U.S. patent application number 14/899902 was filed with the patent office on 2016-12-22 for drilling measurement systems and methods.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to James Curtis Brannigan, Vishwanathan Parmeshwar, Gokturk Tunc, Shunfeng Zheng.
Application Number | 20160369619 14/899902 |
Document ID | / |
Family ID | 56127605 |
Filed Date | 2016-12-22 |
United States Patent
Application |
20160369619 |
Kind Code |
A1 |
Parmeshwar; Vishwanathan ;
et al. |
December 22, 2016 |
DRILLING MEASUREMENT SYSTEMS AND METHODS
Abstract
Systems and methods for tracking depth of a drill string. The
method includes determining a measured elevation difference between
a first position of a sensor and a second position of the sensor,
based on measurements taken by an elevation measurement device,
determining a calibration elevation difference between the first
and second positions based on measurements taken by the sensor
using markers positioned at predetermined elevations, and
calibrating the elevation measurement device based at least
partially on a relationship between the measured elevation
difference and the calibration elevation difference.
Inventors: |
Parmeshwar; Vishwanathan;
(Houston, TX) ; Zheng; Shunfeng; (Katy, TX)
; Tunc; Gokturk; (Houston, TX) ; Brannigan; James
Curtis; (Cypress, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
56127605 |
Appl. No.: |
14/899902 |
Filed: |
December 17, 2015 |
PCT Filed: |
December 17, 2015 |
PCT NO: |
PCT/US2015/066425 |
371 Date: |
December 18, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62094502 |
Dec 19, 2014 |
|
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|
62140705 |
Mar 31, 2015 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/00 20130101;
E21B 44/00 20130101; G01B 11/22 20130101; E21B 19/00 20130101; E21B
47/007 20200501; E21B 44/02 20130101; E21B 47/04 20130101; E21B
19/10 20130101; E21B 47/09 20130101 |
International
Class: |
E21B 47/09 20060101
E21B047/09; E21B 19/00 20060101 E21B019/00; E21B 47/00 20060101
E21B047/00 |
Claims
1. A method for tracking depth of a drill string, comprising:
determining a measured elevation difference between a first
position of a sensor and a second position of the sensor, based on
measurements taken by an elevation measurement device; determining
a calibration elevation difference between the first and second
positions based on measurements taken by the sensor using one or
more markers positioned at one or more predetermined elevations;
and calibrating the elevation measurement device based at least
partially on a relationship between the measured elevation
difference and the calibration elevation difference.
2. The method of claim 1, wherein determining the measured
elevation difference comprises moving the sensor at least partially
vertically from the first position to the second position.
3. The method of claim 2, wherein the elevation measurement device
comprises an encoder configured to measure an angular displacement
of a drum of a drawworks, wherein the drawworks is configured to
move the sensor.
4. The method of claim 3, wherein the sensor is coupled to a top
drive of a drilling rig or to a travelling block of the drilling
rig, the drawworks being configured to move the top drive and the
travelling block.
5. The method of claim 1, wherein determining the calibration
elevation difference between the first position and the second
position comprises: acquiring a first identifier from a first
marker of the one or more markers when the sensor is at the first
position; acquiring a second identifier from a second marker of the
one or more markers when the sensor is at the second position;
determining a first elevation of the sensor based on the first
identifier; and determining a second elevation of the sensor based
on the second identifier.
6. The method of claim 1, wherein determining the calibration
elevation difference between the first position and the second
position comprises: triangulating a first elevation using the
sensor and at least two markers, when the sensor is at the first
position; and triangulating a second elevation using the sensor at
the at least two markers when the sensor is at the second
position.
7. The method of claim 1, wherein determining the calibration
elevation difference comprises determining a size difference
between two or more images captured by the sensor.
8. The method of claim 1, wherein: the sensor comprises an optical
sensor and the one or more markers each comprise a laser; or the
sensor comprises a radiofrequency identification (RFID) tag reader,
and the one or more markers each comprise an RFID tag.
9. The method of claim 1, further comprising measuring a position
change of the drill string using a camera positioned proximal to a
slips, wherein calibrating the elevation measurement device
comprises accounting for the position change of the drill
string.
10. A method for measuring a drilling depth, comprising: moving a
drilling device from a first position to a second position by
spooling or unspooling a drill line on a drawworks drum;
determining a measured elevation of the drilling device at the
second position using a primary elevation measurement device
configured to measure an elevation of the drilling device based on
the spooling or unspooling of the drill line on the drawworks drum;
determining a sensed elevation of the drilling device at the second
position using a sensor that is moved along with the drilling
device; determining a deformation metric selected from the group
consisting of stretch, strain, and stress, in the drill line, based
on a difference between the measured elevation and the sensed
elevation; and correcting the primary elevation measurement device
based on the deformation metric.
11. The method of claim 10, wherein: determining the measured
elevation of the drilling device at the second position comprises
determining the measured elevation of the drilling device at the
second position while supporting a drill string comprising one or
more drill pipes using the drilling device; the method further
comprises, prior to supporting the drill string using the drilling
device, determining the measured elevation of the drilling device
at the second position using the elevation measurement device; and
determining the deformation metric the drill line is further based
on a difference between the measured elevation at the second
position prior to supporting the drill string and the measured
elevation at the second position while supporting the drill
string.
12. The method of claim 10, wherein determining the deformation
metric comprises: determining the strain; and determining the
stretch in the drill line when the drill line is in the first
position based on the determined strain and a difference in a
length of the drill line when the drilling device is in the first
position and when the drilling device is in the second
position.
13. The method of claim 10, further comprising: determining the
measured elevation of the drilling device at the first position
using the elevation measurement device; determining the sensed
elevation of the drilling device at the first position using the
sensor; determining the deformation metric of the drilling line
based on a difference between the measured elevation and the sensed
elevation; and interpolating the deformation metric in the drilling
line when the drilling device is between the first and second
position, based on the stretch determined in the drilling line when
the drilling device is in the first position and when the drilling
device is in the second position.
14. The method of claim 10, wherein the primary elevation
measurement device comprises an encoder coupled to the drawworks
drum and configured to measure a rotation thereof
15. The method of claim 10, wherein the determining the sensed
elevation comprises sensing one or more markers coupled to a rig
structure using the sensor.
16. A method for tracking depth of a drill string, comprising:
coupling a sensor to a drilling device, wherein the drilling device
is movable vertically with respect to a rig floor and is configured
to rotate a drill string; sensing a first marker that is stationary
with respect to the rig floor using the sensor; measuring a
distance between the first marker and the sensor, or an angle at
which the sensor is positioned to sense the first marker, or both;
and determining an elevation of the drilling device above the rig
floor based on the distance or the angle, or both.
17. The method of claim 16, further comprising: sensing a second
marker that is stationary with respect to the rig floor using the
sensor; and measuring a second distance between the second marker
and the sensor, or a second angle at which the sensor is positioned
to sense the second marker, or both, wherein determining the
elevation is further based on the second distance or the second
angle.
18. The method of claim 17, wherein the first and second markers
each comprise a transceiver.
19. The method of claim 17, wherein the first and second markers
are coupled to the rig floor, or to a mast extending from the rig
floor and from which the drilling device is suspended.
20. The method of claim 16, wherein the sensor comprises a camera,
an optical sensor, a laser transmitter, a ultrasonic transmitter, a
radar transmitter, or a combination thereof.
21. The method of claim 16, wherein the sensor operates
continuously to sense the first marker.
22. The method of claim 17, further comprising: sensing a third
marker that is stationary with respect to the rig floor using the
sensor; determining a signal quality associated with sensing the
first marker, the second marker, and the third marker; and
selecting the first distance or the first angle, and the second
distance or the second angle, based on signal quality.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional Patent
Application having Ser. No. 62/140,705, which was filed on Mar. 31,
2015, and to U.S. Provisional Patent Application having Ser. No.
62/094,502 which was filed on Dec. 19, 2014. The entirety of both
of these priority applications is incorporated herein by
reference.
BACKGROUND
[0002] In drilling operations, the length of the drill string may
be monitored and updated by various instruments. Maintaining an
accurate and generally up-to-date measure of the drill string
length may have a variety of uses. For example, knowledge of the
drill string length may facilitate maintaining operational safety.
If drilling depth is not tracked properly, a driller may run the
whole drill string into the rock at full speed without realizing
the bottom end of the hole is approaching, potentially causing
severe equipment damage and operational problems.
[0003] Another use is for depth correlation. For example, a
specific target (e.g., a reservoir) may have a certain depth, or a
kick-off point for a deviated section of a well may be specified in
terms of drilling depth. Drill string length may be used as a proxy
for the drilling depth, and thus, a drilling operator may recognize
that such an event has occurred (or is to occur) when a certain
string length is reached. Further, recorded event occurrences,
logs, etc. may be linked to drilling depth through drill string
length, which may provide insight into the subterranean formation
properties.
[0004] Generally, drill string length is measured using an encoder
at the drawworks of the rig. In many rigs, the drawworks is a winch
that controls the raising and lowering of the travelling block,
which in turn adjusts the elevation of the top drive and the drill
string attached thereto. The encoder records the revolutions, or
otherwise the angular position, of the winch, which in turn
provides the distance that the travelling block has been lowered.
When a stand is fully deployed, the block can be raised again using
the drawworks, and the process can be repeated.
[0005] However, the drawworks encoder measurement may have an
inherent error caused by the radius of the drill line layer
relative to the center of the drawworks, the stretch of drill line
under the hookload (which itself may fluctuate, e.g., by downhole
pressures, etc.), and the like. Accordingly, a geolograph line is
sometimes used to calibrate the drawworks encoder. The geolograph
line is a cable that is attached directly to the top drive or the
block. A cable retrieval system for the cable is provided, along
with an encoding sensor, and both are attached to a fixed point on
or near the rig floor. The geolograph line then travels up and down
the derrick with the top drive while the encoder measures the
amount of line being paid out or retrieved.
SUMMARY
[0006] Embodiments of the disclosure may provide a method for
tracking depth of a drill string. The method includes determining a
measured elevation difference between a first position of a sensor
and a second position of the sensor, based on measurements taken by
an elevation measurement device, determining a calibration
elevation difference between the first and second positions based
on measurements taken by the sensor using markers positioned at
predetermined elevations, and calibrating the elevation measurement
device based at least partially on a relationship between the
measured elevation difference and the calibration elevation
difference.
[0007] Embodiments of the disclosure may also provide a method for
measuring a drilling depth. The method includes moving a drilling
device from a first position to a second position by spooling or
unspooling a drill line on a drawworks drum, determining a measured
elevation of the drilling device at the second position using a
primary elevation measurement device configured to measure an
elevation of the drilling device based on the spooling or
unspooling of the drill line on the drawworks drum, determining a
sensed elevation of the drilling device at the second position
using a sensor that is moved along with the drilling device,
determining a deformation metric selected from the group consisting
of stretch, strain, and stress, in the drill line, based on a
difference between the measured elevation and the sensed elevation,
and correcting the primary elevation measurement device based on
the deformation metric.
[0008] Embodiments of the disclosure may also provide a method for
tracking depth of a drill string. The method includes coupling a
sensor to a drilling device, wherein the drilling device is movable
vertically with respect to a rig floor and is configured to rotate
a drill string, sensing a first marker that is stationary with
respect to the rig floor using the sensor, measuring a distance
between the first marker and the sensor, or an angle at which the
sensor is positioned to sense the first marker, or both, and
determining an elevation of the drilling device above the rig floor
based on the distance or the angle, or both.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The accompanying drawings, which are incorporated in and
constitute a part of this specification, illustrate embodiments of
the present teachings and together with the description, serve to
explain the principles of the present teachings. In the
figures:
[0010] FIG. 1 illustrates a schematic view of a drilling rig and a
control system, according to an embodiment.
[0011] FIG. 2 illustrates a schematic view of a drilling rig and a
remote computing resource environment, according to an
embodiment.
[0012] FIGS. 3A, 3B, and 3C illustrate conceptual, side, schematic
views of three embodiments of an automated calibration system.
[0013] FIG. 4A illustrates a flowchart of a method for automated
calibration of a drilling depth measurement, according to an
embodiment.
[0014] FIG. 4B illustrates a plot of actual versus measured depth
in a calibrated system and in an uncalibrated system, according to
an embodiment.
[0015] FIGS. 5 and 6 illustrate schematic views of an automated
calibration system, according to an embodiment.
[0016] FIG. 7 illustrates a schematic view of a pipe movement
tracking system, according to an embodiment.
[0017] FIG. 8 illustrates a flowchart of a method for measuring a
length of a tubular, according to an embodiment.
[0018] FIGS. 9 and 10 illustrate side, schematic views of a
drilling rig at various points during the method of FIG. 8,
according to an embodiment.
[0019] FIG. 11 illustrates a flowchart of a method for drilling,
according to an embodiment.
[0020] FIG. 12 illustrates a side, schematic view of a drilling rig
having a drill string deployed into a wellbore, according to an
embodiment.
[0021] FIG. 13 illustrates a schematic view of a computing system,
according to an embodiment.
DETAILED DESCRIPTION
[0022] Reference will now be made in detail to specific embodiments
illustrated in the accompanying drawings and figures. In the
following detailed description, numerous specific details are set
forth in order to provide a thorough understanding of the
invention. However, it will be apparent to one of ordinary skill in
the art that the invention may be practiced without these specific
details. In other instances, well-known methods, procedures,
components, circuits, and networks have not been described in
detail so as not to unnecessarily obscure aspects of the
embodiments.
[0023] It will also be understood that, although the terms first,
second, etc. may be used herein to describe various elements, these
elements should not be limited by these terms. These terms are only
used to distinguish one element from another. For example, a first
object could be termed a second object or step, and, similarly, a
second object could be termed a first object or step, without
departing from the scope of the present disclosure.
[0024] The terminology used in the description of the invention
herein is for the purpose of describing particular embodiments only
and is not intended to be limiting. As used in the description of
the invention and the appended claims, the singular forms "a," "an"
and "the" are intended to include the plural forms as well, unless
the context clearly indicates otherwise. It will also be understood
that the term "and/or" as used herein refers to and encompasses any
and all possible combinations of one or more of the associated
listed items. It will be further understood that the terms
"includes," "including," "comprises" and/or "comprising," when used
in this specification, specify the presence of stated features,
integers, steps, operations, elements, and/or components, but do
not preclude the presence or addition of one or more other
features, integers, steps, operations, elements, components, and/or
groups thereof. Further, as used herein, the term "if" may be
construed to mean "when" or "upon" or "in response to determining"
or "in response to detecting," depending on the context.
[0025] FIG. 1 illustrates a conceptual, schematic view of a control
system 100 for a drilling rig 102, according to an embodiment. The
control system 100 may include a rig computing resource environment
105, which may be located onsite at the drilling rig 102 and, in
some embodiments, may have a coordinated control device 104. The
control system 100 may also provide a supervisory control system
107. In some embodiments, the control system 100 may include a
remote computing resource environment 106, which may be located
offsite from the drilling rig 102.
[0026] The remote computing resource environment 106 may include
computing resources locating offsite from the drilling rig 102 and
accessible over a network. A "cloud" computing environment is one
example of a remote computing resource. The cloud computing
environment may communicate with the rig computing resource
environment 105 via a network connection (e.g., a WAN or LAN
connection).
[0027] Further, the drilling rig 102 may include various systems
with different sensors and equipment for performing operations of
the drilling rig 102, and may be monitored and controlled via the
control system 100, e.g., the rig computing resource environment
105. Additionally, the rig computing resource environment 105 may
provide for secured access to rig data to facilitate onsite and
offsite user devices monitoring the rig, sending control processes
to the rig, and the like.
[0028] Various example systems of the drilling rig 102 are depicted
in FIG. 1. For example, the drilling rig 102 may include a downhole
system 110, a fluid system 112, and a central system 114. In some
embodiments, the drilling rig 102 may include an information
technology (IT) system 116. The downhole system 110 may include,
for example, a bottomhole assembly (BHA), mud motors, sensors, etc.
disposed along the drill string, and/or other drilling equipment
configured to be deployed into the wellbore. Accordingly, the
downhole system 110 may refer to tools disposed in the wellbore,
e.g., as part of the drill string used to drill the well.
[0029] The fluid system 112 may include, for example, drilling mud,
pumps, valves, cement, mud-loading equipment, mud-management
equipment, pressure-management equipment, separators, and other
fluids equipment. Accordingly, the fluid system 112 may perform
fluid operations of the drilling rig 102.
[0030] The central system 114 may include a hoisting and rotating
platform, top drives, rotary tables, kellys, drawworks, pumps,
generators, tubular handling equipment, derricks, masts,
substructures, and other suitable equipment. Accordingly, the
central system 114 may perform power generation, hoisting, and
rotating operations of the drilling rig 102, and serve as a support
platform for drilling equipment and staging ground for rig
operation, such as connection make up, etc. The IT system 116 may
include software, computers, and other IT equipment for
implementing IT operations of the drilling rig 102.
[0031] The control system 100, e.g., via the coordinated control
device 104 of the rig computing resource environment 105, may
monitor sensors from multiple systems of the drilling rig 102 and
provide control commands to multiple systems of the drilling rig
102, such that sensor data from multiple systems may be used to
provide control commands to the different systems of the drilling
rig 102. For example, the system 100 may collect temporally and
depth aligned surface data and downhole data from the drilling rig
102 and store the collected data for access onsite at the drilling
rig 102 or offsite via the rig computing resource environment 105.
Thus, the system 100 may provide monitoring capability.
Additionally, the control system 100 may include supervisory
control via the supervisory control system 107.
[0032] In some embodiments, one or more of the downhole system 110,
fluid system 112, and/or central system 114 may be manufactured
and/or operated by different vendors. In such an embodiment,
certain systems may not be capable of unified control (e.g., due to
different protocols, restrictions on control permissions, etc.). An
embodiment of the control system 100 that is unified, may, however,
provide control over the drilling rig 102 and its related systems
(e.g., the downhole system 110, fluid system 112, and/or central
system 114).
[0033] FIG. 2 illustrates a conceptual, schematic view of the
control system 100, according to an embodiment. The rig computing
resource environment 105 may communicate with offsite devices and
systems using a network 108 (e.g., a wide area network (WAN) such
as the internet). Further, the rig computing resource environment
105 may communicate with the remote computing resource environment
106 via the network 108. FIG. 2 also depicts the aforementioned
example systems of the drilling rig 102, such as the downhole
system 110, the fluid system 112, the central system 114, and the
IT system 116. In some embodiments, one or more onsite user devices
118 may also be included on the drilling rig 102. The onsite user
devices 118 may interact with the IT system 116. The onsite user
devices 118 may include any number of user devices, for example,
stationary user devices intended to be stationed at the drilling
rig 102 and/or portable user devices. In some embodiments, the
onsite user devices 118 may include a desktop, a laptop, a
smartphone, a personal data assistant (PDA), a tablet component, a
wearable computer, or other suitable devices. In some embodiments,
the onsite user devices 118 may communicate with the rig computing
resource environment 105 of the drilling rig 102, the remote
computing resource environment 106, or both.
[0034] One or more offsite user devices 120 may also be included in
the system 100. The offsite user devices 120 may include a desktop,
a laptop, a smartphone, a personal data assistant (PDA), a tablet
component, a wearable computer, or other suitable devices. The
offsite user devices 120 may be configured to receive and/or
transmit information (e.g., monitoring functionality) from and/or
to the drilling rig 102 via communication with the rig computing
resource environment 105. In some embodiments, the offsite user
devices 120 may provide control processes for controlling operation
of the various systems of the drilling rig 102. In some
embodiments, the offsite user devices 120 may communicate with the
remote computing resource environment 106 via the network 108.
[0035] The systems of the drilling rig 102 may include various
sensors, actuators, and controllers (e.g., programmable logic
controllers (PLCs)). For example, the downhole system 110 may
include sensors 122, actuators 124, and controllers 126. The fluid
system 112 may include sensors 128, actuators 130, and controllers
132. Additionally, the central system 114 may include sensors 134,
actuators 136, and controllers 138. The sensors 122, 128, and 134
may include any suitable sensors for operation of the drilling rig
102. In some embodiments, the sensors 122, 128, and 134 may include
a camera, a pressure sensor, a temperature sensor, a flow rate
sensor, a vibration sensor, a current sensor, a voltage sensor, a
resistance sensor, a gesture detection sensor or device, a voice
actuated or recognition device or sensor, or other suitable
sensors.
[0036] The sensors described above may provide sensor data to the
rig computing resource environment 105 (e.g., to the coordinated
control device 104). For example, downhole system sensors 122 may
provide sensor data 140, the fluid system sensors 128 may provide
sensor data 142, and the central system sensors 134 may provide
sensor data 144. The sensor data 140, 142, and 144 may include, for
example, equipment operation status (e.g., on or off, up or down,
set or release, etc.), drilling parameters (e.g., depth, hook load,
torque, etc.), auxiliary parameters (e.g., vibration data of a
pump) and other suitable data. In some embodiments, the acquired
sensor data may include or be associated with a timestamp (e.g., a
date, time or both) indicating when the sensor data was acquired.
Further, the sensor data may be aligned with a depth or other
drilling parameter.
[0037] Acquiring the sensor data at the coordinated control device
104 may facilitate measurement of the same physical properties at
different locations of the drilling rig 102. In some embodiments,
measurement of the same physical properties may be used for
measurement redundancy to enable continued operation of the well.
In yet another embodiment, measurements of the same physical
properties at different locations may be used for detecting
equipment conditions among different physical locations. The
variation in measurements at different locations over time may be
used to determine equipment performance, system performance,
scheduled maintenance due dates, and the like. For example, slip
status (e.g., in or out) may be acquired from the sensors and
provided to the rig computing resource environment 105. In another
example, acquisition of fluid samples may be measured by a sensor
and related with bit depth and time measured by other sensors.
Acquisition of data from a camera sensor may facilitate detection
of arrival and/or installation of materials or equipment in the
drilling rig 102. The time of arrival and/or installation of
materials or equipment may be used to evaluate degradation of a
material, scheduled maintenance of equipment, and other
evaluations.
[0038] The coordinated control device 104 may facilitate control of
individual systems (e.g., the central system 114, the downhole
system, or fluid system 112, etc.) at the level of each individual
system. For example, in the fluid system 112, sensor data 128 may
be fed into the controller 132, which may respond to control the
actuators 130. However, for control operations that involve
multiple systems, the control may be coordinated through the
coordinated control device 104. Examples of such coordinated
control operations include the control of downhole pressure during
tripping. The downhole pressure may be affected by both the fluid
system 112 (e.g., pump rate and choke position) and the central
system 114 (e.g. tripping speed). When it is desired to maintain
certain downhole pressure during tripping, the coordinated control
device 104 may be used to direct the appropriate control
commands.
[0039] In some embodiments, control of the various systems of the
drilling rig 102 may be provided via a three-tier control system
that includes a first tier of the controllers 126, 132, and 138, a
second tier of the coordinated control device 104, and a third tier
of the supervisory control system 107. In other embodiments,
coordinated control may be provided by one or more controllers of
one or more of the drilling rig systems 110, 112, and 114 without
the use of a coordinated control device 104. In such embodiments,
the rig computing resource environment 105 may provide control
processes directly to these controllers for coordinated control.
For example, in some embodiments, the controllers 126 and the
controllers 132 may be used for coordinated control of multiple
systems of the drilling rig 102.
[0040] The sensor data 140, 142, and 144 may be received by the
coordinated control device 104 and used for control of the drilling
rig 102 and the drilling rig systems 110, 112, and 114. In some
embodiments, the sensor data 140, 142, and 144 may be encrypted to
produce encrypted sensor data 146. For example, in some
embodiments, the rig computing resource environment 105 may encrypt
sensor data from different types of sensors and systems to produce
a set of encrypted sensor data 146. Thus, the encrypted sensor data
146 may not be viewable by unauthorized user devices (either
offsite or onsite user device) if such devices gain access to one
or more networks of the drilling rig 102. The encrypted sensor data
146 may include a timestamp and an aligned drilling parameter
(e.g., depth) as discussed above. The encrypted sensor data 146 may
be sent to the remote computing resource environment 106 via the
network 108 and stored as encrypted sensor data 148.
[0041] The rig computing resource environment 105 may provide the
encrypted sensor data 148 available for viewing and processing
offsite, such as via offsite user devices 120. Access to the
encrypted sensor data 148 may be restricted via access control
implemented in the rig computing resource environment 105. In some
embodiments, the encrypted sensor data 148 may be provided in
real-time to offsite user devices 120 such that offsite personnel
may view real-time status of the drilling rig 102 and provide
feedback based on the real-time sensor data. For example, different
portions of the encrypted sensor data 146 may be sent to offsite
user devices 120. In some embodiments, encrypted sensor data may be
decrypted by the rig computing resource environment 105 before
transmission or decrypted on an offsite user device after encrypted
sensor data is received.
[0042] The offsite user device 120 may include a thin client
configured to display data received from the rig computing resource
environment 105 and/or the remote computing resource environment
106. For example, multiple types of thin clients (e.g., devices
with display capability and minimal processing capability) may be
used for certain functions or for viewing various sensor data.
[0043] The rig computing resource environment 105 may include
various computing resources used for monitoring and controlling
operations such as one or more computers having a processor and a
memory. For example, the coordinated control device 104 may include
a computer having a processor and memory for processing sensor
data, storing sensor data, and issuing control commands responsive
to sensor data. As noted above, the coordinated control device 104
may control various operations of the various systems of the
drilling rig 102 via analysis of sensor data from one or more
drilling rig systems (e.g. 110, 112, 114) to enable coordinated
control between each system of the drilling rig 102. The
coordinated control device 104 may execute control commands 150 for
control of the various systems of the drilling rig 102 (e.g.,
drilling rig systems 110, 112, 114). The coordinated control device
104 may send control data determined by the execution of the
control commands 150 to one or more systems of the drilling rig
102. For example, control data 152 may be sent to the downhole
system 110, control data 154 may be sent to the fluid system 112,
and control data 154 may be sent to the central system 114. The
control data may include, for example, operator commands (e.g.,
turn on or off a pump, switch on or off a valve, update a physical
property setpoint, etc.). In some embodiments, the coordinated
control device 104 may include a fast control loop that directly
obtains sensor data 140, 142, and 144 and executes, for example, a
control algorithm. In some embodiments, the coordinated control
device 104 may include a slow control loop that obtains data via
the rig computing resource environment 105 to generate control
commands.
[0044] In some embodiments, the coordinated control device 104 may
intermediate between the supervisory control system 107 and the
controllers 126, 132, and 138 of the systems 110, 112, and 114. For
example, in such embodiments, a supervisory control system 107 may
be used to control systems of the drilling rig 102. The supervisory
control system 107 may include, for example, devices for entering
control commands to perform operations of systems of the drilling
rig 102. In some embodiments, the coordinated control device 104
may receive commands from the supervisory control system 107,
process the commands according to a rule (e.g., an algorithm based
upon the laws of physics for drilling operations), and/or control
processes received from the rig computing resource environment 105,
and provides control data to one or more systems of the drilling
rig 102. In some embodiments, the supervisory control system 107
may be provided by and/or controlled by a third party. In such
embodiments, the coordinated control device 104 may coordinate
control between discrete supervisory control systems and the
systems 110, 112, and 114 while using control commands that may be
optimized from the sensor data received from the systems 110 112,
and 114 and analyzed via the rig computing resource environment
105.
[0045] The rig computing resource environment 105 may include a
monitoring process 141 that may use sensor data to determine
information about the drilling rig 102. For example, in some
embodiments the monitoring process 141 may determine a drilling
state, equipment health, system health, a maintenance schedule, or
any combination thereof. In some embodiments, the rig computing
resource environment 105 may include control processes 143 that may
use the sensor data 146 to optimize drilling operations, such as,
for example, the control of drilling equipment to improve drilling
efficiency, equipment reliability, and the like. For example, in
some embodiments the acquired sensor data may be used to derive a
noise cancellation scheme to improve electromagnetic and mud pulse
telemetry signal processing. The control processes 143 may be
implemented via, for example, a control algorithm, a computer
program, firmware, or other suitable hardware and/or software. In
some embodiments, the remote computing resource environment 106 may
include a control process 145 that may be provided to the rig
computing resource environment 105.
[0046] The rig computing resource environment 105 may include
various computing resources, such as, for example, a single
computer or multiple computers. In some embodiments, the rig
computing resource environment 105 may include a virtual computer
system and a virtual database or other virtual structure for
collected data. The virtual computer system and virtual database
may include one or more resource interfaces (e.g., web interfaces)
that enable the submission of application programming interface
(API) calls to the various resources through a request. In
addition, each of the resources may include one or more resource
interfaces that enable the resources to access each other (e.g., to
enable a virtual computer system of the computing resource
environment to store data in or retrieve data from the database or
other structure for collected data).
[0047] The virtual computer system may include a collection of
computing resources configured to instantiate virtual machine
instances. A user may interface with the virtual computer system
via the offsite user device or, in some embodiments, the onsite
user device. In some embodiments, other computer systems or
computer system services may be utilized in the rig computing
resource environment 105, such as a computer system or computer
system service that provisions computing resources on dedicated or
shared computers/servers and/or other physical devices. In some
embodiments, the rig computing resource environment 105 may include
a single server (in a discrete hardware component or as a virtual
server) or multiple servers (e.g., web servers, application
servers, or other servers). The servers may be, for example,
computers arranged in any physical and/or virtual configuration
[0048] In some embodiments, the rig computing resource environment
105 may include a database that may be a collection of computing
resources that run one or more data collections. Such data
collections may be operated and managed by utilizing API calls. The
data collections, such as sensor data, may be made available to
other resources in the rig computing resource environment or to
user devices (e.g., onsite user device 118 and/or offsite user
device 120) accessing the rig computing resource environment 105.
In some embodiments, the remote computing resource environment 106
may include similar computing resources to those described above,
such as a single computer or multiple computers (in discrete
hardware components or virtual computer systems).
[0049] In an embodiment, the rig may include slips located at the
rig floor. The slips may be provided with sensors to register a
transition of the weight bearing between the hook line (via the top
drive) and the slips. In addition, when running tubulars into the
well, at some point, the top of the tubular may be a few feet from
the top of the rig. The system may employ a high resolution
positioning sensor for determining where in the mast of where the
hook was. The hook then gets another stand of tubular, connects the
stand on the tubular string, and then the hook picks up the weight
out of the slips. The pick up transition moment may occur when the
weight disappears from the slips and appears on the hook.
Accordingly, the elevation of the hook (and/or the top drive, etc.)
may be recorded when the hook holds the weight, as determined by
the transition recorded in the slip sensors (and/or the top drive
sensors). This may yield an accurate measurement of the stand
length in a stretched condition, e.g., as the weight of the drill
string is transmitted therethrough.
Elevation Measurement System
[0050] FIG. 3A illustrates a side, schematic view of a drilling rig
302 including an automated calibration system 300, according to an
embodiment. The drilling rig 302 generally includes a travelling
block 304 that is hoisted by a cable or "drill line" 306 that may
be attached to and movable by a drum 308 of a drawworks 315. The
drilling rig 302 may also include a drilling device 305, which may
be or include a kelly or a top drive. The drilling device 305 may
be supported (e.g., suspended) from the travelling block 304 and
may be configured to rotate a tubular segment, such as a drill
string 307 (e.g., one or more drill pipes) so as to drill a
wellbore in the Earth. The drilling rig 302 may also include a
crown block 309, positioned at the top of the rig 302, and a
structural component 311, which may be a part of, for example, a
derrick of the rig 302.
[0051] The drawworks 315 may include a "primary" elevation
measurement device, such as an encoder 313. The encoder 313 may be
configured to measure a rotation in the drum 308, from which the
elevation of the drilling device 305 may be calculated. In turn,
the depth of the drill string 307 may be determined by keeping
track of the amount of the "run-in" of the drill line 306 through
the encoder 313 when the drilling device 305 is coupled with drill
string. However, the encoder 313 (or another device of the
elevation measurement device) may not be responsive to stretching
of the drill line 306 and other potential dynamic errors in the
depth calculation based on the rotation of the drum 308.
[0052] The system 300 may include a calibration sensor 314 that may
move with the drilling device 305. In an embodiment, the sensor 314
may be installed in or on the drilling device 305, as shown, but in
others, it may be attached to the travelling block 304 or elsewhere
(e.g., "coupled" to the drilling device 305). The system 300 may
further include a plurality of elevation markers (five shown:
310(1), 310(2), 310(3), 310(4), 310(5)), which may be installed on
the structural component 311 and may be stationary relative to the
structural component 311. For example, one or more the markers
310(1)-(3) may be installed near the top of the rig 302, e.g., near
the top of the range of motion for the drilling device 305, and one
or more of the markers 310(4)-(5) may be installed near a rig floor
312 of the rig 302, e.g., near the bottom of the range of motion
for the drilling device 305. Still another one or more of the
markers may be installed on the rig along the travelling range of
the top drive. In other embodiments, the markers 310(1)-(5) may be
more uniformly positioned along the range of vertical motion for
the drilling device 305.
[0053] The elevation of the elevation markers 310(1)-(5) may be
predetermined. For example, the elevation may be measured from a
fixed reference point, such as a vertical distance from the rig
floor 312. In another embodiment, the elevation may be relative,
e.g., a vertical distance between two of the markers
310(1)-(5).
[0054] The elevation markers 310(1)-(5) may each include a unique
(among the markers 310(1)-(5)) identifier, such as A, B, C, etc.,
although any suitable format for such identifiers may be employed.
The identifier may be associated with the elevation of the markers
310(1)-(5), e.g., in a database. In some embodiments, the elevation
markers 310(1)-(5) may be passive, visual indicators. In other
embodiments, the elevation markers 310(1)-(5) may be or include a
transceiver that may emit a signal representing the identifier.
[0055] The sensor 314 may recognize and differentiate between the
elevation markers 310(1)-(5). For example, the sensor 314 may
recognize a visual feature of the elevation markers 310(1)-(5) and
thus determine which of the markers 310(1)-(5) that the sensor 314
is viewing, e.g., when aligned horizontally therewith. The sensor
314 may also be a transceiver that receives the signal emitted from
the markers 310(1)-(5) when the sensor 314 is horizontally aligned
with a particular marker 310(1)-(5). For example, the sensor 314
may be an optical sensor, and the elevation markers 310(1)-(5) may
include lasers that emit light beams with different frequencies
from one another. In other embodiments, the sensor 314 may be a
radiofrequency identification (RFID) tag reader, and the markers
310(1)-(5) may be RFID tags. In still other embodiments, the
markers 310(1)-(5) may be audio emitters, or any other type of
marker.
[0056] FIG. 3B illustrates a side, schematic view of another
embodiment of the automated system 300. In this embodiment, rather
than basing the elevation measurement on alignment with vertical
markers, the system 300 includes markers 320(1) and 320(2), which
are located at the same elevation as one another, e.g., at or near
the rig floor 312. The sensor 314 may be positioned on the block
304, in an embodiment, as shown, but in another embodiment, may be
positioned on the drilling device 305 (FIG. 3A) or elsewhere on a
structure that is moved vertically by movement of the drum 308.
[0057] The markers 320(1), 320(2) may be active, and configured to
determine a distance to the sensor 314. In another embodiment, the
markers 320(1), 320(2) may be configured to measure the angular
position of the sensor 314, namely, angles LABC and LACB .The
markers 320(1), 320(2) may thus be considered transceivers. In
other embodiments, the markers 320(1), 320(2) may be passive,
reflective, etc. A combination of the sensor 314 and the markers
320(1), 320(2) may enable a distance determination or an angular
position determination therebetween, e.g., using ultrasonic, laser,
camera, radar, or any other suitable method for determining a
straight line distance between two points.
[0058] Further, the sensor 314 may be located at a point A, while
the markers 320(1), 320(2) may be located at points B and C,
respectively. The well center is denoted by O. The distance along
line BC may be static, as the markers 320(1), 320(2) may be
stationary with respect to the rig structural component 311. The
distance along line AB may change, as may the distance along line
AC, i.e., between the sensor 314 and the markers 320(1), 320(2) as
the block 304, for example, is raised and lowered. Thus, the
distances AB and BC may be measured using the combination of the
sensor 314 and the markers 320(1), 320(2). As such, the distance AO
may be calculated based on triangulation, as:
AO = AB 2 - ( BC 2 + AB 2 - A C 2 2 BC ) 2 ( 1 ) ##EQU00001##
[0059] Although the markers 320(1), 320(2) are shown at the rig
floor 312, and thus configured to measure the distance from the rig
floor 312 to the block 304, the markers 320(1), 320(2) may be
placed at any position below the block 304, and the calculation
would change simply by adding an offset equal to the height above
the rig floor 312. Further, the markers 320(1), (2) may also be
placed above the block 304, and may be used to measure the distance
of the travelling block 304 from the the crown block 309, or any
other structure above the block 304 (and/or the drilling device
305, depending on the location of the calibration sensor 314).
Similar expressions for the distance AO may be determined based on
the angular position measurements, given the distance between the
markers 320(1), 320(2).
[0060] In some embodiments, more than two markers 320(1), 320(2)
may be employed. For example, a third marker may be provided. The
sensor 314 may sense the third marker in addition to the first and
second markers 320(1), 320(2), and a signal quality for the first,
second, and third markers may be determined. The sensor 314 (or a
controller) may then select to employ measurements determined with
respect to the first and second markers 320(1), 320(2) over the
measurements determined with respect to the third marker, based on
the signal quality (e.g., select the two signals with the higher
quality),
[0061] Moreover, the markers 320(1), 320(2) may be positioned at
different elevations. For example, in FIG. 3C, there is illustrated
a side, schematic view of such an embodiment of the system 300. The
embodiment of FIG. 3C may be similar to that of FIG. 3B, in that
markers 320(1), 320(2) are employed for purposes of triangulating
an elevation of the block 304 (or drilling device 305, see FIG. 3A)
above the rig floor 312. However, instead of placing both markers
320(1), 320(2) at the rig floor 312, one marker 320(2) may be
positioned on a vertically-extending portion of the rig structural
component 311, as shown, at a different (e.g., higher) elevation
than the marker 320(1).
[0062] A reference point E may be selected on the rig floor 312, or
at another location having the same elevation from the rig floor
312 as the marker 320(1). Since points B, C, and E are stationary,
the lengths of lines BE, BC, and CE are known. Further, the angle y
between lines BC and CE is known. Therefore, the angle x between
lines AC and BC may be determined as:
x = arccos B C 2 + A C 2 - AB 2 2 * BC * A C ( 2 ) ##EQU00002##
[0063] Thus, the length of line AE may be calculated as:
AE.sup.2=AC.sup.2+CE.sup.2-2*AC*CE*cos(x+y) (3)
[0064] With the length of line AE known, the calculation is similar
to that discussed above with respect to FIG. 3A, and the length AE
may be used in equation 1 instead of AC to solve for AO, which is
the elevation of the block 304 (or drilling device 305). One of
ordinary skill in the art will, with the aid of the present
disclosure, be able to implement a multitude of different ways to
accomplish this triangulation using the system 300 including the
calibration sensor 314 and the markers 320(1), 320(2), and thus it
should be appreciated that the above-described positions for the
markers 320(1), 320(2) and the calculations based thereon represent
merely an example of such triangulation.
[0065] The triangulation technique, as described in FIG. 3B &
3C, may be used for calibrating a primary depth measurement system,
which is described below. In some embodiments, such triangulation
using the markers 320(1), 320(2) may be used as a primary depth
measurement system. Since measurements of distance between the
sensor 314 and the markers 320(1), 320(2), and/or the angular
position of sensor 314 with respect to markers 320(1), 320(2) may
be made continuously, elevation AO may thus be determined
continuously during the movement of the block 304. In this way, the
encoder 313 may be used as a backup or a secondary depth
measurement system. As the term is used herein, "continuously"
refers to a regime in which measurements are taken at a certain
rate or frequency, which may provide a short interval therebetween,
e.g., during the drilling process.
Calibrating a Drilling Depth Measurement Using the Elevation
Measurement System
[0066] In operation, the calculation of the drill string 307 length
based on the rotation measured by the encoder 313 may become
inaccurate. For example, the drill line 306 may stretch over time.
Further, other factors may cause the calculation to be inaccurate.
As such, a given angular movement of the drum 308 may move the
drilling device 305 by one elevation at one time, and the same
angular movement of the drum 308 may result in a different
elevation change at another time.
[0067] Accordingly, FIG. 4A illustrates a flowchart of a method 400
for calibrating a drilling depth measurement, according to an
embodiment. The method 400 may be employed by operation of the
system 300 and is thus explained herein with reference thereto;
however, it will be appreciated that the method 400 may, in some
embodiments, be employed by operation of other systems.
[0068] FIG. 4B illustrates a plot 450 of the measured depth versus
actual depth, according to an illustrative example. The plot 450
specifically illustrates a comparison between measurements taken an
uncalibrated elevation measurement device (line 452) and in a
calibrated device (line 458). The uncalibrated device may operate
under the assumption that measured depth equals actual depth as
between two known depths (e.g., the beginning of a stand or joint
being run-in and at the end thereof). The calibrated device may
account for variations from such a line 452.
[0069] In general, the method 400 may include determining a
measured depth difference between a first position of a calibration
sensor and a second position of the calibration sensor, based on
measurements taken by an elevation measurement device. Further, the
method 400 may include determining a measured depth difference
between the first and second positions based on measurements taken
by the calibration sensor using one or more markers. The method 400
may also include calibrating the elevation measurement device based
at least partially on a relationship between the measured depth
difference and the calibration depth difference.
[0070] Referring to the embodiment specifically illustrated in FIG.
4A, and additionally referring to FIG. 4B, the method 400 may begin
by determining a first measured depth using a elevation measurement
device (e.g., the encoder 313), when the calibration sensor 314 is
at a first position, as at 402. This may occur at any time during
the running/handling of a tubular segment. For example, in the
embodiment of FIG. 3A, this may occur when the calibration sensor
314 reads a first elevation marker, which may be any elevation
marker 310(1)-(5), for example, the elevation marker 310(5). The
elevation measurement device may accomplish this by measuring an
angular displacement of the drum 308, which may be converted into a
measured depth.
[0071] The method 400 may also include determining a first
calibration depth based on a measurement taken by the calibration
sensor 314, using one or more of the markers 310(1)-(5) and/or
320(1), 320(2), as at 404. In an embodiment, such as that shown in
FIG. 3A, the calibration sensor 314 may accomplish this by
determining an elevation of the elevation marker 310(5). In a
specific embodiment, the calibration sensor 314 may acquire an
identifier from the elevation marker 310(5), and determine the
elevation of the elevation marker 310(5) by referring to a database
storing the elevation thereof in association with the identifier.
In the triangulation embodiments of FIGS. 3B and 3C, the
calibration sensor 314 may directly determine its elevation by
triangulation using the markers 320(1), (2). In FIG. 4B, the first
calibration depth measurement taken by the calibration sensor 314
is indicated at 454.
[0072] The method 400 may also include moving the calibration
sensor 314, e.g., by moving the travelling block 304 and/or the
drilling device 305, as at 406. Such movement of the block 304
and/or drilling device 305 may be accomplished using the drawworks
315 (e.g., by rotating the drum 308), and thus the elevation
measurement device may register at least a part of this change.
[0073] The method 400 may then include determining a second
measured depth based on a measurement taken by the elevation
measurement device when the calibration sensor is at a second
position, as at 408. This may occur at any time during the running
of a tubular segment after the calibration sensor 314 is moved from
the first position at 404. For example, in the embodiment of FIG.
3A, this may occur when the calibration sensor 314 reads a second
elevation marker, which may be any elevation marker 310(1)-(5), for
example, the elevation marker 310(4) that is vertically adjacent to
the elevation marker 310(5). The elevation measurement device may
again accomplish this by registering an angular displacement of the
drum 308.
[0074] The method 400 may then proceed to determining a second
calibration depth based on a measurement taken by the calibration
sensor 314 using one or more of the markers 310(1)-(5) and/or the
markers 320(1), (2), as at 410. For example, the calibration sensor
314 may determine an elevation of the elevation marker 310(4)
through acquisition of an identifier and reference to a database
linking the identifier to a predetermined elevation. In the
triangulation embodiments of FIGS. 3B and 3C, the calibration
sensor 314 may again directly determine its elevation by
triangulation.
[0075] The second calibration depth measurement is indicated at 462
in FIG. 4B. As can be seen, the second depth measurement 462 may
deviate from the measured depth in an uncalibrated device along
line 452.
[0076] The method 400 may also include determining a measured depth
difference between the first and second positions, based on the
first and second measured depths, as measured by the elevation
measurement device, as at 412. The method 400 may further include
determining a calibration depth difference between the first and
second positions, as at 414. This may be based on the depth
measurements taken by the calibration sensor 314 using any one or
more of the sensors 310(1)-(5) or 320(1), (2).
[0077] Since the rig structural component 311 may be generally
static (e.g., as compared to the movable drum 308, drill line 306,
etc.), the distance between adjacent elevation markers 310(4) and
310(5) and/or the position of the triangulation markers 320(1),
320(2) may remain relatively constant. The measured depth
difference from the elevation measurement device (e.g., encoder 313
at the drum 308 of the drawworks 315), however, may be more prone
to error, and thus may be calibrated against the calibration
depth.
[0078] As such, the measured depth difference determined at 412 may
be compared to the calibration depth difference determined at 414,
in order to adjust the elevation measurement device, when
appropriate, as at 416. For example, the angular displacement of
the drum 308 as the drilling device 305 moves from the first
position to the second position may be compared to the calibration
depth difference, so as to develop a relationship between these two
values. In this way, as an example, the method 400 may include
calibrating the elevation measurement device based on the
comparison at 416, as at 418. This process may, for example, be
repeated for one, some, or all of the other elevation markers
310(3), 310(2), 310(1), or similarly at a plurality of different
times, intervals, at user discretion, etc. (e.g., with a
triangulation embodiment), e.g., as indicated in FIG. 4B at 464,
466, and 468, respectively. Thus, the higher resolution provided by
the calibration may allow for an interpolation of the precise
position of the drill string during run-in.
[0079] In a specific example, the acquisition clock of the sensor
314 may be synched with the clock for the drawworks 315. When, for
example, at the two positions, the absolute elevation difference is
.DELTA.L.sub.a, and the corresponding drawworks encoder reading
between two elevation points is .DELTA.L.sub.e. The calibration
coefficient .zeta. may thus be established as:
.zeta. = .DELTA. L a .DELTA. L e ( 4 ) ##EQU00003##
[0080] This calibration coefficient may be used to calibrate the
depth measurements taken using the elevation measurement device
(e.g., encoder 313 at the drum 308). For example, the measured
elevation may be multiplied by the calibration coefficient. At a
next calibration opportunity, either according to the operator's
choice, or any time the drilling device 305 and/or travelling block
304 passes the next elevation markers 310(1)-(5), another
calibration coefficient may be calculated. As such, calibration may
be done automatically. In some embodiments, any two adjacent
elevation markers may yield a new calibration coefficient.
[0081] FIG. 5 illustrates another calibration system 500, according
to an embodiment. The system 500 may also include a plurality of
elevation markers 502, which may be installed on the rig structural
component 311. The markers 502 may be associated with an elevation
above the rig floor 312.
[0082] In this embodiment, the calibration sensor 314 (FIG. 3) may
be provided by a camera 504, which may be installed on the
travelling block 304 and/or the drilling device 305. When a
particular marker 502 is in the field of view of the camera 504,
the camera 504 may read the marker 502. A controller coupled to or
integral with the camera 504 may differentiate the markers 502 by a
feature or indicator that is unique to the individual markers 502,
such as a letter, color, bar code, or the like. In another
embodiment, the controller may count the number of markers 502 that
have passed, e.g., without distinguishing individual markers 502,
and with the markers 502 being positioned at uniform intervals. By
matching the reading from the camera 504 with the associated
elevation of the marker, the depth of the block position can be
determined. The resolution of the depth measurement may thus be
controlled by the resolution of the markers 502. Moreover, any
elevation reading from two adjacent markers 310(1)-(5) may be used
to calibrate the elevation measurement device for depth measurement
near these two adjacent markers.
[0083] FIG. 6 illustrates a schematic view of the drilling rig 302
with another embodiment of the calibration system 300, according to
an embodiment. As shown, a rig feature 602 may be provided as part
of the rig 302. The rig feature 602 may serve another function as
part of the drilling rig 302, but in other embodiments, it may not.
The rig feature 602 may have a distinguishable feature that may be
read by a camera 604, again providing the sensor 314 (FIG. 3). The
rig feature 602 may, in a specific embodiment, be a rectangular
structure with a particular color installed on the rig structural
component 311, e.g., below the crown block 309.
[0084] The camera 604 may be installed above the travelling block
304. The camera 604 may take a picture of this rig feature 602, and
may determine its distance therefrom based on the size of the rig
feature 602. By using this method, the elevation of the camera 604,
and thus the block 304 and/or drilling device 305 may be determined
continuously, e.g., and employed similar to the triangulation
embodiment described above with reference to FIGS. 3B and 3C.
Monitoring Pipe Movement
[0085] FIG. 7 illustrates a side, schematic view of the drilling
rig 302, including a system 700 for monitoring pipe movement,
according to an embodiment. In this embodiment, a camera 702 may be
installed near the drill string 307, e.g., below the rig floor 312.
The drill string 307 may extend through a blowout preventer (BOP)
703 below the rig floor 312, and into a well 704 below the BOP 703.
By continuously taking images of the drill pipe during tripping,
and/or rotation, and using pattern recognition algorithm to keep
track of the unique features within each image, the movement
(rotation speed and/or translation speed) of the drill pipe may be
determined. Integrating these speeds over time may allow a
calculation of the rotation angle, and translation distance (depth)
of the drill pipe.
Increased Accuracy of Drilling Depth Measurement
[0086] When a new stand is added to the drill string, and the slips
are removed, the weight of drill string is transferred from the
slips to the top drive/drill line, causing the drill line to
stretch. Depending on the weight of the drill string, this stretch
may be several centimeters (or more), but may not be measured by
the elevation measurement device (i.e., encoder on the drawworks),
as the stretching of the drill line may not cause the reel of the
drawworks to rotate.
[0087] Accordingly, FIG. 8 illustrates a flowchart of a method 800
for drilling a wellbore and considers the stretched length of drill
line, according to an embodiment. FIGS. 9 and 10 illustrate side,
schematic views of a drilling rig 900 at two points in the
operation of the method 800, according to an embodiment. The
drilling rig 900 may be generally similar to the drilling rig 302.
The drilling rig 900 may include slips 902, which may be positioned
at or near the rig floor 312. The slips 902 may receive the drill
string 307 therethrough, and may be configured to support the
weight of the drill string 307, e.g., as a new stand of tubulars
904 is added or removed.
[0088] The slips 902 may include a slips sensor 906 (e.g., a load
cell), which may be configured to detect when the slips 902 are
supporting the weight of the drill string 307 and, further, may be
capable of measuring and sending a signal representing the amount
of the load supported thereby (e.g., slips weight Ws). Similarly,
the drilling rig 900 may also include a load sensor 908, e.g.
attached to the drill line 306 (or the drilling device 305, the
drum 308, see FIG. 3, or anywhere else suitable), to measure the
weight of the drill string 307 being suspended via the drilling
device 305. In the specific, illustrated embodiment, the measured,
suspended load may be the hookload W.sub.H; however, other loads
may be measured at locations other than the hook and employed
consistent with the method 800.
[0089] The method 800 may begin by positioning the drilling device
305 above the drill string 307 at a height h1, while supporting the
drill string 307 using the slips 902, as at 802 (e.g., slips weight
W.sub.S=drill string weight W.sub.T; suspended load W.sub.H=0).
Next, a stand of tubulars 904 (e.g., a tubular segment including
one or more joints of pipe, such as drill pipe) may be connected to
the drill string 307 and the drilling device 305, as at 804 and as
shown in FIG. 9.
[0090] The slips 902 may then be released from engagement with the
drill string 307. Releasing the slips 902 may transition the weight
of the string W.sub.T to the suspended load W.sub.S, which may
result in the drill line 306 stretching, and thus the drilling
device 305 being at the lower height h2, as shown in FIG. 10. The
encoder 313 may not register this elevation change.
[0091] In some embodiments, the method 800 may also include moving
the drilling device 305 from a first position to a second position
using the drawworks 315, as at 806. For example, the drilling
device 305 may be raised by spooling the drill line 306 on the drum
308, or lowered by unspooling the drill line 306 from the drum 308.
In some embodiments, however, the method 800 may not include moving
the drilling device 305, and the drilling device 305 may begin in
the second position.
[0092] Before or after moving the drilling device 305, the method
800 may include determining a measured elevation of the drilling
device 305 at the second position using the primary elevation
measurement device (e.g., the encoder 313), as at 808. The measured
elevation may be determined based on an angular displacement of the
drum 308 (which may be corrected for increased layer diameter on
drum 308 diameter due to the spooling of the drill line 306) and a
known reference elevation.
[0093] The method 800 may also include determining a sensed
elevation at the second position using a sensor, as at 810. This
determination may be made using any of the aforementioned sensors,
e.g., those sensors that move with the drilling device 305, the
travelling block 304, or both, by operation of the drawworks 315.
As such, the sensor may, for example, use markers to determine an
actual elevation of the drilling device (e.g., drilling device
305), the travelling block, or both from a reference plane such as
the rig floor 312.
[0094] The method 800 may also include determining a deformation
metric based on the difference between the measured elevation and
the sensed elevation, as at 812. The measured elevation, detected
by the encoder 313 may be subject to error caused by the stretching
of the drill line 306 under the increased weight suspended
therefrom provided by the drill string 307 being out of slips. Such
stretching may not be registered by the encoder 313, as it may
result in an elevation change without a rotation of the drum 308.
The deformation metric may be an amount of stretch (e.g., length of
stretch) in the drill line 306. In another embodiment, the stress,
strain, or both may instead be measured. Later, in some
embodiments, the stress or strain may be used to determine the
stretch, e.g., taking into consideration the overall length of the
drill line 306. However, using the strain may allow for a stretch
per unit length to be determined, and thus, so long as the drill
string 307 weight remains constant, the strain at any position
(e.g., the first position) of the drilling device 305 may be
calculated, despite the change in length of the drill string 316 as
it is spooled onto or unspooled from the drum 308.
[0095] The deformation metric may be employed to correct the
primary elevation measurement device, as at 814. For example, if
the deformation metric is stretch, the stretch may be subtracted
from the measured elevation recorded by the primary elevation
measurement device (encoder 313).
[0096] In some embodiments, this procedure may be repeated for
another position (e.g., the first position), which may provide two
points of data for the deformation metric (e.g., stretch) in the
drill line 306, and thus the deformation metric may be based on the
difference between the measured and sensed elevations at both
positions. This may then allow for an interpolation of the
deformation metric across the at least a portion (e.g., an
entirety) of the range of motion of the drilling device 305 or the
travelling block 304.
Determining the Distance Between the Drill Bit and the Bottom of
the Well
[0097] FIG. 11 illustrates a flowchart of a method 1100 for
drilling, which includes determining a distance between the drill
bit and the bottom of the wellbore, according to an embodiment. The
method 1100 may employ the drilling rig 900, or another drilling
rig, with a capability of sensing a position (e.g., elevation) of
the drilling device 305, block 304, or another tubular handling
device. FIG. 12 illustrates another schematic view of the drilling
rig 900, illustrating the running of the drill string 307 in a
wellbore 1200, according to an embodiment. In particular, FIG. 12
illustrates a bottom hole assembly 1202 including a drill bit 1204
and a bottom 1206 of the wellbore 1200. The drill bit 1204 may
engage the bottom 1206 of the wellbore 1200, so as to bore into the
Earth and extend the wellbore 1200.
[0098] In general, the drill string 307 may change length during a
drilling process, which may affect the driller's ability to
determine a distance between the drill bit 1204 and the bottom 1206
of the wellbore 1200, e.g., when adding a new stand of tubulars 904
to the drill string 307. By way of example, the drilling rig 900
may be employed to determine the distance between the drill bit
1204 and the bottom 1206, e.g., using one or more of the
embodiments described above, such as calibration, or direct
measurement through a triangulation method (sensor 314 is shown in
FIG. 12 as an example).
[0099] The method 1100 may commence, as an example, at the end of
running a tubular stand of the drill string 307 into the well,
e.g., with the drill bit 1204 engaged with the bottom 1206 of the
wellbore 1200. At this point, the method 1100 may include
determining a first surface weight W.sub.d (namely, a load, such as
hookload, measured either at the drilling device, or at the
deadline drill line anchor) of the drill string 307, as at 1102.
The first surface weight W.sub.d may be the hookload, and thus may
be measured using the dead drill line anchor, a load cell in the
drilling device 305, etc.
[0100] A depth of the wellbore ("hole depth") Dh may be expressed
in terms of the length of the drill string 307. The length of the
drill string 307 may account for stretching and/or compression of
the drill string 307 during operation. For example, let L be the
length of the drill string 307 below the drilling device 305 under
no axial load. During drilling, the actual length L.sub.d of the
drill string below the drilling device 305 may be expressed as:
L.sub.d=L+.DELTA.L.sub.W+.DELTA.L.sub.T-L.sub.f-.DELTA.L.sub.wob-.DELTA.-
L.sub.S (5)
where .DELTA.L.sub.W is the change of drill string length due to
its weight and wellbore pressure, .DELTA.L.sub.T is the change of
drill string length due to temperature, .DELTA.L.sub.f is the
change of drill string length due to the friction force between the
drill string and the wellbore, .DELTA.L.sub.wob is the change of
the drill string length due to the weight-on-bit, and
.DELTA.L.sub.S is the length of the drill string 307 between the
rig floor 312 and the drilling device 305.
[0101] During tripping out, the length L.sub.o of the drill string
307 below the rig floor 312 may be expressed as
L.sub.o=L+.DELTA.L.sub.W+.DELTA.L.sub.T+.DELTA.L.sub.f-.DELTA.L.sub.S
(6)
[0102] The hole depth Dh may thus be expressed as (note:
.DELTA.L.sub.S is the distance between the drilling device and the
rig floor):
D.sub.h=L+.DELTA.L.sub.W+.DELTA.L.sub.T-.DELTA.L.sub.f-.DELTA.L.sub.wob--
.DELTA.L.sub.S (7)
[0103] The bit 1204 may then be raised off of the bottom 1206 of
the wellbore 1200, e.g., by raising the drilling device 305 by a
distance s, as at 1104. The distance s may be measured, as at 1106
e.g., using the encoder 313 of the drawworks 315 and/or any of the
elevation measurement embodiments, including the calibration and
triangulation methods, using one or more sensors 314, 504, as
described above. After raising the bit 1204 off of the bottom 1206,
the slips 902 may be set, e.g. by engaging teeth thereof with the
drill string 307, so as to secure and support the drill string 307,
as at 1108.
[0104] With the measurement of the distance s obtained, the
following relationship may be established:
S=D.sub.h-D.sub.b (8)
[0105] If s>2.DELTA.L.sub.f+.DELTA.L.sub.wob, the bit depth
D.sub.b may be expressed as:
D.sub.b=L.sub.o-.DELTA.L.sub.S-s=L+.DELTA.L.sub.W+.DELTA.L.sub.T+.DELTA.-
L.sub.f-.DELTA.L.sub.S-s (9)
[0106] The distance between the bit and the bottom end of the hole
.DELTA.D.sub.b may be expressed as:
.DELTA.D.sub.b=D.sub.h-D.sub.b=s-2.DELTA.L.sub.f-.DELTA.L.sub.wob
(10)
[0107] The method 1100 may then proceed to connecting a new stand
of tubulars 904 to the drilling device 305 and the drill string 307
supported in the slips 902, as at 1110. After connecting the new
tubular 907 at 1110, the slips 902 may be disengaged and the
drilling device 305 may support the drill string 307, as at
1112.
[0108] The method 1100 may then include measuring a second surface
weight Wt (another measurement of the load, e.g., hookload,
measured either at the drilling device, or at or near the deadline
anchor) of the drill string 307 with the new stand of tubulars 904,
and prior to lowering the drill bit into engagement with the bottom
of the wellbore, as at 1114. A relationship between the first
surface weight W.sub.d and the second surface weight Wt reveals the
weight-on-bit WOB, which may be determined at 1116. The
weight-on-bit WOB may be expressed as (note Ws is the weight of the
stand just added to the drill string from the surface):
WOB=W.sub.d-(W.sub.t-W.sub.s) (11)
[0109] The method 1100 may then include determining a distance t to
lower the drilling device 305, such that the drill bit 1204 engages
the bottom 1206 of the wellbore 1200, based on the distance s that
the drilling device 305 was raised, and the weight-on-bit WOB, as
at 1118. The distance t may be expressed as:
D.sub.b+t-2.DELTA.L.sub.f=D.sub.h (12)
Substituting equation 10 into equation 12, yields:
t=s-.DELTA.L.sub.wob (13)
[0110] .DELTA.L.sub.wob may be determined as
.DELTA. L wob = WOB * L E * 1 A ( 14 ) ##EQU00004##
where E is Young's modulus, and A is the drill string
cross-sectional area, and <1/A> refers to the average of the
inverse of the drill string cross-sectional area. Thus, the
distance for the drilling device 305 to be moved before the drill
bit 1204 reaches the bottom 1206 of the wellbore 1200 may be:
t = s - WOB * L E * 1 A ( 15 ) ##EQU00005##
[0111] Since the distance s and the weight-on-bit WOB may be known
from the measurements and calculations above, and the dimensions
and Young's modulus of the drill string 307 may also be known, the
distance t may be readily calculated. The method 1100 may then
proceed to lowering the drilling device 305 by the distance t, such
that the drill bit 1204 engages the bottom 1206 of the wellbore
1200, for further drilling, as at 1120. The engagement may be
controlled, such that the drill bit 1204 is not caused to impact
the bottom 1206 at a high rate of speed, since the distance across
which the drilling device 305 is to be lowered has been
determined.
[0112] In some embodiments, the methods of the present disclosure
may be executed by a computing system. FIG. 13 illustrates an
example of such a computing system 1300, in accordance with some
embodiments. The computing system 1300 may include a computer or
computer system 1301A, which may be an individual computer system
1301A or an arrangement of distributed computer systems. The
computer system 1301A includes one or more analysis modules 1302
that are configured to perform various tasks according to some
embodiments, such as one or more methods disclosed herein. To
perform these various tasks, the analysis module 1302 executes
independently, or in coordination with, one or more processors
1304, which is (or are) connected to one or more storage media
1306. The processor(s) 1304 is (or are) also connected to a network
interface 1307 to allow the computer system 1301A to communicate
over a data network 1309 with one or more additional computer
systems and/or computing systems, such as 1301B, 1301C, and/or
1301D (note that computer systems 1301B, 1301C and/or 1301D may or
may not share the same architecture as computer system 1301A, and
may be located in different physical locations, e.g., computer
systems 1301A and 1301B may be located in a processing facility,
while in communication with one or more computer systems such as
1301C and/or 1301D that are located in one or more data centers,
and/or located in varying countries on different continents).
[0113] A processor may include a microprocessor, microcontroller,
processor module or subsystem, programmable integrated circuit,
programmable gate array, or another control or computing
device.
[0114] The storage media 1306 may be implemented as one or more
computer-readable or machine-readable storage media. Note that
while in the example embodiment of FIG. 13 storage media 1306 is
depicted as within computer system 1301A, in some embodiments,
storage media 1306 may be distributed within and/or across multiple
internal and/or external enclosures of computing system 1301A
and/or additional computing systems. Storage media 1306 may include
one or more different forms of memory including semiconductor
memory devices such as dynamic or static random access memories
(DRAMs or SRAMs), erasable and programmable read-only memories
(EPROMs), electrically erasable and programmable read-only memories
(EEPROMs) and flash memories, magnetic disks such as fixed, floppy
and removable disks, other magnetic media including tape, optical
media such as compact disks (CDs) or digital video disks (DVDs),
BLURAY.RTM. disks, or other types of optical storage, or other
types of storage devices. Note that the instructions discussed
above may be provided on one computer-readable or machine-readable
storage medium, or alternatively, may be provided on multiple
computer-readable or machine-readable storage media distributed in
a large system having possibly plural nodes. Such computer-readable
or machine-readable storage medium or media is (are) considered to
be part of an article (or article of manufacture). An article or
article of manufacture may refer to any manufactured single
component or multiple components. The storage medium or media may
be located either in the machine running the machine-readable
instructions, or located at a remote site from which
machine-readable instructions may be downloaded over a network for
execution.
[0115] In some embodiments, the computing system 1300 contains one
or more rig control module(s) 1308. In the example of computing
system 1300, computer system 1301A includes the rig control module
1308. In some embodiments, a single rig control module may be used
to perform some or all aspects of one or more embodiments of the
methods disclosed herein. In alternate embodiments, a plurality of
rig control modules may be used to perform some or all aspects of
methods herein.
[0116] The computing system 1300 is one example of a computing
system; in other examples, the computing system 1300 may have more
or fewer components than shown, may combine additional components
not depicted in the example embodiment of FIG. 13, and/or the
computing system 1300 may have a different configuration or
arrangement of the components depicted in FIG. 13. The various
components shown in FIG. 13 may be implemented in hardware,
software, or a combination of both hardware and software, including
one or more signal processing and/or application specific
integrated circuits.
[0117] Further, the steps in the processing methods described
herein may be implemented by running one or more functional modules
in information processing apparatus such as general purpose
processors or application specific chips, such as ASICs, FPGAs,
PLDs, or other appropriate devices. These modules, combinations of
these modules, and/or their combination with general hardware are
all included within the scope of protection of the invention.
[0118] The foregoing description, for purpose of explanation, has
been described with reference to specific embodiments. However, the
illustrative discussions above are not intended to be exhaustive or
to limit the invention to the precise forms disclosed. Many
modifications and variations are possible in view of the above
teachings. Moreover, the order in which the elements of the methods
described herein are illustrate and described may be re-arranged,
and/or two or more elements may occur simultaneously. The
embodiments were chosen and described in order to best explain the
principals of the invention and its practical applications, to
thereby enable others skilled in the art to best utilize the
invention and various embodiments with various modifications as are
suited to the particular use contemplated.
* * * * *