U.S. patent application number 16/723582 was filed with the patent office on 2021-06-24 for reducing effects of rig noise on telemetry.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Pavel Annenkov, Shunfeng Zheng.
Application Number | 20210189869 16/723582 |
Document ID | / |
Family ID | 1000004626269 |
Filed Date | 2021-06-24 |
United States Patent
Application |
20210189869 |
Kind Code |
A1 |
Zheng; Shunfeng ; et
al. |
June 24, 2021 |
Reducing Effects of Rig Noise on Telemetry
Abstract
Apparatus and methods for reducing effects of rig noise on
telemetry. A method may include commencing operation of a telemetry
system of a drilling rig and commencing operation of an equipment
controller of the drilling rig. Commencing operation of the
equipment controller may cause the equipment controller to
automatically output control commands to automatically change
operational parameters of the telemetry system and/or rig equipment
of the drilling rig to reduce interference by rig noise with a
telemetry signal.
Inventors: |
Zheng; Shunfeng; (Katy,
TX) ; Annenkov; Pavel; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000004626269 |
Appl. No.: |
16/723582 |
Filed: |
December 20, 2019 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 44/02 20130101;
E21B 47/13 20200501; E21B 47/18 20130101 |
International
Class: |
E21B 47/13 20120101
E21B047/13; E21B 47/18 20120101 E21B047/18; E21B 44/02 20060101
E21B044/02 |
Claims
1. An apparatus comprising: a telemetry system of a drilling rig,
wherein the telemetry system comprises: a transmitter carried by a
drill string and operable to transmit a telemetry signal; and a
receiver included in surface equipment of the drilling rig and
operable to generate an output signal comprising: a telemetry
signal signature based on the telemetry signal; and a rig noise
signature based on rig noise generated by rig equipment of the
drilling rig; and an equipment controller comprising a processor
and a memory storing computer program code, wherein the equipment
controller is operable to automatically reduce interference by the
rig noise with the telemetry signal by outputting control commands
to change operational parameters of the rig equipment and/or the
telemetry system.
2. The apparatus of claim 1 wherein the telemetry signal comprises
at least one of a mud-pulse telemetry signal and electromagnetic
telemetry signal.
3. The apparatus of claim 1 wherein the telemetry signal signature
is indicative of frequency of the telemetry signal and the rig
noise signature is indicative of frequency of the rig noise.
4. The apparatus of claim 1 wherein: the receiver is or comprises a
pressure sensor; the telemetry signal comprises pressure
fluctuations propagating through drilling fluid flowing within the
drill string and the surface equipment; the receiver is further
operable to receive the telemetry signal and the rig noise; and the
output signal is an electrical signal comprising the telemetry
signal signature and the rig noise signature.
5. The apparatus of claim 1 wherein: the receiver is or comprises
an electromagnetic signal sensor; the telemetry signal comprises an
electromagnetic signal transmitted through rock formation extending
between the transmitter and the receiver; the receiver is further
operable to receive the telemetry signal and the rig noise; and the
output signal is an electrical signal comprising the telemetry
signal signature and the rig noise signature.
6. The apparatus of claim 1 wherein changing the operational
parameters of the rig equipment comprises changing the operational
parameters of the rig equipment such that a frequency range of the
rig noise signature does not overlap with a frequency range of the
telemetry signal signature.
7. The apparatus of claim 1 wherein changing the operational
parameters of the rig equipment comprises changing starting and/or
stopping operating time of the rig equipment such that operation of
the rig equipment that generates the rig noise that interferes with
the telemetry signal does not happen at the same time as operation
of the telemetry system.
8. The apparatus of claim 1 wherein changing the operational
parameters of the telemetry system comprises changing the
operational parameters of the telemetry system such that an
operating frequency range of the telemetry system does not overlap
with a frequency range of the rig noise signature.
9. The apparatus of claim 1 wherein changing the operational
parameters of the telemetry system comprises changing starting
and/or stopping operating time of the telemetry system such that
operation of the telemetry system does not happen at the same time
as operation of the rig equipment that generates the rig noise that
interferes with the telemetry signal.
10. The apparatus of claim 1 wherein the equipment controller is
further operable to store associations between each instance of the
rig equipment and a corresponding instance of the rig noise
signature caused by each instance of the rig equipment, and wherein
the equipment controller is operable to output control commands to
an instance of the rig equipment to reduce a corresponding instance
of the rig noise and thereby reduce interference of the rig noise
with the telemetry signal based on the stored associations.
11. The apparatus of claim 10 wherein the equipment controller is
further operable to store a digital well construction plan for
operating the telemetry system and the rig equipment to construct a
well, and wherein the equipment controller is further operable to
change the digital well constriction plan and thereby reduce
interference of the rig noise with the telemetry signal based on
the stored associations.
12. The apparatus of claim 1 wherein the equipment controller is
further operable to store a digital plan for operating the
telemetry system and the rig equipment to construct a well, and
wherein the equipment controller is further operable to change the
digital plan to reduce interference of the rig noise with the
telemetry signal.
13. The apparatus of claim 12 wherein changing the digital plan to
reduce interference of the rig noise with the telemetry signal
comprises changing starting and/or stopping operating time of the
rig equipment such that operation of the rig equipment that
generates the rig noise that interferes with the telemetry signal
does not happen at the same time as operation of the telemetry
system.
14. A method comprising: commencing operation of a telemetry system
of a drilling rig; and commencing operation of an equipment
controller of the drilling rig, thereby causing the equipment
controller to output control commands to change operational
parameters of the telemetry system and/or rig equipment of the
drilling rig to reduce interference by rig noise with a telemetry
signal.
15. The method of claim 14 wherein commencing operation of the
telemetry system of the drilling rig causes: the telemetry signal
to be transmitted by a transmitter carried by a drill string; and
an output signal to be generated by a receiver included in surface
equipment of the drilling rig, wherein the output signal comprises:
a telemetry signal signature based on the telemetry signal; and a
rig noise signature based on the rig noise generated by the rig
equipment of the drilling rig.
16. The method of claim 15 wherein the equipment controller is
operable to store associations between each instance of the rig
equipment and a corresponding instance of the rig noise signature
caused by each instance of the rig equipment, and wherein
commencing operation of the equipment controller causes the
equipment controller to output control commands to an instance of
the rig equipment to reduce a corresponding instance of the rig
noise and thereby reduce interference by the rig noise with the
telemetry signal based on the stored associations.
17. The method of claim 14 wherein the equipment controller is
operable to store a digital plan for operating the telemetry system
and the rig equipment to construct a well, and wherein commencing
operation of the equipment controller causes the equipment
controller to change the digital plan to reduce interference of the
rig noise with the telemetry signal.
18. A method comprising: commencing operation of a telemetry system
a drilling rig; and manually operating a control workstation of the
drilling rig by a rig personnel to change operational parameters of
the rig equipment and/or the telemetry system to reduce
interference by rig noise with a telemetry signal.
19. The method of claim 18 wherein: commencing operation of the
telemetry system of the drilling rig causes: the telemetry signal
to be transmitted by a transmitter carried by a drill string; and
an output signal to be generated by a receiver included in surface
equipment of the drilling rig, wherein the output signal comprises:
a telemetry signal signature based on the telemetry signal; and a
rig noise signature based on rig noise generated by rig equipment
of the drilling rig; and the method further comprises commencing
operation of a processing device of the drilling rig, thereby
causing the telemetry signal signature and the rig noise signature
to be displayed by the processing system on a video output device
for viewing by rig personnel; and manually operating the control
workstation of the drilling rig by the rig personnel to reduce
interference by the rig noise with the telemetry signal is based on
the displayed telemetry signal signature and the rig noise
signature.
20. The method of claim 19 wherein the processing device is
operable to store associations between each instance of the rig
equipment and a corresponding instance of the rig noise signature,
and wherein commencing operation of the processing device further
causes the associations between each instance of the rig equipment
and the corresponding instance of the rig noise signature to be
displayed on the video output device for viewing by the rig
personnel.
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 rock formations. Well construction (e.g.,
drilling) operations may be performed at a wellsite by a well
construction system (e.g., a drilling rig) having various surface
and subterranean well construction equipment (e.g., rig equipment)
operating in a coordinated manner. For example, a drive mechanism,
such as a top drive located at a wellsite surface, can be utilized
to rotate and advance a drill string into a subterranean rock
formation to drill a wellbore. The drill string may include a
plurality of drill pipes coupled together and terminating with a
drill bit. Length of the drill string may be increased by adding
additional drill pipes while depth of the wellbore increases.
Drilling fluid may be pumped from the wellsite surface down through
the drill string to the drill bit. The drilling fluid lubricates
and cools the drill bit, and carries drill cuttings from the
wellbore back to the wellsite surface. The drilling fluid returning
to the surface may then be cleaned and again pumped through the
drill string. The equipment of the well construction system may be
grouped into various subsystems, wherein each subsystem performs a
different operation.
[0002] During well drilling operations, downhole telemetry (e.g.,
mud-pulse telemetry, electromagnetic telemetry) may be utilized to
communicate information between a bottom-hole assembly (BHA) of a
drill string and surface equipment. Mud-pulse telemetry transmits
downhole (e.g., sensor) data between the surface equipment and the
BHA in the form of modulated pressure pulses generated by a
downhole transmitter. The pressure pulses propagate to a surface
receiver (i.e., a pressure sensor) through a drilling fluid
transferred downhole through the drill string. Conversely,
electromagnetic telemetry transmits downhole data between the
surface equipment and the BHA in the form of modulated
electromagnetic waves generated by a downhole transmitter. The
electromagnetic waves propagate to a surface receiver (i.e., an
electromagnetic probe) through the rock formation extending between
the downhole transmitter and the surface receiver.
[0003] Efficiency of mud-pulse telemetry and electromagnetic
telemetry is affected by noise generated by the well construction
equipment (i.e., rig noise), which can interfere with telemetry
signals communicated between the downhole transmitters and surface
receivers. When rig noise interferes with telemetry signals, sensor
data encoded in such telemetry signals cannot be correctly
extracted (e.g., demodulated) and the telemetry operations have to
be repeated, thereby resulting in flat time for rig 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] The present disclosure introduces an apparatus including a
telemetry system of a drilling rig and an equipment controller
comprising a processor and a memory storing computer program code.
The telemetry system includes a transmitter and a receiver. The
transmitter is carried by a drill string and is operable to
transmit a telemetry signal. The receiver is included in surface
equipment of the drilling rig. The receiver is operable to generate
an output signal including a telemetry signal signature, based on
the telemetry signal, and a rig noise signature, based on rig noise
generated by rig equipment of the drilling rig. The equipment
controller is operable to automatically reduce interference by the
rig noise with the telemetry signal by outputting control commands
to change operational parameters of the rig equipment and/or the
telemetry system.
[0006] The present disclosure also introduces a method including
commencing operation of a telemetry system of a drilling rig and
commencing operation of an equipment controller of the drilling
rig, thereby causing the equipment controller to output control
commands to change operational parameters of the telemetry system
and/or rig equipment of the drilling rig to reduce interference by
rig noise with a telemetry signal.
[0007] The present disclosure also introduces a method including
commencing operation of a telemetry system a drilling rig and
manually operating a control workstation of the drilling rig by a
rig personnel to change operational parameters of the rig equipment
and/or the telemetry system to reduce interference by rig noise
with a telemetry signal.
[0008] 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 material
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
[0009] The present disclosure is 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.
[0010] FIG. 1 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. 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.
[0012] 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.
[0013] FIG. 4 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.
[0014] FIG. 5 is a graph according to one or more aspects of the
present disclosure.
DETAILED DESCRIPTION
[0015] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, merely examples and are
not intended to be limiting. In addition, the present disclosure
may repeat reference numerals and/or letters in the various
examples. This repetition is for simplicity and clarity, and does
not in itself dictate a relationship between the various
embodiments and/or configurations discussed.
[0016] 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 of the present disclosure described below may
be implemented. The well construction system 100 may be or comprise
a drilling rig and associated equipment. Although the well
construction system 100 is depicted as an onshore implementation,
the aspects described below are also applicable to offshore
implementations.
[0017] 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 rock
formation 106. The well construction system 100 comprises well
construction equipment, such as 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 support structure 112 disposed over a rig
floor 114. The drill string 120 may be suspended within the
wellbore 102 from the support structure 112. The support structure
112 and the rig floor 114 are collectively supported over the
wellbore 102 by legs and/or other support structures (not shown).
Certain pieces of surface equipment 110 may be manually operated
(e.g., by hand, via a local control panel) by rig personnel 195
(e.g., a roughneck or another human rig operator) located at
various portions (e.g., rig floor 114) of the well construction
system 100.
[0018] 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, 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 by a driver
at the wellsite surface 104 and/or via a downhole mud motor 182
connected with the drill bit 126. The BHA 124 may also include one
or more downhole tools 180 above and/or below the mud motor
182.
[0019] The downhole tools 180 may be or comprise a
measurement-while-drilling (MWD) or logging-while-drilling (LWD)
tool comprising downhole sensors 184 operable for the acquisition
of measurement data pertaining to the BHA 124, the wellbore 102,
and/or the rock formation 106. The downhole sensors 184 may
comprise an inclination sensor, a rotational position sensor,
and/or a rotational speed sensor, which may include one or more
accelerometers, magnetometers, gyroscopic sensors (e.g.,
micro-electro-mechanical system (MEMS) gyros), and/or other sensors
for determining the orientation, position, and/or speed of one or
more portions of the BHA 124 (e.g., the drill bit 126, the downhole
tool 180, the mud motor 182) and/or other portions of the tool
string 120 relative to the wellbore 102 and/or the wellsite surface
104. The downhole sensors 184 may comprise a depth correlation tool
utilized to determine and/or log position (i.e., depth) of one or
more portions of the BHA 124 and/or other portions of the tool
string 120 within the wellbore 102 and/or with respect to the
wellsite surface 104.
[0020] One or more of the downhole tools 180 and/or another portion
of the BHA 124 may also comprise a telemetry device 186 operable to
communicate with the surface equipment 110 via downhole telemetry,
such as mud-pulse telemetry and/or electromagnetic telemetry. One
or more of the downhole tools 180 and/or another portion of the BHA
124 may also comprise a downhole controller 188 operable to
receive, process, and/or store data received from the surface
equipment 110, the downhole sensors 184, and/or other portions of
the BHA 124. The controller 188 may also store executable computer
programs (e.g., program code instructions), including for
implementing one or more aspects of the operations described
herein.
[0021] The support structure 112 may support the driver, such as a
top drive 116, operable to connect (perhaps indirectly) with an
upper end of the drill string 120, and to impart rotary motion 117
and vertical motion 135 to the drill string 120, including the
drill bit 126. However, another driver, such as a kelly and a
rotary table (neither own), may be utilized in addition to or
instead of the top drive 116 to impart the rotary motion 117 to the
drill string 120. The top drive 116 and the connected drill string
120 may be suspended from the support structure 112 via a hoisting
system or equipment, which may include a traveling block 113, a
crown block 115, and a drawworks 118 storing a support cable or
line 123. The crown block 115 may be connected to or otherwise
supported by the support structure 112, and the traveling block 113
may be coupled with the top drive 116. The drawworks 118 may be
mounted on or otherwise supported by the rig floor 114. The crown
block 115 and traveling block 113 comprise pulleys or sheaves
around which the support line 123 is reeved to operatively connect
the crown block 115, the traveling block 113, and the drawworks 118
(and perhaps an anchor). The drawworks 118 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 118
may comprise a drum, a base, 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 113 and the top
drive 116 to move upward. The drawworks 118 may be further operable
to reel out the support line 123 via a controlled rotation of the
drum, causing the traveling block 113 and the top drive 116 to move
downward.
[0022] The top drive 116 may comprise a grabber, a swivel (neither
shown), elevator links 127 terminating with an elevator 129, and a
drive shaft 125 operatively connected with a prime mover (e.g., an
electric motor) (not shown) of the top drive 116, such as via a
gear box or transmission (not shown). The drive shaft 125 may be
selectively coupled with the upper end of the drill string 120 and
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 118, may advance the
drill string 120 into the formation 106 to form the wellbore 102.
The elevator links 127 and the elevator 129 of the top drive 116
may handle tubulars (e.g., drill pipes, drill collars, casing
joints, etc.) 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 top drive 116 may have a guide system (not shown),
such as rollers that track up and down a guide rail on the support
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 support structure 112.
[0023] The well construction system 100 may further include a
drilling fluid circulation system or equipment 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
the drilling fluid 140 (i.e., mud), and one or more drilling fluid
pumps 144 (i.e., mud pumps) 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 145 (e.g., stand pipe) extending
from the pumps 144 to the top drive 116 and an internal passage
extending through the top drive 116.
[0024] During drilling operations, the drilling fluid may continue
to flow downhole through the internal passage 121 of the drill
string 120, as indicated by directional arrow 158. The drilling
fluid may exit the BHA 124 via ports in the drill bit 126 and then
circulate uphole through an annular space 108 of the wellbore 102
defined between an exterior of the drill string 120 and the
sidewall of the wellbore 102, such flow being indicated by
directional arrows 159. In this manner, the drilling fluid
lubricates the drill bit 126 and carries formation cuttings uphole
to the wellsite surface 104. The drilling fluid flowing downhole
through the internal passage 121 may selectively actuate the mud
motor 182 to rotate the drill bit 126 instead of or in addition to
the rotation of the drill string 120 via the top drive 116.
Accordingly, rotation of the drill bit 126 caused by the top drive
116 and/or mud motor 182 may advance the drill string 120 through
the formation 106 to form the wellbore 102.
[0025] The well construction system 100 may further include fluid
control equipment 130 for maintaining well pressure control and for
controlling fluid being discharged from the wellbore 102. The fluid
control equipment 130 may be mounted on top of a wellhead 134. The
drilling fluid flowing uphole 159 toward the wellsite surface 104
may exit the annulus 108 via one or more instances of the fluid
control equipment 130, such as a bell nipple, an RCD, and/or a
ported adapter (e.g., a spool, cross adapter, a wing valve, etc.).
The drilling fluid may then pass through drilling fluid
reconditioning equipment 170 to be cleaned and reconditioned before
returning to the fluid container 142. The drilling fluid
reconditioning equipment 170 may also separate drill cuttings 146
from the drilling fluid into a cuttings container 148.
[0026] An iron roughneck 165 may be positioned on the rig floor
114. The iron roughneck 165 may comprise a torqueing portion 167,
such as may include a spinner and a torque wrench comprising a
lower tong and an upper tong. The torqueing portion 167 of the iron
roughneck 165 may be moveable toward and at least partially around
the drill string 120, such as may permit the iron roughneck 165 to
make up and break out connections of the drill string 120. The
torqueing portion 167 may also be moveable away from the drill
string 120, such as may permit the iron roughneck 165 to move clear
of the drill string 120 during drilling operations. The spinner of
the iron roughneck 165 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.
[0027] A set of slips 162 may be located on the rig floor 114, such
as may accommodate therethrough the drill string 120 during tubular
make up and break out operations, tubular running operations, and
drilling operations. The slips 162 may be in an open position
during running and drilling operations to permit advancement of the
drill string 120, and in a closed position to clamp the upper end
(e.g., uppermost tubular) of the drill string 120 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.
[0028] 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 a drill
string rotation system (e.g., the top drive 116, the rotary table),
a hoisting system (e.g., the drawworks 118, the blocks 113, 115), a
tubular handling system (e.g., a catwalk, a tubular handling
device), a drilling fluid circulation system (e.g., the pumps 144,
the fluid conduit 145), a drilling fluid cleaning and
reconditioning system (e.g., the drilling fluid reconditioning
equipment 170, the containers 142, 148), the well control system
(e.g., a BOP stack, a choke manifold), and the BHA 124, 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 rig personnel 195 (e.g., a driller or another
human rig operator) 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 surface equipment controller 192 (e.g., a
processing device, 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 controller 192 may be
communicatively connected with the various surface 110 and downhole
120 equipment described herein, and may be operable to receive
signals (e.g., sensor data, sensor measurements) from and transmit
signals (e.g., control data, control signals, control commands) to
the equipment to perform various operations described herein. The
controller 192 may store executable program code, instructions,
and/or operational parameters or set-points, including for
implementing one or more aspects of methods and operations
described herein. The controller 192 may be located within and/or
outside of the facility 191.
[0029] The control workstation 197 may be operable for entering or
otherwise communicating control commands to the controller 192 by
the rig personnel 195, and for displaying or otherwise
communicating information from the controller 192 to the rig
personnel 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 touchscreen, a printer, audio speakers, etc.).
Communication between the controller 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.
[0030] 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.
[0031] The present disclosure is further directed to various
implementations of systems and/or methods for monitoring and/or
controlling operations of telemetry equipment and/or well
construction equipment (i.e., rig equipment) of a well construction
system (i.e., a drilling rig) to reduce negative effects of (e.g.,
interference by) noise generated by the well construction equipment
(referred to hereinafter as "rig noise") on efficiency of
telemetry. The systems and/or methods within the scope of the
present disclosure may be utilized to monitor or otherwise
determine (e.g., analyze, measure, evaluate) signatures of the rig
noise and then to adjust or otherwise change operations of the
telemetry equipment and/or well construction equipment based on the
determined rig noise signatures to reduce interference to telemetry
signal by the rig noise. For example, telemetry operations may be
adjusted by performing the telemetry operations during a time
interval when the rig noise is relatively low and/or at frequency
ranges that are different from frequencies of the rig noise. The
rig noise signatures may be displayed to rig personnel in
conjunction with a signature of the telemetry signal. The rig
personnel may then manually adjust or change the telemetry
operations and/or well construction equipment operations based on
the displayed rig noise signatures and telemetry signal signature
to reduce the negative effects of rig noise on telemetry
efficiency. The telemetry operations and/or well construction
equipment operations may also or instead be adjusted or changed
automatically by an equipment controller based on the rig noise
signatures and telemetry signal signature to reduce the negative
effects of rig noise on telemetry efficiency.
[0032] FIG. 2 is a schematic view of at least a portion of an
example implementation of a telemetry system 200 for transmitting a
telemetry signal 206 from a BHA 124 located downhole to surface
equipment 110 according to one or more aspects of the present
disclosure. The telemetry system 200 may operate in association
with a fluid circulation system 202. The telemetry system 200 and
the fluid circulation system 202 may form a portion of or operate
in conjunction with the well construction system 100 shown in FIG.
1 and, thus, may comprise one or more features of the well
construction system 100, including where indicated by the same
reference numbers. Accordingly, the following description refers to
FIGS. 1 and 2, collectively.
[0033] The telemetry system 200 may comprise a downhole mud-pulse
telemetry device 204 (e.g., a mud-pulse transmitter) installed or
otherwise disposed within the BHA 124 of a drill string 120
extending within a wellbore 102 and operable to communicate with
the surface equipment 110 via mud-pulse telemetry. For example, the
downhole telemetry device 204 may be operable to transmit the
mud-pulse telemetry signal 206 (e.g., pressure pulses, pressure
waves) uphole through drilling fluid being pumped downhole, to
transmit downhole data to the surface equipment 110. The telemetry
device 204 may be located within a downhole tool 180 of the BHA
124, which may further comprise a mud motor 182 and a drill bit
126. The downhole tool 180 and/or another portion of the BHA 124
may also comprise a downhole controller 188 operable to receive,
process, and/or store information received from the surface
equipment 110, downhole sensors 184, and/or other portions of the
BHA 124. The controller 188 may also store executable computer
programs (e.g., program code instructions), including for
implementing one or more aspects of the operations described
herein. The downhole sensors 184 may be operable to acquire
downhole measurement data associated with and/or indicative of the
BHA 124, the wellbore 102, and/or the formation 106. The downhole
sensors 184 may comprise an inclination sensor, a rotational
position sensor, and/or a rotational speed sensor, which may
include one or more accelerometers, magnetometers, gyroscopic
sensors (e.g., micro-electro-mechanical system (MEMS) gyros),
and/or other sensors for determining the orientation, position,
and/or speed of one or more portions of the BHA 124 (e.g., the
drill bit 126, the downhole tool 180, the mud motor 182) and/or
other portions of the tool string 120 relative to the wellbore 102
and/or the wellsite surface 104. The downhole sensors 184 may
comprise a depth correlation tool for determining and/or logging
position (i.e., depth) of one or more portions of the BHA 124
and/or other portions of the tool string 120 within the wellbore
102 and/or with respect to the wellsite surface 104.
[0034] The telemetry system 200 may also comprise one or more
mud-pulse telemetry signal sensors 210 disposed in association with
one or more portions of a fluid circulation system 202. The
drilling fluid circulation system 202 may be operable to circulate
the drilling fluid between the surface equipment 110 and the drill
bit 126 during drilling operations. For example, the drilling fluid
circulation system 202 may be operable to inject the drilling fluid
from the wellsite surface into the wellbore 102 via an internal
fluid passage (e.g., the internal fluid passage 121 shown in FIG.
1) extending longitudinally through the drill string 120. The
drilling fluid circulation system 202 may comprise a pit, a tank,
and/or other fluid container (e.g., the fluid container 142 shown
in FIG. 1) holding the drilling fluid (i.e., mud), and one or more
drilling fluid pumps 144 (i.e., mud pumps) operable to transfer the
drilling fluid from the container into the wellbore 102. The
drilling fluid may be drawn from the container via a suction fluid
conduit 212 and distributed among the pumps 144 via a suction
manifold or another common suction conduit 214. The drilling fluid
may be discharged from the pumps 144 into a discharge manifold or
another common discharge conduit 216 and transferred to a top drive
116 via a fluid conduit 145 (e.g., a stand pipe). The drilling
fluid 140 may then flow through an internal passage of the top
drive 116 into the internal fluid passage of the drill string 120.
The drilling fluid may continue to flow downhole through the
internal passage of the drill string 120, as indicated 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 108 of the wellbore 102 defined between an exterior
of the drill string 120 and the sidewall of the wellbore 102, such
flow being indicated by directional arrows 159.
[0035] One or more of the mud-pulse telemetry signal sensors 210
may be installed or otherwise disposed along one or more fluid
conduits fluidly connecting the drilling fluid pumps 114 to the top
drive 116. For example, one or more of the sensors 210 may be
disposed near or adjacent to the top drive 116 at or near an upper
(top) end of the fluid conduit 145 for passing (i.e., transferring)
drilling fluid from drilling fluid pumps 144 to the top drive 116.
One or more of the sensors 210 may also or instead be disposed near
or adjacent to the pumps 144 at or near a lower (bottom) end of the
fluid conduit 145. One or more of the telemetry signal sensors 210
may also or instead be disposed closer to fluid outlets of the
pumps 144 along the fluid conduit 216 fluidly connecting the pumps
144 with the fluid conduit 145.
[0036] The mud-pulse telemetry signal 206 transmitted by the
downhole telemetry device 204 may be or comprise pressure pulses or
fluctuations sent through the drilling fluid flowing downhole
within the fluid passage of the drill string 120, the fluid passage
of the top drive 116, and the fluid conduits 145, 216. For example,
the downhole telemetry device 204 may comprise a modulator
selectively operable to cause pressure pulses in the drilling fluid
flowing downhole. During telemetry operations, the downhole
telemetry device 204 may modulate the pressure of the drilling
fluid flowing downhole to transmit downhole data (e.g., uplink
mud-pulse telemetry data) received from the controller 188, the
downhole sensors 184, and/or other portions of the BHA 124 in the
form of the pressure pulses. The telemetry signal 206 (i.e.,
modulated pressure pulses or waves) then travel uphole along the
drilling fluid through the fluid passage, the top drive 116, and
the fluid conduits 145, 216 to be received (e.g., detected, sensed)
by one or more of the telemetry signal sensors 210. Thus, one or
more of the telemetry signal sensors 210 may be or comprise dynamic
pressure transducers or sensors operable to receive or sense the
telemetry signal 206 in the form of pressure pulses or waves
propagating along the drilling fluid flowing within corresponding
fluid conduits 145, 216. Each sensor 210 may then generate or
otherwise output an output signal (i.e., raw telemetry data)
comprising a signature (e.g., characteristics, waveform, frequency,
amplitude, etc.) of the telemetry signal 206, which in turn
comprises, contains, or is indicative of the downhole data
transmitted by the downhole telemetry device 204. Namely, each
sensor 210 may be operable to convert the telemetry signal 206
having the form of pressure pulses or waves, to an electrical
output signal comprising the telemetry signal signature. A
telemetry signal processor 220 (i.e., a demodulator) may receive
the telemetry signal signature and demodulate, reconstruct, or
otherwise ascertain the downhole data from the telemetry signal
signature.
[0037] An equipment controller 222 may receive the downhole data
from the telemetry signal processor 220. The equipment controller
222 may also or instead receive the telemetry signal signature from
the telemetry signal processor 220 and/or telemetry signal sensors
210. The equipment controller 222 may cause the telemetry signal
signature and/or the downhole data to be displayed to rig
personnel. The equipment controller 222 may also or instead analyze
the telemetry signal signature and/or the downhole data to monitor
and control telemetry operations and/or the well construction
operations based on the telemetry signal signature and/or the
downhole data. The sensors 210 may be communicatively connected
with the telemetry signal processor 220 and/or the equipment
controller 222 via wired and/or wireless communication means 218.
The telemetry signal processor 220 may be communicatively connected
with the equipment controller 222 via wired and/or wireless
communication means 224.
[0038] The equipment controller 222 may be or comprise a
programmable logic controller (PLCs), a computer (PCs), an
industrial computer (IPC), or other equipment controller equipped
with control logic. The equipment controller 222 may be or comprise
a portion of a rig control system operable to monitor and control
one or more pieces of the well construction equipment of the well
constriction system, such as the well construction system 100 shown
in FIG. 1. For example, the equipment controller 222 may be or
comprise a direct control device, such as a PLC, communicatively
connected with and operable to control one or more pieces of
equipment of the well construction system. The equipment controller
222 may be imparted with and operable to execute program code
instructions, such as rigid computer programing. Such equipment
controller 222 may be a local control device disposed in
association with the one or more pieces of equipment. The equipment
controller 222 may also or instead be or comprise a coordinated
control device, such as a PC, an IPC, and/or another processing
device. The equipment controller 222 may be imparted with and
operable to execute program code instructions, including high level
programming languages, such as C, and C++, among other examples,
and may be used with program code instructions running in a
real-time operating system (RTOS). Such equipment controller 222
may be a system-wide control device communicatively connected with
and operable to control a plurality of devices and/or subsystems of
the well construction system. The equipment controller 222 may be
or form at least a portion of the controller 192 shown in FIG.
1.
[0039] FIG. 3 is a schematic view of at least a portion of an
example implementation of a telemetry system 250 for transmitting a
telemetry signal 256 from a BHA 124 located downhole to surface
equipment 110 according to one or more aspects of the present
disclosure. The telemetry system 250 may form a portion of or
operate in conjunction with the well construction system 100 shown
in FIG. 1 and, thus, may comprise one or more features of the well
construction system 100, including where indicated by the same
reference numbers. The telemetry system 250 may comprise one or
more features of the telemetry system 200 shown in FIG. 2,
including where indicated by the same reference numbers.
Accordingly, the following description refers to FIGS. 1-3,
collectively.
[0040] The telemetry system 250 may comprise a downhole
electromagnetic telemetry device 254 (e.g., an electromagnetic
signal transmitter) installed or otherwise disposed within a BHA
124 of a drill string 120 extending within a wellbore 102 and
operable to communicate with surface equipment 110 via
electromagnetic telemetry. For example, the downhole telemetry
device 254 may be operable to transmit the electromagnetic
telemetry signal 256 (e.g., a voltage, a current, an
electromagnetic field) uphole through a rock formation 106 through
which the wellbore 102 extends between the BHA 124 and a wellsite
surface 104, to transmit downhole data to the surface equipment
110. The telemetry device 254 may be located within a downhole tool
180 of the BHA 124, which may further comprise a mud motor 182 and
a drill bit 126. The downhole tool 180 and/or another portion of
the BHA 124 may also comprise a downhole controller 188 operable to
receive, process, and/or store information received from the
surface equipment 110, downhole sensors 184, and/or other portions
of the BHA 124.
[0041] The telemetry system 250 may also comprise one or more
electromagnetic telemetry signal sensors 260 (e.g., electromagnetic
telemetry signal receivers, probes, or ground antennas) extending
at least partially into the ground at the wellsite surface 104. For
example, the signal sensors 260 may be distributed at the wellsite
surface 104 at various locations and distances around the wellbore
102. The electromagnetic telemetry signal 256 transmitted by the
downhole telemetry device 254 may be or comprise electromagnetic
waves sent through the rock formation comprising downhole data
(e.g., uplink electromagnetic telemetry data) received from the
downhole controller 188, the downhole sensors 184, and/or other
portions of the BHA 124. The telemetry signal 256 then travels to
the wellsite surface 104 through the rock formation 106 to be
received (e.g., detected, sensed) by one or more of the telemetry
signal sensors 260. Each sensor 260 may then generate or otherwise
output an output signal (i.e., raw telemetry data) comprising a
signature (e.g., characteristics, waveform, frequency, amplitude,
etc.) of the telemetry signal 256, which in turn comprises,
contains, or is indicative of the downhole data transmitted by the
downhole telemetry device 254. Namely, each sensor 260 may be
operable to convert the telemetry signal 256 having the form of
electromagnetic waves, to an electrical output signal comprising
the telemetry signal signature. A telemetry signal processor 270
may receive the telemetry signal signature and demodulate,
reconstruct, or otherwise ascertain the downhole data from the
telemetry signal signature.
[0042] An equipment controller 222 may receive the downhole data
from the telemetry signal processor 270. The equipment controller
222 may also or instead receive the telemetry signal signature from
the telemetry signal processor 270 and/or telemetry signal sensors
210. The equipment controller 222 may cause the telemetry signal
signature and/or the downhole data to be displayed to rig
personnel. The equipment controller 222 may also or instead analyze
the telemetry signal signature and/or the downhole data to monitor
and control telemetry operations and/or the well construction
operations based on the telemetry signal signature and/or the
downhole data. The sensors 260 may be communicatively connected
with the telemetry signal processor 270 and/or the equipment
controller 222 via wired and/or wireless communication means 268.
The telemetry signal processor 270 may be communicatively connected
with the equipment controller 222 via wired and/or wireless
communication means 224.
[0043] FIG. 4 is a schematic view of at least a portion of an
example implementation of a processing device 300 (or system)
according to one or more aspects of the present disclosure. The
processing device 300 may be or form at least a portion of one or
more processing devices, equipment controllers, and/or other
electronic devices shown in one or more of the FIGS. 1-3.
Accordingly, the following description refers to FIGS. 1-4,
collectively.
[0044] The processing device 300 may be or comprise, for example,
one or more processors, controllers, special-purpose computing
devices, PCs (e.g., desktop, laptop, and/or tablet computers),
personal digital assistants, smartphones, IPCs, PLCs, servers,
internet appliances, and/or other types of computing devices. The
processing device 300 may be or form at least a portion of the
surface equipment controller 192 shown in FIG. 1. The processing
device 300 may further be or form at least a portion of the
downhole controller 188 shown in FIGS. 1-3. The processing device
300 may also be or form at least a portion of the telemetry signal
processors 220, 270 and the equipment controller 222 shown in FIGS.
2 and 3. Although it is possible that the entirety of the
processing device 300 is implemented within one device, it is also
contemplated that one or more components or functions of the
processing device 300 may be implemented across multiple devices,
some or an entirety of which may be at the wellsite and/or remote
from the wellsite.
[0045] The processing device 300 may comprise a processor 312, such
as a general-purpose programmable processor. The processor 312 may
comprise a local memory 314, and may execute machine-readable and
executable program code instructions 332 (i.e., computer program
code) present in the local memory 314 and/or another memory device.
The processor 312 may execute, among other things, the program code
instructions 332 and/or other instructions and/or programs to
implement the example methods, processes, and/or operations
described herein. For example, the program code instructions 332,
when executed by the processor 312 of the processing device 300,
may cause the equipment controllers 192, 222 to perform example
methods, processes, and/or operations described herein. The program
code instructions 332, when executed by the processor 312 of the
processing device 300, may also or instead cause the processor 312
to receive and analyze telemetry signal profiles (e.g., raw
telemetry data), and output control commands to one or more pieces
of well construction equipment and/or telemetry devices 204, 254
based on the analyzed telemetry signal profiles.
[0046] The processor 312 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. Examples of the
processor 312 include one or more INTEL microprocessors,
microcontrollers from the ARM and/or PICO families of
microcontrollers, embedded soft/hard processors in one or more
FPGAs.
[0047] The processor 312 may be in communication with a main memory
316, such as may include a volatile memory 318 and a non-volatile
memory 320, perhaps via a bus 322 and/or other communication means.
The volatile memory 318 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 320 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 318 and/or non-volatile memory
320.
[0048] The processing device 300 may also comprise an interface
circuit 324, which is in communication with the processor 312, such
as via the bus 322. The interface circuit 324 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 324 may comprise a graphics driver card. The
interface circuit 324 may 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.).
[0049] The processing device 300 may be in communication with
various sensors, video cameras, actuators, processing devices,
equipment controllers, and other devices of the well construction
system via the interface circuit 324. The interface circuit 324 can
facilitate communications between the processing device 300 and one
or more devices by utilizing one or more communication protocols,
such as an Ethernet-based network protocol (such as ProfiNET, OPC,
OPC/UA, Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7
communication, or the like), a proprietary communication protocol,
and/or another communication protocol.
[0050] One or more input devices 326 may also be connected to the
interface circuit 324. The input devices 326 may permit the rig
personnel (e.g., a driller) to enter the program code instructions
332, which may be or comprise control commands, operational
parameters, operational thresholds, and/or other operational
set-points. The program code instructions 332 may further comprise
modeling or predictive routines, equations, algorithms, processes,
applications, and/or other programs operable to perform example
methods, calculations, and/or operations described herein. The
input devices 326 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 328 may also be
connected to the interface circuit 324. The output devices 328 may
permit for visualization or other sensory perception of various
data, such as sensor data, status data, and/or other example data.
The output devices 328 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 one or more input devices 326 and the one or more
output devices 328 connected to the interface circuit 324 may, at
least in part, facilitate the HMIs described herein.
[0051] The processing device 300 may comprise a mass storage device
330 for storing data and program code instructions 332. The mass
storage device 330 may be connected to the processor 312, such as
via the bus 322. The mass storage device 330 may be or comprise a
tangible, non-transitory storage medium, such as a floppy disk
drive, a hard disk drive, a compact disk (CD) drive, and/or digital
versatile disk (DVD) drive, among other examples. The processing
device 300 may be communicatively connected with an external
storage medium 334 via the interface circuit 324. The external
storage medium 334 may be or comprise a removable storage medium
(e.g., a CD or DVD), such as may be operable to store data and
program code instructions 332.
[0052] As described above, the program code instructions 332 and
other data (e.g., sensor data or measurements database) may be
stored in the mass storage device 330, the main memory 316, the
local memory 314, and/or the removable storage medium 334. Thus,
the processing device 300 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 312. 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 instructions 332 (i.e., software or firmware) thereon
for execution by the processor 312. The program code instructions
332 may include program instructions or computer program code that,
when executed by the processor 312, may perform and/or cause
performance of example methods, calculations, processes, and/or
operations described herein.
[0053] During well construction operations (e.g., drilling
operations), the telemetry sensors 210, 260 described above and
shown in FIGS. 2 and 3 may be further operable to receive, pick up,
sense, or otherwise detect vibrational (e.g., acoustic), and
electrical and electromagnetic rig noise, respectively, generated
by the various pieces of well construction equipment, in addition
to the respective mud-pulse and electromagnetic telemetry signals.
For example, the telemetry sensors 210, 260 may be operable to
detect vibrations and/or electromagnetic waves, respectively, that
are generated by the well construction equipment shown in FIGS.
1-3, such as the top drive 116, the drawworks 118, drilling fluid
pumps 144, the drill bit 126, and other well construction
equipment, comprising, for example, rotary actuators (e.g., motors,
engines), linear actuators (e.g., hydraulic cylinders), and/or
electromagnetic actuators. The rig noise generated by the well
construction equipment may propagate from the well construction
equipment along the ground 104, 106, the ambient air, and various
portions of the well construction system (e.g., the conveyance
means 122, the support structure 112, the drill floor 114, the
fluid conduits 145, 216, etc.) to the sensors 210, 260. The sensors
210, 260 may each output an electrical signal containing a
telemetry signal signature based on or otherwise indicative of the
detected telemetry signal and a plurality of rig noise signatures
based on or otherwise indicative of the detected rig noise
generated by the well construction equipment. The electrical signal
containing the telemetry signal signature and the rig noise
signatures generated by each sensor 210, 260 may then be received
by an equipment controller (e.g., the equipment controller 222, the
processing device 300) from the telemetry signal processor 220, 270
and/or directly from the sensors 210, 260. However, when rig noise
interferes with the telemetry signal 206, 256, the telemetry signal
processor 220, 270 and/or the equipment controller may be unable to
distinguish or discern the telemetry signal signatures from one or
more rig noise signatures.
[0054] The equipment controller may record and/or analyze the
telemetry signal signature, along with the rig noise signatures
output by the sensors 210, 260. The equipment controller may then
output control commands (e.g., control signals or data) to change
operational parameters of well construction equipment based on the
telemetry signal signature and rig noise signatures to prevent,
minimize, or otherwise reduce interference to the telemetry signal
206, 256 by the rig noise. The equipment controller may also or
instead output control commands to change operational parameters of
the telemetry system 200, 250 based on the telemetry signal
signature and rig noise signatures to reduce interference to the
telemetry signal 206, 256 by the rig noise. The equipment
controller may also or instead transmit the telemetry signal
signature and the rig noise signatures to a video output device
(e.g., a video output device 196 shown in FIG. 1) or otherwise
cause the telemetry signal signature and rig noise signatures to be
displayed on the video output device for viewing by rig personnel
(e.g., a driller). The rig personnel may then cause the equipment
controller to output control commands to change operational
parameters or operation sequences of the well construction
equipment based on the displayed telemetry signal signature and rig
noise signatures to reduce interference to the telemetry signal
206, 256 by the rig noise, and/or to change operational parameters
of the telemetry system 200, 250 based on the displayed telemetry
signal signature and rig noise signatures to reduce interference to
the telemetry signal 206, 256 by the rig noise.
[0055] FIG. 5 is a graph 400 (e.g., a frequency spectrogram)
showing example rig noise signatures 402 and telemetry signal
signature 404 contained within a sensor signal output by one or
more of the sensors 210, 260 shown in FIGS. 2 and 3 according to
one or more aspects of the present disclosure. The rig noise
signatures 402 are indicative of rig noise generated by various
well construction equipment of a well construction system 100 shown
in FIGS. 1-3, and the telemetry signal signature 404 is indicative
of a telemetry signal 206, 256 generated by a telemetry device 204,
254 shown in FIGS. 2 and 3, respectively. The rig noise signatures
402 and the telemetry signal signature 404 may each be a component
of a raw electrical (e.g., digital or analog) sensor signal
generated by one or more of the sensors 210, 260. The rig noise
signatures 402 and the telemetry signal signature 404 (e.g., raw
telemetry data) may each be or comprise an acoustic or
electromagnetic signature indicative of characteristics (e.g.,
waveform, amplitude, frequency) of an acoustic or electromagnetic
rig noise and the telemetry signals 206, 256, respectively.
Frequency (e.g., Hertz (Hz)) of the rig noise signatures 402 and
telemetry signal signature 404 are shown plotted along the vertical
axis, with respect to time (e.g., seconds), which is shown plotted
along the horizontal axis. The graph 400 may be generated by a
processing device (e.g., the equipment controller 222, the
processing device 300) and output to a visual (e.g., video) output
device (e.g., the video output device 196). The following
description refers to FIGS. 1-5, collectively.
[0056] An equipment controller (e.g., the equipment controller 222,
the processing device 300) within the scope of the present
disclosure may be operable to control one or more pieces of the
well construction equipment generating the rig noise based on
information indicative of a telemetry signal 206, 256 and rig noise
to improve the quality (e.g., distinguishability, discernibility)
of the telemetry signal 206, 256 with respect to the rig noise and,
thus, improve efficiency of downhole telemetry. For example, the
equipment controller may be operable to analyze the telemetry
signal signature 404 and the rig noise signatures 402 to determine
characteristics of the telemetry signal 206, 256 and the rig noise,
respectively, and determine if the rig noise interferes with the
telemetry signal 206, 256. The equipment controller may then
control the telemetry device 204, 254 and/or one or more pieces of
the well construction equipment based on the analyzed telemetry
signal signature 404 and rig noise signatures 402 to reduce
interference by the rig noise to the telemetry signal 206, 256. The
equipment controller may also record the telemetry signal signature
404 and the rig noise signatures 402.
[0057] Before the telemetry device 204, 254 and/or one or more
pieces of the well construction equipment can be controlled to
reduce interference by the rig noise to the telemetry signal 206,
256, a relationship between each piece (or instance) of the well
construction equipment and the rig noise that each such piece of
well construction equipment generates may be determined. Namely,
rig noise generated by well construction equipment may be detected
and converted to a plurality of rig noise signatures 402 by the
sensors 210, 260, and then each rig noise signature 402 may be
associated with a corresponding piece of well construction
equipment (and/or with an operational parameter or state of the
corresponding piece of well construction equipment), thereby
determining a relationship (i.e., an association) between each
piece of construction equipment (and/or each operational parameter
or state of each piece of well construction equipment) and a
corresponding rig noise signature 402.
[0058] For example, various well construction (e.g., drilling)
operations or testing operations (i.e., test runs) may be performed
by the well construction equipment, thereby generating
corresponding rig noise that is detected by the sensors 210, 260.
The well construction operations and the testing operations may be
performed by the well construction equipment when telemetry
operations are not performed by the telemetry devices 204, 254.
Each rig noise signature 402 may be output (e.g., generated) by the
sensor 210, 260 and recorded and/or analyzed by the equipment
controller in association with a corresponding piece of well
construction equipment to determine the equipment to noise
relationship between each noise signature 402 and piece of well
construction equipment. The rig noise signatures 402 may be output,
recorded, and/or analyzed during different phases of well
construction or testing operations (e.g., equipment operating
and/or stopped, equipment in open and/or closed positions,
equipment moving pipes, equipment at different depths, etc.) to
determine a full or otherwise comprehensive profile (i.e.,
historical data) of the equipment to noise relationship between the
well construction equipment (and/or the operational parameters or
operational states) and corresponding rig noise signatures 402. The
determined and recorded equipment to noise relationship (or
associations) may be used to determine if planned or current well
construction operations will cause rig noise that can cause
interference to the telemetry signal 206, 256. Thus, if a planned
parallel operation (e.g., offline stand-building) generates rig
noise that interferes with the telemetry operations, the equipment
controller may automatically adjust the planned operation sequence
(such as by swapping such sequence with another sequence, or
delaying the start of the sequence, etc.), such that this planned
operation sequence doesn't happen at the same as the telemetry
operations.
[0059] The equipment to noise relationship may be indicative of
which pieces of well construction equipment and/or which stages of
well construction operations generate rig noise that interferes
with the telemetry operations and to what extent or degree, such as
by examining which rig noise signature 402 (and thus which piece of
equipment) has a frequency range that overlaps with a frequency
range of the telemetry signal signature 404. The rig noise
signatures 402 and the telemetry signal signature 404 may be
further indicative of relative amplitude of the overlapping
frequency ranges. The rig noise signatures 402 may be further
indicative of which type and location of the telemetry signal
sensors 210, 260 result in less interfering rig noise being
captured by the sensors 210, 260 along with the telemetry signals
206, 256 and during which stages of the well construction
operations. The equipment controller and/or other portions of the
rig control system may use the rig noise signatures 402, the
telemetry signal signature 404, and the equipment to noise
relationship as a basis for automatically controlling the well
construction equipment generating the corresponding rig noise
and/or to control the telemetry devices 204, 254 to execute or
otherwise implement telemetry operations while reducing
interference to the telemetry signal 206, 256 by the rig noise.
Based on the rig noise signatures 402, the telemetry signal
signature 404, and the equipment to noise relationship, the
equipment controller may be operable to determine which well
construction equipment to control, determine how to control the
telemetry devices 204, 254, determine the optimal time to start or
stop telemetry operations, and/or determine optimal time to start
or stop selected well construction operations performed by the well
construction equipment to reduce interference to the telemetry
signal 206, 256 by the rig noise and, thus, optimize efficiency of
the telemetry operations. Based on such determinations, the
equipment controller may then automatically control the well
construction equipment generating the corresponding rig noise
and/or control the telemetry devices 204, 254 to reduce
interference to the telemetry signal 206, 256 by the rig noise.
[0060] An equipment controller within the scope of the present
disclosure may receive and analyze in real-time current rig noise
signatures 402 (i.e., real-time data) output by the sensors 210,
260 during well construction operations and control well
construction equipment generating the rig noise based on the
current rig noise signatures 402 and on the previously determined
equipment to noise relationship. For example, the equipment
controller may change operational parameters of the well
construction equipment associated with the received rig noise
signatures 402 such that frequency ranges of the rig noise
signatures 402 do not overlap (i.e., are the same or close) with a
frequency range of the telemetry signal signature 404 (i.e., an
operating frequency range of the telemetry device 204, 206).
Namely, the equipment controller may change operational parameters
(e.g., position, speed, oscillation rate, operating frequency,
etc.) of a piece of well construction equipment that generates a
rig noise signature 402 that overlaps with a frequency range of
(and happens at the same time as) the telemetry signal signature
404. As shown in graph 400, the frequency of a rig noise signature
406 associated with a piece of well construction equipment may be
increased automatically by the equipment controller by changing
operational parameters of the piece of well construction equipment
to shift 408 the rig noise signature 406 from its original
frequency of about 14 Hz, identified by reference number 416, to
its new frequency of about 18 Hz, identified by reference number
418, thereby eliminating or reducing interference caused by rig
noise associated with the rig noise signature 406 to the telemetry
signal 206, 256 associated with the telemetry signal signature 404.
The equipment controller may also or instead change starting and/or
stopping operating time of the well construction equipment causing
the rig noise, such that the telemetry operations (with telemetry
signal signature 404) do not happen at the same time when the rig
noise signatures 402 are present. For example, the equipment
controller may change starting and/or stopping operating time of
the well construction equipment that generates a rig noise
signature 410 having a frequency that overlaps with a frequency
range of the telemetry signal signature 404. As further show in
graph 400, the equipment controller may automatically stop
operations of a piece of well construction equipment associated
with the rig noise signature 410, having a frequency ranging
between about 14 and 15 Hz, at a time of about 750 seconds,
identified by reference number 420, right before the telemetry
device 204, 254 starts operating at the frequency ranging between
about 13 and 15 Hz, thereby eliminating or reducing interference
caused by rig noise associated with the rig noise signature 410 to
the telemetry signal 206, 256 associated with the telemetry signal
signature 404.
[0061] The equipment controller may also or instead change the
operational parameters of the telemetry system 200, 250 such that a
frequency range of the telemetry signal signature 404 does not
overlap with frequency ranges of one or more of the rig noise
signatures 402. Namely, the equipment controller may change an
operating frequency range (e.g., telemetry signal transmission
rate, mud-pulse transmission rate, electromagnetic wave
transmission rate) of the telemetry device 204, 254, such that the
frequency range of the telemetry signal signature 404 does not
overlap with frequency ranges of one or more of the rig noise
signatures 402. As further shown in graph 400, the operating
frequency of the telemetry device 204, 254 associated with the
telemetry signal signature 404 may be automatically increased by
the equipment controller to shift 412 the telemetry signal
signature 404 from its original operating frequency ranging between
about 8 Hz and 10 Hz and centered at about 9 Hz, identified by
reference number 422, to its new operating frequency ranging
between about 13 and 15 Hz and centered at about 14 Hz, identified
by the reference number 416, thereby eliminating or reducing
interference caused by rig noise associated with rig noise
signature 414 to the telemetry signal 206, 256 associated with the
telemetry signal signature 404. The equipment controller may also
or instead change starting and/or stopping operating times of the
telemetry device 204, 254 having an operating frequency that
overlaps with frequency of the rig noise, such that the telemetry
operations (with telemetry signal signature 404) do not happen at
the same time when the rig noise signatures 402 are present. As
further shown in graph 400, the equipment controller may
automatically start operations of the telemetry device 204, 254
associated with the telemetry signal signature 404, at a time of
about 750 seconds, identified by the reference number 420, right
after the piece of well construction equipment associated with the
rig noise signature 410 stops operating, thereby eliminating or
reducing interference caused by rig noise associated with the rig
noise signature 410 to the telemetry signal 206, 256 associated
with the telemetry signal signature 404.
[0062] In circumstances when rig noise frequencies cover or
otherwise overlap with substantially every frequency range usable
by the telemetry devices 204, 254 to perform telemetry operations,
the equipment controller may change order and/or timing of
telemetry operations and/or selected well construction operations
such that the telemetry signals 206, 256 (and corresponding
telemetry signal signature 404) are not being transmitted at the
same time when interfering rig noise (and corresponding rig noise
signatures 402) is being generated. Thus, as described above, the
equipment controller may change starting and/or stopping operating
times of the telemetry device 204, 254 and/or change the operation
sequences of well construction equipment generating a rig noise
signature 402 that overlaps with frequency range of the telemetry
device 204, 254, such that the telemetry device 204, 254 and the
well construction equipment generating the interfering rig noise do
not operate at the same time.
[0063] The equipment controller may also or instead filter out rig
noise signatures 402 having frequency ranges that overlap with
frequency range of the telemetry signal signature 404. For example,
the equipment controller may monitor frequency ranges of rig noise
signatures 402 and, if frequency ranges of one or more rig noise
signatures 402 overlap with frequency range of the telemetry signal
signature 404, then the equipment controller may apply a signal
filter to filter out such rig noise signatures 402. The frequency
ranges of rig noise signatures 402 may be determined or otherwise
known before initiating operations of the corresponding well
construction equipment based on the saved or otherwise previously
determined equipment to noise relationship.
[0064] When a pending telemetry operation coincides with a planned
operation sequence (or equipment operational states) that generates
rig noise that interferes with a telemetry signal 206, 256,
operations (e.g., operation sequence, operational state,
operational parameters) of the well construction equipment may be
changed automatically to facilitate telemetry operations. For
example, an equipment controller (e.g., the equipment controller
222 or another processing device) within the scope of the present
disclosure may be further operable to receive, store, and/or
analyze a digital well construction plan (i.e., a well
construction, drilling, or job plan in the form of a computer
program code) and to automatically execute the digital well
construction plan to perform well construction operation, such as
to trip in a drill string from depth A to depth B, or to drill from
depth C to depth D, with simultaneous operations performed by
multiple pieces of well construction equipment (i.e., rig
equipment), including telemetry operations. The equipment
controller may compare the planned telemetry operations with other
concurrent planned well construction operations based on the
equipment to noise relationship to determine if certain planned
well construction operations will generate rig noise that will
interfere with the telemetry signal 206, 256 of the planned
telemetry operations. If the equipment controller determines that
certain planned well construction operations will generate rig
noise that will interfere with the telemetry signal 206, 256 of the
planned telemetry operations, the equipment controller may
automatically change the digital well construction plan to prevent,
minimize, or otherwise reduce interference to the telemetry signal
206, 256 by the rig noise before execution of the digital well
construction plan. Namely, the equipment controller may adjust or
otherwise change the operational parameters or timing of the
planned telemetry operations and/or certain planned well
construction operation sequences to reduce interference to the
telemetry signal 206, 256 by the rig noise during the planned
telemetry operations.
[0065] The equipment controller may change the digital well
construction plan by changing operational parameters or timing of
the telemetry operations and/or well construction operation
sequences to minimize interruptions by or effect of rig noise on
the telemetry operations. For example, the equipment controller may
change the digital well construction plan to inhibit operation or
change timing of operations of a selected one or more of the well
construction equipment and/or the telemetry devices 204, 254 to
reduce interference to the telemetry signal 206, 256 by the rig
noise. Namely, the equipment controller may be operable to
automatically determine the optimal time to start or stop the
telemetry operations and/or optimal time to start or stop well
construction operation sequences to minimize interference by the
rig noise with the telemetry signals 206, 256 during telemetry
operations. The equipment controller may change the digital well
construction plan to stop or change operational parameters (e.g.,
speed, power, frequency, amplitude, etc.) of a piece of well
construction equipment that causes rig noise that interferes with
the telemetry signal 206, 256 right before the telemetry operations
start. The equipment controller may also or instead change the
digital well construction plan to stop telemetry operations right
before a piece of well construction equipment that causes a
relatively high amount of rig noise or interferes with the
telemetry signal 206, 256 starts operating. The equipment
controller may also or instead change the digital well construction
plan to start the telemetry operations right after a piece of well
construction equipment that causes the rig noise that interferes
with the telemetry signal 206, 256 stops operating.
[0066] Current rig noise signatures 402 output by the telemetry
sensors 210, 260 and/or current telemetry signal signature 404
associated with the telemetry device 204, 254 may be displayed in
real-time to a rig personnel (e.g., the driller) via one or more of
the output devices 196 of the control workstation 197 to assist the
rig personnel to manually operate the control workstation 197 to:
(1) change operational parameters of the well construction
equipment based on the rig noise signatures 402 and telemetry
signal signature 404 displayed on the one or more of the video
output devices 196 to reduce interference to the telemetry signal
by the rig noise; (2) change operational parameters of the
telemetry system 200, 250 based on the determined equipment to
noise relationship and the telemetry signal signature 404 and/or
rig noise signatures 402 displayed on the video output device 196
to reduce interference to the telemetry signal by the rig noise;
and/or (3) change operation sequence of a well construction plan
such that telemetry operation do not occur at the same time as
operations of well construction equipment that generate rig noise
that interfere with the telemetry signal 206, 256.
[0067] The graph 400 shown in FIG. 5 may be or comprise an example
display screen of a video output device 196 of the control
workstation 197 showing rig noise signatures 402 and a telemetry
signal signature 404 to a rig personnel to assist the rig personnel
to manually operate the control workstation 197 to change
operational parameters of the well construction equipment and/or
the telemetry system 200, 250. The previously determined equipment
to noise relationship (or associations) may be displayed to and
used by the rig personnel to determine which pieces of well
construction equipment and/or which stages of well construction
operations generate rig noise signatures 402 that overlap in
frequency and take place at the same time as and, thus, interfere
with the telemetry signal signature 404. The equipment to noise
relationship between each instance of the well construction
equipment and the corresponding instance of the rig noise signature
402 may be displayed on the video output device for viewing by the
rig personnel. For example, the video output device may display a
list of each instance of the well construction equipment adjacent a
frequency range of each corresponding rig noise signature 402
caused by that instance of the well construction equipment. The
video output device may also or instead display a name or another
identifier of each piece of well construction equipment along the
vertical axis of the graph 400 or otherwise in association with
each displayed rig noise signature 402.
[0068] The displayed rig noise signatures 402, the current
telemetry signal signature 404, and the previously determined
equipment to noise relationship may aid the rig personnel to
determine which well construction equipment generates rig noise
that can interfere with telemetry operations, determine how to
control the well construction equipment to reduce interference by
the rig noise, determine how to control the telemetry devices 204,
254 to reduce interference by the rig noise, determine an optimal
time to start or stop telemetry operations to reduce interference
by the rig noise, and/or determine an optimal time to start or stop
selected well construction operations to reduce interference by the
rig noise. Based on such determinations, the rig personnel may then
manually control the well construction equipment generating the rig
noise and/or the telemetry devices 204, 254 via the control
workstation 197 to reduce interference by the rig noise and, thus,
optimize efficiency of the telemetry operations.
[0069] For example, the rig personnel may change the operational
parameters of the well construction equipment such that a frequency
range of the rig noise (and the rig noise signatures 402) does not
overlap with a frequency range of the telemetry signals 206, 256
(and the telemetry signal signature 404). Namely, the rig personnel
may change an operating parameter (e.g., rotational speed,
oscillation rate, operating frequency) of a piece of well
construction equipment that generates a rig noise signature 402
that overlaps with a frequency range of the telemetry signal
signature 404. As shown in graph 400, frequency of the telemetry
signal signature 404 ranges between about 13 and 15 Hz, and is
centered at about 14 Hz. Thus, the operating parameter of a piece
of well construction equipment associated with a rig noise
signature 406 may be changed (e.g., increased) to shift 408 the rig
noise signature 406 from its original frequency of about 14 Hz,
identified by reference number 416, to its new frequency of about
18 Hz, identified by reference number 418, thereby eliminating or
reducing interference caused by rig noise associated with the rig
noise signature 406 to the telemetry signal 206, 256 associated
with the telemetry signal signature 404.
[0070] The rig personnel may also or instead change starting and/or
stopping operating time of the piece of well construction equipment
that generates the interfering rig noise associated with the rig
noise signature 410 such that that piece of well construction
equipment does not operate at the same time the telemetry signal
206, 256 associated with the telemetry signal signature 404 is
being transmitted. As further shown in graph 400, the rig personnel
may stop operations of a piece of well construction equipment
associated with the rig noise signature 410, having a frequency
ranging between about 14 and 15 Hz, at a time of about 750 seconds,
identified by reference number 420, right before the telemetry
device 204, 254 starts operating at the frequency ranging between
about 13 and 15 Hz, thereby eliminating or reducing interference
caused by rig noise associated with the rig noise signature 410 to
the telemetry signal 206, 256 associated with the telemetry signal
signature 404.
[0071] The rig personnel may also or instead change the operational
parameters of the telemetry system 200, 250 such that a frequency
range of the telemetry signal signature 404 does not overlap with
frequency ranges of one or more of the rig noise signatures 402.
Namely, the rig personnel may change an operating frequency range
(e.g., telemetry signal transmission rate, mud-pulse transmission
rate, electromagnetic wave transmission rate) of the telemetry
device 204, 254, such that the frequency range of the telemetry
signal signature 404 does not overlap with frequency ranges of one
or more of the rig noise signatures 402. As further shown in graph
400, the operating frequency of the telemetry device 204, 254
associated with the telemetry signal signature 404 may be increased
to shift 412 the telemetry signal signature 404 from its original
operating frequency ranging between about 8 Hz and 10 Hz and
centered at about 9 Hz, identified by reference number 422, to its
new operating frequency ranging between about 13 and 15 Hz and
centered at about 14 Hz, identified by the reference number 416,
thereby eliminating or reducing interference caused by rig noise
associated with rig noise signature 414 to the telemetry signal
206, 256 associated with the telemetry signal signature 404.
[0072] The rig personnel may also or instead change starting and/or
stopping operating times of the telemetry device 204, 254, such
that the telemetry signal 206, 256 associated with the telemetry
signal signature 404 is not being transmitted at the same time that
a piece of well construction equipment that generates the
interfering rig noise associated with the rig noise signature 410
is being operated. As further shown in graph 400, the rig personnel
may start operations of the telemetry device 204, 254 associated
with the telemetry signal signature 404, at a time of about 750
seconds, identified by the reference number 420, right after the
piece of well construction equipment associated with the rig noise
signature 410 stops operating, thereby eliminating or reducing
interference caused by rig noise associated with the rig noise
signature 410 to the telemetry signal 206, 256 associated with the
telemetry signal signature 404.
[0073] In view of the entirety of the present disclosure, including
the figures and the claims, a person having ordinary skill in the
art will readily recognize that the present disclosure introduces
an apparatus comprising: (A) a telemetry system of a drilling rig,
wherein the telemetry system comprises: (i) a transmitter carried
by a drill string and operable to transmit a telemetry signal; and
(ii) a receiver included in surface equipment of the drilling rig
and operable to generate an output signal comprising: (a) a
telemetry signal signature based on the telemetry signal; and (b) a
rig noise signature based on rig noise generated by rig equipment
of the drilling rig; and (B) an equipment controller comprising a
processor and a memory storing computer program code, wherein the
equipment controller is operable to automatically reduce
interference by the rig noise with the telemetry signal by
outputting control commands to change operational parameters of the
rig equipment and/or the telemetry system.
[0074] The telemetry signal may comprise at least one of a
mud-pulse telemetry signal and electromagnetic telemetry
signal.
[0075] The telemetry signal signature may be indicative of
frequency of the telemetry signal and the rig noise signature may
be indicative of frequency of the rig noise.
[0076] The receiver may be or comprise a pressure sensor, the
telemetry signal may comprise pressure fluctuations propagating
through drilling fluid flowing within the drill string and the
surface equipment, the receiver may be further operable to receive
the telemetry signal and the rig noise, and the output signal may
be an electrical signal comprising the telemetry signal signature
and the rig noise signature.
[0077] The receiver may be or comprise an electromagnetic signal
sensor, the telemetry signal may comprise an electromagnetic signal
transmitted through rock formation extending between the
transmitter and the receiver, the receiver may be further operable
to receive the telemetry signal and the rig noise, and the output
signal may be an electrical signal comprising the telemetry signal
signature and the rig noise signature.
[0078] Changing the operational parameters of the rig equipment may
comprise changing the operational parameters of the rig equipment
such that a frequency range of the rig noise signature does not
overlap with a frequency range of the telemetry signal
signature.
[0079] Changing the operational parameters of the rig equipment may
comprise changing starting and/or stopping operating time of the
rig equipment such that operation of the rig equipment that
generates the rig noise that interferes with the telemetry signal
does not happen at the same time as operation of the telemetry
system.
[0080] Changing the operational parameters of the telemetry system
may comprise changing the operational parameters of the telemetry
system such that an operating frequency range of the telemetry
system does not overlap with a frequency range of the rig noise
signature.
[0081] Changing the operational parameters of the telemetry system
may comprise changing starting and/or stopping operating time of
the telemetry system such that operation of the telemetry system
does not happen at the same time as operation of the rig equipment
that generates the rig noise that interferes with the telemetry
signal.
[0082] The equipment controller may be further operable to store
associations between each instance of the rig equipment and a
corresponding instance of the rig noise signature caused by each
instance of the rig equipment, and the equipment controller may be
operable to output control commands to an instance of the rig
equipment to reduce a corresponding instance of the rig noise and
thereby reduce interference of the rig noise with the telemetry
signal based on the stored associations. The equipment controller
may be further operable to store a digital well construction plan
for operating the telemetry system and the rig equipment to
construct a well, and the equipment controller may be further
operable to change the digital well constriction plan and thereby
reduce interference of the rig noise with the telemetry signal
based on the stored associations.
[0083] The equipment controller may be further operable to store a
digital plan for operating the telemetry system and the rig
equipment to construct a well, and the equipment controller may be
further operable to change the digital plan to reduce interference
of the rig noise with the telemetry signal. Changing the digital
plan to reduce interference of the rig noise with the telemetry
signal may comprise changing starting and/or stopping operating
time of the rig equipment such that operation of the rig equipment
that generates the rig noise that interferes with the telemetry
signal does not happen at the same time as operation of the
telemetry system.
[0084] The present disclosure also introduces a method comprising:
commencing operation of a telemetry system of a drilling rig; and
commencing operation of an equipment controller of the drilling
rig, thereby causing the equipment controller to output control
commands to change operational parameters of the telemetry system
and/or rig equipment of the drilling rig to reduce interference by
rig noise with a telemetry signal.
[0085] Commencing operation of the telemetry system of the drilling
rig may cause: (A) the telemetry signal to be transmitted by a
transmitter carried by a drill string; and (B) an output signal to
be generated by a receiver included in surface equipment of the
drilling rig, wherein the output signal comprises: (i) a telemetry
signal signature based on the telemetry signal; and (ii) a rig
noise signature based on the rig noise generated by the rig
equipment of the drilling rig. The equipment controller may be
operable to store associations between each instance of the rig
equipment and a corresponding instance of the rig noise signature
caused by each instance of the rig equipment, and commencing
operation of the equipment controller may cause the equipment
controller to output control commands to an instance of the rig
equipment to reduce a corresponding instance of the rig noise and
thereby reduce interference by the rig noise with the telemetry
signal based on the stored associations.
[0086] The equipment controller may be operable to store a digital
plan for operating the telemetry system and the rig equipment to
construct a well, and commencing operation of the equipment
controller may cause the equipment controller to change the digital
plan to reduce interference of the rig noise with the telemetry
signal.
[0087] The present disclosure also introduces a method comprising:
commencing operation of a telemetry system a drilling rig; and
manually operating a control workstation of the drilling rig by a
rig personnel to change operational parameters of the rig equipment
and/or the telemetry system to reduce interference by rig noise
with a telemetry signal.
[0088] Commencing operation of the telemetry system of the drilling
rig may cause: (A) the telemetry signal to be transmitted by a
transmitter carried by a drill string; and (B) an output signal to
be generated by a receiver included in surface equipment of the
drilling rig, wherein the output signal comprises: (i) a telemetry
signal signature based on the telemetry signal; and (ii) a rig
noise signature based on rig noise generated by rig equipment of
the drilling rig. The method may further comprise commencing
operation of a processing device of the drilling rig, thereby
causing the telemetry signal signature and the rig noise signature
to be displayed by the processing system on a video output device
for viewing by rig personnel. Manually operating the control
workstation of the drilling rig by the rig personnel to reduce
interference by the rig noise with the telemetry signal may be
based on the displayed telemetry signal signature and the rig noise
signature. The processing device may be operable to store
associations between each instance of the rig equipment and a
corresponding instance of the rig noise signature, and commencing
operation of the processing device may further cause the
associations between each instance of the rig equipment and the
corresponding instance of the rig noise signature to be displayed
on the video output device for viewing by the rig personnel.
[0089] 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 functions
and/or achieving the same benefits of the embodiments introduced
herein. A person having ordinary skill in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the scope of the present disclosure.
[0090] The Abstract at the end of this disclosure is provided to
permit the reader to quickly ascertain the nature of the technical
disclosure. It is submitted with the understanding that it will not
be used to interpret or limit the scope or meaning of the
claims.
* * * * *