
the local controllers 241-247 and/or the actuators 231-237 of the
subsystems 211-217 to execute the coded instructions 742 to
implement at least a portion of one or more example methods and/or
operations described herein, and/or to implement at least a portion
of one or more of the example systems described herein.
[0129] The processing device 700 may be or comprise, for example,
one or more processors, special-purpose computing devices, servers,
personal computers (e.g., desktop, laptop, and/or tablet
computers), personal digital assistants, smartphones, internet
appliances, and/or other types of computing devices. The processing
device 700 may comprise a processor 712, such as a general-purpose
programmable processor. The processor 712 may comprise a local
memory 714, and may execute coded instructions 742 present in the
local memory 714 and/or another memory device. The processor 712
may execute, among other things, the machine-readable coded
instructions 742 and/or other instructions and/or programs to
implement the example methods and/or operations described herein.
The programs stored in the local memory 714 may include program
instructions or computer program code that, when executed by the
processor 712 of the processing device 700, may cause the
subsystems 211-217 of the well construction system 100 to perform
the example methods and/or operations described herein. The
processor 712 may be, comprise, or be implemented by one or more
processors of various types suitable to the local application
environment, and may include one or more of general-purpose
computers, special-purpose computers, microprocessors, digital
signal processors (DSPs), field-programmable gate arrays (FPGAs),
application-specific integrated circuits (ASICs), and processors
based on a multi-core processor architecture, as non-limiting
examples. Of course, other processors from other families are also
appropriate.
[0130] The processor 712 may be in communication with a main memory
717, such as may include a volatile memory 718 and a non-volatile
memory 720, perhaps via a bus 722 and/or other communication means.
The volatile memory 718 may be, comprise, or be implemented by
random access memory (RAM), static random access memory (SRAM),
synchronous dynamic random access memory (SDRAM), dynamic random
access memory (DRAM), RAMBUS dynamic random access memory (RDRAM),
and/or other types of random access memory devices. The
non-volatile memory 720 may be, comprise, or be implemented by
read-only memory, flash memory, and/or other types of memory
devices. One or more memory controllers (not shown) may control
access to the volatile memory 718 and/or non-volatile memory
720.
[0131] The processing device 700 may also comprise an interface
circuit 724. The interface circuit 724 may be, comprise, or be
implemented by various types of standard interfaces, such as an
Ethernet interface, a universal serial bus (USB), a third
generation input/output (3GIO) interface, a wireless interface, a
cellular interface, and/or a satellite interface, among others. The
interface circuit 724 may also comprise a graphics driver card. The
interface circuit 724 may also comprise a communication device,
such as a modem or network interface card to facilitate exchange of
data with external computing devices via a network (e.g., Ethernet
connection, digital subscriber line (DSL), telephone line, coaxial
cable, cellular telephone system, satellite, etc.). One or more of
the local controllers 241-247, the sensors 221-227, and the
actuators 231-237 may be connected with the processing device 700
via the interface circuit 724, such as may facilitate communication
between the processing device 700 and the local controllers
241-247, the sensors 221-227, and/or the actuators 231-237.
[0132] One or more input devices 726 may also be connected to the
interface circuit 724. The input devices 726 may permit the
wellsite operators 195 to enter the coded instructions 742, such as
control commands, processing routines, and/or operational settings
and set-points. The input devices 726 may be, comprise, or be
implemented by a keyboard, a mouse, a joystick, a touchscreen, a
track-pad, a trackball, an isopoint, and/or a voice recognition
system, among other examples. One or more output devices 728 may
also be connected to the interface circuit 724. The output devices
728 may be, comprise, or be implemented by video output devices
(e.g., an LCD, an LED display, a CRT display, a touchscreen, etc.),
printers, and/or speakers, among other examples. The processing
device 700 may also communicate with one or more mass storage
devices 740 and/or a removable storage medium 744, such as may be
or include floppy disk drives, hard drive disks, compact disk (CD)
drives, digital versatile disk (DVD) drives, and/or USB and/or
other flash drives, among other examples.
[0133] The coded instructions 742 may be stored in the mass storage
device 740, the main memory 717, the local memory 714, and/or the
removable storage medium 744. Thus, the processing device 700 may
be implemented in accordance with hardware (perhaps implemented in
one or more chips including an integrated circuit, such as an
ASIC), or may be implemented as software or firmware for execution
by the processor 712. In the case of firmware or software, the
implementation may be provided as a computer program product
including a non-transitory, computer-readable medium or storage
structure embodying computer program code (i.e., software or
firmware) thereon for execution by the processor 712. The coded
instructions 742 may include program instructions or computer
program code that, when executed by the processor 712, may cause
the various subsystems 211-217 of the well construction system 100
to perform intended methods, processes, and/or operations disclosed
herein.
[0134] The foregoing outlines features of several embodiments so
that a person having ordinary skill in the art may better
understand the aspects of the present disclosure. A person having
ordinary skill in the art should appreciate that they may readily
use the present disclosure as a basis for designing or modifying
other processes and structures for carrying out the same purposes
and/or achieving the same advantages of the embodi