| United States Patent Application |
20170370151
|
| Kind Code
|
A1
|
|
BANIRAZI-MOTLAGH; Reza
;   et al.
|
December 28, 2017
|
SYSTEMS AND METHODS TO CONTROL DIRECTIONAL DRILLING FOR HYDROCARBON WELLS
Abstract
Embodiments of systems and methods to control directional drilling in
borehole drilling for hydrocarbon wells are disclosed. An actual toolface
orientation measurement value and an actual downhole torque on bit (DTOB)
or actual downhole weight on bit (DWOB) measurement value for a drill
string positioned in a borehole are determined. Responsive to a
comparison of target measurement values and actual measurement values,
error values are determined. A control command for one or more of a top
drive, a drawworks, and a mud pump responsive to the DTOB or DWOB error
value and the toolface orientation error value is determined.
Additionally, one or more of the top drive, the drawworks, and the mud
pump are operated responsive to the control command thereby to correct a
toolface orientation of the drill string.
| Inventors: |
BANIRAZI-MOTLAGH; Reza; (Houston, TX)
; PENN; Mark Charles; (Katy, TX)
; PINK; Anthony; (Houston, TX)
; SMITH; Joseph Kyle; (Cleveland, TX)
|
| Applicant: | | Name | City | State | Country | Type | NATIONAL OILWELL VARCO, L.P. | Houston | TX |
US | | |
| Assignee: |
National Oilwell Varco, L.P.
Houston
TX
|
| Family ID:
|
56163586
|
| Appl. No.:
|
15/540593
|
| Filed:
|
December 29, 2015 |
| PCT Filed:
|
December 29, 2015 |
| PCT NO:
|
PCT/US2015/067865 |
| 371 Date:
|
June 29, 2017 |
Related U.S. Patent Documents
| | | | |
|
| Application Number | Filing Date | Patent Number | |
|---|
| | 14627581 | Feb 20, 2015 | | |
| | 15540593 | | | |
| | 62097644 | Dec 30, 2014 | | |
|
|
| Current U.S. Class: |
1/1 |
| Current CPC Class: |
E21B 7/04 20130101; E21B 44/00 20130101; G05B 15/02 20130101; E21B 47/022 20130101 |
| International Class: |
E21B 7/04 20060101 E21B007/04; E21B 44/00 20060101 E21B044/00; E21B 47/022 20120101 E21B047/022; G05B 15/02 20060101 G05B015/02 |
Claims
1-6. (canceled)
7. A system to control directional drilling in borehole drilling for
hydrocarbon wells, the system comprising: a controller including one or
more processors; a non-transitory computer-readable medium in
communication with the one or more processors of the controller and
having one or more computer programs stored thereon that, when executed
by the one or more processors, cause the system to: determine an actual
downhole torque on bit (DTOB) measurement value and an actual toolface
orientation measurement value for a drill string positioned in a borehole
for a hydrocarbon well, determine, responsive to a comparison of a target
DTOB measurement value and the actual DTOB measurement value, a DTOB
error value, determine, responsive to a comparison of a target toolface
orientation measurement value and the actual toolface orientation
measurement value, a toolface orientation error value, determine a
control command for one or more of a top drive and a drawworks responsive
to the DTOB error value and the toolface orientation error value, and
operate one or more of the top drive and the drawworks responsive to the
control command thereby to correct a toolface orientation of the drill
string.
8. A system of claim 7, wherein determining the actual DTOB measurement
value includes determining an actual downhole weight on bit (DWOB)
measurement value, and wherein determining the actual DTOB measurement
value and the actual toolface orientation measurement value is responsive
to one or more of: (a) a Kalman filter and (b) one or more measurements
at one or more sensors positioned within the borehole.
9. A system of claim 7, wherein the controller is in communication with
one or more sensors positioned within the borehole through one or more
segments of wired drill pipe; wherein the one or more computer programs,
when executed by the one or more processors, further cause the system to
determine a current top drive operation measurement value and a current
drawworks operation measurement value; and wherein the control command is
responsive to the current top drive operation measurement value and the
current drawworks operation measurement value.
10. A system of claim 9, wherein the control command is for one or more
of the top drive, the drawworks, and a mud pump; and wherein the one or
more computer programs, when executed by the one or more processors,
further cause the system to determine a current mud pump operation
measurement value and to operate the mud pump responsive to the control
command thereby to correct a toolface orientation of the drill string.
11. A system of claim 8, wherein determining the actual DTOB measurement
value and the actual toolface measurement value includes: validating the
one or more measurements at the one or more sensors thereby to produce
one or more validated measurements; filtering the one or more validated
measurements thereby to produce one or more filtered measurements;
reconciling the one or more filtered measurements thereby to produce one
or more reconciled measurements; verifying the one or more reconciled
measurements thereby to produce one or more verified measurements; and
remediating gross errors in the one or more verified measurements thereby
to produce the actual DTOB measurement value and the actual toolface
measurement value.
12. A system of claim 7, wherein operation of the drawworks includes
altering a weight on bit (WOB) measurement value at a surface of the
borehole, wherein operation of the top drive includes altering one or
more of an angle of the drill string with respect to the surface and a
rotational speed of the drill string within the borehole, and wherein the
one or more computer programs, when executed by the one or more
processors, further cause the system to: determine the target DTOB
measurement value responsive to receipt of user input from a user
computing device in communication with the controller, the user input
including one or more of: a preselected DTOB measurement value, a
preselected rate of penetration, a preselected downhole WOB, and a
preselected mud motor differential pressure; and determine the target
toolface orientation measurement value responsive to receipt of the user
input from the user computing device.
13. A system of claim 7, wherein the control command is responsive to one
or more dynamic models of the drill string within the borehole; wherein
operation of the drawworks controls a rate of penetration of the drill
string; wherein the one or more computer programs, when executed by the
one or more processors, cause the system to estimate one or more future
values of one or more downhole variables and to determine an optimal rate
of penetration of the drill string responsive to a constrained
optimization problem; and wherein the control command is responsive to
the determined optimal rate of penetration of the drill string.
14. A method to control directional drilling in borehole drilling for
hydrocarbon wells, the method comprising: determining an actual downhole
torque on bit (DTOB) measurement value and an actual toolface orientation
measurement value for a drill string positioned in a borehole for a
hydrocarbon well, determining, responsive to a comparison of a target
DTOB measurement value and the actual DTOB measurement value, a DTOB
error value, determining, responsive to a comparison of a target toolface
orientation measurement value and the actual toolface orientation
measurement value, a toolface orientation error value, determining a
control command for one or more of a top drive and a drawworks responsive
to the DTOB error value and the toolface orientation error value, and
operating one or more of the top drive and the drawworks responsive to
the control command thereby to correct a toolface orientation of the
drill string.
15. A method of claim 14, wherein determining the actual DTOB measurement
value includes determining an actual downhole weight on bit (DWOB)
measurement value, and wherein determining the actual DTOB measurement
value and the actual toolface orientation measurement value is responsive
to one or more of: (a) a Kalman filter and (b) one or more measurements
at one or more sensors positioned within the borehole.
16. A method of claim 14, wherein the method further comprises receiving
the one or more measurements from one or more sensors positioned within
the borehole through one or more segments of wired drill pipe and
determining a current top drive operation measurement value and a current
drawworks operation measurement value, and wherein the control command is
responsive to the current top drive operation measurement value and the
current drawworks operation measurement value.
17. A method of claim 16, wherein the control command is for one or more
of the top drive, the drawworks, and a mud pump; and wherein the method
further comprises determining a current mud pump operation measurement
value and operating the mud pump responsive to the control command
thereby to correct a toolface orientation of the drill string.
18. A method of claim 15, wherein determining the actual DTOB measurement
value and the actual toolface measurement value includes: validating the
one or more measurements at the one or more sensors thereby to produce
one or more validated measurements; filtering the one or more validated
measurements thereby to produce one or more filtered measurements;
reconciling the one or more filtered measurements thereby to produce one
or more reconciled measurements; verifying the one or more reconciled
measurements thereby to produce one or more verified measurements; and
remediating gross errors in the one or more verified measurements thereby
to produce the actual DTOB measurement value and the actual toolface
measurement value.
19. A method of claim 14, wherein operation of the drawworks includes
altering a weight on bit (WOB) measurement value at a surface of the
borehole, wherein operation of the top drive includes altering one or
more of an angle of the drill string with respect to the surface and a
rotational speed of the drill string within the borehole, and wherein the
method further comprises: determining the target DTOB measurement value
responsive to receipt of user input from a user computing device, the
user input including one or more of: a preselected DTOB measurement
value, a preselected rate of penetration, a preselected downhole WOB, and
a preselected mud motor differential pressure; and determining the target
toolface orientation measurement value responsive to receipt of the user
input from the user computing device.
20. A method of claim 14, wherein the control command is responsive to
one or more dynamic models of the drill string within the borehole;
wherein operation of the drawworks controls a rate of penetration of the
drill string; wherein the method further comprises estimating one or more
future values of one or more downhole variables and determining an
optimal rate of penetration of the drill string responsive to a
constrained optimization problem; and wherein the control command is
responsive to the determined optimal rate of penetration of the drill
string.
Description
[0001] This application is related to and claims the benefit and priority
of provisional U.S. Patent Application No. 62/097,644, titled "Drilling
Direct Control System" and filed Dec. 30, 2014, and non-provisional U.S.
patent application Ser. No. 14/627,581, titled "Drilling Direct Control
User Interface" and filed Feb. 20, 2015, of which this application is a
continuation-in-part, each of which is hereby incorporated by reference.
FIELD OF INVENTION
[0002] Embodiments of the invention relate to hydrocarbon well drilling
and, more specifically, to systems, computer-readable media, interfaces,
and methods to control directional drilling.
BACKGROUND
[0003] In the field of oil and gas exploration and production, hydrocarbon
wells may be drilled to recover hydrocarbons from subterranean
formations. Such wells may be constructed by drilling a borehole into a
formation using a rotary drill bit attached to a remote end of a drill
string. A fluid that may be referred to as "drilling mud" may be
circulated down through the drill string to lubricate the drill bit and
carry drill cuttings out of the wellbore as the fluid returns to the
surface at the well site. The particular methods and equipment used to
construct a particular well may vary extensively based on the environment
and formation in which the well is being drilled. Many different types of
equipment and systems may be used in the construction of wells,
including, but not limited to, a rotating system for turning the drill
bit, a hoisting system for lifting the drill string, a circulating system
for managing the drilling fluid, pressure management equipment for
controlling wellbore pressure, a directional drilling and steering system
for non-vertical drilling, and several downhole tools.
[0004] Some oil and gas wells may not be drilled vertically straight but
rather at a deviated angle from vertical and in a specified direction.
Specific drilling methods may be deployed to deviate these wells to
direct them in the desired well path. Such methods, known collectively as
"directional drilling," may require drilling personnel to orient downhole
equipment to drill the well in the desired well path. The overall
directional drilling operation may be directed by a specific person known
as the "directional driller."
[0005] "Sliding" may describe drilling with a mud motor rotating the bit
downhole without rotating the drill string from the surface. This
operation may be conducted when a bottom hole assembly has been fitted
with a bent sub or a bent housing mud motor, or both, for directional
drilling. Sliding may be a predominant method to build and control or
correct hole angle in modern and conventional directional drilling
operations.
[0006] A precise drill bit direction may be essential to drilling a
borehole successfully, particularly in controlled steering and
directional drilling. Achieving a precise drill bit direction may be
obtained either by steering while sliding, which orients the bent segment
of a downhole mud motor from the surface, or by steering while rotating,
which utilizes a downhole rotary steerable system (RSS).
[0007] A drill bit direction may be determined by a toolface orientation
in three-dimensional space. Downhole toolface orientation is a complex
function of several drilling variables including, but not limited to,
weight on bit (WOB), torque on bit (TOB), drill bit torsional speed
(rotations per minute or RPM), mud motor differential pressure, rate of
penetration (ROP), drill bit type, formation lithology, and the angular
position of a rotating system. The overall efficiency of directional
drilling, especially in the slide drilling, may depend on analyzing all
of these variables and accordingly applying torque or angle corrections
to the drill bit.
[0008] Current directional drilling practices may require the directional
driller to verbally translate desired downhole equipment orientation to
the rig's "driller," a person who may control the machinery on a rig
floor that is used to drill the well. The driller then may apply and
maintain the required settings of drilling machinery located on the
drilling rig floor. These directional drilling methods may result in
human error that consequentially may increase rig non-productive time,
lower drilling efficiency, and drive up overall directional drilling
cost.
SUMMARY
[0009] Applicant has recognized problems associated with drill bit
direction in directional drilling and advantageously provides solutions
to these problems in fields such as drilling control and automation
systems. Applicant has recognized that, in the presence of latency or a
delay in receiving toolface orientation information, a controlled
steering process can lead to undesirable back-and-forth wandering of the
drill bit, which can result in high trajectory tortuosity. Further,
Applicant has recognized that substantially online transmission of
downhole data while drilling can provide new and unique opportunities for
automated drilling operations by eliminating or dramatically reducing the
communication delay between downhole and the surface. Wired drill pipe
technology, for example, can enable such data transmission. This online
data transmission can enable real-time monitoring, optimization, and
autonomous direct control solutions and systems for three-dimensional
directional drilling. Applicant advantageously has recognized a need in
the art for methods, systems, and apparatuses that can provide these
capabilities.
[0010] Further, a measure of efficiency in a drilling operation can
include how fast a borehole can be drilled, which is directly related to
rate of penetration (ROP). An optimal ROP can be a function of several
drilling variables including, but not limited to, weight on bit (WOB),
torque on bit (TOB), drill bit torsional speed (rotations per minute or
RPM), drilling fluid hydraulics, toolface orientation, drill bit type,
and formation lithology. Increasing ROP can decrease the life of the
drill bit, which in turn can increase drilling time because shorter drill
bit life can necessitate more frequent replacements of the drill bit. An
inappropriate ROP also can lead to such issues as vibration and sticking
that can eventually slow down the drilling process. Applicant therefore
has recognized that an autonomous directional drilling solution can
optimize ROP while steering.
[0011] Applicant advantageously provides systems, methods,
computer-readable media, interfaces, and apparatuses for drilling control
and automation systems. More specifically, embodiments of systems,
methods, computer-readable media, interfaces, and apparatuses for
autonomous, closed-loop directional drilling that can interface with a
plurality of drilling sensors and communication systems to support a
variety of autonomous real-time direct control functions using a common
operation infrastructure are provided. The common operation
infrastructure can be configured to acquire data from a variety of
sources and sensors, communicate that data with a variety of control
functions and information interfaces, and provide substantially online
operating instructions to drilling equipment and systems, all in real
time and at a high data rate, which can be enabled by wired drill pipe
and a surface data network, for example. Embodiments thus can enable an
operator (or another application) to determine slide drilling with a
preselected target downhole TOB (DTOB) and/or downhole WOB (DWOB) and
under a specific toolface orientation.
[0012] Directional drilling conceptually can include orienting the bit in
the desired direction and executing a series of slide drill and rotate
drill iterations. Orienting can be accomplished by rotating and holding
the axial position of the drill string so that the bent sub or bent
housing, which has a small angle offset, orients the new direction in
which to drill. Without turning the drill string, the bit can be rotated
with a mud motor and drill in the direction it points. With steerable
motors, when the desired wellbore direction is attained, the entire drill
string can be rotated and drill straight rather than at an angle. By
controlling the amount of hole drilled in the sliding versus the rotating
mode, the wellbore trajectory can be controlled precisely.
[0013] Advantages of embodiments of the invention can include that a
feedback control can obtain direct data at downhole. Because of this, the
control can take into account unforeseen disturbances due to, for
example, frictional, hydraulic, and lithology changes. By altering one or
more surface drilling parameters immediately once deviations are observed
in toolface orientation and downhole TOB, regardless of what caused the
deviation, embodiments can deliver slide drilling with higher accuracy
and stability.
[0014] For example, embodiments can include systems and methods to control
directional drilling in borehole drilling for hydrocarbon wells. A system
according to an embodiment can include, for example, a drill string
positioned within a borehole for a hydrocarbon well. The borehole can
extend from a surface into subterranean material. Further, a drill string
can include one or more substantially cylindrical segments of drill pipe,
a wire drilling line, a bottom hole assembly, a drill bit, and a downhole
drive controller to control rotation of the drill bit. A system also can
include a top drive positioned substantially at the surface and connected
to the drill string. Operation of the top drive can rotate the drill
string within the borehole. Additionally, a system can include a
drawworks positioned substantially at the surface and connected to the
drill string. The drawworks can include a substantially cylindrical spool
around which the wire drilling line is wound, and the drawworks also can
include a pulley and a brake to inhibit unwinding of the wire drilling
line from the spool. Further, operation of the drawworks can rotate the
spool thereby to extend the wire drilling line into the borehole and
alternatively to retract the wire drilling line from the borehole. As a
result, operation of the drawworks thereby can lower the drill string
into the borehole and alternatively can reel the drill string in from the
borehole. A system still further can include a mud pump positioned
substantially at the surface and connected to the drill string. Operation
of the mud pump can pump a drilling fluid through the one or more
segments of drill pipe and the bottom hole assembly of the drill string
to the drill bit. In addition, a system can include a first set of one or
more sensors positioned along the drill string thereby defining one or
more downhole sensors. A system also can include a second set of one or
more sensors positioned at the surface thereby defining one or more
surface sensors.
[0015] Additionally, a system according to an embodiment can include a
controller. A controller can include one or more processors positioned at
the surface and in communication with the downhole drive controller, the
top drive, the drawworks, the mud pump, the one or more downhole sensors,
and the one or more surface sensors. Further, the controller can be in
communication with the downhole drive controller and the one or more
downhole sensors through the one or more segments of drill pipe. A system
also can include a non-transitory computer-readable medium in
communication with the one or more processors of the controller. The
non-transitory computer-readable medium can have one or more computer
programs stored thereon that, when executed by the one or more
processors, cause the system to perform certain actions. For example, a
system can determine one or more of a target downhole torque on bit
(DTOB) measurement value and a target downhole weight on bit (DWOB)
measurement value responsive to receipt of user input from a user
computing device in communication with the controller. A system also can
determine a target toolface orientation measurement value responsive to
receipt of the user input from the user computing device. In addition, a
system can determine, responsive to one or more measurements at the one
or more downhole sensors, an actual toolface orientation measurement
value and one or more of an actual DTOB measurement value and an actual
DWOB measurement value. A system further can determine, responsive to one
or more measurements at the one or more surface sensors, a current top
drive operation measurement value, a current drawworks operation
measurement value, and a current mud pump operation value. Additionally,
a system can determine one or more error values selected from a group of
a DTOB error value and a DWOB error value. A DTOB error value can be
determined responsive to a comparison of the target DTOB measurement
value to the actual DTOB measurement value, and a DWOB error value can be
determined responsive to a comparison of the target DWOB measurement
value to the actual DWOB measurement value. Still further, a system can
determine, responsive to a comparison of the target toolface orientation
measurement value and the actual toolface orientation measurement value,
a toolface orientation error value. A system also can determine a control
command for one or more of the top drive, the drawworks, and the mud pump
to correct each of the toolface orientation error value and the one or
more of the DTOB error value and the DWOB error value responsive to the
current top drive operation measurement value, the current drawworks
operation measurement value, and the current mud pump operation value. In
addition, a system can operate one or more of the top drive, the
drawworks, and the mud pump responsive to the control command thereby to
correct a toolface orientation of the drill string. Operation of the
drawworks can include altering a weight on bit measurement value at the
surface. Further, operation of the top drive can include altering one or
more of an angle of the drill string with respect to the surface and a
rotational speed of the drill string within the borehole. Operation of
the mud pump can include altering a flow rate measurement value of the
drilling fluid at the surface.
[0016] In some instances, determining the actual toolface measurement
value and the one or more of the actual DTOB measurement value and the
actual DWOB measurement value can include validating the one or more
measurements at the one or more downhole sensors thereby to produce one
or more validated measurements, as well as filtering the one or more
validated measurements thereby to produce one or more filtered
measurements. Further, determining the actual toolface measurement value
and the one or more of the actual DTOB measurement value and the actual
DWOB measurement value can include reconciling the one or more filtered
measurements thereby to produce one or more reconciled measurements and
verifying the one or more reconciled measurements thereby to produce one
or more verified measurements. Determining the actual toolface
measurement value and the one or more of the actual DTOB measurement
value and the actual DWOB measurement value also can include remediating
gross errors in the one or more verified measurements thereby to produce
the actual toolface measurement value and the one or more of the actual
DTOB measurement value and the actual DWOB measurement value.
Additionally, in some circumstances, the control command can be
responsive to one or more dynamic models of the drill string within the
borehole. Further, operation of the drawworks can control a rate of
penetration of the drill string. In addition, in some instances, the one
or more computer programs, when executed by the one or more processors,
can cause the system to estimate one or more future values of one or more
downhole variables and to determine an optimal rate of penetration of the
drill string responsive to a constrained optimization problem. The
control command can be responsive to the determined optimal rate of
penetration of the drill string.
[0017] Additionally, the control command can be for each of the top drive
and the drawworks. In some circumstances, determining the control command
can include using multi-input, multi-output control logic to determine
the control command. Further, the multi-input, multi-output control logic
can include a plurality of decision rules, and each of the decision rules
can be associated with one or more of: drawworks control, top drive
control, and mud pump control. In other circumstances, determining the
control command can include using a first single-input, single-output
control logic to determine the control command for the top drive and a
second single-input, single-output control logic to determine the control
command for the drawworks.
[0018] Another system according to an embodiment can include a controller,
which can include one or more processors. Such a system also can include
a non-transitory computer-readable medium in communication with the one
or more processors of the controller. The non-transitory
computer-readable medium can have one or more computer programs stored
thereon that, when executed by the one or more processors, can cause the
system to perform certain actions. For example, a system can determine an
actual downhole torque on bit (DTOB) measurement value and an actual
toolface orientation measurement value for a drill string positioned in a
borehole for a hydrocarbon well. A system also can determine, responsive
to a comparison of a target DTOB measurement value and the actual DTOB
measurement value, a DTOB error value. Further, a system can determine,
responsive to a comparison of a target toolface orientation measurement
value and the actual toolface orientation measurement value, a toolface
orientation error value. A system still further can determine a control
command for one or more of a top drive and a drawworks responsive to the
DTOB error value and the toolface orientation error value. Additionally,
a system can operate one or more of the top drive and the drawworks
responsive to the control command thereby to correct a toolface
orientation of the drill string.
[0019] In some instances, determining the actual DTOB measurement value
can include determining an actual downhole weight on bit (DWOB)
measurement value. Additionally, determining the actual DTOB measurement
value and the actual toolface orientation measurement value can be
responsive to one or more of: (a) a Kalman filter and (b) one or more
measurements at one or more sensors positioned within the borehole.
Further, the controller can be in communication with one or more sensors
positioned within the borehole through one or more segments of wired
drill pipe. The one or more computer programs, when executed by the one
or more processors, further can cause the system to determine a current
top drive operation measurement value and a current drawworks operation
measurement value. Additionally, the control command can be responsive to
the current top drive operation measurement value and the current
drawworks operation measurement value. Further, the control command can
be for one or more of the top drive, the drawworks, and a mud pump, and
the one or more computer programs, when executed by the one or more
processors, further can cause the system to determine a current mud pump
operation measurement value and to operate the mud pump responsive to the
control command thereby to correct a toolface orientation of the drill
string. In some circumstances, determining the actual DTOB measurement
value and the actual toolface measurement value can include validating
the one or more measurements at the one or more sensors thereby to
produce one or more validated measurements and filtering the one or more
validated measurements thereby to produce one or more filtered
measurements. Further, determining the actual DTOB measurement value and
the actual toolface measurement value can include reconciling the one or
more filtered measurements thereby to produce one or more reconciled
measurements and verifying the one or more reconciled measurements
thereby to produce one or more verified measurements. In addition,
determining the actual DTOB measurement value and the actual toolface
measurement value can include remediating gross errors in the one or more
verified measurements thereby to produce the actual DTOB measurement
value and the actual toolface measurement value.
[0020] In addition, operation of the drawworks can include altering a
weight on bit (WOB) measurement value at a surface of the borehole, and
operation of the top drive can include altering one or more of an angle
of the drill string with respect to the surface and a rotational speed of
the drill string within the borehole. Further, the one or more computer
programs, when executed by the one or more processors, also can cause the
system to determine the target DTOB measurement value responsive to
receipt of user input from a user computing device in communication with
the controller. The user input can include one or more of: a preselected
DTOB measurement value, a preselected rate of penetration, a preselected
downhole WOB, and a preselected mud motor differential pressure. The one
or more computer programs, when executed by the one or more processors,
also can cause the system to determine the target toolface orientation
measurement value responsive to receipt of the user input from the user
computing device. Still further, the control command can be responsive to
one or more dynamic models of the drill string within the borehole, and
operation of the drawworks can control a rate of penetration of the drill
string. The one or more computer programs, when executed by the one or
more processors, can cause the system to estimate one or more future
values of one or more downhole variables and to determine an optimal rate
of penetration of the drill string responsive to a constrained
optimization problem. Additionally, the control command can be responsive
to the determined optimal rate of penetration of the drill string.
[0021] In addition to systems, embodiments of the invention can include
methods to control directional drilling in borehole drilling for
hydrocarbon wells. A method according to an embodiment can include, for
example, determining an actual downhole torque on bit (DTOB) measurement
value and an actual toolface orientation measurement value for a drill
string positioned in a borehole for a hydrocarbon well. A method also can
include determining, responsive to a comparison of a target DTOB
measurement value and the actual DTOB measurement value, a DTOB error
value. Further, a method can include determining, responsive to a
comparison of a target toolface orientation measurement value and the
actual toolface orientation measurement value, a toolface orientation
error value. A method additionally can include determining a control
command for one or more of a top drive and a drawworks responsive to the
DTOB error value and the toolface orientation error value. Still further,
a method can include operating one or more of the top drive and the
drawworks responsive to the control command thereby to correct a toolface
orientation of the drill string.
[0022] In some instances, determining the actual DTOB measurement value
can include determining an actual downhole weight on bit (DWOB)
measurement value. Further, determining the actual DTOB measurement value
and the actual toolface orientation measurement value can be responsive
to one or more of: (a) a Kalman filter and (b) one or more measurements
at one or more sensors positioned within the borehole. Additionally, a
method further can include receiving the one or more measurements from
one or more sensors positioned within the borehole through one or more
segments of wired drill pipe and determining a current top drive
operation measurement value and a current drawworks operation measurement
value. The control command also can be responsive to the current top
drive operation measurement value and the current drawworks operation
measurement value. Further, the control command can be for one or more of
the top drive, the drawworks, and a mud pump, and the method also can
include determining a current mud pump operation measurement value and
operating the mud pump responsive to the control command thereby to
correct a toolface orientation of the drill string. In some
circumstances, determining the actual DTOB measurement value and the
actual toolface measurement value can include validating the one or more
measurements at the one or more sensors thereby to produce one or more
validated measurements, as well as filtering the one or more validated
measurements thereby to produce one or more filtered measurements.
Determining the actual DTOB measurement value and the actual toolface
measurement value also can include reconciling the one or more filtered
measurements thereby to produce one or more reconciled measurements and
verifying the one or more reconciled measurements thereby to produce one
or more verified measurements. Further, determining the actual DTOB
measurement value and the actual toolface measurement value can include
remediating gross errors in the one or more verified measurements thereby
to produce the actual DTOB measurement value and the actual toolface
measurement value.
[0023] In addition, operation of the drawworks can include altering a
weight on bit (WOB) measurement value at a surface of the borehole, and
operation of the top drive can include altering one or more of an angle
of the drill string with respect to the surface and a rotational speed of
the drill string within the borehole. A method further can include
determining the target DTOB measurement value responsive to receipt of
user input from a user computing device. The user input can include one
or more of: a preselected DTOB measurement value, a preselected rate of
penetration, a preselected downhole WOB, and a preselected mud motor
differential pressure. A method also can include determining the target
toolface orientation measurement value responsive to receipt of the user
input from the user computing device. Additionally, the control command
can be responsive to one or more dynamic models of the drill string
within the borehole. Further, operation of the drawworks can control a
rate of penetration of the drill string. A method further can include
estimating one or more future values of one or more downhole variables
and determining an optimal rate of penetration of the drill string
responsive to a constrained optimization problem. The control command
also can be responsive to the determined optimal rate of penetration of
the drill string.
BRIEF DESCRIPTION OF DRAWINGS
[0024] These and other features, aspects, and advantages of the present
invention will become better understood with regard to the following
descriptions, claims, and accompanying drawings. It is to be noted,
however, that the drawings illustrate only several embodiments of the
invention and are therefore not to be considered limiting of the
invention's scope as it can admit to other equally effective embodiments.
[0025] FIG. 1 is a schematic diagram of a system according to an
embodiment of the invention.
[0026] FIG. 2 is a schematic diagram of a system according to an
embodiment of the invention.
[0027] FIG. 3 is a schematic diagram of a method according to an
embodiment of the invention.
[0028] FIG. 4 is a schematic diagram of a method according to an
embodiment of the invention.
[0029] FIG. 5 is a schematic diagram of a system according to an
embodiment of the invention.
[0030] FIG. 6 is a schematic diagram of a system according to an
embodiment of the invention.
[0031] FIG. 7 is a schematic diagram of a system according to an
embodiment of the invention.
[0032] FIG. 8A is a schematic diagram of a system according to an
embodiment of the invention.
[0033] FIG. 8B is a schematic diagram of a system according to an
embodiment of the invention.
[0034] FIG. 9 is a schematic diagram of a system according to an
embodiment of the invention.
[0035] FIG. 10 is a schematic diagram of a method according to an
embodiment of the invention.
[0036] FIG. 11 is a schematic diagram of a system according to an
embodiment of the invention.
DETAILED DESCRIPTION
[0037] So that the manner in which the features and advantages of the
embodiments of systems, computer-readable media, interfaces, and methods
of the present invention, as well as others, which will become apparent,
may be understood in more detail, a more particular description of the
embodiments of systems, computer-readable media, interfaces, and methods
of the present invention briefly summarized above may be had by reference
to the embodiments thereof, which are illustrated in the appended
drawings, which form a part of this specification. It is to be noted,
however, that the drawings illustrate only various embodiments of the
embodiments of systems, computer-readable media, interfaces, and methods
of the present invention and are therefore not to be considered limiting
of the embodiments of systems, computer-readable media, interfaces, and
methods of the present invention's scope as it may include other
effective embodiments as well.
[0038] Systems, methods, and computer-readable media for autonomous direct
controlled steering in directional drilling can use substantially online
data transmission (that is, data transmission that can be accomplished
during drilling) to take drilling parameter measurements at one or more
downhole locations. Wired drill pipe, for example, can enable online data
transmission, as can additional or other hardware and signals, as will be
understood by those skilled in the art. These measurements can be used,
along with data validation and reconciliation techniques, to produce
reliable online information from downhole and surface variables in
real-time intervals. Further, such direct control in autonomous
directional drilling can be based on joint control of downhole torque on
bit (DTOB) and toolface orientation while taking into consideration the
coupling dynamics between torque and angular displacement in slide
drilling. Additionally, control methods can adaptively predict the impact
of changing downhole torque on the toolface orientation and can
compensate accordingly for that impact in advance before it can influence
the toolface angular displacement. In some instances, a closed-loop
control of directional drilling can include a first set of control
operations that ensure stability and robustness of automated directional
drilling against a wide range of external disturbances, measurement
errors, and unknown lithology and hydraulic conditions. Such a first set
of control operations can be implemented fully either in a downhole
device or in a surface application. Further, such a first set of control
operations can be executed by a controller to issue operating commands to
a drilling equipment system (including, for example, one or more of a
rotating system, a hoisting system, a circulating system, and a downhole
rotary steerable system (RSS)) that can either directly or indirectly
affect one or more drilling parameters. Additionally, in some
circumstances, a closed-loop control of directional drilling also can
include a second set of control operations that can evaluate the drilling
operating conditions and adaptively modify the first set of control
operations thereby to alter the manner of issuing operating commands to
one or more of a rotating system, a hoisting system, a circulating
system, and a downhole RSS. The second set of control operations can
include online adjusting the control parameters used as input to the
first set of control operations, as well as choosing a suitable control
structure from a database based on one or more if-then scenarios. Still
further, a closed-loop control of directional drilling also can include a
third set of control operations that can determine an optimal rate of
penetration (ROP) online to enhance the overall directional drilling
performance by estimating short- to mid-term future values of a
preselected set of downhole variables and by solving a set of parametric
constrained optimization problems. Each set of control operations can be
associated with one or more separate controllers or other computing
devices, or one or more sets of control operations can be associated with
the same controller or other computing devices.
[0039] Embodiments of the invention can include, for example, systems to
control directional drilling in borehole drilling for hydrocarbon wells.
A system 100 according to an embodiment, for instance, can relate to a
borehole 102 for a hydrocarbon well extending from a surface into
subterranean material, as illustrated in FIG. 1, for example. Such a
system 100 can include a drill string 104 positioned within the borehole
102. A drill string 104 can include one or more substantially cylindrical
segments of drill pipe 106, a wire drilling line 117, a bottom hole
assembly (BHA) 108, a drill bit 110, and a downhole drive controller 112
to control and adjust rotation of the drill bit 110. A downhole drive
controller 112 can include, for example, a controller associated with the
RSS. A drill bit 110 can be located at the bottom of the BHA 108, as
illustrated in FIG. 1, for example. A system 100 further can include a
top drive 114 or other rotating system positioned substantially at the
surface and connected to the drill string 104. Operation of the top drive
114 can rotate the drill string 104 within the borehole 102 along an axis
substantially parallel to the walls of the borehole 102. Such a top drive
114 can be a device or assembly made up of one or more components or
machines (including, for example, one or more motors, one or more gears,
and a rotary mechanism) that is operable to rotate the drill string 104
within the borehole 102. In addition, a system 100 can include a
drawworks 116 or other hoisting system positioned substantially at the
surface and connected to the drill string 104. The drawworks 116 can
include a substantially cylindrical spool around which the wire drilling
line 117 can be wound. Further, the drawworks 116 also can include a
pulley 119 and a brake to inhibit unwinding of the wire drilling line 117
from the spool. Operation of the drawworks 116 can rotate the spool
thereby to extend the wire drilling line 117 into the borehole 102 and,
alternatively, to retract the wire drilling line 117 from the borehole
102. That is, operation of the drawworks 116 thereby can lower the drill
string 104 into the borehole 102 and alternatively can reel the drill
string 104 in from the borehole 102. Consequently, operation of the
drawworks 116 can control ROP of the drill string 104. The drawworks 116
can be a device or assembly made up of one or more components or machines
(including, for example, the wire drilling line 117, one or more spools,
one or more pulleys 119, and one or more brakes) that is operable to
hoist the drill string 104 in and out of the borehole 102. A system 100
also can include a mud pump 118 or other circulating system positioned
substantially at the surface and connected to the drill string 104.
Operation of the mud pump 118 can pump a drilling fluid through the one
or more segments of drill pipe 106 and the BHA 108 of the drill string
104 to the drill bit 110. That is, such a mud pump 118 (or another
circulating system) can pump a drilling fluid down via the drill pipe 106
where the drilling fluid subsequently can exit the drill string 104 via
orifices in the drill bit 110 and then flow upwardly to the surface
through the annulus of the borehole 102, as will be understood by those
skilled in the art.
[0040] The drill bit 110, the downhole drive controller 112, a sensor
assembly 126, the drill pipe 106, the top drive 114 (or other rotating
system), the drawworks 116 (or other hoisting system), the mud pump 118
(or other circulating system), and any other drilling equipment
(including those not illustrated in the example depicted in FIG. 1) each
can include one or more high sampling rate drilling parameter sensors.
For example, a system 100 can include a first set of one or more sensors
positioned along the drill string 104 thereby defining one or more
downhole sensors 120 (sometimes called downhole parameter sensors). As
illustrated, downhole sensors 120 are positioned on or at the BHA 108 but
can be positioned in other locations, as well, and need not be positioned
in the locations illustrated in the example depicted in FIG. 1. A system
100 also can include a second set of one or more sensors positioned at
the surface thereby defining one or more surface sensors 122. As
illustrated, surface sensors 122 are rig-mounted sensors and positioned
at the top drive 114, the drawworks 116, and the mud pump 118, but
surface sensors 122 can be positioned at other locations, as well, and
need not be positioned in the locations illustrated in the example
depicted in FIG. 1. A drilling parameter sensor, such as a downhole
sensor 120 or a surface sensor 122, can be any sensor operable to measure
and provide raw data regarding at least one drilling parameter. Such a
sensor can be mounted to any location available to sense the drilling
parameter being monitored. Exemplary downhole sensors 120 can include
(but are not limited to) direction measurement sensors, formation and
wellbore evaluation sensors, sensors for determining the performance and
physical condition of the BHA 108 and the drill bit 110, mud motor
parameter sensors, and sensors for determining the operating condition of
the drill string 104, as will be understood by those skilled in the art.
Exemplary surface sensors 122 can include (but are not limited to)
sensors for measuring variables related to the drill string 104, such as
load, torque, position, velocity, acceleration, and vibration, as well as
sensors for measuring the fluid-related variables such as mud pressure,
mud flow rate, and casing annular pressure and temperature, as will be
understood by those skilled in the art.
[0041] A system 100 also can include a controller 130 positioned at the
surface. A controller 130 can include one or more processors 132 and can
be in communication with the downhole drive controller 112, the top drive
114, the drawworks 116, the mud pump 118, the one or more downhole
sensors 120, and the one or more surface sensors 122, as illustrated in
FIG. 5, for example. A downhole communication hub 128 can be operable to
collect data from different downhole sensors 120 and to transmit the
collected data to the surface via a substantially online data
transmission system 124, in some circumstances, as illustrated in FIG. 1,
for example. The communications hub 128 also can be operable to receive
operating instructions and control signals from the surface and relay
those signals to one or more downhole sensors 120, the downhole drive
controller 112, or other downhole tools. Such a substantially online data
transmission system 124 can be any system suitable for the continuous
transmission of measurement data, control commands, and other signals
between downhole and the surface in real-time intervals of, for example,
one second. Exemplary communication methods can include, but are not
limited to, direct communication via electric signals along wired drill
pipe (such as drill pipe 106), mud-pulse telemetry, fiber optics,
wireless signals, acoustic signals, and electromagnetic signals. For
example, a data transmission system 124 can include a wired drill pipe
106 that in turn includes conductors coupled to the drill pipe 106 to
provide a direct link between downhole and the surface. For example, in
some instances, the controller 130 can be in communication with the
downhole drive controller 112 and the one or more downhole sensors 120
through the one or more segments of drill pipe 106, for example, as
illustrated in FIG. 5. The data transmission system 124 can be connected
to a surface data network (such as a network to which the controller 130
also is connected) via a surface communications link that can be
integrated into a component such as a swivel, internal blow out preventer
(IBOP) or into an instrumented saver sub coupled to the drill string 104.
Consequently, the controller 130 can be in communication with the data
transmission system 124, as illustrated in FIG. 1, for example.
[0042] A system 100 also can include a non-transitory computer-readable
medium (such as a memory 136) in communication with the one or more
processors 132 of the controller 130. The computer-readable medium 136
can have one or more computer programs stored thereon that, when executed
by the one or more processors 132, cause the system 100 to perform
certain steps. For example, the system 100 can receive user input from a
user, such as a directional driller, before performing additional steps.
For instance, a system 100 can determine a target downhole torque on bit
(DTOB) measurement value (that is, a targeted DTOB value to be measured
by one or more downhole sensors 120) responsive to receipt of user input
from a user computing device in communication with the controller 130.
Further, for example, a user such as a directional driller can preselect
a desired or target DTOB, or a target DTOB can be calculated from or
otherwise determined based on some other preselected target value, such
as ROP, WOB, or mud motor differential pressure. As an alternative or in
addition to determining a target DTOB, a system 100 can determine a
target downhole WOB (DWOB) measurement value (that is, a targeted DWOB
value to be measured by one or more downhole sensors 120) responsive to
receipt of user input from the user computing device. A system 100 also
can determine a target toolface orientation measurement value (that is, a
targeted toolface orientation value to be measured by one or more
downhole sensors 120) responsive to receipt of the user input from the
user computing device. As an alternative to a directional driller's
preselection of these target values, any or all of the target values can
be automatically computed by a drilling path planner, for example, in
some circumstances.
[0043] Further, a system 100 can determine6--responsive to one or more
measurements at the one or more downhole sensors 120--an actual toolface
orientation measurement value (that is, an actual toolface orientation
value as measured by one or more downhole sensors 120) and one or more of
an actual DTOB measurement value (that is, an actual DTOB value as
measured by one or more downhole sensors 120) and an actual DWOB
measurement value (that is, an actual DWOB value as measured by one or
more downhole sensors 120). For example, when a target DTOB measurement
value has been determined, a system 100 can determine an actual DTOB
measurement value; when a target DWOB has been determined, a system 100
can determine an actual DWOB measurement value. A system 100 also can
determine--responsive to one or more measurements at the one or more
surface sensors 122--one or more of a current top drive operation
measurement value, a current drawworks operation measurement value, and a
current mud pump operation measurement value.
[0044] In addition, a system 100 can determine one or more of a DTOB error
value and a DWOB error value. For example, when a target DTOB measurement
value and an actual DTOB measurement value have been determined, a DTOB
error value can be determined responsive to a comparison of the target
DTOB measurement value to the actual DTOB measurement value. As an
alternative to or in addition to determining a DTOB error value, for
example, a DWOB error value can be determined--responsive to a comparison
of the target DWOB measurement value to the actual DWOB measurement
value--when a target DWOB measurement value and an actual DWOB
measurement value have been determined. For example, the actual DTOB
measurement value can be compared to the target DTOB measurement value to
generate one or more of torque position error (E.sub.TOB), torque
velocity error (.DELTA.E.sub.TOB), and torque acceleration error
(.DELTA..sup.2E.sub.TOB). Each of these error variables then can be
scaled using a corresponding, in some instances nonlinear, scale function
(such as, for example, SE.sub.TOB, S.DELTA.E.sub.TOB, and
S.DELTA..sup.2E.sub.TOB) that can determine the general sensitivity of
control logic with respect to different values of the respective error
variable. Likewise, the actual DWOB measurement value can be compared to
the target DWOB measurement value to generate one or more of weight
position error (E.sub.WOB), weight velocity error (.DELTA.E.sub.WOB), and
weight acceleration error (.DELTA..sup.2E.sub.WOB). Each of these error
variables then can be scaled using a corresponding, in some instances
nonlinear, scale function (such as, for example, SE.sub.WOB,
S.DELTA.E.sub.WOB, and S.DELTA..sup.2E.sub.WOB) that can determine the
general sensitivity of control logic with respect to different values of
the respective error variable. Each scale function can be determined
analytically or using a knowledge-based approach.
[0045] In a similar manner, a system 100 can determine, responsive to a
comparison of the target toolface orientation measurement value and the
actual toolface orientation measurement value, a toolface orientation
error value. For example, the actual toolface orientation measurement
value can be compared to the target toolface orientation measurement
value to generate one or more of position error E.sub.toolface, velocity
error .DELTA.E.sub.toolface, and acceleration error
.DELTA..sup.2E.sub.toolface that then can be scaled using one or more (in
some instances, nonlinear) scale functions, such as, for example,
SE.sub.toolface, S.DELTA.E.sub.toolface, and
S.DELTA..sup.2E.sub.toolface.
[0046] A system 100 then can determine a control command for one or more
of the top drive 114, the drawworks 116, and the mud pump 118 to correct
each of the toolface orientation error value and the one or more of the
DTOB error value and the DWOB error value responsive to the one or more
of the current top drive operation measurement value, the current
drawworks operation measurement value, and the current mud pump operation
value, for example. A control command for the top drive 114 can be
responsive to the current top drive operation measurement value, for
instance, and a control command for the drawworks 116 can be responsive
to the current drawworks operation measurement value. A control command
for the mud pump 118 can be responsive to the current mud pump operation
measurement value. Further, a system 100 can operate one or more of the
top drive 114, the drawworks 116, and the mud pump 118 responsive to the
control command, which can include one or more commands for the
respective equipment. Operation of the drawworks 116 can include altering
an ROP, and consequently a WOB, measurement value at the surface.
Further, operation of the top drive 114 can include altering one or more
of an angle of the drill string 104 with respect to the surface and a
rotational speed of the drill string 104 within the borehole 102. In
addition, operation of the mud pump 118 can include altering a flow rate
measurement value of the drilling fluid at the surface and, as a result,
a fluid differential pressure (DiffP) at the surface. Consequently,
operation of one or more of the top drive 114, the drawworks 116, and the
mud pump 118 responsive to the control command thereby eventually can
correct one or more of a toolface orientation of the drill string 104, a
DTOB, and a DWOB.
[0047] A system 100 also can perform data validation and reconciliation
operations. The raw measurement data obtained by downhole sensors 120 and
surface sensors 122 may not be fully correct as a result of measurement
errors. Measurement errors can be categorized into two basic types: (1)
random errors that can result from intrinsic sensor accuracy and (2)
gross or systematic errors that can result from sensor calibration or
faulty data transmission. Data validation and reconciliation operations
can use filtering and estimation techniques to produce a single
consistent set of data that represent the most likely value of a drilling
parameter in real-time intervals of, for example, one second, while the
raw data measured by the downhole sensors 120 and surface sensors 122 can
exceed, for example, 50 Hz in sampling rate.
[0048] Exemplary data validation and reconciliation operations are
illustrated, for instance, in FIG. 3. For example, in some circumstances,
determining the actual toolface measurement value and the one or more of
the actual DTOB measurement value and the actual DWOB measurement value
can include validating 204 the one or more measurements at the one or
more downhole sensors 120 (such as high sampling rate raw measurement
data 202) thereby to produce one or more validated measurements, as
illustrated in FIG. 3, for example. Validating 204 the one or more
measurements, which can have been sampled at a high rate, can provide
certain improvements to the fitness, accuracy, and consistency of the
measured values. Exemplary validation 204 operations can include, but are
not limited to, examining data for consistency within a minimum and
maximum expected range, discarding isolated data that deviate
significantly from neighboring data measurements, cleaning data from
spike faults when the rate of change in a gradient of measurement data
over a specific period of time is much greater than expected, and
monitoring stuck-at fault or frozen data where a series of measurement
data remain with little or no variation for a period of time greater than
expected.
[0049] Data validation and reconciliation operations also can include
filtering 208 the validated data. For example, determining the actual
toolface measurement value and the one or more of the actual DTOB
measurement value and the actual DWOB measurement value also can include
filtering 208 the one or more validated measurements thereby to produce
one or more filtered measurements. Filtering 208 the one or more
validated measurements can attenuate noise components of the measurement
data. Exemplary filtering 208 methods can include, but are not limited
to, taking the simple average of measured values over a specific time
period, taking the moving average based on a specific moving time window,
taking the exponentially weighted moving average that places greater
importance on more recent data by discounting older data in an
exponential manner, using local regression methods, and applying
Savitzky-Golay filtering.
[0050] In addition, data validation and reconciliation operations can
include reconciling 210 the filtered data. For instance, determining the
actual toolface measurement value and the one or more of the actual DTOB
measurement value and the actual DWOB measurement value further can
include reconciling 210 the one or more filtered measurements thereby to
produce one or more reconciled measurements. Reconciling 210 the one or
more filtered measurements can correct random errors. From a statistical
viewpoint, a main assumption in data reconciliation can be that no gross
errors exist in the set of measurements, since gross errors can bias the
reconciliation results and reduce the robustness of the reconciliation.
Given n measurements for each variable in a set of m variables, data
reconciliation can be expressed as an optimization problem of the
following form:
minimize f ( y * ) = p = 1 m i = 1 n
( y i p - y p * .sigma. p ) 2 ##EQU00001## subject
to y min .ltoreq. y * .ltoreq. y max and
F ( y * ) = 0 ##EQU00001.2##
where f(y*) can be called a measurement penalty function, a can be the
variance of the random noise, y.sub.min and y.sub.max can be bounds on
the measured variables, and F(y*)=0 can represent a set of model
equations 206 that express the general structure of the process as
functions of reconciled data. Models 206 can have different levels of
detail. For example, a model 206 can incorporate simple static material
balances or advanced dynamic models.
[0051] Data validation and reconciliation operations also can include
verifying 212 the reconciled data. For example, determining the actual
toolface measurement value and the one or more of the actual DTOB
measurement value and the actual DWOB measurement value also can include
verifying 212 the one or more reconciled measurements thereby to produce
one or more verified measurements. Result verification 212 can include,
but is not limited to, measurement penalty analysis for determining the
reliability of the reconciliation and bound checks to ensure that the
reconciled values lie in a certain reasonable bounds. Result verification
212 can utilize analytical redundancy-based methods where an analytical
model 206 is used to provide estimates of measured variables. This
redundancy then can be used to detect any discrepancy or residual between
the reconciled data and expected values. The analytical model 206 can be
mathematical or knowledge-based. Exemplary model-based techniques can
include, but are not limited to, an observer-based approach, a
parity-space approach, a parameter identification-based approach, and a
Kalman filter approach. After result verification 212, data validation
and reconciliation operations can include determining whether a valid
result has been produced 214. If a valid result has not been produced at
step 214, data reconciliation 210 can begin again. If a valid result has
been produced at step 214, however, data validation and reconciliation
operations can proceed.
[0052] Data validation and reconciliation operations still further can
include detecting 216 and remediating 220 gross errors in the verified
data. For example, determining the actual toolface measurement value and
the one or more of the actual DTOB measurement value and the actual DWOB
measurement value can include remediating gross errors 220 in the one or
more verified measurements thereby to produce the actual toolface
measurement value and the one or more of the actual DTOB measurement
value and the actual DWOB measurement value. Gross error detection 216
can indicate whether a gross error exists somewhere in the set of
measurements at step 218, for instance. In some circumstances, it can be
assumed that the measurement errors are normally distributed. Then, if no
gross errors exist in the set of measurements, each penalty term in f(y*)
can be a random variable that is normally distributed with a mean equal
to 0 and a variance equal to 1. By consequence, the measurement penalty
function f(y*) can be a random variable which follows a chi-square
distribution, since it is the sum of the square of normally distributed
random variables. This can lead to an exemplary gross error detection
approach that can include comparing the value of the objective function
f(y*) with a given percentile P.sub..alpha. of the probability density
function of a chi-square distribution that can give an indication of
whether a gross error exists. In such an example, if
f(y*).ltoreq.P.sub.90, no gross errors exists with a 90% probability.
Another exemplary gross error detection approach can include an
individual test that compares each penalty term in f(y*) with the
critical values of the normal distribution, and if the i-th penalty term
is outside, for example, the 90% confidence interval of the normal
distribution, then this measurement has a gross error with 90%
probability. If no gross error exists somewhere in the set of
measurements at step 218, data validation and reconciliation operations
can conclude and produce low sampling rate reconciled data 222. If a
gross error exists somewhere in the set of measurements at step 218,
gross remediation 220 can begin.
[0053] Gross error remediation 220 can include either discarding or
relaxing measurement systematic errors that can bias the reconciliation
results. In some circumstances, gross error remediation 220 can include
determining the measurement data that are biased by a systematic error
and discarding these data from the data set. The determination of the
measurement to be discarded can be based on different kinds of penalty
terms that express the degree to which the measured values deviate from
the reconciled values. After gross errors have been discarded from the
measurement data, data reconciliation 210 can be performed without these
erroneous data that can spoil the reconciliation process. In some
instances, the elimination can be repeated until no gross error exists in
the set of reconciled data. Further, in some circumstances where it is
not possible to determine which measurement data are responsible for
systematic errors, gross error remediation 220 can rely on relaxing the
estimate for the uncertainty of suspicious measurements so that the
reconciled values lie within, for example, the 90% confidence interval.
[0054] In some circumstances, a control command can be responsive to one
or more dynamic models of the drill string 104 within the borehole 102.
For example, the actual toolface orientation measurement value and the
one or more of the actual DTOB measurement value and the actual DWOB
measurement value can be used to estimate a drill string torsional
compliance by analyzing the coupling dynamics between toolface angular
displacement and DTOB. In some instances, the torsional compliance can be
estimated using a drill string dynamic model that can be mathematical or
knowledge-based. In other instances, the torsional compliance can be
estimated by calculating the torsional compliance using actual
observations at near past times that show the angular toolface
displacements as a response to the downhole torque variations. In yet
other instances, the torsional compliance can be estimated using a
combination of a drill string dynamic model and actual observations,
where the actual observations also can be used to update the drill string
dynamic model.
[0055] Additionally, in some circumstances, the one or more computer
programs, when executed by the one or more processors 132, can cause the
system 100 to estimate one or more future values of one or more downhole
variables and to determine an optimal ROP of the drill string 104
responsive to a constrained optimization problem. Further, the control
command can be responsive to the determined optimal ROP.
[0056] A control command can be for each of the top drive 114, the
drawworks 116, and the mud pump 118, or for any combination of them. In
some circumstances, determining the control command can include using
multi-input, multi-output (MIMO) core logic to determine the control
command. Further, the MIMO core logic can include a plurality of decision
rules, and each of the decision rules can be associated with one or more
of: drawworks control, top drive control, and mud pump control. The
outcome of each decision rule can be scaled by a weight factor that,
according to drilling conditions, can determine the impact of that
decision rule on the final control command. An aggregation logic then can
be used to combine the weighted results from different decision rules and
to produce quantifiable control command(s) for one or more of the top
drive 114, the drawworks 116, and the mud pump 118. Exemplary MIMO
control logic can include, but is not limited to, a multivariable fuzzy
logic controller and a multivariable model predictive controller.
[0057] Alternatively, in other circumstances, determining the control
command can include using a first single-input, single-output (SISO)
control logic to determine the control command for the top drive 114 and
a second SISO control logic to determine the control command for the
drawworks 116. Exemplary SISO control logic can include, but is not
limited to, a conventional proportional-integral-derivative (PID)
controller and fuzzy logic controller, as will be understood by those
skilled in the art.
[0058] For example, exemplary operations of a system or exemplary steps of
a method 238 according to an embodiment are illustrated in FIG. 4. As
depicted, inputs can include desired (that is, target) downhole variables
240, target toolface orientation 242, and real-time information of
drilling parameter variables 244. Such real-time information of drilling
parameter variables 244 can be obtained from one or more sensors, such as
downhole sensors 120 or surface sensors 122. Given the desired downhole
variables 240, one or more of a target DWOB and a target DTOB 246 can be
determined. Further, given the real-time information of drilling
parameter variables 244, one or more of an actual DWOB and an actual DTOB
248, as well as an actual toolface orientation 250, can be determined.
Given one or more of a target DWOB and a target DTOB 246 and one or more
of an actual DWOB and an actual DTOB 248, one or more of a DWOB scaled
error and a DTOB scaled error 252 can be determined. Further, given the
target toolface orientation 242 and the actual toolface orientation 250,
a toolface orientation scaled error 254 can be determined. A system
states and disturbance observer 256 then can operate responsive to the
actual toolface orientation 250 and one or more of the actual DWOB and
the actual DTOB 248. Further, a steering compliance estimator 258 can
estimate the drill string torsional compliance responsive to the actual
toolface orientation 250 and one or more of the actual DWOB and the
actual DTOB 248. Given the toolface orientation scaled error 254, one or
more of DWOB scaled error and DTOB scaled error 252, estimate from the
steering compliance estimator 258, and input from the system states and
disturbance observer 256, multi-input multi-output (MIMO) control logic
260 can operate to determine a command 262 to send to one or more
drilling equipment driving systems. Output of the MIMO control logic 260
also can feed back into the system states and disturbance observer 256 to
be used for subsequent time-step calculations.
[0059] MIMO control logic can take into account the mutual effects among
downhole torque, toolface orientation, top drive angle, and ROP, for
example, as illustrated in FIG. 7 and FIG. 8. For instance, MIMO control
logic 302 can utilize input from a user through a graphical user
interface (GUI) or another application 304, as well as input from one or
more drilling sensors 306, as illustrated in FIG. 7. Input from a user
through a graphical user interface (GUI) or another application 304 can
include, for example, toolface orientation (TF) setpoint (that is, target
toolface orientation), DTOB setpoint (that is, target DTOB), DWOB
setpoint (that is, target DWOB), maximum ROP, maximum DiffP, slide
length, maximum DTOB, and pipe tally, as will be understood by those
skilled in the art. Further, input from one or more downhole drilling
sensors 306 (such as downhole sensors 120, for example) can include
actual toolface orientation, actual DTOB, actual DWOB, and actual
downhole differential pressure (DDiffP), as will be understood by those
skilled in the art. Still further, input from one or more surface
drilling sensors 306 (such as surface sensors 122, for example) can
include top drive (TD) orientation, ROP, WOB, DiffP, block height, hole
depth, drill bit position, and survey, as will be understood by those
skilled in the art. The output of the MIMO control logic 302 can include
control commands to a top drive 308 regarding top drive orientation. Such
control commands 308 can include one or more of angular position,
throttle, and torque. Further, the output of the MIMO control logic 302
can include commands to a drawworks 310 regarding ROP. Such drawworks
commands 310 can include drilling line payoff, WOB, and DiffP. Still
further, the output of the MIMO control logic 302 can include commands to
a mud pump 311 regarding mud flow that can include mud pump strokes. For
example, a controller 318 using the MIMO core logic 302 can utilize
target DTOB 314 and a target toolface orientation 316 as inputs to
generate a surface ROP command 320 that can be sent to a drawworks 310,
as well as a surface top drive orientation command 322 that can be sent
to a top drive 308, as illustrated in FIG. 8A, for example. Top drive 308
can provide feedback regarding top drive orientation 324 to the MIMO
control logic 302. In the drilling process 312, the operation of the
drawworks 310 and top drive 308 then can modify DTOB and toolface
orientation to produce updated DTOB 328 and TF 330. These updated
drilling parameter measurements then can be fed back into the MIMO
control logic 302 to be used for subsequent time-step calculations. In
some instances, the controller 318 also can send a mud flow command 321
to a mud pump 309, which can feed into the MIMO control logic 302, as
illustrated in FIG. 8B, for example.
[0060] As an alternative to MIMO control logic 302, two disjointed SISO
controllers (one for each of top drive orientation and surface ROP) can
be used, as illustrated in FIG. 9, for example. Each independent SISO
controller can compare its setpoint with its corresponding downhole
actual value and accordingly can generate a command to the process. For
instance, a SISO control logic performed by a controller associated with
TF 338 can use TF setpoint 316 and actual TF 334 as inputs to determine a
command to send to a top drive 308. Top drive can be used to compensate
for error between the TF setpoint 316 and the actual TF 334. That is,
operation of the top drive can be used to correct toolface orientation.
Similarly, a SISO control logic performed by a controller associated with
DTOB 340 can use DTOB setpoint 314 and actual DTOB 336 as inputs to
determine a command to send to a drawworks 310. Drawworks can be used to
compensate for error between the DTOB setpoint 314 and the actual DTOB
336. That is, operation of the drawworks can be used to correct DTOB.
[0061] Another system according to an embodiment can include a controller
130 that includes one or more processors 132. A system also can include a
non-transitory computer-readable medium 136 in communication with the one
or more processors 132 of the controller 130. The computer-readable
medium 136 can have one or more computer programs stored thereon that,
when executed by the one or more processors 132, cause the system to
determine an actual downhole torque on bit (DTOB) measurement value and
an actual toolface orientation measurement value for a drill string 104
positioned in a borehole 102 for a hydrocarbon well. As an alternative to
or in addition to determining the actual DTOB measurement value, a system
can determine a DWOB measurement value; in such circumstances, steps
performed by the system related to DTOB can instead be related to DWOB. A
system also can determine, responsive to a comparison of a target DTOB
measurement value and the actual DTOB measurement value, a DTOB error
value. As an alternative to or in addition to determining the DTOB error
value, a system can determine a DWOB error value. Further, a system can
determine, responsive to a comparison of a target toolface orientation
measurement value and the actual toolface orientation measurement value,
a toolface orientation error value. In addition, a system can determine a
control command for one or more of a top drive 114 and a drawworks 116
responsive to the DTOB error value (and/or the DWOB error value) and the
toolface orientation error value. A system further can operate one or
more of the top drive 114 and the drawworks 116 responsive to the control
command thereby to correct a toolface orientation of the drill string
104.
[0062] In some instances, determining the actual DTOB measurement value
can include determining an actual DWOB measurement value. Additionally,
the actual DTOB measurement value can be a sensor measurement value, and
the actual DWOB measurement value can be a sensor measurement value, as
well. Further, determining the actual DTOB measurement value and the
actual toolface orientation measurement value can be responsive to one or
more of: (a) one or more measurements at one or more sensors 120
positioned within the borehole 102 and (b) an appropriate estimator, such
as a Kalman filter. For example, DTOB and toolface orientation can be
obtained or estimated from measurements by downhole sensors 120 or
estimated by an appropriate estimator (such as a Kalman filter, for
example) or a combination of both.
[0063] The controller 130 can be in communication with the one or more
sensors 120 through one or more segments of wired drill pipe 106, in some
circumstances. Further, a system also can determine a current top drive
operation measurement value and a current drawworks operation measurement
value, and the control command can be responsive to the current top drive
operation measurement value and the current drawworks operation
measurement value. In some instances, the control command can be for one
or more of the top drive 114, the drawworks 116, and a mud pump 118. The
one or more computer programs, when executed by the one or more
processors 132, further can cause the system to determine a current mud
pump operation measurement value and to operate the mud pump 118
responsive to the control command thereby to correct a toolface
orientation of the drill string 104.
[0064] Additionally, in some circumstances, determining the actual DTOB
measurement value and the actual toolface measurement value can include
validating the one or more measurements at the one or more sensors 120
thereby to produce one or more validated measurements and filtering the
one or more validated measurements thereby to produce one or more
filtered measurements. Determining the actual DTOB measurement value and
the actual toolface measurement value also can include reconciling the
one or more filtered measurements thereby to produce one or more
reconciled measurements and verifying the one or more reconciled
measurements thereby to produce one or more verified measurements.
Further, determining the actual DTOB measurement value and the actual
toolface measurement value can include remediating gross errors in the
one or more verified measurements thereby to produce the actual DTOB
measurement value and the actual toolface measurement value.
[0065] Operation of the drawworks 116 can include altering a weight on bit
(WOB) measurement value at a surface of the borehole, and operation of
the top drive 114 can include altering one or more of an angle of the
drill string 104 with respect to the surface and a rotational speed of
the drill string 104 within the borehole 102.
[0066] Further, the control command can be responsive to one or more
dynamic models of the drill string 104 within the borehole 102, and
operation of the drawworks 116 can control ROP of the drill string 104. A
system also can estimate one or more future values of one or more
downhole variables and determine an optimal ROP of the drill string 104
responsive to a constrained optimization problem. In addition, the
control command can be responsive to the determined optimal ROP of the
drill string 104.
[0067] In some circumstances, the one or more computer programs, when
executed by the one or more processors 132, further can cause the system
determine the target toolface orientation measurement value responsive to
receipt of user input from a user computing device in communication with
the controller 130 and to determine the target DTOB measurement value
(and/or the target DWOB measurement value) responsive to receipt of the
user input from the user computing device. Such user input can include,
for example, one or more of: a preselected DTOB measurement value, a
preselected ROP, a preselected DWOB, and a preselected mud motor
differential pressure.
[0068] For instance, a user such as a directional driller can select a
desired target DTOB measurement value directly. A target DTOB measurement
value also can be automatically computed, such as by drilling application
software, for example. That is, user input can include a preselected DTOB
measurement value.
[0069] Further, user input can include a preselected ROP. A desired ROP
can be selected by a directional driller or other user, for example, and
the target DTOB measurement value can be determined as a function of the
desired ROP:
DTOB.sub.desired=g(ROP.sub.desired)
[0070] subject to: 1) WOB.sub.min.ltoreq.WOB.ltoreq.WOB.sub.max [0071]
2) DiffP.sub.min.ltoreq.DiffP.ltoreq.DiffP.sub.max [0072] 3)
RPM.sub.min.ltoreq.RPM.ltoreq.RPM.sub.max [0073] 4) safety operational
limits where RPM is drill bit torsional speed. The safety operational
limits can include, but are not limited to, a hook-load limit, an annular
pressure limit, and a vibration limit.
[0074] In addition, user input can include a preselected DWOB. The desired
DWOB can be used to compute the desired DTOB as a function of the desired
DWOB:
DTOB.sub.desired=f(DWOB.sub.desired)
[0075] subject to: 1) ROP.sub.min.ltoreq.ROP.ltoreq.ROP.sub.max [0076]
2) DiffP.sub.min.ltoreq.DiffP.ltoreq.DiffP.sub.max [0077] 3)
RPM.sub.min.ltoreq.RPM.ltoreq.RPM.sub.max [0078] 4) safety operational
limits
[0079] User input still further can include a preselected mud motor
differential pressure. A desired mud motor differential pressure can be
used to compute the desired DTOB as a function of the desired DiffP:
DTOB.sub.desired=f(.DELTA.P.sub.desired)
[0080] subject to: 1) ROP.sub.min.ltoreq.ROP.ltoreq.ROP.sub.max [0081]
2) DWOB.sub.min.ltoreq.DWOB.ltoreq.DWOB.sub.max [0082] 3)
RPM.sub.min.ltoreq.RPM.ltoreq.RPM.sub.max [0083] 4) safety operational
limits
[0084] The target DTOB measurement value also can be determined as a
function of two or more of desired ROP, desired DWOB, desired DiffP, and
desired drill bit RPM, subject to safety operational limits.
[0085] In addition to systems, embodiments of the invention can include
methods to control directional drilling in borehole drilling for
hydrocarbon wells. For example, a method according to an embodiment can
include determining an actual DTOB measurement value (and/or an actual
DWOB measurement value) and an actual toolface orientation measurement
value for a drill string 104 positioned in a borehole 102 for a
hydrocarbon well. A method also can include determining, responsive to a
comparison of a target DTOB measurement value (and/or a target DWOB
measurement value) and the actual DTOB measurement value (and/or the
actual DWOB measurement value), a DTOB error value (and/or a DWOB error
value). Further, a method can include determining, responsive to a
comparison of a target toolface orientation measurement value and the
actual toolface orientation measurement value, a toolface orientation
error value. In addition, a method can include determining a control
command for one or more of a top drive 114 and a drawworks 116 responsive
to the DTOB error value (and/or the DWOB error value) and the toolface
orientation error value. A method still further can include operating one
or more of the top drive 114 and the drawworks 116 responsive to the
control command thereby to correct a toolface orientation of the drill
string 104.
[0086] In some circumstances, determining the actual DTOB measurement
value can include determining an actual DWOB measurement value.
Additionally, determining the actual DTOB measurement value (and/or the
actual DWOB measurement value) and the actual toolface orientation
measurement value can be responsive to one or more of: (a) one or more
measurements at one or more sensors 120 positioned within the borehole
102 and (b) a Kalman filter. Further, a method also can include receiving
the one or more measurements from the one or more sensors 102 through one
or more segments of wired drill pipe 106 and determining a current top
drive operation measurement value and a current drawworks operation
measurement value. The control command can be responsive to the current
top drive operation measurement value and the current drawworks operation
measurement value. The control command can be for one or more of the top
drive, the drawworks, and a mud pump, and the method also can include
determining a current mud pump operation measurement value and operating
the mud pump responsive to the control command thereby to correct a
toolface orientation of the drill string 104. Determining the actual DTOB
measurement value (and/or the actual DWOB measurement value) and the
actual toolface measurement value can include validating the one or more
measurements at the one or more sensors 120 thereby to produce one or
more validated measurements and filtering the one or more validated
measurements thereby to produce one or more filtered measurements.
Additionally, determining the actual DTOB measurement value (and/or the
actual DWOB measurement value) and the actual toolface measurement value
can include reconciling the one or more filtered measurements thereby to
produce one or more reconciled measurements and verifying the one or more
reconciled measurements thereby to produce one or more verified
measurements. Determining the actual DTOB measurement value (and/or the
actual DWOB measurement value) and the actual toolface measurement value
also can include remediating gross errors in the one or more verified
measurements thereby to produce the actual DTOB measurement value (and/or
the actual DWOB measurement value) and the actual toolface measurement
value.
[0087] Additionally, operation of the drawworks 116 can include altering a
WOB measurement value at a surface of the borehole, and operation of the
top drive 114 can include altering one or more of an angle of the drill
string 104 with respect to the surface and a rotational speed of the
drill string 104 within the borehole 102. A method also can include
determining the target DTOB measurement value (and/or the target DWOB
measurement value) responsive to receipt of user input from a user
computing device. The user input can include one or more of: a
preselected DTOB measurement value, a preselected rate of penetration, a
preselected DWOB, and a preselected mud motor differential pressure. A
method also can include determining the target toolface orientation
measurement value responsive to receipt of the user input from the user
computing device.
[0088] Further, the control command can be responsive to one or more
dynamic models of the drill string 104 within the borehole 102, and
operation of the drawworks 116 can control a ROP of the drill string 102.
A method also can include estimating one or more future values of one or
more downhole variables and determining an optimal ROP of the drill
string 104 responsive to a constrained optimization problem.
Additionally, the control command can be responsive to the determined
optimal ROP of the drill string 104.
[0089] Embodiments also can include non-transitory computer-readable media
to control directional drilling in borehole drilling for hydrocarbon
wells. For example, a non-transitory computer-readable medium according
to an embodiment can have computer-executable instructions stored thereon
that can be executed by one or more processors to perform a method, such
as one or more of the methods described herein.
[0090] Another method according to an embodiment to control directional
drilling in borehole drilling for hydrocarbon wells can include providing
a directional drilling monitor application to a user on a user computing
device 170, as illustrated in FIG. 6, for example. Such a user computing
device 170 can include, for example, a desktop computer, a laptop, a
smartphone, a tablet computer, or a personal digital assistant, among
other examples. Further, the user computing device 170 can be positioned
and located at or near a drilling site, but the user computing device 170
also can be positioned at a remote location, such as an operator's office
facility or remote operations center, for example, or at any other
location. A user computing device 170 can include one or more processors
172, one or more memories 174 (such as non-transitory computer-readable
media) in communication with the one or more processors 172, and one or
more displays 176 in communication with the one or more processors 172,
for example.
[0091] A method also can include receiving measurements at a server 178
from one or more sensors 120 positioned in a borehole 102 for a
hydrocarbon well. The borehole 102 can extend from a surface into a
subsurface of the hydrocarbon well. The server 178 can be positioned and
located at the drilling site, but the server 178 also can be positioned
at a remote location, similarly to the user computing device 170.
Further, the server 178 and the user computer device 170 can be
positioned at the same location, either at the drilling site or at a
remote site, or the server 178 and the user computer device 170 can be
positioned at different locations from each other, including two separate
remote locations. The server 178 can include one or more processors 180
and a memory 182 (such as a non-transitory computer-readable medium) that
stores the user's preferences for information format and is in
communication with the one or more processors 180. The server 178 can be
in communication with the user computing device 170, a top drive 114, a
drawworks 116, and the one or more sensors 120.
[0092] The one or more processors 180 of the server 178 can operate to
perform a series of steps. For example, the one or more processors 180
can operate to determine, responsive to the received measurements, an
actual DTOB measurement value and an actual toolface orientation
measurement value for a drill string 104 positioned in the borehole 102.
The one or more processors 180 also can operate to determine a target
DTOB measurement value responsive to receipt of user input from the user
computing device 170. Further, the one or more processors 180 can operate
to determine a target toolface orientation measurement value responsive
to receipt of the user input from the user computing device 170. The one
or more processors 180 also can operate to determine, responsive to a
comparison of the target DTOB measurement value and the actual DTOB
measurement value, a DTOB error value. In addition, the one or more
processors 180 can operate to determine, responsive to a comparison of
the target toolface orientation measurement value and the actual toolface
orientation measurement value, a toolface orientation error value. Still
further, the one or more processors 180 can operate to determine a
control command for one or more of a top drive 114 and a drawworks 116 to
correct each of the DTOB error value and the toolface orientation error
value responsive to a current top drive operation measurement value and a
current drawworks operation measurement value. The one or more processors
180 also can operate to generate a directional drilling alert from the
actual DTOB measurement value, the actual toolface orientation
measurement value, and the control command. Further, the one or more
processors 180 can operate to format the directional drilling alert
according to the information format and transmit the formatted
directional drilling alert to the user computing device 170 thereby to
indicate a planned change in drill string orientation. In addition, the
one or more processors 180 can operate one or more of the top drive 114
and the drawworks 116 responsive to the control command thereby to
correct a toolface orientation of the drill string 104. Operation of the
drawworks 116 can include altering a WOB measurement value at the
surface, and operation of the top drive 114 can include altering one or
more of an angle of the drill string 104 with respect to the surface and
a rotational speed of the drill string 104 within the borehole 102.
[0093] In some instances, a system according to an embodiment can include
one or more modules. A module can include a set of instructions or
operations or one or more portions of a software application that relate
to and operate to effect certain functions of the software, for example,
as will be understood by those skilled in the art. Computer-executable
instructions that make up a software application can be stored on a
non-transitory computer-readable medium, for example, such as those
described herein. For example, as depicted in the exemplary system
diagram illustrated in FIG. 2, an autonomous direct controlled steering
system 150 according to an embodiment can be configured to automate
directional drilling operations where a drill string 104 is guided along
a non-vertical path. In operation, the high sampling rate drilling
parameter sensors 168 (which can include downhole sensors 120 and surface
sensors 122, for example) and a downhole drive controller 112 can provide
data to a data validation and reconciliation module 162 via the
substantially online data transmission system 164 (such as data
transmission system 124), which can make direct control possible. Such a
data validation and reconciliation module 162 can process the raw data
and provide the refined information to an autonomous direct control
system 152, which can evaluate the real-time performance of the steering
operation and accordingly provide online operating commands to one or
more drilling equipment driving systems 166. The one or more drilling
equipment driving systems 166 can include the top drive 114, the
drawworks 116, the mud pump 118, as well as controllers associated with
any of the equipment used during drilling. A drilling equipment driving
system 166 can be a drive control interface or software of any drilling
equipment or apparatus that can either directly or indirectly affect one
or more drilling parameters. Further, such equipment can be mounted in
downhole or at the surface. Exemplary rig-mounted equipment includes, but
is not limited to, rotating system equipment (such as one or more top
drives 114), hoisting system equipment (such as one or more drawworks
116), and circulating system equipment (such as one or more mud pumps
118). Exemplary downhole equipment can include any downhole active or
adjustable devices such as mud motors, turbines, bent subs or whipstocks,
adjustable stabilizers, agitators, and rotary steerable systems.
[0094] Some or all of the data validation and reconciliation operations
described above, including some or all of those illustrated in FIG. 3,
can be performed by a data validation and reconciliation module 162, for
example. In such an example, FIG. 3 can depict an exemplary workflow of
the data validation and reconciliation module 162.
[0095] Further, the autonomous direct control system 152 can perform some
of the other operations described above. The autonomous direct control
system 152 can be in bidirectional communication with a common operation
infrastructure, including an operator station 160. The operator station
160 can provide a user interface that can be accessed by a directional
driller on the rig or in a remote location, for example. The operator
station 160 also can provide a location for providing manual input to the
control system 152 and for manual override of the control system 152 if
needed. The control station 160 can provide a visual representation of
the operation of the autonomous direct control system 152, including the
status of one or more drilling equipment 166 and a real-time
representation of data received from the drilling parameter sensors 168.
The BHA 108 can be coupled to and in communication with a rotating system
(such as a top drive 114), a hoisting system (such as a drawworks 116),
or other surface equipment via a drill pipe 106. Under an autonomous
direct control operation, the raw data collected by the high sampling
rate drilling parameter sensors 168 can be relayed to the data validation
and reconciliation module 162 via the online data transmission system
164. The drilling parameter sensors 168 also can be configured to receive
operating instructions (in addition to sending measurements) via the
online transmission system 164. The raw data collected by the drilling
parameter sensors 168 can be processed online by the data validation and
reconciliation module 162 to obtain refined information useful for
decision-making by the autonomous direct control system 152.
[0096] An autonomous direct control system 152 can include one or more
components referred to herein as mechanisms, such as a primary control
mechanism 154, a secondary control mechanism 156, and a tertiary control
mechanism 158. A mechanism as described can include a set of instructions
or operations or a portion of a software application that relates to and
operates to effect certain functions of the software, for example, as
will be understood by those skilled in the art. Computer-executable
instructions that make up a software application can be stored on a
non-transitory computer-readable medium, for example, such as those
described herein. In some instances, the autonomous direct control system
152 depicted in FIG. 2 can include only a primary control mechanism 154
that provides online operating commands to one or more drilling equipment
driving systems 166 in order to ensure stability and robustness of
automated directional drilling against a wide range of external
disturbances, measurement uncertainties, and unknown environmental
conditions. Such a primary control mechanism 154 can be fully implemented
either in a downhole device or in a surface application. In either case,
the communication between the surface and the downhole can be enabled by
an online data transmission system 164.
[0097] Some or all of the operations described above, including some or
all of those illustrated in FIG. 4, can be performed by such a primary
control mechanism 154, for example. In such an example, FIG. 4 can depict
a simplified block diagram and an exemplary workflow of the primary
control mechanism 154. More specifically, FIG. 4 can illustrate an
exemplary workflow of the primary control mechanism 154 utilizing control
logic related to a disturbance rejection method. Such disturbance
rejection control logic can receive a scaled deviation error of toolface
orientation 254 and one or more of scaled deviation errors of DTOB and
DWOB 252, along with drill string torsional compliance data, and
accordingly can issue operating commands 262 via an output interface to
one or more drilling equipment and apparatuses, including rotating system
equipment such as top drives, hoisting system equipment such as
drawworks, circulating system equipment such as mud pumps, and downhole
RSS equipment. The control logic can be a multivariable (also called
multi-input multi-output) control method with a model-independent core
logic 262. In some instances, such active disturbance rejection control
logic can include one or more proportional-integral-derivative (PID)
controllers, where the input to each PID controller can be a function of
the scaled deviation errors and drill string torsional compliance data.
Further, in some circumstances, the control logic can be associated with
a fuzzy logic controller. An extension of a system model with an
additional and fictitious state variable that represents everything that
a user does not include in a mathematical description of the plant of
interest can be used, as well. A plant, as will be understood by those
skilled in the art, can include a system on which the disturbance control
logic can operate, including drilling equipment (such as sensors, a
drawworks, a top drive, and a mud pump, for example) and information
transmitted to and from the drilling equipment. This virtual state (sum
of internal and external disturbances, sometimes denoted as a "total
disturbance") can be estimated online with a state observer and used in
the control signal in order to decouple unknown uncertainties from the
rest of the drilling system. This disturbance rejection feature can allow
the user to treat the considered system with a simpler model, since the
negative effects of modeling uncertainty can be compensated in real time.
As a result, it can eliminate a need for a precise analytical description
of the system, as one can assume the unknown parts of dynamics as the
internal disturbance in the drilling system. Robustness and the adaptive
ability of this method can provide an advantageous solution in scenarios
where the full knowledge of the drilling system is not available.
[0098] An additional method according to an embodiment is illustrated in
FIG. 10, for example. Measurements can be taken 350 from one or more
downhole sensors 120 positioned along a drill string 104, including
measurements related to toolface orientation, downhole WOB (DWOB),
downhole torque (Dtorque), and downhole differential pressure (Ddiff P).
These measurements can be used to determine toolface orientation, which
can be filtered 352 to generate a toolface estimate 354. The toolface
estimate 354 and a target toolface 316 can be summed 356, then
optimization criteria can be selected 358. A torque command can be
processed 360 and used as an input to a state space MIMO 362. The state
space MIMO 362 can include inputs of downhole bit torque, surface torque,
downhole WOB, and downhole differential pressure. The state space MIMO
362 further can utilize as given inputs the length of the drill pipe, the
type and size of the drill pipe, and one or more optimizing parameters.
Outputs of the state space MIMO 362 can include line payoff, pipe
rotation, and pump speed. Line payoff, drill pipe incremental rotation,
and bit speed then can be sent to one or more controllers 364, which can
control operation of a drawworks, a pipe rotator (which can be a subset
of a top drive control), and a pump controller.
[0099] Further, an additional system according to an embodiment is
illustrated in FIG. 11, for example. Such a system can allow input from
one or more users 372 through a user interface 374. The user interface
374 can be in communication, through input/output services 376, with
surface instrumentation 378, downhole instrumentation 382, a rig control
system 384, data services 386, and an application engine 380. The
application engine 380 can perform one or more of the operations or
methods described herein. Further, the data services 386 can be in
communication with configuration storage 388 and data logging 390.
[0100] Embodiments of the invention thus can provide autonomous direct
controlled steering in directional drilling that can include: a drilling
parameter sensor with high sampling rate; a data validation and
reconciliation module that can be communicatively coupled to the drilling
parameter sensor through an online data transmission system and can
generate processed data from the raw data gathered by the drilling
parameter sensor; a primary control mechanism that can enhance stability
and robustness of automated directional drilling by online commanding a
drilling equipment driving system; a secondary control mechanism that
adaptively can guide the primary control mechanism based on a drill
string dynamic model; and a tertiary control mechanism that can determine
an optimal rate of penetration by online solving a constrained
optimization problem.
[0101] Consequently, embodiments of the invention can provide drilling
optimization software to automate and optimize directional drilling
practices to set and continuously maintain downhole equipment orientation
while also optimizing drilling rate of penetration. Such a software
application can achieve this automation by applying downhole measurements
of torque, WOB, and differential pressure to continuously control surface
pipe rotary and drawworks systems. Further, such a software application
also can enable automated directional drilling to be performed and
monitored from a remote operations center.
[0102] In the various embodiments of the invention described herein, a
person having ordinary skill in the art will recognize that various types
of memory are readable by a computer, such as the memory described herein
in reference to the various computers and servers, e.g., computer,
computer server, web server, or other computers with embodiments of the
present invention. Examples of computer-readable media can include but
are not limited to: nonvolatile, hard-coded type media, such as read only
memories (ROMs), CD-ROMs, and DVD-ROMs, or erasable, electrically
programmable read only memories (EEPROMs); recordable type media, such as
floppy disks, hard disk drives, CD-R/RWs, DVD-RAMs, DVD-R/RWs, DVD+R/RWs,
flash drives, memory sticks, and other newer types of memories; and
transmission type media such as digital and analog communication links.
For example, such media can include operating instructions, as well as
instructions related to the systems and the method steps described above
and can operate on a computer. It will be understood by those skilled in
the art that such media can be at other locations instead of, or in
addition to, the locations described to store computer program products,
e.g., including software thereon. It will be understood by those skilled
in the art that the various software modules or electronic components
described above can be implemented and maintained by electronic hardware,
software, or a combination of the two, and that such embodiments are
contemplated by embodiments of the present invention.
[0103] This application is related to and claims the benefit and priority
of provisional U.S. Patent Application No. 62/097,644, titled "Drilling
Direct Control System" and filed Dec. 30, 2014, and non-provisional U.S.
patent application Ser. No. 14/627,581, titled "Drilling Direct Control
User Interface" and filed Feb. 20, 2015, of which this application is a
continuation-in-part, each of which is hereby incorporated by reference.
[0104] In the drawings and specification, there have been disclosed
embodiments of systems, interfaces, computer-readable media, and methods
of the present invention, and although specific terms are employed, the
terms are used in a descriptive sense only and not for purposes of
limitation. The embodiments of systems, interfaces, computer-readable
media, and methods of the present invention have been described in
considerable detail with specific reference to these illustrated
embodiments. It will be apparent, however, that various modifications and
changes can be made within the spirit and scope of the embodiments of
systems, interfaces, computer-readable media, and methods of the present
invention as described in the foregoing specification, and such
modifications and changes are to be considered equivalents and part of
this disclosure.
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