U.S. patent application number 16/070550 was filed with the patent office on 2019-01-17 for dynamic block retraction for drilling rigs.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Jarle OEVSTHUS, Jacques ORBAN, Vishwanathan PARMESHWAR.
Application Number | 20190017326 16/070550 |
Document ID | / |
Family ID | 59362147 |
Filed Date | 2019-01-17 |
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United States Patent
Application |
20190017326 |
Kind Code |
A1 |
ORBAN; Jacques ; et
al. |
January 17, 2019 |
DYNAMIC BLOCK RETRACTION FOR DRILLING RIGS
Abstract
A drill rig system for drilling a wellbore in the earth, the
drill rig system comprising: a drill rig comprising: a substructure
supporting a rig floor and a mast extending vertically above the
rig floor; a top drive supported by a line spooled between a crown
block and a travelling block, a carriage that is guided by the
guide rails on the mast, wherein the carriage at least one arm that
extends/retracts to position the top drive farther/closer to the
mast; a theodolite and/or laser ranging systems positioned to
reflect a laser beam off a reflector associated with the top drive
to determine the top drive's position relative to a well axis; and
a controller of the at least one arm based on the top drive
position determined by the theodolite and/or laser ranging
systems.
Inventors: |
ORBAN; Jacques; (Houston,
TX) ; PARMESHWAR; Vishwanathan; (Houston, TX)
; OEVSTHUS; Jarle; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
59362147 |
Appl. No.: |
16/070550 |
Filed: |
January 20, 2017 |
PCT Filed: |
January 20, 2017 |
PCT NO: |
PCT/US2017/014437 |
371 Date: |
July 17, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62280943 |
Jan 20, 2016 |
|
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 19/20 20130101;
E21B 19/24 20130101; E21B 3/02 20130101; E21B 19/165 20130101; E21B
15/00 20130101 |
International
Class: |
E21B 3/02 20060101
E21B003/02; E21B 15/00 20060101 E21B015/00; E21B 19/16 20060101
E21B019/16; E21B 19/20 20060101 E21B019/20; E21B 19/24 20060101
E21B019/24 |
Claims
1. A drill rig system for drilling a wellbore in the earth, the
drill rig system comprising: a drill string turning device; a
sensor of the position of the turning device relative to a well
axis; and a mover of the turning device to a position on the well
axis.
2. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the turning device comprises a top drive.
3. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the turning device comprises a turn table and kelly.
4. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises a theodolite and a laser ranging system positioned a
distance away from the turning device.
5. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises a first sensor positioned a distance away from the
turning device and a second sensor positioned another distance away
from the turning device, wherein the first sensor, the well axis,
and the second sensor form an angle of approximately 90 degrees at
the well axis in a plane perpendicular to the well axis.
6. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises first and second theodolites positioned in a plane
defined by the flexing of the mast and two distances away from the
turning device.
7. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises two primary theodolites positioned in the plane defined
the flexing of the mast and two distances away from the turning
device and two secondary theodolites positioned in a vertical plane
perpendicular to the plane defined the flexing of the mast and two
distances away from the turning device.
8. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises at least one inclinometer that detects an inclination of
the mast.
9. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the sensor of the position of the turning device
comprises a device that measures a position of the turning device
relative to the mast, and wherein the drill rig system further
comprises a sensor of the weight of the drill string turning device
and a drill string suspended from the drill string turning
device.
10. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the turning device comprises a top drive and the mover
comprises arms that extend/retract from a carriage to move the top
drive relative to a drill rig mast.
11. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the turning device comprises a top drive and the mover
comprises a mover of a crown block relative to a drill rig
mast.
12. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the turning device comprises a turn table and kelly and
the mover comprises at least one jack of the drill rig.
13. A drill rig system for drilling a wellbore, as claimed in claim
1, wherein the mover comprises a carriage that extends/retracts the
top drive relative to a drill rig mast and at least one jack of the
drill rig.
14. A drill rig system for drilling a wellbore, as claimed in claim
1, further comprising a controller of the mover based on data from
the sensor of the position.
15. A drill rig system for drilling a wellbore, as claimed in claim
1, further comprising a control system, wherein the control system
records position data corresponding to the position of the turning
device relative to a well axis where the data is taken with the
turning device at a plurality of mast elevations and the drill rig
system being subject to a plurality of hookloads at each mast
elevation, wherein the control system commands the mover to move
the turning device to a recorded position based on a measured mast
elevation and a measured hookload compared to the plurality of mast
elevations and the plurality of hookloads at which the position
data was recorded.
16. A method for drilling a wellbore in the earth, the method
comprising: turning a drill string with a turning device;
determining the position of the turning device relative to a well
axis; and positioning the turning device on the well axis.
17. A method for drilling a wellbore as claimed in claim 16,
wherein the turning comprises turning the drill string with a top
drive.
18. A method for drilling a wellbore as claimed in claim 16,
wherein the turning comprises turning the drill string with a turn
table and kelly.
19. A method for drilling a wellbore as claimed in claim 16,
wherein the determining the position of the turning device
comprises: positioning a laser generator a distance away from the
turning device, sensing a laser beam generated via the laser
generator to determine the distance between the laser generator and
the turning device, and measuring an angle between the laser beam
and a reference constant.
20. A method for drilling a wellbore as claimed in claim 16,
wherein the determining the position of the turning device
comprises: positioning first and second laser generators a distance
from each other, generating a first laser beam between the first
laser generator and the turning device, generating a second laser
beam between the second laser generator and the turning device, and
measuring angles between each laser beam and a reference
constant.
21. A method for drilling a wellbore as claimed in claim 16,
wherein the determining the position of the turning device
comprises: positioning first and second ranging systems a distance
from each other, measuring a distance between the first ranging
system and the turning device, and measuring a distance between the
second ranging system and the turning device.
22. A method for drilling a wellbore as claimed in claim 16,
wherein the turning comprises turning the drill string with a top
drive and the positioning comprises extending/retracting a carriage
of the top drive relative to a drill rig mast.
23. A method for drilling a wellbore as claimed in claim 16,
wherein the turning comprises turning the drill string with a turn
table and Kelly and the positioning comprises jacking portions of a
drill rig.
24. A method for drilling a wellbore as claimed in claim 16,
wherein the positioning comprises extending/retracting a carriage
of the top drive relative to a drill rig mast and jacking portions
of a drill rig.
25. A method for drilling a wellbore as claimed in claim 16,
wherein the determining the position of the turning device relative
to a well axis comprises determining distances between the turning
device and the well axis at a plurality of mast elevations and a
plurality of hookloads at each mast elevation, and wherein the
positioning the turning device on the well axis comprises moving
the turning device a determined distance relative to the well axis
depending on the turning device's mast elevation and hookload
compared to the plurality of mast elevations and the plurality of
hookloads at each mast elevation.
26. A drill rig system for drilling a wellbore in the earth, the
drill rig system comprising: a drill rig comprising: a substructure
supporting a rig floor and a mast extending vertically above the
rig floor; a top drive supported by a line spooled between a crown
block and a travelling block, a carriage that is guided by the
guide rails on the mast, wherein the carriage has at least one arm
that extends/retracts to position the top drive farther/closer to
the mast; a first laser generator positioned to generate a laser
beam relative to the top drive to determine the top drive's
position relative to a well axis; and a controller of the at least
one arm based on the top drive position determined by the laser
generator.
27. A drill rig system for drilling a wellbore, as claimed in claim
26, further comprising a second laser generator positioned to
generate a laser beam relative to the top drive to determine the
top drive's position relative to a well axis, wherein the second
laser generator is positioned a distance from the first laser
generator.
28. A drill rig system for drilling a wellbore, as claimed in claim
26, further comprising a plurality of jacks under the substructure
that tilt the drill rig under control of the controller based on
the top drive position determined by the first laser generator.
Description
TECHNICAL FIELD
[0001] The present disclosure relates in general to drilling rigs
for drill wellbores and, more particularly, to drilling rigs with
top drive drilling systems.
BACKGROUND
[0002] Top drives are used to suspend and rotate a string of drill
string and/or casing in drilling applications. The top drive is
movable along a mast that extends upward from a rig floor. The top
drive is supported by and moved by a drilling line wrapped on a set
of sheaves and connected to the drawworks at one extremity. The top
drive supports the drill string via a thrust bearing. Mud may be
pumped into the drill string via a swivel. Furthermore, the top
drive generally includes one or more motors (electric or hydraulic)
which generate(s) the rotation of the drill string. The reaction
torque applied to the top drive may be transmitted to the mast via
a set of rollers attached to the top drive chassis.
[0003] In some situations, the path along which the top drive moves
in the mast may tend to deviate from the axis of the well. This may
occur via uneven compaction of the earth below the rig floor and/or
due to uneven bending of the mast, which generally has an
asymmetric, U-shaped geometry. When the path of the top drive
differs from the axis of the well, the drill pipe being rotated by
the top drive may engage the well equipment (e.g., the blowout
preventer, rotating control device, etc.), which may potentially
damage the well equipment, or otherwise damage the drill pipe.
SUMMARY OF THE INVENTION
[0004] According to one aspect of the invention, there is provided
a drill rig system for drilling a wellbore in the earth, the drill
rig system comprising: a drill rig comprising: a substructure
supporting a rig floor and a mast extending vertically above the
rig floor; a top drive supported by a line spooled between a crown
block and a travelling block, a carriage that is guided by the
guide rails on the mast, wherein the carriage has at least one arm
that extends/retracts to position the top drive farther/closer to
the mast in a preferred direction typically opposed to the catwalk;
a sensing method allowing to determine the horizontal distance from
the center of the top-drive quill and the vertical axis of the well
(in the direction defined by the block-retract system). Such
sensing method can be based on theodolite and/or laser ranging
systems positioned to reflect a laser beam off a reflector
associated with the top drive to determine the top drive's position
relative to a well axis; and a controller of the at least one arm
based on the top drive position determined by the theodolite and/or
laser ranging systems.
[0005] A further aspect of the invention provides a drill rig
system for drilling a wellbore in the earth, the drill rig system
comprising: a drill string turning device; a sensor of the position
of the turning device relative to a well axis; and a mover of the
turning device to a position on the well axis.
[0006] According to another aspect of the invention, there is
provided a method for drilling a wellbore in the earth, the method
comprising: turning a drill string with a turning device;
determining the position of the turning device relative to a well
axis; and positioning the turning device on the well axis.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] 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:
[0008] FIG. 1 illustrates a schematic view of a drilling rig and a
control system, according to an embodiment.
[0009] FIG. 2 illustrates a schematic view of a drilling rig and a
remote computing resource environment, according to an
embodiment.
[0010] FIG. 3A illustrates a conceptual, side, schematic view of a
drilling rig, according to an embodiment.
[0011] FIG. 3B illustrates a conceptual, side, schematic view of a
drilling rig, according to an alternate embodiment.
[0012] FIG. 4A illustrates a conceptual, front, schematic view of
the drilling rig with the top drive axis differing from the well
axis, according to an embodiment.
[0013] FIG. 4B illustrates a conceptual, front, schematic view of
the drilling rig with the top drive axis differing from the well
axis, according to an alternative embodiment.
[0014] FIG. 5 illustrates a schematic view of a computing system,
according to an embodiment.
[0015] FIG. 5A illustrates some of the deformations associated with
rig operation, as well as the paths potentially followed by the
travelling block, in particular, the deformations affecting the
travel path of the travelling block.
[0016] FIG. 5B shows a schematic diagram of a drill rig and two
laser generators and angle measurement devices.
[0017] FIG. 5C shows a schematic diagram of a drill rig and two
laser generators and devices for measuring the distances between
the laser generators and the drill rig.
[0018] FIGS. 6A, 6B and 6C illustrate perspective, and side views,
respectively, of an embodiment of block retraction system.
[0019] FIG. 7 is a side view of a rig and a laser generator.
[0020] FIG. 8 is a schematic illustration of a side view of a rig
jack.
DETAILED DESCRIPTION
[0021] 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.
[0022] 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
merely used to distinguish one element from another. For example, a
first object could be termed a second object, and, similarly, a
second object could be termed a first object, without departing
from the scope of the present disclosure.
[0023] The terminology used in the description 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.
[0024] 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.
[0025] 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).
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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).
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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.
[0039] 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.
[0040] 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 realtime 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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).
[0046] 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.
[0047] 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).
[0048] In some embodiments, the methods of the present disclosure
may be executed by a computing system. FIG. 5 illustrates an
example of such a computing system 500, in accordance with some
embodiments. The computing system 500 may include a computer or
computer system 501A, which may be an individual computer system
501A or an arrangement of distributed computer systems. The
computer system 501A includes one or more analysis modules 502 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 502 executes
independently, or in coordination with, one or more processors 504,
which is (or are) connected to one or more storage media 506. The
processor(s) 504 is (or are) also connected to a network interface
505 to allow the computer system 501A to communicate over a data
network 509 with one or more additional computer systems and/or
computing systems, such as 501B, 501C, and/or 501D (note that
computer systems 501B, 501C and/or 501D may or may not share the
same architecture as computer system 501A, and may be located in
different physical locations, e.g., computer systems 501A and 501B
may be located in a processing facility, while in communication
with one or more computer systems such as 501C and/or 501D that are
located in one or more data centers, and/or located in varying
countries on different continents).
[0049] A processor may include a microprocessor, microcontroller,
processor module or subsystem, programmable integrated circuit,
programmable gate array, or another control or computing
device.
[0050] The storage media 506 may be implemented as one or more
computer-readable or machine-readable storage media. Note that
while in the example embodiment of FIG. 5 storage media 506 is
depicted as within computer system 501A, in some embodiments,
storage media 506 may be distributed within and/or across multiple
internal and/or external enclosures of computing system 501A and/or
additional computing systems. Storage media 506 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),
BLU-RAY.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.
[0051] In some embodiments, the computing system 500 contains one
or more rig control module(s) 508. In the example of computing
system 500, computer system 501A includes the rig control module
508. 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.
[0052] It should be appreciated that computing system 500 is only
one example of a computing system, and that computing system 500
may have more or fewer components than shown, may combine
additional components not depicted in the example embodiment of
FIG. 5, and/or computing system 500 may have a different
configuration or arrangement of the components depicted in FIG. 5.
The various components shown in FIG. 5 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.
[0053] 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.
[0054] FIG. 3A illustrates a side, schematic view of a drilling rig
300, according to an embodiment. The drill rig 300 is positioned
over a well, wherein a casing 341 is cemented with cement 342 in
the well and a wellhead 340 is attached to the casing 341. A cellar
343 is dug around the wellhead 340. The wellhead 340 comprises a
blow out preventer BOP 344, a bell nipple 345, and a rotating
control device RCD 346. A flow out line 347 extends from the bell
nipple 345.
[0055] The drilling rig (or "rig system") 300 may include a rig
floor 302, through which a drill string 304 is received. The drill
string 304 is deployed into, so as to form, the wellbore. The drill
string 304 is rotated via a drilling device, such as a top drive
306, although other drilling equipment such as rotary table 303 may
be employed instead of or in addition to a top drive 306. A quill
307 may extend from the bottom of the top drive 306 to allow the
connection to the drill-string 304 In some operations, the
drill-string 304 may be supported by slip 305 engaged in the
rotary-table 303.
[0056] The top drive 306 is movable via a drill line 308 and a
drawworks 310. The drawworks 310 operates to spool or unspool the
drill line 308 to a fast sieve 309, and thereby raise or lower the
top drive 306 in a mast 312, relative to the rig floor 302. The top
drive 306 is guided along the mast 312, and the mast 312 bears the
weight of the drill line 308 and the top drive 306 through the
crown block 314 at the top of the mast 312. The mast 312 transmits
this weight to the ground via the rig substructure 316. Further,
the mast 312 bears the reactionary torque from the top drive 306
rotating the drill string 304.
[0057] The mast 312 may have an asymmetric, e.g., U-shaped
geometry. The open end of the U-shape may face the inclined slide
318 of the rig 300, as shown, which may facilitate loading new
drill pipes into the mast 312 for connection with the drill string
304. A catwalk 317 delivers new pipes to the rig floor 302. The new
pipes may be loaded and made-up into a pipestand 319 using a pipe
handler 320, as shown, although a single-joint elevator or another
structure may also or instead be used. Further, a block retractor
(or "block retraction system") 322 may be provided, which may
include one or more vertically-extending rails along the U-shaped
geometry of the mast. The block retraction system 322 may also
include a rigid arm, or potentially a flexible cable, which may
serve to push or pull the travelling block 324 horizontally
relative to mast 312, and thus adjust the horizontal position of
the top drive 306.
[0058] As shown in FIG. 4A, because the mast 312 has an asymmetric
geometry, the mast may tend to bend unevenly under the load of the
top drive 306 and/or the drill string 304 (when hanging onto the
top-drive 306. As the mast 312 bends, the travel path 328 of the
quill 307 becomes inclined (or even curved) relative to the well
axis 326. Further, the ground beneath the rig substructure 316 may
compact unevenly during drilling. Compacted earth 336 may cause the
rig substructure 316 to tilt as it settles unevenly on the ground.
A substructure axis 325 may become inclined relative to the well
axis 326. These circumstances may be additive, e.g., the rig
compaction and the uneven bending may build on one another, or they
may be subtractive. However, the uneven bending and/or uneven
compaction may result in the travel path 328 along which the quill
307 and travelling block 324 move in the mast 312 being angled
and/or even curved with respect to the well axis 326. This is
called the "loaded" travel path 328. In particular, a quill axis
327 may become displaced relative to the well axis 326, wherein the
misalignment shown in FIG. 3A is due to activation of the block
retractions system 322. Accordingly, the present disclosure may
employ a method for dynamically adjusting the lateral position of
the travelling block 324 (and thus the top drive 306) using the
retraction system 322 while moving the top drive 306 as part of the
drilling operation. The main objective of such method is to insure
that the axis of the quill 307 moves along the axis 326 of the
well. In one embodiment, the method includes 2 steps. The first
step is the determination of the travel path of the
travelling-block and/or top drive in the mast when moving up or
down without activation of the block retraction system 322: such
path is the "uncorrected" travel path of the travelling block 324.
The second step is the application of the required effect
(correction) on the travel block 324 by the retraction system 322
to insure a linear vertical path of the top-drive when moving
up/down in the mast 312. The travelling block 324 may then move
along the "corrected" travel path.
[0059] FIG. 3B illustrates a side, schematic view of a drilling rig
300, according to an alternate embodiment that is similar to the
drilling rig shown in FIG. 3A. In this embodiment, block retraction
system 322 is located at the top of the mast 312 so as to move the
crown block 314 relative to the mast 312. In this embodiment, the
required effect (correction) on the travel block 324 to insure a
linear vertical path of the top-drive 306 when moving up/down in
the mast 312, is done by moving the crown block 314 with the
retraction system 322. When the crown block 314 is positioned on
the well axis 326, the travelling block 324 may then move along the
"corrected" travel path.
[0060] In a further embodiment of the invention, the retraction
system 322 comprises a combination of the retraction systems
illustrated in FIGS. 3A and 3B. In this embodiment, both the crown
block 314 and the travelling block 324 may be moved to and retained
in "corrected" positions more in line with the well axis 326 to
insure a linear vertical path of the top-drive 306 when moving
up/down in the mast 312.
[0061] As shown in FIG. 4B, because the mast 312 has an asymmetric
geometry, the mast may tend to bend unevenly under the load of the
top drive 306 and/or the drill string 304 (when hanging onto the
top-drive 306. In this embodiment, block retraction system 322 is
located at the top of the mast 312 so as to move the crown block
314 relative to the mast 312. In this embodiment, the required
effect (correction) on the travel block 324 to insure a linear
vertical path of the top-drive 306 when moving up/down in the mast
312, is done by moving the crown block 314 with the retraction
system 322. When the crown block 314 is positioned on the well axis
326, the travelling block 324 may then move along the "corrected"
travel path.
[0062] In a further embodiment of the invention, the retraction
system 322 comprises a combination of the retraction systems
illustrated in FIGS. 4A and 4B. In this embodiment, both the crown
block 314 and the travelling block 324 may be moved to and retained
in "corrected" positions more in line with the well axis 326 to
insure a linear vertical path of the top-drive 306 when moving
up/down in the mast 312.
[0063] In order to execute such a method, the rig system may
include a method to determine the distance X between the axis 326
of the well versus the default travel path 328 of the quill 307
when travelling vertically in the mast 312. The travel path 328
depends directly on the load in the mast and the ground compaction
336. It is supposed that the travel path 328 for the quill 307
and/or travel block 324 is in a vertical plane passing by the axis
326 of the well and perpendicular to the direction of the movement
performed during block retract (which is typically opposed to the
direction of the catwalk 317). This travel path 328 is the location
of point "P" which can be located by some 2D coordinate systems. In
particular, the 2D coordinates can be determined by the length "L"
from a reference point and the angle "a" in reference to a given
horizon. Any laser generator, such as a theodolite associated with
a laser ranging system can deliver these two measurements. In some
embodiments, this may be provided by the theodolite 334 and/or
laser ranging systems, which may be located at a stationary
position some distance away from the rig 300, as shown in FIG. 4A.
In another embodiment, the 2D coordinate system may be determined
by the are "E" and the radius "L." The are "E" is obtained from the
hook-position which is typically tracked on a drilling rig versus
the rig floor 302. The radius "L" may be obtained from a pulsed
laser system. In another embodiment (see FIG. 5B), two theodolites
334A and 334B are shown installed in the plane of flexing of the
mast 312 to allow a determination of the position of the point "P"
of the travel path 328 of the travelling block 324 and/or the quill
307. The relative positions of the two theodolites 334A and 334B
must be known. In the FIG. 5B, they are represented on the same
elevation and separated from each other at a distance "D." The
solution method for the proper determination of the position of "P"
from the measured angles .alpha.1 and .alpha.2 is well known by
persons of skill in the art. In a further embodiment, as shown in
FIG. 5C, two laser ranging systems 370A and 370B are enabled to
measure distances L1 and L2 to the position "P" of the travel path
328 of the travelling block 324 and/or the quill 307. In still
further embodiments of the invention a combination of angle
measurement and distance measurement devices may be used to
determine the position "P" of the travel path 328 of the travelling
block 324 and/or the quill 307 relative to the well axis 326.
[0064] Embodiments of the invention may use any laser generator
known to persons of skill, such as a theodolite, a laser ranging
system, etc.
[0065] For example, the theodolite and/or laser ranging system 334
may be stationed on a concrete pad formed at a range of about 100
meters away from the rig floor 302. The theodolite and/or laser
ranging system 334 may bounce a laser beam 335 off a reflector 333
to determine a distance between the theodolite and/or laser ranging
systems 334 and the reflector 333. The 2D coordinates of the point
"P" on the travel path defined by the reflector 333 can be
determined as "L" and "a" if a combined theodolite and laser
ranging system is being used or as "L" and "E" if a pulsed laser
system is associated with the hook-position measurement (such as a
drawwork encoder 315). Such determination can be determined for
multiple points "P" along the travel path 328. When no correction
is performed by the block retraction system 322, this travel path
328 is called the "uncorrected" travel path.
[0066] It should be noted that the "uncorrected" travel path
depends on the lifted force by the travelling block 324, as the
mast 312 may bend more and the earth compaction 336 may also be
affected with a change in the lifted force (hookload). So the
"uncorrected" travel path is associated with a measured lifted
force or "hookload" supported in the mast 312. The rig system 300
may also employ a determination of the hookload supported by the
mast 312. This hookload may be may be measured on the deadline 330
of the drawworks 310 via a hookload sensor 331, as shown in FIG.
4A, but could also be a load measured directly by the top drive
306, crown block 314, etc. Such hookload may unevenly bend the mast
312.
[0067] The "uncorrected" travel path is a set of points "P,"
wherein for each position "P" on the travel path 328, the
corresponding position "P'" on the well axis 326 can be determined
by geometry. Then the horizontal offset "X" can then be determined.
Such information corresponding to the N positions of the travelling
block 324 and/or top drive 306 can be reformatted as N pairs of
"elevation above the rig floor" (as measured by the hook-position)
and the correction from vertical "X" as determined above. This
would produce a correction matrix of N.times.2. Such matrix is
determined for a defined hookload. The corrections may be referred
to the mast itself or the guidance rail 313 of the retraction
system 322, as shown in FIG. 4A, by applying a horizontal
correction (W-X), where W is the distance between the well axis 326
and the guidance rail 313. W is called the "required retraction."
This provides a matric of N.times.2 of "required retraction" versus
"block elevation above the rig floor." Such information may depend
on the hookload.
[0068] When that matrix is available after the first step
(travel-path determination) of the overall process, then correction
can be applied. The block retraction system 322 may then be
controlled to extend/retract the travelling block 324 and/or top
drive 306 to/from the guide rails 313 so that the quill axis 327 is
collinear with the well axis 326 (see FIG. 3A). Typically, the hook
position is continuously determined via the encoder 315 on the
drawwork 310 to determine the "block elevation above the rig
floor." Then the required concretion is determined based on the
matrix. Interpolation may be required between points of the matrix.
The "required correction" is then applied via the retraction system
322.
[0069] The usage of the 2 steps methods (determination of
"uncorrected" travel path under load, followed by application of
correction) as described above allows use of the theodolite and/or
the ranging system during a limited time. This may be advantageous
as the usage of these devices may require the support of technical
experts. In another embodiment, the usage of the theodolite and/or
the ranging systems may be continuous so that there is no need of a
"correction" table. The retraction system is controlled in a
continuous fashion to insure that the axis 327 of the quill 307 is
aligned with the axis 326 of the well.
[0070] Such process may be performed by rig computer 105, which may
be part of the rig control system 100 discussed above. In turn, the
rig control system 100 may determine a distance to from the guide
rails 313 of the mast 312 that the top drive 306 is to be located,
based on its vertical position. The rig computer may control the
block retraction system 322, which may push and/or pull the
travelling block 324 as it moves along the mast 312, so as to
laterally position the top drive 306 along the well axis 326 (e.g.,
such that the top drive 306 "follows" the well axis 326 at a
plurality of points, e.g., continuously, along the travel of the
top drive 306). It will be appreciated that the distance between
the top drive 306 and the guide rails 313 of the mast 312 may be
continuously, or at relatively short intervals, adjusted during the
movement of the top drive 306, so as to maintain the top drive 306
movement along the well axis 326.
[0071] Accordingly, the rig system 300 may receive information
representing the hookload, elevation of the top drive 306, and
lateral position of the top drive 306. The rig computer 105 may
then employ this information to determine a distance from the guide
rail 313 of the mast 312 that the top drive 306 should be, at
various elevations (or adjusted continuously) in the mast 312,
depending on the hookload.
[0072] FIG. 5A illustrates some of the deformations associated with
rig operation, as well as the paths potentially followed by the
travelling block. In ideal condition, the quill 307 of the top
drive 306 should move in the mast along the axis 326 of the
well-bore. Difference of ground compaction (shown as 336.sub.B and
336.sub.A) creates some tilting of the rig, wherein such tilting
could be determine by inclinometer 337 connected to the rig base
350. Furthermore, the rig substructures 316.sub.A and 316.sub.B may
be compressed by the effect of hookload: this effect may generate
differences of elevation RF.sub.A and RF.sub.B in the rig-floor 302
as the loads in the substructures 316.sub.A and 316E may not be
balanced. This difference of elevation creates additional
inclination. The rig-floor inclination 13 may be different than the
inclination .gamma. of the base system 350. The mast axis 338 would
normally be perpendicular to the rig floor. The mast axis 338 would
normally be the travel path of the travelling block 324 and/or
quill 307 when the hookload is low.
[0073] If the hookload is at a certain defined value, the mast
bends (flexes) elastically and the travel path of the travelling
block 324 and/or quill 307 becomes the path 328T ("T" for total
deformation including ground differential compaction 336 and the
elastic deformations of the rig. The elastic deformation of the rig
has two key components: [0074] (1) the effect of the differences of
deformation of the substructure 316. This substructure deformations
modify the rig floor elevation RF.sub.A and RF.sub.B, generating
some tilting of the rig floor as well as the mast; and [0075] (2)
the flexing of the mast under hookload effect.
[0076] In case of the rig being installed on very rigid ground, the
ground deformation effects 336.sub.B and 336.sub.A can be similar
(and even negligible) so that the inclination .gamma. measured by
the inclinometers 337 is small (or close to null). In such
condition, only the two types of elastic deformations of the rig
affect the travel path of the travelling block 324 and/or quill
307, which is defined as 328R (index "R" for "rig deformation).
[0077] In practical terms, the rig deformation 328R depends on the
hookload and should be reproducible. Such deformation could be
measured by a combined theodolite and laser ranging system in a
defined stable condition (such as new rig on tick concrete pad).
This would allow generation of a matrix of n-lines with columns
including the "required correction W" for the given hookload and
elevation, as shown in Table 1.
TABLE-US-00001 TABLE 1 Block Elevation Hookload 1 Hookload 2
Hookload 3 Hookload 4 . . . E1 W1_1 W1_2 W1_3 W1_4 E2 W2_1 W2_3
W2_3 W2_4 E3 W3_1 W3_2 W3_3 W3_4 E4 W4_1 W4_2 W4_3 W4_4 . . . . . .
. . . . . . . . .
[0078] The "required correction W" for the given hookloads and
elevations are characteristic of the rig. Interpolation may be
performed to obtain the "required correction W" between measured
data points, in relation to block elevation and hookload.
[0079] When the rig operates on deformable ground, the rig base 350
may generate ground deformations 336.sub.A and 336.sub.B so that
inclination .gamma. occurs at/between rig bases. Such inclination
.alpha. would add tilt .gamma. in the mast (defined by the axis
339). This additional tilting may induce the need for an additional
correction WT for the retraction system.
WT="block-elevation" sinus(.gamma.)
[0080] The total correction W to apply by the retraction system
would be WT+Wij, wherein Wij may be obtained from the matrix in
Table 1, depending on block elevation and hookload.
[0081] When using such approach, a theodolite may only be necessary
to create the matrix for "required correction W." During drilling
operation, the computer 105 may only need to measure hookload,
block elevation and inclination .gamma. (by inclinometer 337).
[0082] FIG. 6A illustrates a perspective view of a block retractor
322 capable of use with the invention. The retractor has a carriage
360 from which extend four guide brackets 361. Of course, the guide
brackets mate with and glide along guide rails 313 in the mast 312
(see FIGS. 3 and 4). Upper and lower arms 362 and 363 extend from
the carriage for mounting the top drive 306 and/or travelling block
324 to the carriage 360. Pistons 364 extend between the carriage
360 and the lower arms 363 to move the top drive 306 and/or
travelling block 324 between a retracted position (see FIG. 6B) and
an extended position (see FIG. 6C).
[0083] Although bending in a single plane, and commensurately,
adjusting the position of the top drive 306 in a single axis, is
shown, it will be appreciated that such bending and adjusting may
be extended to two dimensions consistent with the present
disclosure. For example, a second device for determining the
lateral position of the top drive 306 (e.g., another theodolite
and/or laser ranging systems 334 or another inclinometer positioned
90 degrees from the first one shown) may be provided, which may
allow to determine the position of the top drive 306 along an axis
extending perpendicular the present figure. The combination of the
measurements from the two sensors, e.g., theodolites and/or laser
ranging systems 334, may result in a determination of the position
of the top drive 306 in the horizontal plane, rather than along a
single axis. Further, a second guide rail and block retraction
system may be provided in the mast, e.g., also rotated 90 degrees
from the guide rail shown. Accordingly, the position of the
travelling block 324, and thus the top drive 306, may also be
adjusted in the horizontal plane.
[0084] FIG. 7 illustrates a side view of a drill rig 300. The drill
rig mast 312 extends vertically from a substructure 316 with a rig
floor 302 between. The substructure 316 is supported by a rig base
350, which rest upon the ground. The rig base 350 generally is a
square shape and is positioned around the wellbore and cellar 343
(see FIGS. 3 and 4). At each of the four corners of the rig base
350, there is a jack 351. The jacks 351 are capable of lifting the
entire drill rig 300 off the ground, when extended in unison. The
jacks 351 may be hydraulic jacks or any other jacks known to
persons of skill. The theodolite and/or laser ranging systems 334
is positioned on the ground at a distance from the drill rig 300 so
as to direct a laser beam 335 at a reflector 333 located at the top
of the mast 312. A computer may use distance information provided
by the theodolite and/or laser ranging systems 334 to determine
whether the top of the mast 312 is positioned in line with the well
axis 326. If the top of the mast 312 is not positioned in line with
the well axis 326, the two jacks on the catwalk 317 side of the rig
300 may be extended, or the two jacks on the drawwork 310 side of
the rig 300 may be extended, to reposition the top of the mast 312
farther away from or closer to the theodolite and/or laser ranging
systems 334, respectively, until the top of the mast 312 is again
positioned in line with the well axis 326. In a further embodiment,
a second theodolite and/or laser ranging systems may be positioned
on the ground at a distance from the drill rig 300, wherein lines
from the theodolites and/or laser ranging systems to the drill rig
300 are perpendicular. The second theodolite and/or laser ranging
systems may be used to reposition the top of the mast 312 in a
plane defined by the well axis 326 and the second theodolite and/or
laser ranging systems by extending either the jacks 351 in the
foreground or the jacks in the background (not visible) in FIG. 7.
With two theodolites and/or laser ranging systems 334, the top of
the mast 312 may be positioned directly over the well in line with
the well axis 326, by extending one or more of the jacks 351.
[0085] In another embodiment, inclinometers may be installed on the
base 350 of the drilling rig to measure the tilting effect of the
base in two perpendicular directions. These measurements determine
the effect of the difference of earth compaction 336. These
measurement can be used to determine the correction to perform with
the rig jack 351 to correct the inclinations in the two directions
so that the effect of these compaction is cancelled.
[0086] Rig jack 351 may be any type of jack known to persons of
skill in the art. For example, they may be hydraulic rig jacks,
such as those used to walk the rig from one well bore to another,
where operations are conducted with respect to more than one
wellbore on a particular pad site.
[0087] Further, a lock may be implemented relative to each jack to
hold the jack in a particular position. Hydraulic jacks, for
example, may leak fluid and therefore not maintain the jack at a
particular height under the extremely heavy load of the drill rig.
Thus, a locking mechanism may be implemented to carry the weight of
the drill rig once the jack has lifted it to a particular height.
Each time the jack is adjusted, the lock may be released to allow
the jack to reposition the drilling rig and once repositioned, the
jack may again be fixed in the position by the lock. As shown in
FIG. 8, the jack 351 may comprise housing 353 that is fixed to the
rig base 350. A piston 352 extends from the housing 353, and a pad
354 is attached to the end of the piston 352. A lock 355 extends
between the pad 354 and the rig base 350 to lock the drill rig at a
particular height once set by the jack 351.
[0088] In an alternative embodiment, the two theodolites and/or
laser ranging systems 334 may be used by the computer 105 to
determine the horizontal position of the top drive 306 relative to
the well axis 326 and the four jacks 351 may be used to tilt the
drill rig 300 to reposition the top drive 306.
[0089] In a further embodiment of the invention, the drive system
may be a turn table in the rig floor that rotates a Kelly around
the drill string. Because the rig floor is supported several feet
above the ground by the rig substructure, the turntable may become
off center when the drill rig settles into the ground due to uneven
compaction of the dirt. Two theodolites and/or laser ranging
systems 334 may be used by the computer 105 to determine the
horizontal position of the turn table and Kelly. The four jacks 351
may be used to relocate the turn table and Kelly directly over the
well bore to align with the well axis.
[0090] A further embodiment of the invention comprises a drill rig
system for drilling a wellbore wherein the sensing of the position
of the turning device comprises two primary theodolites positioned
in the plane defined the flexing of the mast and two distances away
from the turning device and two secondary theodolites positioned in
a vertical plane perpendicular to the plane defined the flexing of
the mast and two distances away from the turning device.
[0091] 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. Additional information
supporting the disclosure is contained in the appendix attached
hereto.
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