U.S. patent application number 17/073444 was filed with the patent office on 2021-04-22 for autodriller utilizing intermediate rop setpoint.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Fergus Hopwood, Nathaniel Wicks, Jian Wu.
Application Number | 20210115779 17/073444 |
Document ID | / |
Family ID | 1000005194828 |
Filed Date | 2021-04-22 |
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United States Patent
Application |
20210115779 |
Kind Code |
A1 |
Hopwood; Fergus ; et
al. |
April 22, 2021 |
Autodriller Utilizing Intermediate ROP Setpoint
Abstract
Apparatus and methods for automatically controlling selected
drilling operations. The apparatus may be a control system operable
to control rate of penetration (ROP) by a drill bit of a drill
string for drilling a wellbore. The control system may include a
sensor operable to facilitate an ROP measurement indicative of a
measured ROP and a controller comprising a processor and a memory
storing computer program code. The controller may be operable to
receive the ROP measurement, determine an intermediate ROP setpoint
based on the ROP measurement, and determine an ROP command based on
the intermediate ROP setpoint, wherein the ROP command is to be
received by a drawworks and is indicative of an intended ROP.
Inventors: |
Hopwood; Fergus; (Houston,
TX) ; Wu; Jian; (Houston, TX) ; Wicks;
Nathaniel; (Somerville, MA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000005194828 |
Appl. No.: |
17/073444 |
Filed: |
October 19, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62916334 |
Oct 17, 2019 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 45/00 20130101;
E21B 44/04 20130101 |
International
Class: |
E21B 44/04 20060101
E21B044/04; E21B 45/00 20060101 E21B045/00 |
Claims
1. An apparatus comprising: a system operable to control rate of
penetration (ROP) by a drill bit of a drill string for drilling a
wellbore, wherein the system comprises: a sensor operable to
facilitate an ROP measurement indicative of a measured ROP; and a
controller comprising a processor and a memory storing computer
program code, wherein the controller is operable to: receive the
ROP measurement; determine an intermediate ROP setpoint based on
the ROP measurement; and determine an ROP command based on the
intermediate ROP setpoint, wherein the ROP command is to be
received by a drawworks and is indicative of an intended ROP.
2. The apparatus of claim 1 wherein the controller is operable to
determine the intermediate ROP setpoint by adding a step value to
the ROP measurement.
3. The apparatus of claim 2 wherein the controller is further
operable to receive an ROP upper limit setpoint defined by rig
personnel, and wherein the step value comprises a percentage of the
ROP upper limit setpoint.
4. The apparatus of claim 1 wherein the controller is further
operable to receive an ROP upper limit setpoint defined by rig
personnel, and wherein the controller is operable to determine the
intermediate ROP setpoint by: limiting the ROP measurement to the
ROP upper limit setpoint; and adding a step value to the limited
ROP measurement.
5. The apparatus of claim 1 wherein the controller is further
operable to receive an ROP upper limit setpoint defined by rig
personnel, and wherein the controller is operable to determine the
intermediate ROP setpoint by: adding a step value to the ROP
measurement to determine a first intermediate ROP setpoint;
limiting the first intermediate ROP setpoint between an
acceleration limit and a deceleration limit to determine a second
intermediate ROP setpoint; and limiting the second intermediate ROP
setpoint with the ROP upper limit setpoint.
6. The apparatus of claim 1 wherein the controller is an ROP
controller operable to: receive a normalized weight on bit (WOB)
output from a WOB controller; receive a normalized torque on bit
(TOB) output from a drilling torque controller; receive a
normalized differential pressure (DeltaP) output from a DeltaP
controller; and determine the ROP command based further on one or
more of the normalized WOB output, the normalized TOB output, and
the normalized DeltaP output.
7. The apparatus of claim 1 wherein the controller is an ROP
controller operable to: receive a normalized weight on bit (WOB)
output from a WOB controller; receive a normalized torque on bit
(TOB) output from a drilling torque controller; receive a
normalized differential pressure (DeltaP) output from a DeltaP
controller; find a smallest one of the normalized WOB output, the
normalized TOB output, and the normalized DeltaP output; and
determine the ROP command by taking a product of the intermediate
ROP setpoint and the smallest one of the normalized WOB output, the
normalized TOB output, and the normalized DeltaP output.
8. A method comprising: commencing operation of a control system
for controlling rate of penetration (ROP) by a drill bit of a drill
string for drilling a wellbore, wherein the operating control
system: receives an ROP measurement; determines an intermediate ROP
setpoint based on the ROP measurement; and determines an ROP
command based on the intermediate ROP setpoint, wherein the ROP
command is to be received by a drawworks and is indicative of an
intended ROP.
9. The method of claim 8 wherein determining the intermediate ROP
setpoint comprises adding a step value to the ROP measurement.
10. The method of claim 9 wherein the operating control system also
receives an ROP upper limit setpoint defined by rig personnel, and
wherein the step value comprises a percentage of the ROP upper
limit setpoint.
11. The method of claim 8 wherein the operating control system also
receives an ROP upper limit setpoint defined by rig personnel, and
wherein determining the intermediate ROP setpoint comprises:
limiting the ROP measurement to the ROP upper limit setpoint; and
adding a step value to the limited ROP measurement.
12. The method of claim 8 wherein determining the intermediate ROP
setpoint comprises: adding a step value to the ROP measurement to
increase the ROP measurement; and limiting the increased ROP
measurement between an acceleration limit and a deceleration
limit.
13. The method of claim 8 wherein the operating control system
also: receives a normalized weight on bit (WOB) output from a WOB
controller; receives a normalized torque on bit (TOB) output from a
drilling torque controller; receives a normalized differential
pressure (DeltaP) output from a DeltaP controller; and determines
the ROP command further based on one or more of the normalized WOB
output, the normalized TOB output, and the normalized DeltaP
output.
14. The method of claim 8 wherein the operating control system
also: receives a normalized weight on bit (WOB) output from a WOB
controller; receives a normalized torque on bit (TOB) output from a
drilling torque controller; receives a normalized differential
pressure (DeltaP) output from a DeltaP controller; finds a smallest
one of the normalized WOB output, the normalized TOB output, and
the normalized DeltaP output; and determines the ROP command by
taking a product of the intermediate ROP setpoint and the smallest
one of the normalized WOB output, the normalized TOB output, and
the normalized DeltaP output.
15. A computer program product comprising: a non-transitory,
computer-readable medium comprising computer instructions
executable by a processor of a control system communicatively
connected with a drawworks for raising and lowering a drill string,
wherein the computer instructions, when executed by the processor,
cause the control system to: receive a rate of penetration (ROP)
measurement; determine an intermediate ROP setpoint based on the
ROP measurement; and determine an ROP command based on the
intermediate ROP setpoint, wherein the ROP command is to be
received by a drawworks and is indicative of an intended ROP.
16. The computer program product of claim 15 wherein execution of
the computer instructions also causes the control system to
determine the intermediate ROP setpoint by adding a step value to
the ROP measurement.
17. The computer program product of claim 16 wherein execution of
the computer instructions also causes the control system to receive
an ROP upper limit setpoint defined by rig personnel, and wherein
the step value comprises a percentage of the ROP upper limit
setpoint.
18. The computer program product of claim 15 wherein execution of
the computer instructions also causes the control system to:
receive an ROP upper limit setpoint defined by rig personnel; and
determine the intermediate ROP setpoint by: limiting the ROP
measurement to the ROP upper limit setpoint; and adding a step
value to the limited ROP measurement.
19. The computer program product of claim 15 wherein execution of
the computer instructions also causes the control system to:
receive a normalized weight on bit (WOB) output from a WOB
controller; receive a normalized torque on bit (TOB) output from a
drilling torque controller; receive a normalized differential
pressure (DeltaP) output from a DeltaP controller; and determine
the ROP command further based on one or more of the normalized WOB
output, the normalized TOB output, and the normalized DeltaP
output.
20. The computer program product of claim 15 wherein execution of
the computer instructions also causes the control system to:
receive a normalized weight on bit (WOB) output from a WOB
controller; receive a normalized torque on bit (TOB) output from a
drilling torque controller; receive a normalized differential
pressure (DeltaP) output from a DeltaP controller; find a smallest
one of the normalized WOB output, the normalized TOB output, and
the normalized DeltaP output; and determine the ROP command by
taking a product of the intermediate ROP setpoint and the smallest
one of the normalized WOB output, the normalized TOB output, and
the normalized DeltaP output.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to and the benefit of U.S.
Provisional Application No. 62/916,334, titled "METHOD AND SYSTEM
FOR ADAPTIVE AUTODRILLER," filed Oct. 17, 2019, the entire
disclosure of which is hereby incorporated herein by reference.
BACKGROUND OF THE DISCLOSURE
[0002] Wells are generally drilled into the ground or ocean bed to
recover natural deposits of oil, gas, and other materials that are
trapped in subterranean formations. Well construction operations
(e.g., drilling operations) may be performed at a wellsite by a
well construction system (i.e., a drill rig) having various
automated surface and subterranean well construction equipment
operating in a coordinated manner. For example, a drive mechanism,
such as a top drive or a rotary table located at a wellsite
surface, may be utilized to rotate and advance a drill string into
a subterranean formation to drill a wellbore. The drill string may
include a plurality of drill pipes coupled together and terminating
with a drill bit. The length of the drill string is increased by
adding additional drill pipes while the depth of the wellbore
increases. A drilling fluid (i.e., drilling mud) may be pumped by
mud pumps 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.
[0003] Success of well construction operations may depend on many
factors, including the cost of drilling a well. The costs
associated with drilling a well are primarily time dependent.
Accordingly, the faster a target well depth is achieved, the lower
the cost for drilling the well. However, cost and time associated
with well construction may increase substantially if a wellbore
becomes unstable during drilling operations. Accordingly,
successful drilling operations depend on achieving a target well
depth as fast as possible, but within safety limits defined for the
drilling operations.
[0004] A target well depth may be achieved in a shortest amount of
time by drilling through subterranean formations at an optimum rate
of penetration (ROP). An optimum ROP that is achieved during
drilling operations depends on various drilling parameters,
including geological composition of the formation being drilled,
geometry and material of the drill bit, rotational speed (RPM) of
the drill bit, amount of torque applied to the drill bit, pressure
and flow rate of drilling fluid being pumped through the drill
string, and axial force applied at the drill bit, which may be
known in the industry as the weight on bit (WOB). An ROP generally
increases with increasing WOB, until a maximum beneficial WOB is
reached, thereafter decreasing the ROP with further increase of the
WOB. Thus, for a given well, an optimum WOB exists that will
achieve an optimum ROP. However, an optimum ROP for one set of
drilling parameters may not be optimal for another set of drilling
parameters.
SUMMARY OF THE DISCLOSURE
[0005] 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.
[0006] The present disclosure introduces an apparatus including a
system for controlling ROP by a drill bit of a drill string for
drilling a wellbore. The system includes a sensor facilitating an
ROP measurement indicative of a measured ROP. The system also
includes a controller having a processor and a memory storing
computer program code. The controller receives the ROP measurement,
determines an intermediate ROP setpoint based on the ROP
measurement, and determines an ROP command based on the
intermediate ROP setpoint. The ROP command is to be received by a
drawworks and is indicative of an intended ROP.
[0007] The present disclosure also introduces a method that
includes commencing operation of a control system for controlling
ROP by a drill bit of a drill string for drilling a wellbore. The
operating control system receives an ROP measurement, determines an
intermediate ROP setpoint based on the ROP measurement, and
determines an ROP command based on the intermediate ROP setpoint.
The ROP command is to be received by a drawworks and is indicative
of an intended ROP.
[0008] The present disclosure also introduces a computer program
product including a non-transitory, computer-readable medium having
computer instructions executable by a processor of a control system
communicatively connected with a drawworks for raising and lowering
a drill string. The computer instructions, when executed by the
processor, cause the control system to receive an ROP measurement,
determine an intermediate ROP setpoint based on the ROP
measurement, and determine an ROP command based on the intermediate
ROP setpoint. The ROP command is to be received by a drawworks and
is indicative of an intended ROP.
[0009] 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
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] FIG. 5 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.
[0016] FIG. 6 is a schematic view of at least a portion of an
example implementation of a user interface according to one or more
aspects of the present disclosure.
[0017] FIG. 7 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0018] FIG. 8 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
DETAILED DESCRIPTION
[0019] It is to be understood that the following disclosure
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.
[0020] Systems and methods (e.g., processes, operations, etc.)
according to one or more aspects of the present disclosure may be
used or performed in association with a well construction system at
a wellsite, such as for constructing a wellbore to obtain
hydrocarbons (e.g., oil and/or gas) or other natural resources from
a subterranean formation. A person having ordinary skill in the art
will readily understand that one or more aspects of systems and
methods disclosed herein may be utilized in other industries and/or
in association with other systems.
[0021] 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.
[0022] The well construction system 100 is depicted in relation to
a wellbore 102 formed by rotary and/or directional drilling from a
wellsite surface 104 and extending into a subterranean formation
106. The well construction system 100 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, etc.) 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.
[0023] 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.
[0024] The drill bit 126 may be rotated via operation of a top
drive 116 at the wellsite surface 104 and/or via operation of a
downhole mud motor 182 operatively connected with the drill bit
126. During rotary drilling operations, just the top drive 116 or
both the top drive 116 and the mud motor 182 may rotate the drill
bit 126. When just the top drive 116 rotates the drill bit 126, the
resulting average drill bit rotational rate is equal to the
rotational rate of the top drive 116. When both the top drive 116
and the mud motor 182 rotate the drill bit 126, the resulting
average drill bit rotational rate is equal to the sum of the
rotational rates of the top drive 116 and the mud motor 182. The
drill string 120 may also or instead be rotated by a rotary table
(not shown) that is rotatably supported on the rig floor 114.
Drilling torque applied to the drill string 120 by the top drive
116 or the rotary table to rotate the drill string 120 may be known
in the industry as rotary torque. Drilling torque applied to the
drill bit 126 may be known in the industry as torque on bit
(TOB).
[0025] The BHA 124 may also include one or more downhole tools 180,
181 connected above and/or below the mud motor 182. One or more of
the downhole tools 180, 181 may be or comprise a directional
drilling tool, such as a bent sub operable to facilitate slide
drilling or a rotary steerable system (RSS) operable to facilitate
directional drilling while continuously rotating the drill string
120 from the surface (e.g., via the top drive 116). One or more of
the downhole tools 180, 181 may be or comprise a power generating
sub having a mud-powered turbine operable to generate electrical
power to energize one or more of the electrical devices of the BHA
124.
[0026] One or more of the downhole tools 180, 181 may be or
comprise a measurement-while-drilling (MWD) or
logging-while-drilling (LWD) tools comprising downhole sensors 184
operable for the acquisition of measurement data pertaining to 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 tools 180, 181, and/or the mud motor
182) and/or other portions of the drill string 120 relative to the
wellbore 102 and/or the wellsite surface 104. The downhole sensors
184 may comprise a depth correlation sensor 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 drill string 120 within the
wellbore 102 and/or with respect to the wellsite surface 104. The
downhole sensors 184 may comprise one or more pressure sensors
operable to facilitate pressure data (i.e., pressure measurements)
indicative of internal pressure of the drilling fluid while flowing
158 within the internal passage 121 and/or indicative of external
pressure of the drilling fluid while flowing 159 within the annulus
108 of the wellbore 102.
[0027] The downhole sensors 184 may comprise an axial load sensor
operable to facilitate axial load data (i.e., axial load
measurements) indicative of axial load (i.e., weight) applied to
the drill bit 126 by the drill string 120. The axial load data may
thus comprise or otherwise be indicative of WOB that is applied by
the drill bit 126 to the formation 106 during drilling operations.
During drilling operations, the weight of the drill string 120 may
be greater than an optimum or otherwise intended WOB. As such, part
of the weight of the drill string 120 may be supported by the
hoisting system (e.g., the drawworks 118). Therefore, the drill
string 120 may be maintained in tension over some (e.g., most) of
its length above the BHA 124. The drill string 120 may also exhibit
buoyancy when submerged in the drilling fluid in the wellbore 102.
Therefore, WOB may be equal to the weight of the drill string 120
in the drilling mud, minus the amount of weight suspended by the
hoisting system. The WOB may be further offset (e.g., increased or
decreased) by friction between the drill string 120 and the
sidewall of the wellbore 102. The portion of the weight of the
drill string 120 supported by the hoisting system from the
travelling block 113 (or hook) may be known in the industry as the
hook load.
[0028] The downhole sensors 184 may comprise a torque sensor
operable to facilitate torque data (i.e., torque measurements)
indicative of TOB applied by the top drive 116 and/or mud motor 182
to the drill bit 126 during drilling operations. The torque data
may thus comprise or otherwise be indicative of drilling torque
applied by the drill bit 126 to the formation 106 during drilling
operations. The drilling torque output by the mud motor 182 may be
calculated based on the pressure data indicative of pressure of the
drilling fluid in the internal passage 121 at the mud motor 182 and
operational (e.g., structural) specifications of the mud motor
182.
[0029] One or more of the downhole tools 180, 181 may comprise a
downhole telemetry device 186 operable to communicate with the
surface equipment 110, such as via mud-pulse telemetry,
electromagnetic telemetry, and/or other telemetry means. One or
more of the downhole tools 180, 181 and/or other portion(s) of the
BHA 124 may 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.
[0030] The support structure 112 may support the top drive 116,
operable to connect 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 shown), may be utilized
in addition to or instead of the top drive 116 to impart the rotary
motion 117 to the drill string 120.
[0031] The top drive 116 may be suspended from (i.e., supported by)
the support structure 112 via a hoisting system operable to impart
vertical motion 135 to the top drive 116 and the drill string 120
connected to the top drive 116. During drilling operations, the top
drive 116, in conjunction with operation of the hoisting system,
may advance the drill string 120 into the formation 106 to form the
wellbore 102. The hoisting system may comprise a traveling block
113, a crown block 115, and a drawworks 118 storing a flexible line
123 (e.g., a cable, a wire rope, etc.). The crown block 115 may be
connected to and supported by the support structure 112, and the
traveling block 113 may be connected to and support the top drive
116. The drawworks 118 may be mounted to the rig floor 114. The
crown block 115 and traveling block 113 comprise pulleys or sheaves
around which the flexible line 123 is reeved to operatively connect
the crown block 115, the traveling block 113, and the drawworks
118. The drawworks 118 may comprise a drum and an electric motor
(not shown) operatively connected with and operable to rotate the
drum. The drawworks 118 may selectively impart tension to the
flexible line 123 to lift and lower the top drive 116, resulting in
the vertical movement 135 of the top drive 116 and the drill string
120 (when connected with the top drive 116). The drawworks 118 may
be operable to reel in the flexible 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 flexible line 123, causing
the traveling block 113 and the top drive 116 to move downward.
[0032] The hoisting system may further comprise a weight sensor 119
operable to output weight data (i.e., weight measurements)
indicative of weight of the drill string 120 at the surface. The
weight sensor 119 may be disposed or installed in association with
a top drive link, the elevator links 127, the elevator 129, a
deadline anchor (not shown), and/or other portions of the hoisting
system. The weight sensor 119 may be or comprise a load sensor
(e.g., a force sensor, a load cell, a strain gauge, etc.) operable
to output weight data indicative of load (i.e., weight) applied by
the drill string 120 to the hoisting system at the surface. The
weight data of the drill string 120 may comprise or be indicative
of hook load caused by the drill string 120.
[0033] The drill string hoisting system may further comprise a
position sensor 131 operable to output position data (i.e.,
position measurements) indicative of position of a predetermined
portion of the hoisting system. The position sensor 131 may be or
comprise a rotational position sensor disposed or installed in
association with, for example, the drum of the drawworks 118. The
position sensor 131 may thus be operable to output position data
indicative of rotational position of the drum. The position data
may be indicative of block position, which may be or comprise
position of the traveling block 113 or another portion of the drill
string hoisting system (e.g., top drive 116) supported by the
traveling block 113. The position data may be further indicative of
rotational speed of the drum, and thus indicative of linear speed
of the traveling block 113 and the drill string 120. The position
data may be further indicative of rotational acceleration of the
drum, and thus linear acceleration of the traveling block 113 and
the drill string 120. The position sensor 131 may be or comprise,
for example, an encoder, a rotary potentiometer, or a rotary
variable-differential transformers (RVDTs).
[0034] 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 motor (e.g., an
electric motor) (not shown) of the top drive 116. 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. The elevator links 127 and the elevator 129 of
the top drive 116 may handle tubulars (e.g., joints and/or stands
of drillpipe, drill collars, casing, 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.
[0035] A torque sensor 128 (e.g., a torque sub) may be mechanically
connected or otherwise disposed between an upper end of the drill
string 120 and a drive shaft 125 of the top drive 116, such as may
permit the torque sensor to transfer and measure torque output by
the top drive 116. The torque sensor 128 may be operable to output
torque data (i.e., torque measurements) indicative of torque
applied by the top drive 116 to the drill string 120. The torque
sensor 128 may also facilitate determination of rotational
position, rotational distance, rotational speed, and/or rotational
acceleration of the drive shaft 125. A top drive controller (e.g.,
a VFD) may also operate as a torque sensor operable to determine
torque output by the top drive 116 to the drill string 120, such as
based on the electrical power (e.g., current, voltage, frequency,
etc.) delivered to the electric motor of the top drive 116.
[0036] 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., drilling mud), and one or more pumps
144 operable to move the drilling fluid 140 from the container 142
into the fluid passage 121 of the drill string 120 via a fluid
conduit 145 (i.e., a standpipe) extending from the pump 144 to the
top drive 116 and an internal passage extending through the top
drive 116 (not shown).
[0037] A pressure sensor 147 may be connected along the fluid
conduit 146 to measure pressure of the drilling fluid being pumped
downhole. The pressure sensor 147 may be operable to output
pressure data (i.e., pressure measurements) indicative of pressure
of the drilling fluid at the wellsite surface 104 being pumped
downhole via the drill string 120. The pressure sensor 147 may be
connected close to the top drive 116 or at top of the conduit 145,
such as may permit the pressure sensor 147 to measure the pressure
within the drill string 120 at the top of the internal passage 121
of the drill string 120. The pressure of the drilling fluid at the
wellsite surface 104 being pumped downhole may be known in the
industry as standpipe pressure.
[0038] The pressure sensor 147 may be used to determine
differential pressure, by measuring the standpipe pressure while
the drill bit 126 is on-bottom (i.e., contacting the bottom of the
wellbore 102) during drilling operations, measuring the standpipe
pressure while the drill bit 126 is off-bottom (i.e., not
contacting the bottom of the wellbore 102) and the drilling fluid
is being pumped downhole to rotate the drill bit 126 via the mud
motor 182, and then calculating the difference between the two
standpipe pressure measurements. Thus, the differential pressure
may be or comprise an increase in standpipe pressure while drilling
relative to standpipe pressure while off-bottom. The off-bottom
standpipe pressure may be determined (i.e., taken) after each piece
of drill pipe (or stand) is connected, before going on-bottom, but
while rotating the drill via the mud motor 182 and pumping drilling
fluid at the nominal drilling flowrate. The differential pressure
may be known in the industry as DeltaP (or AP).
[0039] 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 mud motor 182 and/or
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 in FIG. 1 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, in conjunction with the
weight-on-bit (WOB), may advance the drill string 120 through the
formation 106 to form the wellbore 102.
[0040] 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 of the wellbore 102 via one or more
components of the fluid control equipment 130, such as a bell
nipple, a rotating control device (RCD), and/or a ported adapter
(e.g., a spool, a cross adapter, a wing valve, etc.). The drilling
fluid may then pass through one or more fluid conduits 151 into
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.
[0041] A pressure sensor 153 may be connected along one or more of
the fluid conduits 151 to measure pressure of the drilling fluid
exiting the annulus 108 via one or more components of the fluid
control equipment 130. The pressure sensor 153 may be operable to
output pressure data (i.e., pressure measurements) indicative of
the pressure of the drilling fluid exiting the annulus 108. The
pressure sensor 153 may be connected close to the fluid control
equipment 130, such as may permit the pressure sensor 153 to
measure the pressure of the drilling fluid at the top of the
annulus 108 proximate the wellsite surface 104. Monitoring annular
pressure may aid in diagnosing condition of the wellbore 102 and
help prevent or otherwise avoid potentially dangerous well control
issues. Monitoring annular pressure during drilling operations,
when used in conjunction with measuring and controlling other
drilling parameters, may improve steering performance and aid in
detection of abnormal events, such as sticking, hanging or balling
stabilizers, drilling fluid problems, and cuttings build-up.
[0042] 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), a hoisting system
(e.g., the drawworks 118 and the blocks 113, 115), a drilling fluid
circulation system (e.g., the mud pump 144 and the fluid conduit
145), a drilling fluid cleaning and reconditioning system (e.g.,
the drilling fluid reconditioning equipment 170 and the containers
142, 148), the well control system (e.g., a BOP stack, a choke
manifold, and/or other components of the fluid control equipment
130), 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, a truck or other
service vehicle, etc.) containing a control workstation 197, which
may be operated by rig personnel 195 (e.g., a driller or other
human rig operator(s)) to monitor and control various wellsite
equipment and/or portions of the well construction system 100. The
control workstation 197 may be communicatively connected with a
central (or surface) 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 surface equipment 110 and downhole equipment 120 described
herein, and may be operable to receive signals (e.g., sensor data,
sensor measurements, etc.) from and transmit signals (e.g., control
data, control signals, control commands, etc.) to the equipment to
perform various operations described herein. The controller 192 may
store executable program code, instructions, and/or operational
parameters or setpoints, 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.
[0043] Communication (i.e., telemetry) between the BHA 124 and the
controller 192 may be via mud-pulse telemetry (i.e., pressure
pulses) sent through the drilling fluid flowing within a fluid
passage 121 of the drill string 120. For example, the downhole
telemetry device 186 may comprise a modulator selectively operable
to modulate the pressure (i.e., cause pressure changes, pulsations,
and/or fluctuations) of the drilling fluid flowing within the fluid
passage 121 of the downhole tool 189 to transmit downhole data
(i.e., downhole measurements) received from the downhole controller
188, the downhole sensors 184, and/or other portions of the BHA 124
in the form of pressure pulses. The modulated pressure pulses
travel uphole along the drilling fluid through the fluid passage
121, the top drive 116, and the fluid conduit 145 to be detected by
an uphole telemetry device 149. The uphole telemetry device 149 may
comprise a pressure transducer or sensor in contact with the
drilling fluid being pumped downhole. The uphole telemetry device
149 may thus be disposed along or in connection with the fluid
conduit 145, the top drive 116, and/or another conduit or device
transferring or in contact with the drilling fluid being pumped
downhole. The uphole telemetry device 149 may be operable to detect
the modulated pressure pulses, convert the pressure pulses to
electrical signals, and communicate the electrical signals to the
controller 192. The controller 192 may be operable to interpret the
electrical signals to reconstruct the downhole data transmitted by
the downhole telemetry device 186. Although shown and described as
separate devices, the pressure sensor 147 and the uphole telemetry
device 149 may be or form the same device.
[0044] 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 one or more
input devices 194 (e.g., one or more keyboards, mouse devices,
joysticks, touchscreens, etc.) and one or more output devices 196
(e.g., one or more video monitors, touchscreens, printers, audio
speakers, etc.). Communication between the controller 192, the
input and output devices 194, 196, and various sensors 119, 128,
131, 147, 149 of the well construction system 100 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.
[0045] 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.
[0046] The present disclosure further provides various
implementations of systems and/or methods for controlling one or
more portions of the well construction system 100. FIG. 2 is a
schematic view of at least a portion of an example implementation
of a drilling rig control system 200 (hereinafter "rig control
system") for monitoring and controlling various equipment,
portions, and subsystems of the well construction system 100 shown
in FIG. 1. The rig control system 200 may comprise one or more
features of the well construction system 100, including where
indicated by the same reference numerals. Accordingly, the
following description refers to FIGS. 1 and 2, collectively.
However, the rig control system 200 depicted in FIG. 2, as well as
other implementations of rig control systems also within the scope
of the present disclosure, may also be applicable or readily
adapted for utilization with other implementations of well
construction systems also within the scope of the present
disclosure.
[0047] The various pieces of well construction equipment described
above and shown in FIGS. 1 and 2 may each comprise one or more
actuators (e.g., combustion, hydraulic, and/or electric), which
when operated may cause the corresponding well construction
equipment to perform intended actions (e.g., work, tasks,
movements, operations, etc.). Each piece of well construction
equipment may further carry or comprise one or more sensors
disposed in association with a corresponding actuator or another
portion of the piece of equipment. Each sensor may be
communicatively connected with a corresponding equipment controller
and operable to generate sensor data (e.g., electrical sensor
signals or measurements) indicative of an operational (e.g.,
mechanical or physical) status of the corresponding actuator or
component, thereby permitting the operational status of the
actuator to be monitored by the equipment controller. The sensor
data may be utilized by the equipment controller as feedback data,
permitting operational control of the piece of well construction
equipment and coordination with other well construction equipment.
Such sensor data may be indicative of performance of each
individual actuator and, collectively, of the entire piece of well
construction equipment.
[0048] The rig control system 200 may be in real-time communication
with one or more components, subsystems, systems, and/or other
equipment of the well construction system 100 that are monitored
and/or controlled by the rig control system 200. As described
above, the equipment of the well construction system 100 may be
grouped into several subsystems, each operable to perform a
corresponding operation and/or a portion of the well construction
operations described herein. For example, the subsystems may
include a drill string rotation system 211 (e.g., the top drive
116), a hoisting system 212 (e.g., the drawworks 118 and the blocks
113, 115), a drilling fluid circulation system 213 (e.g., the mud
pump 144 and the fluid conduit 145), a drilling fluid cleaning and
reconditioning (DFCR) system 214 (e.g., the drilling fluid
reconditioning equipment 170 and the containers 142, 148), a well
control system 215 (e.g., a BOP stack, a choke manifold, and/or
other components of the fluid control equipment 130), and the BHA
124 (designated in FIG. 2 by reference number 216), among other
examples. The control workstation 197 may be utilized by rig
personnel to monitor, configure, control, and/or otherwise operate
one or more of the subsystems 211-216.
[0049] Each of the well construction subsystems 211-216 may further
comprise various communication equipment (e.g., modems, network
interface cards, etc.) and communication conductors (e.g., cables)
communicatively connecting the equipment (e.g., sensors and
actuators) of each subsystem 211-216 with the control workstation
197 and/or other equipment. Although the well construction
equipment described above and shown in FIG. 1 is associated with
certain wellsite subsystems 211-216, such associations are merely
examples that are not intended to limit or prevent such well
construction equipment from being associated with two or more of
the wellsite subsystems 211-216 and/or different wellsite
subsystems 211-216.
[0050] One or more of the subsystems 211-216 may include one or
more local controllers 221-226, each operable to control various
well construction equipment of the corresponding subsystem 211-216
and/or an individual piece of well construction equipment of the
corresponding subsystem 211-216. Each well construction subsystem
211-216 includes various well construction equipment comprising
corresponding actuators 241-246 for performing operations of the
well construction system 100. One or more of the subsystems 211-216
may include various sensors 231-236 operable to generate or output
sensor data (e.g., signals, information, measurements, etc.)
indicative of operational status of the well construction equipment
of the corresponding subsystem 211-216. Each local controller
221-226 may output control data (i.e., control commands, signals,
and/or information) to one or more actuators 241-246 to perform
corresponding actions of a piece of equipment of the corresponding
subsystem 211-216. One or more of the local controllers 221-226 may
receive sensor data generated by one or more corresponding sensors
231-236 indicative of operational status of an actuator or another
portion of a piece of equipment of the corresponding subsystem
211-216. Although the local controllers 221-226, the sensors
231-236, and the actuators 241-246 are each shown as a single
block, it is to be understood that each local controller 221-226,
sensor 231-236, and actuator 241-246 may illustratively represent a
plurality of local controllers, sensors, and actuators.
[0051] The sensors 231-236 may include sensors utilized for
operation of the various subsystems 211-216 of the well
construction system 100. For example, the sensors 231-236 may
include cameras, position sensors, pressure sensors, temperature
sensors, flow rate sensors, vibration sensors, current sensors,
voltage sensors, resistance sensors, gesture detection sensors or
devices, voice actuated or recognition devices or sensors, and/or
other examples. The sensor data may include signals, information,
and/or measurements indicative of equipment operational status
(e.g., on or off, up or down, set or released, etc.), drilling
parameters (e.g., depth, hook load, torque, etc.), auxiliary
parameters (e.g., vibration data of a pump), flow rate,
temperature, operational speed, position, and pressure, among other
examples. The acquired sensor data may include or be associated
with a timestamp (e.g., date and/or time) indicative of when the
sensor data was acquired. The sensor data may also or instead be
aligned with a depth or other drilling parameter.
[0052] For example, the sensors 231 may comprise one or more
rotation sensors (e.g., the torque sub 128) operable to output or
otherwise facilitate rotational position, rotational speed, and/or
rotational acceleration measurements of the top drive 116 (e.g.,
the drive shaft 125) indicative of rotational position, rotational
speed, and/or rotational acceleration of the upper end of the drill
string 120 connected to the top drive 116. The sensors 231 may also
comprise one or more torque sensors (e.g., the torque sub 128)
operable to facilitate torque measurements indicative of torque
output by the top drive 116 to the top of the drill string 120. The
torque sensors may also or instead be or comprise a variable
frequency drive (VFD) supplying electrical power to the top drive
116, whereby torque output by the top drive 116 to the drill string
120 may be measured or otherwise determined based on measurements
of electrical current transmitted to the top drive 116 by the VFD.
The sensors 232 may comprise one or more rotation sensors (e.g.,
the sensor 131) operable to output or otherwise facilitate
rotational position, rotational speed, and/or rotational
acceleration measurements of the drawworks 118 indicative of
vertical position, vertical speed, and/or vertical acceleration of
the traveling block 113 and the drill string 120 (including the BHA
124) connected to the travelling block 113 via the top drive 116.
The sensors 232 may comprise a weight sensor 119 (e.g., the sensor
119) operable to output weight data (i.e., weight measurements)
indicative of weight of the drill string 120 at the surface. The
sensors 233 may comprise one or more pressure sensors (e.g., the
sensors 147, 153) operable to facilitate pressure measurements
indicative of pressure of the drilling fluid being pumped downhole
by the mud pumps 144 via the internal fluid passage 121 of the
drill string 120. The pressure sensors may be disposed at the
outlets of the pumps 144 and/or along the fluid conduits 145, 151.
The sensors 236 may comprise axial load sensors, torque sensors,
pressure sensors, position sensors (e.g., the sensors 184) disposed
downhole within or as part of the BHA 216 (e.g., the BHA 124).
[0053] The local controllers 221-226, the sensors 231-236, and the
actuators 241-246 may be communicatively connected with a central
controller 192. For example, the local controllers 221-226 may be
in communication with the sensors 231-236 and actuators 241-246 of
the corresponding subsystems 211-216 via local communication
networks (e.g., field buses) (not shown) and the central controller
192 may be in communication with the subsystems 211-216 via a
central communication network 209 (e.g., a data bus, a field bus, a
wide-area-network (WAN), a local-area-network (LAN), etc.). The
sensor data generated by the sensors 231-236 of the subsystems
211-216 may be made available for use by the central controller 192
and/or the local controllers 221-226. Similarly, control data
(i.e., control commands, signals, and/or information) output by the
central controller 192 and/or the local controllers 221-226 may be
automatically communicated to the various actuators 241-246 of the
subsystems 211-216, perhaps pursuant to predetermined programming,
such as to facilitate well construction operations and/or other
operations described herein. Although the central controller 192 is
shown as a single device (i.e., a discrete hardware component), it
is to be understood that the central controller 192 may be or
comprise a plurality of equipment controllers and/or other
electronic devices collectively operable to perform operations
(i.e., computational processes or methods) described herein.
[0054] The sensors 231-236 and actuators 241-246 may be monitored
and/or controlled by corresponding local controllers 221-226 and/or
the central controller 192. For example, the central controller 192
may be operable to receive sensor data from the sensors 231-236 of
the subsystems 211-216 in real-time, and to output real-time
control data directly to the actuators 241-246 of the subsystems
211-216 based on the received sensor data. However, certain
operations of the actuators 241-246 of one or more of the
subsystems 211-216 may be controlled by a corresponding local
controller 221-226, which may control the actuators 241-246 based
on sensor data received from the sensors 231-236 of the
corresponding subsystem 211-216 and/or based on control data
received from the central controller 192.
[0055] The rig control system 200 may be a tiered control system,
wherein control of the subsystems 211-216 of the well construction
system 100 may be provided via a first tier of the local
controllers 221-226 and a second tier of the central controller
192. The central controller 192 may facilitate control of one or
more of the subsystems 211-216 at the level of each individual
subsystem 211-216. For example, in the hoisting system 212, sensor
data may be fed into the local controller 242, which may respond to
control the actuators 232. However, for control operations that
involve more than one of the subsystems 211-216, the control may be
coordinated through the central controller 192 operable to
coordinate control of well construction equipment of two, three,
four, or more (each) of the subsystems 211-216.
[0056] The downhole controller 188, the central controller 192, the
local controllers 221-226, and/or other controllers or processing
devices (individually or collectively referred to hereinafter as an
"equipment controller") of the rig control system 200 may each or
collectively be operable to receive and store machine-readable and
executable program code instructions (e.g., computer program code,
algorithms, programmed processes or operations, etc.) on a memory
device (e.g., a memory chip) and then execute the program code
instructions to run, operate, or perform a process for monitoring
and/or controlling the well construction equipment of the well
construction system 100. Equipment controllers 188, 192, 221-226
within the scope of the present disclosure can include, for
example, programmable logic controllers (PLCs), industrial
computers (IPCs), personal computers (PCs), soft PLCs, variable
frequency drives (VFDs), and/or other controllers or processing
devices operable to store and execute program code instructions,
receive sensor data, and output control data (i.e., control
commands, signals, and/or information) to cause operation of the
well construction equipment based on the program code instructions,
sensor data, and/or control data.
[0057] A control workstation 197 may be communicatively connected
with the central controller 192 and/or the local controllers
221-226 via the communication network 209, such as to receive
sensor data from the sensors 231-236 and transmit control data to
the central controller 192 and/or the local controllers 221-226 to
control the actuators 241-246. Accordingly, the control workstation
197 may be utilized by rig personnel (e.g., a driller) to monitor
and control the actuators 241-246 and other portions of the
subsystems 211-216 via the central controller 192 and/or local
controllers 221-226.
[0058] The central controller 192 may be operable to receive and
store machine-readable and executable program code instructions on
a memory device and then execute such program code instructions to
run, operate, or perform a control process 250 (e.g., a coordinated
control process or anther computer process). Each local controller
221-226 may execute a corresponding control process (e.g., a local
control process or another computer processor) (not shown). Two or
more of the local controllers 221-226 may execute their local
control processes to collectively coordinate operations between
well construction equipment of two or more of the subsystems
211-216. The control process 250 of the central controller 192 may
operate as a mechanization manager of the rig control system 190,
such as by coordinating operational sequences of the well
construction equipment of the well construction system 100. The
control process of each local controller 221-226 may facilitate a
lower (e.g., basic) level of control within the rig control system
200 to operate a corresponding piece of well construction equipment
or a plurality of pieces of well construction equipment of a
corresponding subsystem 211-216. Such control process may
facilitate, for example, starting, stopping, and setting or
maintaining an operating speed of a piece of well construction
equipment.
[0059] Each control process being executed by an equipment
controller of the rig control system 200 may receive and process
(i.e., analyze) sensor data (i.e., sensor measurements) from one or
more of the sensors 231-236 according to the program code
instructions, and generate control data (i.e., control commands) to
operate or otherwise control one or more of the actuators 241-246
of the well construction equipment. The control process 250 of the
central controller 192 may output control data directly to the
actuators 241-246 to control the well construction operations. The
control process 250 may also or instead output control data to the
control process of one or more local controllers 221-226, wherein
each control process of the local controllers 221-226 may then
output control data to the actuators 241-246 of the corresponding
subsystem 211-216 to control a portion of the well construction
operations performed by that subsystem 211-216. Thus, the control
processes of equipment controllers (e.g., the central controller
192 and/or the local controllers 221-226) of the rig control system
200 individually and collectively perform monitoring and control
operations described herein, including monitoring and controlling
well construction operations. The program code instructions forming
the basis for the control processes described herein may comprise
rules (e.g., algorithms) based upon the laws of physics for
drilling and other well construction operations.
[0060] The central controller 192 may also or instead be operable
to receive and store machine-readable and executable program code
instructions on a memory device and then execute such program code
instructions to run, operate, or perform an automatic drilling
control process 252 (hereinafter an "autodriller") to automatically
control predetermined drilling operations performed by the
drawworks 118. The autodriller 252 may be executed by the central
controller 190 and/or the autodriller 252 may be executed by a
separate controller (i.e., a processing device) that includes
hardware and/or software with functionality for controlling the
drawworks 118. The autodriller 252 may also or instead be executed
by a local controller 222 for controlling the drawworks 118.
[0061] The autodriller 252 may receive and process (i.e., analyze)
sensor data (i.e., sensor measurements) from one or more of the
sensors 231, 232, 233, 236 according to the program code
instructions, and generate control data (i.e., control commands) to
operate or otherwise control one or more of the actuators 242
(e.g., drawworks 118) of the hoisting system 212 to control at
least a portion of the drilling operations (e.g., ROP). The
autodriller 252 may output control data directly to the actuators
242 to control the drilling operations. The autodriller 252 may
also or instead output control data to one or more local
controllers 222, which may then output control data to the
actuators 242.
[0062] The autodriller 252 may automatically control predetermined
drilling operations based on various operational measurements
(i.e., sensor data), including WOB, drilling torque, and DeltaP (or
standpipe pressure). The autodriller 252 may then output ROP
control commands (i.e., control data) indicative of intended ROP
based on such operational measurements. The ROP control commands
may then be received by the drawworks 118 to control downward speed
of the travelling block 113 and thus control downward speed of the
drill string 120 to achieve an intended (e.g., optimal) ROP. The
autodriller 252 may be operable to cause the drawworks 118 to
achieve the intended ROP and/or to maintain intended setpoints of
WOB, drilling torque, and/or DeltaP. The intended setpoints of WOB,
drilling torque, and DeltaP may be selected by rig personnel or
automatically by the autodriller 252.
[0063] FIGS. 3-5 are schematic views of example implementations of
control systems 301, 302, 303, respectively, each operable to
execute program code instructions to run, operate, or perform the
autodriller 252 shown in FIG. 2. Each control system 301, 302, 303
may be implemented by or form at least a portion of one or more of
the central controller 192 and/or the local controllers 221, 222,
223, 226 shown in FIGS. 1 and 2. Accordingly, the following
description refers to FIGS. 1-5, collectively.
[0064] FIG. 3 shows an example implementation of the control system
301, which may comprise a WOB controller 310, a drilling torque
controller 320, a DeltaP controller 330, and an ROP controller 340.
The ROP controller 340 may be operable to receive information
(e.g., control data) from the WOB controller 310, the drilling
torque controller 320, and the DeltaP controller 330 and output an
ROP output 345 (i.e., a control command). For example, the WOB
controller 310 may output a normalized WOB output 315 in response
to a WOB input (i.e., WOB measurements) from a WOB sensor 184.
While the WOB output 315 is shown transmitted from the WOB
controller 310 to the ROP controller 340 as normalized WOB output
315, it is to be understood that normalization of data from the WOB
sensor 184 of the WOB controller 310 may be performed either by the
WOB controller 310, the ROP controller 340, or an external
normalization unit (not shown) located between the WOB controller
310 and the ROP controller 340. Furthermore, although the term
"normalized" may refer to any scheme and scale for normalizing
output across multiple data sources, selected implementations of
the present disclosure are operable to normalize the WOB output 315
to a range between zero (0) and one (1).
[0065] Similarly, the drilling torque controller 320 is operable to
communicate with the ROP controller 340. As such, the drilling
torque controller 320 may receive a drilling torque input (i.e.,
drilling torque measurements) from a downhole torque sensor 184 and
convert the drilling torque input to a normalized TOB output 325 to
be received by the ROP controller 340. The torque sensor 184 in
communication with drilling torque controller 320 may be operable
to measure torque (i.e., TOB) applied to the drill bit 126.
However, the drilling torque controller 320 may also or instead be
operable to receive rotary torque input from a surface torque
sensor 128 operable to measure torque applied to the drill string
120 at the surface by the top drive 116 or rotary table. It is to
be understood that because of frictional losses and the composition
and geometry of the drill string 120, the rotary drilling torque
applied to the drill string 120 at the surface may not be equal to
the TOB, but operate as an approximation of the TOB. Nonetheless,
the drilling torque controller 320 may receive and process the
rotary drilling torque applied to the drill string 120 at the
surface as an approximation of the TOB. Regardless of which
drilling torque input the drilling torque controller 320 receives,
the drilling torque controller 320 may be operable to convert the
drilling torque input to the normalized TOB output 325 for use by
the ROP controller 340.
[0066] Similarly, the DeltaP controller 330 may be operable to
communicate with ROP controller 340. As such, the DeltaP controller
330 may be operable to receive DeltaP input (i.e., DeltaP
measurements) from the pressure sensor 147 and convert that input
to a normalized DeltaP output 335 for communication to the ROP
controller 340. Depending on the type and configuration of the well
construction equipment of the well construction system 100, the
DeltaP inputs may be of various types and configurations. For
example, the DeltaP controller 330 may receive two separate
pressure inputs and calculate the DeltaP input internally. The
DeltaP controller 330 may receive the first pressure input from the
pressure sensor 147 while the drill bit 126 is off-bottom and being
rotated by the mud motor 182 and a second pressure input while the
drill bit 126 is on-bottom and being rotated by the mud motor 182
to perform the drilling operations. The DeltaP controller 330 may
also or instead receive the DeltaP input from an external device
that calculates a non-normalized DeltaP input and transmits it to
the DeltaP controller 330.
[0067] Additionally, one or more of the controllers 310, 320, 330
may be operable to generate more than one output. Furthermore, the
controllers 310, 320, 330 may be toggled on and off by a user
(e.g., rig personnel) and therefore, at predetermined times, not
provide a normalized output 315, 325, 335 to the ROP controller
340.
[0068] In addition to receiving the normalized outputs 315, 325,
335, the ROP controller 340 may be further operable to receive an
ROP setpoint 342, which may be or comprise an intended or target
ROP for the control system 301. As such, the ROP setpoint 342 may
be selected through one of many methods known to one of ordinary
skill in the art. For example, the ROP setpoint 342 may be an
estimated maximum ROP for the formation 106 the drill bit 126 is
expected to be drilling through or the ROP setpoint 342 may be a
value selected based on experience with similar formations 106 in
the same region. Regardless of how the ROP setpoint 342 is
determined, the ROP setpoint 342 may be a value that, absent the
control system 301, controls the ROP of the drill string 120 into
the formation 106. Such control may come in the form of varying the
hook load of a hoisting system 212 or varying the amount of thrust
or lift applied to the top drive 116. The ROP setpoint 342 may
represent a maximum ROP for the control system 100, with the
controllers 310, 320, 330 operating to retard the maximum ROP as
intended. The ROP setpoint 342 may be entered into the ROP
controller 340 by a user (e.g., rig personnel) or automatically by
another controller.
[0069] The ROP controller 340 may receive the normalized outputs
315, 325, 335 and ROP setpoint 342 as inputs, and generate the ROP
output 345 based on the received normalized outputs 315, 325, 335
and ROP setpoint 342. The ROP controller 340 may determine (i.e.,
calculate) the ROP output 345 by taking a product of (i.e.,
multiplying) the ROP setpoint 342 and the normalized outputs 315,
325, 335. The controller outputs 315, 325, 335 may be normalized to
be between zero (0) and one (1), such that their product will also
be calculated to be between zero (0) and one (1). Therefore, the
product of the normalized outputs 315, 325, 335 and the ROP
setpoint 342, and thus the ROP output 345, will also be between
zero (0) and the value of the ROP setpoint 342. Thus, the inputs to
the controllers 310, 320, 330 may be normalized, such that their
corresponding normalized outputs 315, 325, 335 may be "scaled"
while maximum and/or minimum permissive values for WOB, TOB, and
DeltaP are reached. For example, if the WOB sensor 184 facilitates
a WOB input ranging between zero (0) and one hundred (100), with
eighty (80) being the maximum permitted WOB, then the WOB
controller 310 may generate a normalized WOB output 315 of zero (0)
when the WOB input is eighty (80) and above, and a normalized WOB
output 315 of one (1) when the WOB input is less than thirty (30).
Thus, the normalized WOB output 315 may be scaled between zero (0)
and one (1) for the WOB input ranging between thirty (30) and
eighty (80), depending on how critical the WOB input is to the
success of drilling operations. The normalized TOB output 325 and
the normalized DeltaP output 335 may be similarly scaled to reflect
their effect on the ROP output 345.
[0070] FIG. 4 show an example implementation of the control system
302, which may include controllers 310, 320, 330 operable to
receive predetermined inputs 311, 312, 321, 322, 331, 332 and
generate corresponding normalized outputs 315, 325, 335 based on
such inputs 311, 312, 321, 322, 331, 332. For example, the WOB
controller 310 may be operable to receive a WOB setpoint 311, which
may be defined by a user (e.g., rig personnel), and a measured WOB
input 312, which may be received from the WOB sensor 184 installed
along the drill string 120. The user-defined WOB setpoint 311 may
be selected by a driller, a project engineer, or a programming
engineer. The user-defined WOB setpoint 311 may also or instead be
received from a computer simulation, a database of historical
drilling records, or a computer having artificial intelligence (AI)
capabilities. Similarly, the drilling torque controller 320 may be
operable to receive a drilling torque setpoint 321, which may be
defined by a user, and a measured drilling torque input 322, which
may be received from the torque sensors 128, 184 installed along
the drill string 120 or in association with the top drive 116. The
DeltaP controller 330 may be operable to receive a DeltaP setpoint
331, which may be defined by a user, and a measured DeltaP input
332, which may be received from the pressure sensor 147.
[0071] The normalized WOB output 315, the normalized TOB output
325, and the normalized DeltaP output 335 may be normalized to fall
between zero (0) and one (1). Such normalization of the outputs
315, 325, 335 (which are received as inputs by the ROP controller
340) between zero (0) and one (1) facilitates a simplified process
in which decimal numbers may be viewed or interpreted as
percentages. For example, a normalized value of 0.453 may be
interpreted as 45.3%, which can then be scaled and manipulated for
use by the control system 302. However, it is to be understood that
the normalized values may fall between or within other numerical
ranges. For example, the normalized values may be normalized
between zero (0) and three (3) or zero (0) and one hundred (100),
and so on.
[0072] FIG. 5 shows an example implementation of the control system
303, which may include controllers 310, 320, 330 operable to
execute predetermined internal processes to generate normalized
outputs 315, 325, 335. For example, a WOB controller 310 may
compare a measured WOB input 312 (i.e., WOB present value or "Pv")
with a WOB setpoint 311 ("Sp"). The difference (i.e., an error
signal) may be received by a PI control 314 to calculate a new
value for the normalized WOB output 315 ("K1") to be input to an
ROP controller 340, which may cause the ROP controller 340 to
change the drilling operations (e.g., drawworks operations) such
that the measured WOB input 312 is equal to or approaches the WOB
setpoint 311. A gain setpoint 313 ("GainSp") may be input to the PI
control 314 to provide a constant used to change (e.g., increase)
the new value for the normalized WOB output 315 generated by the PI
control 314. It is to be understood that PID control may be used in
addition to or instead of the PI control 314. As such, additional
control inputs or constants may be used. Furthermore, the new value
for the normalized WOB output 315 generated by the PI control 314
may be a value representing a percent change (up or down) used by
the control system 303. Although the output 315 is shown as a
percentage (i.e., between zero (0) and one (1)), the output 315 may
instead be represented in other ways. For example, the output 315
may be a numerical value specifically representative of the shift
needed to correct the error signal. Further, an absolute value of
the output 315 may be taken and then normalized to fall between
zero (0) and one (1). Such operations may be executed by the WOB
controller 310, by a separate or external normalization unit (not
shown), or by the ROP controller 340.
[0073] A similar process may be executed by the drilling torque
controller 320 to generate a new normalized TOB output 325 ("K2")
via a corresponding PI control 324 based on a difference between a
measured drilling torque input 322 (present value or "Pv") and the
drilling torque setpoint 321 ("Sp"). The new normalized TOB output
325 may also be changed by a corresponding gain setpoint 323
("GainSp"). A similar process may be executed by the DeltaP
controller 330 to generate a new normalized DeltaP output 335
("K3") via a corresponding PI control 334 based on a difference
between a measured DeltaP input 332 (present value or "Pv") and the
DeltaP setpoint 331 ("Sp"). The new normalized DeltaP output 335
may also be changed by a corresponding gain setpoint 333
("GainSp").
[0074] The ROP controller 340 may comprise a direction generator
341 operable to calculate a direction indicator 343 ("K4") for the
ROP output 345. Although the calculation for the direction
indicator 343 for the ROP output 345 is shown calculated by the ROP
controller 340, such calculations may be performed externally, such
as by one or more of the controllers 310, 320, 330, and
incorporated into the normalized outputs 315, 325, 335. The
direction generator 341 may permit the control system 303 to
control the rate of release of the drill string 120 by the
drawworks 118 and, in certain circumstances, to raise the drill
string 120 by the drawworks 118. Thus, the direction generator 341
may output a positive indicator 343 or a negative indicator 343,
wherein a positive indicator 343 indicates that the drill string
120 is being released (i.e., lowered) and a negative indicator 343
indicates that the drill string 120 is being taken up (i.e.,
raised). Accordingly, the direction generator 341 may be operable
to output a positive indicator 343 during normal drilling
operations and output a negative indicator 343 during extraordinary
or otherwise abnormal circumstances. For example, the direction
generator 341 may be operable to output a negative indicator 343
when a measured input 312, 322, 332 falls outside a predetermined
tolerance value or when a normalized output 315, 325, 335 is
assigned a negative value by a corresponding controller 310, 320,
330.
[0075] After the normalized outputs 315, 325, 335, the direction
indicator 343, and the ROP setpoint 342 are received by ROP
controller 340, such values may be multiplied together to generate
the ROP output 345. The order in which the values are multiplied
together does not matter and may therefore occur in any order. One
or more of the normalized outputs 315, 325, 335 may be omitted and
other inputs indicative of other drilling factors may be input to
the ROP controller 340 in any order. Because the normalized outputs
315, 325, 335 range between zero (0) and one (1), other normalized
outputs to be received by the ROP controller 340 may be added or
removed without affecting the scale of the remaining normalized
outputs 315, 325, 335.
[0076] Each controller 310, 320, 330 may comprise a corresponding
switch 316, 326, 336 operable to permit the corresponding
controllers 310, 320, 330 to be turned on or off with respect to
the ROP controller 340. When turned off, each corresponding
controller 310, 320, 330 may output a default value of one (1) as
the normalized output 315, 325, 335 to the ROP controller 340.
Because multiplying a value of one (1) has no effect on a
mathematical product (i.e., solution for multiplication), a
normalized output 315, 325, 335 having a value of one (1) has the
same effect as turning off a controller 310, 320, 330. Nonetheless,
a product of the normalized outputs 315, 325, 335 produces the ROP
output 345, which may be known in the industry as a block velocity
setpoint.
[0077] FIG. 6 is an example user interface 350 (e.g., a display
screen, a control panel, etc.) that may be displayed on a video
output device, a touchscreen, or other output devices 196 of the
workstation 197 or another workstation of the well construction
system 100 and/or located remotely from the wellsite 104. The user
interface 350 may be used by a user (e.g., rig personnel) to
monitor and control execution of the autodriller 252 by the central
controller 190 and/or the local controllers 221-226 forming one or
more of the control systems 301, 302, 303.
[0078] The interface 350 may comprise an input panel 352 where the
ROP setpoint 342 may be entered manually or via a corresponding
slider arrow that may be dragged to an intended value of the ROP
setpoint 342. A measured ROP 346 may be shown graphically and/or
numerically.
[0079] Similarly, the WOB setpoint 311, the TOB setpoint 321, and
the DeltaP setpoint 331 may be entered and displayed on the input
panel 352. Furthermore, the measured WOB 312, the measured drilling
torque 322, and the measured DeltaP 332 may be displayed in a
similar fashion. Status of the switches 316, 326, 336 for
selectively engaging and disengaging each controller 310, 320, 330
(i.e., the WOB, TOB, and DeltaP factors) to and from the ROP
controller 340 may also be indicated. Status of switch 347 for
selectively turning on and off the ROP controller 240 may also be
indicated. The user interface 350 may include a response adjuster
input panel 354 where the user may speed up or slow down control
loops by adjusting the default loop gains. The user interface 350
may include a trend window 356 for displaying to the user response
of the controllers 310, 320, 330 (i.e., operation of the
autodriller 252) over a defined period of time (e.g., a few
minutes, an hour, a few hours, etc.).
[0080] The control systems 301, 302, 303 described above may each
generate a normalized WOB output 315, a normalized TOB output 325,
and a normalized DeltaP output 330, which may then be multiplied
together by a constant ROP setpoint 342 to generate an ROP output
345 (i.e., a drawworks control command). Thus, the ROP setpoint 342
operates as a multiplicative control gain, which can be input
and/or adjusted by rig personnel. However, an improperly selected
(e.g., too large) ROP setpoint 342 may result in unintended control
performance, such as drilling instability and/or large fluctuations
of WOB, TOB, and/or DeltaP. Thus, the constant ROP setpoint 342 may
be replaced with an automatically changing (i.e., variable) ROP
setpoint that adopts to, follows, or otherwise changes with the
changing drilling parameters, such as changing well conditions
and/or changed drilling setpoints 311, 321, 331.
[0081] FIG. 7 is a schematic view of an example implementation of
at least a portion of a control system 400 operable to execute
program code instructions to run, operate, or perform the
autodriller 252 shown in FIG. 2 to determine an ROP output (i.e., a
drawworks or ROP control command) for controlling ROP. The control
system 400 may be implemented by or form at least a portion of the
central controller 192 and/or the local controllers 221, 222, 223,
226 shown in FIGS. 1 and 2. The control system 400 may thus be or
comprise an ROP controller. The control system 400 may comprise or
be communicatively connected with one or more of the controllers
310, 320, 330 shown in FIGS. 3-5. Accordingly, the following
description refers to FIGS. 1-7, collectively.
[0082] The control system 400 may be operable to receive ROP
measurements (i.e., present values) facilitated by an ROP sensor
(e.g., the sensor 131) and determine an ROP output (i.e., an ROP
control command or signal) indicative of intended ROP at least
partially based on the received ROP measurements. Instead of using
a constant ROP setpoint 342, as described above in association with
FIGS. 3-5, the control system 400 may use the ROP measurements to
generate one or more intermediate (or temporary) ROP setpoints that
vary with time as the received ROP measurements vary. The
intermediate ROP setpoints may be used internally and/or
temporarily by the control system 400 to determine the ROP output.
The ROP output may be received by the drawworks 118 to control the
drawworks 118, thereby causing the drawworks 118 to achieve the
intended ROP by the drill string 120. The control system 400 may
reduce the effort of rig personnel in controlling the drawworks 118
by automatically adjusting (i.e., varying) the intermediate ROP
setpoints to follow or be consistent with average of the ROP
measurements that the well construction system 100 is able to
presently achieve. In practice, the ROP measurements reflect
changes in the well conditions (e.g., formation hardness) and
drilling parameters (e.g., top drive RPM, mud flow rate, etc.). The
normalized outputs 315, 325, 335 (i.e., control loop gains)
generated by at least one of the controllers 310, 320, 330 may also
be used by the control system 400 to determine the ROP output.
[0083] The control system 400 may receive ROP measurements 410
("RopPV") facilitated by an ROP sensor (e.g., the sensor 131). The
control system 400 may further receive a manual (i.e.,
user-selected) ROP setpoint 416 ("HmiRopSp"), which may be input to
the control system 400 by rig personnel via the control workstation
197. A low pass filter 412 may permit input of the ROP measurements
410 that are below a predetermined cutoff frequency, such as to
condition the ROP measurements 410 for further processing (e.g., to
avoid anomalous measurements that may affect the ROP output later
in the workflow). The cutoff frequency may be a low frequency
because a low frequency permits more previous values to be taken
into account for the average. By filtering the ROP measurements
410, noise may be removed from the measurements, such as with
respect to excessively high or low values. The filtered ROP
measurements 410 may then pass through a limiter 414 that limits
the filtered ROP measurements 410 between the manual ROP setpoint
416, representing an upper ROP value or limit of the filtered ROP
measurements 410, and a predetermined lower ROP value or limit 418
(e.g., zero ("0.0")).
[0084] The control system 400 may further receive a positive ROP
step value 420 ("RopStep"), which may be passed through a limiter
422 operable to limit the ROP step value 420 to a predetermined
upper value or limit 424 ("RopStepMax") and a predetermined lower
value or limit 426 ("RopStepMin"). The ROP step value 420 may be or
comprise a percentage or proportion of the manual ROP setpoint 416.
For example, the ROP step value 420 may range between about zero
percent (0%) and about one hundred percent (100%) of the manual ROP
setpoint 416. The ROP step value 420 may instead be or comprise an
actual ROP speed value. The ROP step value 420 may be or comprise,
for example, 5%-30% of the manual ROP setpoint 416, or the ROP step
value 420 may be or comprise, for example, an ROP speed ranging
between 2-15 feet per hour. The control system 400 may then add 428
the limited positive ROP step value 420 to the filtered and limited
ROP measurements 410 to increase the filtered and limited ROP
measurements 410 and thereby generate a first intermediate (or
temporary) ROP setpoint 402 ("RopSp01"). Thus, the ROP step value
420 may be a positive value that can be added to the ROP
measurements 410 to increase the value of the first intermediate
ROP setpoint 402 to be larger than the ROP measurements 410.
[0085] The control system 400 may further comprise a rate of change
(i.e., acceleration or deceleration) limiter 440 ("RateLim")
operable to limit the first intermediate ROP setpoint 402 to
generate a second intermediate (or temporary) ROP setpoint 404. The
rate of change limiter 440 defines or sets a maximum acceleration
rate and a maximum deceleration rate for the first intermediate ROP
setpoint 402 to thereby generate the second intermediate ROP
setpoint 404. The maximum acceleration rate may be determined by
dividing 442 the manual ROP setpoint 416 by a configurable increase
in time 446 ("RopSpIncTm") and the maximum deceleration rate may be
determined by dividing 444 the manual ROP setpoint 416 by a
configurable decrease in time 448 ("RopSpDecTm"). The manual ROP
setpoint 416 may be passed through a limiter 432 that limits the
manual ROP setpoint 416 to a predetermined upper value or limit 434
("RopRmpSatLim") and a predetermined lower value or limit 436
(e.g., zero ("0.0")). The limiter 432 may thus limit the manual ROP
setpoint 416 if the predetermined manual ROP setpoint 416 entered
by the rig personnel is too large. Thus, the first intermediate ROP
setpoint 402 that was limited by the rate of change limiter 440 may
be or comprise the second intermediate ROP setpoint 404.
[0086] The control system 400 may further comprise a limiter 450
operable to limit the second intermediate ROP setpoint 404 to
thereby generate a third intermediate (or temporary) ROP setpoint
406 ("IntRopSp"), which may also be referred to as an internal or
final ROP setpoint. The limiter 450 may be operable to limit the
second intermediate ROP setpoint 404 to the manual ROP setpoint 416
if the second intermediate ROP setpoint 404 exceeds the manual ROP
setpoint 416. Thus, the second intermediate ROP setpoint 404 that
was limited by the limiter 450 may be or comprise the third
intermediate ROP setpoint 406.
[0087] The control system 400 may further comprise the controllers
310, 320, 330 (i.e., feedback control loops) described above and
shown in FIGS. 3-5, each operable to generate a corresponding
normalized output 315, 325, 335 (i.e., a normalized output value
between zero (0) and one (1)). However, instead of the control
system 400 comprising the controllers 310, 320, 330, the control
system 400 may be communicatively connected with the controllers
310, 320, 330 located externally from the control system 400. The
control system 400 may be operable to receive the normalized WOB
output 315 ("K1") from the controller 310, the normalized TOB
output 325 ("K2") from the controller 320, and the normalized
DeltaP output 335 ("K3") from the controller 330. As described
above, one or more of the controllers 310, 320, 330 may be disabled
(i.e., turned off) or otherwise not used. An output of a disabled
controller 310, 320, 330 may output a value of one (1).
[0088] When the DeltaP controller 330 is used in conjunction with
the control system 400, the measured DeltaP input 332 received by
the DeltaP controller 330 may be filtered comparably more by the
DeltaP controller 330 than the measured WOB input 312 and the
measured drilling torque input 322 are filtered by their respective
controllers 310, 320, such as to reduce the effect of mud pulse
from the MWD tool 180. As described above, the measured inputs 312,
322, 332 may then be taken as feedback values to be compared with
corresponding setpoint values 311, 321, 331 to generate error
signals to be input to corresponding PI controls 314, 324, 334.
[0089] The control system 400 may then process 454 the third
intermediate ROP setpoint 406 and the normalized outputs 315, 325,
335 and generate an ROP output 456 ("RopMv") indicative of intended
ROP based on the third intermediate ROP setpoint 406 and one or
more of the normalized outputs 315, 325, 335. For example, the
control system 400 may isolate or otherwise determine (i.e., find)
which one of the normalized outputs 315, 325, 335 has the smallest
(i.e., minimum or lowest) value, and then multiply the smallest one
of the normalized outputs 315, 325, 335 by the third intermediate
ROP setpoint 406 to determine (i.e., calculate) the ROP output 456.
Because the third intermediate ROP setpoint 406 is limited to the
manual ROP setpoint 416 and each of the normalized outputs 315,
325, 335 comprise a value ranging between zero (0) and one (1), the
manual ROP setpoint 416 may thus be, comprise, or otherwise operate
as an ROP upper limit setpoint for the ROP output 456. Accordingly,
the ROP output 456 cannot exceed the manual ROP setpoint 416.
[0090] The ROP output 456 may be converted 458 to different units
(e.g., from feet per hour to feet per minute). The ROP output 456
may be received by the drawworks 118 (or a local controller (e.g.,
a VFD) for controlling the drawworks 118) to control the drawworks
118, thereby causing the drawworks 118 to achieve the intended ROP
by the drill string 120. Thus, the ROP output 456 may be or
comprise a drawworks control command or signal.
[0091] FIG. 8 is a schematic view of at least a portion of an
example implementation of a processing device 500 (or system)
according to one or more aspects of the present disclosure. The
processing device 500 may be or form at least a portion of one or
more equipment controllers and/or other electronic devices shown in
one or more of the FIGS. 1-7. Accordingly, the following
description refers to FIGS. 1-8, collectively.
[0092] The processing device 500 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. One
or more instances of the processing device 500 may be or form at
least a portion of the rig control system 200. For example, one or
more instances of the processing device 500 may be or form at least
a portion of the downhole controller 188, the central controller
192, one or more of the local controllers 221-226, and/or the
control workstation 197. One or more instances of the processing
device 500 may be or form at least a portion of the control systems
301, 302, 303, 400. Although it is possible that the entirety of
the processing device 500 is implemented within one device, it is
also contemplated that one or more components or functions of the
processing device 500 may be implemented across multiple devices,
some or an entirety of which may be at the wellsite and/or remote
from the wellsite.
[0093] The processing device 500 may comprise a processor 512, such
as a general-purpose programmable processor. The processor 512 may
comprise a local memory 514 and may execute machine-readable and
executable program code instructions 532 (i.e., computer program
code) present in the local memory 514 and/or another memory device.
The processor 512 may execute, among other things, the program code
instructions 532 and/or other instructions and/or programs to
implement the example methods and/or operations described herein.
For example, the program code instructions 532, when executed by
the processor 512 of the processing device 500, may cause one or
more portions or pieces of well construction equipment of a well
construction system to perform the example methods and/or
operations described herein. The processor 512 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 512 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.
[0094] The processor 512 may be in communication with a main memory
516, such as may include a volatile memory 518 and a non-volatile
memory 520, perhaps via a bus 522 and/or other communication means.
The volatile memory 518 may be, comprise, or be implemented by
random-access memory (RAM), static RAM (SRAM), dynamic RAM (DRAM),
synchronous DRAM (SDRAM), RAMBUS DRAM (RDRAM), and/or other types
of RAM devices. The non-volatile memory 520 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 518 and/or non-volatile
memory 520.
[0095] The processing device 500 may also comprise an interface
circuit 524, which is in communication with the processor 512, such
as via the bus 522. The interface circuit 524 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 524 may comprise a graphics
driver card. The interface circuit 524 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.).
[0096] The processing device 500 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 524. The interface circuit 524 can
facilitate communications between the processing device 500 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.
[0097] One or more input devices 526 may also be connected to the
interface circuit 524. The input devices 526 may permit rig
personnel to enter the program code instructions 532, which may be
or comprise control data, operational parameters, operational
setpoints, a well construction drill plan, and/or database of
operational sequences. The program code instructions 532 may
further comprise modeling or predictive routines, equations,
algorithms, processes, applications, and/or other programs operable
to perform example methods and/or operations described herein. The
input devices 526 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 528 may also be
connected to the interface circuit 524. The output devices 528 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 528 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 526 and the one or more
output devices 528 connected to the interface circuit 524 may, at
least in part, facilitate the HMIs described herein.
[0098] The processing device 500 may comprise a mass storage device
530 for storing data and program code instructions 532. The mass
storage device 530 may be connected to the processor 512, such as
via the bus 522. The mass storage device 530 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 500 may be communicatively connected with an external
storage medium 534 via the interface circuit 524. The external
storage medium 534 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 532.
[0099] As described above, the program code instructions 532 may be
stored in the mass storage device 530, the main memory 516, the
local memory 514, and/or the removable storage medium 534. Thus,
the processing device 500 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 512. 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 532 (i.e., software or firmware) thereon
for execution by the processor 512. The program code instructions
532 may include program instructions or computer program code that,
when executed by the processor 512, may perform and/or cause
performance of example methods, processes, and/or operations
described herein.
[0100] The present disclosure is further directed to example
methods (e.g., operations, processes, actions, etc.) for monitoring
and controlling well construction equipment 110, 120 of a well
construction system 100. In the following description, one or more
descriptors and/or other references to such example methods may not
be applicable to the entirety of one or more of the methods. That
is, such references may instead be applicable to just one or more
aspects of one or more of the methods. Thus, references to "the
example methods" are to be understood as being applicable to the
entirety of one or more of the methods and/or one or more aspects
of one or more of the methods.
[0101] The example methods may be performed utilizing or otherwise
in conjunction with one or more implementations of one or more
instances of one or more components of the apparatus shown in one
or more of FIGS. 1-8 and/or otherwise within the scope of the
present disclosure. For example, the example methods may be at
least partially performed (and/or caused to be performed) by a
processing device, such as the processing device 500 executing
program code instructions according to one or more aspects of the
present disclosure. Thus, the present disclosure is also directed
to a non-transitory, computer-readable medium comprising computer
program code that, when executed by the processing device, may
cause such processing device to perform the example methods
described herein. The methods may also or instead be at least
partially performed (or be caused to be performed) by a human
operator (e.g., rig personnel) utilizing one or more
implementations of one or more instances of one or more components
of the apparatus shown in one or more of FIGS. 1-8 and/or otherwise
within the scope of the present disclosure. Accordingly, the
following description refers to apparatus shown in one or more of
FIGS. 1-8 and example methods that may be performed by such
apparatus. However, the example methods may also be performed in
conjunction with implementations of apparatus other than those
depicted in FIGS. 1-8 that are also within the scope of the present
disclosure.
[0102] An example implementation of a method according to one or
more aspects of the present disclosure may comprise commencing
operation of a control system 400 for controlling ROP by a drill
bit 126 of a drill string 120 for drilling a wellbore 120. The
operating control system may receive an ROP measurement 410
indicative of a measured ROP, determine an intermediate (or
temporary) ROP setpoint (e.g., one or more of the intermediate ROP
setpoints 402, 404, 406) based on the ROP measurement 410, and
determine 454 an ROP command 456 based on the intermediate ROP
setpoint. The ROP command 456 may be indicative of an intended ROP.
The ROP command 456 may be received by a drawworks 118.
[0103] The operating control system 400 may receive an ROP upper
limit setpoint 416 defined by rig personnel via the control
workstation 197 or another HMI. The control system 400 may
determine the intermediate ROP setpoint by adding a step value 420
to the ROP measurement 410. The step value 420 may comprise a
percentage of or otherwise be based on the ROP upper limit setpoint
416. The control system 400 may instead determine the intermediate
ROP setpoint by limiting 414 the ROP measurement 410 to the ROP
upper limit setpoint 416, and adding 428 the step value 420 to the
limited ROP measurement 410. The control system 400 may instead
determine the intermediate ROP setpoint by adding the step value
420 to the ROP measurement 410 to increase the ROP measurement 410,
and limiting the increased ROP measurement 410 between an
acceleration limit 446 and a deceleration limit 448. The control
system 400 may instead determine the intermediate ROP setpoint by
adding 428 a step value 420 to the ROP measurement 410 to determine
a first intermediate ROP setpoint 402, limiting 440 the first
intermediate ROP setpoint 402 between an acceleration limit 446 and
a deceleration limit 448 to determine a second intermediate ROP
setpoint 404, and limiting 450 the second intermediate ROP setpoint
404 with the ROP upper limit setpoint 416.
[0104] The operating control system 400 may also receive a
normalized weight on bit (WOB) output 315 from a WOB controller
310, receive a normalized torque on bit (TOB) output 325 from a
drilling torque controller 320, and receive a normalized
differential pressure (DeltaP) output 335 from a DeltaP controller
330. The control system 400 may then determine 454 the ROP command
456 further based on one or more of the normalized WOB output 315,
the normalized TOB output 325, and the normalized DeltaP output
335. The control system 400 may also or instead find 454 the
smallest one of the normalized WOB output 315, the normalized TOB
output 325, and the normalized DeltaP output 335, and then
determine 454 the ROP command 456 by taking a product of the
intermediate ROP setpoint and the smallest one of the normalized
WOB output 315, the normalized TOB output 325, and the normalized
DeltaP output 335.
[0105] 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 system operable to control ROP by a drill
bit of a drill string for drilling a wellbore, wherein the system
comprises: (A) a sensor operable to facilitate an ROP measurement
indicative of a measured ROP; and (B) a controller comprising a
processor and a memory storing computer program code, wherein the
controller is operable to: (1) receive the ROP measurement; (2)
determine an intermediate ROP setpoint based on the ROP
measurement; and (3) determine an ROP command based on the
intermediate ROP setpoint, wherein the ROP command is to be
received by a drawworks and is indicative of an intended ROP.
[0106] The controller may be operable to determine the intermediate
ROP setpoint by adding a step value to the ROP measurement. In such
implementations, among others within the scope of the present
disclosure, the controller may be operable to receive an ROP upper
limit setpoint defined by rig personnel, and the step value may
comprise a percentage of the ROP upper limit setpoint.
[0107] The controller may be operable to receive an ROP upper limit
setpoint defined by rig personnel. The controller may also be
operable to determine the intermediate ROP setpoint by limiting the
ROP measurement to the ROP upper limit setpoint and adding a step
value to the limited ROP measurement.
[0108] The controller may be operable to determine the intermediate
ROP setpoint by adding a step value to the ROP measurement to
increase the ROP measurement and limiting the increased ROP
measurement between an acceleration limit and a deceleration
limit.
[0109] The controller may be operable to receive an ROP upper limit
setpoint defined by rig personnel. The controller may also be
operable to determine the intermediate ROP setpoint by adding a
step value to the ROP measurement to determine a first intermediate
ROP setpoint, limiting the first intermediate ROP setpoint between
an acceleration limit and a deceleration limit to determine a
second intermediate ROP setpoint, and limiting the second
intermediate ROP setpoint with the ROP upper limit setpoint.
[0110] The controller may be an ROP controller operable to receive
a normalized WOB output from a WOB controller, receive a normalized
TOB output from a drilling torque controller, and receive a
normalized DeltaP output from a DeltaP controller. The ROP
controller may also be operable to determine the ROP command based
further on one or more of the normalized WOB output, the normalized
TOB output, and the normalized DeltaP output.
[0111] The controller may be an ROP controller operable to receive
a normalized WOB output from a WOB controller, receive a normalized
TOB output from a drilling torque controller, receive a normalized
DeltaP output from a DeltaP controller, find the smallest one of
the normalized WOB output, the normalized TOB output, and the
normalized DeltaP output, and determine the ROP command by taking a
product of the intermediate ROP setpoint and the smallest one of
the normalized WOB output, the normalized TOB output, and the
normalized DeltaP output.
[0112] The present disclosure also introduces a method comprising
commencing operation of a control system for controlling ROP by a
drill bit of a drill string for drilling a wellbore, wherein the
operating control system: receives an ROP measurement; determines
an intermediate ROP setpoint based on the ROP measurement; and
determines an ROP command based on the intermediate ROP setpoint,
wherein the ROP command is to be received by a drawworks and is
indicative of an intended ROP.
[0113] Determining the intermediate ROP setpoint may comprise
adding a step value to the ROP measurement. In such
implementations, among others within the scope of the present
disclosure, the operating control system may also receive an ROP
upper limit setpoint defined by rig personnel, and the step value
may comprise a percentage of the ROP upper limit setpoint.
[0114] The operating control system may also receive an ROP upper
limit setpoint defined by rig personnel, wherein determining the
intermediate ROP setpoint may comprise limiting the ROP measurement
to the ROP upper limit setpoint and adding a step value to the
limited ROP measurement.
[0115] Determining the intermediate ROP setpoint may comprise:
adding a step value to the ROP measurement to increase the ROP
measurement; and limiting the increased ROP measurement between an
acceleration limit and a deceleration limit.
[0116] The operating control system may also receive an ROP upper
limit setpoint defined by rig personnel. In such implementations,
among others within the scope of the present disclosure,
determining the intermediate ROP setpoint may comprise: adding a
step value to the ROP measurement to determine a first intermediate
ROP setpoint; limiting the first intermediate ROP setpoint between
an acceleration limit and a deceleration limit to determine a
second intermediate ROP setpoint; and limiting the second
intermediate ROP setpoint with the ROP upper limit setpoint.
[0117] The operating control system may: receive a normalized WOB
output from a WOB controller; receive a normalized TOB output from
a drilling torque controller; receive a normalized DeltaP output
from a DeltaP controller; and determine the ROP command based
further on one or more of the normalized WOB output, the normalized
TOB output, and the normalized DeltaP output.
[0118] The operating control system may: receive a normalized WOB
output from a WOB controller; receive a normalized TOB output from
a drilling torque controller; receive a normalized DeltaP output
from a DeltaP controller; find the smallest one of the normalized
WOB output, the normalized TOB output, and the normalized DeltaP
output; and determine the ROP command by taking a product of the
intermediate ROP setpoint and the smallest one of the normalized
WOB output, the normalized TOB output, and the normalized DeltaP
output.
[0119] The present disclosure also introduces a computer program
product comprising a non-transitory, computer-readable medium
comprising computer instructions executable by a processor of a
control system communicatively connected with a drawworks for
raising and lowering a drill string, wherein the computer
instructions, when executed by the processor, cause the control
system to: receive an ROP measurement; determine an intermediate
ROP setpoint based on the ROP measurement; and determine an ROP
command based on the intermediate ROP setpoint, wherein the ROP
command is to be received by a drawworks and is indicative of an
intended ROP.
[0120] Execution of the computer instructions may also cause the
control system to determine the intermediate ROP setpoint by adding
a step value to the ROP measurement.
[0121] Execution of the computer instructions may also cause the
control system to receive an ROP upper limit setpoint defined by
rig personnel, wherein the step value may comprise a percentage of
the ROP upper limit setpoint.
[0122] Execution of the computer instructions may also cause the
control system to receive an ROP upper limit setpoint defined by
rig personnel and determine the intermediate ROP setpoint by
limiting the ROP measurement to the ROP upper limit setpoint and
adding a step value to the limited ROP measurement.
[0123] Execution of the computer instructions may cause the control
system to determine the intermediate ROP setpoint by: adding a step
value to the ROP measurement to increase the ROP measurement; and
limiting the increased ROP measurement between an acceleration
limit and a deceleration limit.
[0124] Execution of the computer instructions may also cause the
control system to receive an ROP upper limit setpoint defined by
rig personnel and determine the intermediate ROP setpoint by:
adding a step value to the ROP measurement to determine a first
intermediate ROP setpoint; limiting the first intermediate ROP
setpoint between an acceleration limit and a deceleration limit to
determine a second intermediate ROP setpoint; and limiting the
second intermediate ROP setpoint with the ROP upper limit
setpoint.
[0125] Execution of the computer instructions may cause the control
system to: receive a normalized WOB output from a WOB controller;
receive a normalized TOB output from a drilling torque controller;
receive a normalized DeltaP output from a DeltaP controller; and
determine the ROP command based further on one or more of the
normalized WOB output, the normalized TOB output, and the
normalized DeltaP output.
[0126] Execution of the computer instructions may cause the control
system to: receive a normalized WOB output from a WOB controller;
receive a normalized TOB output from a drilling torque controller;
receive a normalized DeltaP output from a DeltaP controller; find
the smallest one of the normalized WOB output, the normalized TOB
output, and the normalized DeltaP output; and determine the ROP
command by taking a product of the intermediate ROP setpoint and
the smallest one of the normalized WOB output, the normalized TOB
output, and the normalized DeltaP output.
[0127] 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
scope of the present disclosure, and that they may make various
changes, substitutions and alterations herein without departing
from the spirit and scope of the present disclosure.
[0128] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn. 1.72(b) to allow 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.
* * * * *