U.S. patent application number 16/247909 was filed with the patent office on 2020-07-16 for utilizing vision systems at a wellsite.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Vishwanathan Parmeshwar, Manat Singh, Richard Wang.
Application Number | 20200224525 16/247909 |
Document ID | / |
Family ID | 71516317 |
Filed Date | 2020-07-16 |
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United States Patent
Application |
20200224525 |
Kind Code |
A1 |
Parmeshwar; Vishwanathan ;
et al. |
July 16, 2020 |
Utilizing Vision Systems at a Wellsite
Abstract
Utilizing vision systems at a wellsite, which may include
operating a video camera to generate a video signal comprising
images of one or more pieces of equipment or components and
receiving the video signal by a processing system, which may then
process the images to monitor or determine physical and/or
operational characteristics associated with the one or more pieces
of equipment in the images. The physical and/or operational
characteristics may include amount of stretch of a drill string
extending within a wellbore and/or amount of stretch an uppermost
tubular of a drill string extending within a wellbore.
Inventors: |
Parmeshwar; Vishwanathan;
(Houston, TX) ; Singh; Manat; (Houston, TX)
; Wang; Richard; (Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
71516317 |
Appl. No.: |
16/247909 |
Filed: |
January 15, 2019 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 19/165 20130101;
E21B 47/01 20130101; E21B 44/00 20130101; E21B 17/006 20130101 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 19/16 20060101 E21B019/16; E21B 17/00 20060101
E21B017/00; E21B 47/01 20060101 E21B047/01 |
Claims
1. A method comprising: operating a video camera to capture: a
first image of a mark located on a first tubular while the first
tubular is engaged by a top drive and a second tubular coupled with
the first tubular is engaged by slips of a drilling rig comprising
the top drive; and a second image of the mark while the first
tubular remains engaged by the top drive and the second tubular is
not engaged by the slips; and determining an amount of stretch of
the first tubular by determining a change in position of the mark
among the first and second images, wherein determining the mark
position change among the first and second images comprises
operating a processing system comprising a processor and a memory
storing computer program code.
2. The method of claim 1 wherein determining the mark position
change among the first and second images comprises determining a
quantity of video pixels interposing respective first and second
positions of the mark in the first and second images.
3. The method of claim 2 wherein determining the stretch amount is
based on the determined quantity of video pixels and a
predetermined relationship.
4. The method of claim 3 further comprising converting the
determined quantity of video pixels to a physical measurement to
determine the stretch amount based on a relationship between: the
determined quantity of video pixels; a radial distance of the first
tubular from the video camera; and a focal length of the video
camera.
5. The method of claim 1 further comprising: operating the video
camera to capture additional images of additional marks on
additional tubulars as each additional tubular is added to a string
of tubulars comprising the first and second tubulars; determining
an amount of stretch of each additional tubular by determining a
change in position of the additional mark among the first and
second images of that additional tubular; and determining an amount
of stretch of the string of tubulars based on the determined amount
of stretch of each individual tubular.
6. The method of claim 1 wherein the mark is or comprises a
physical feature of the first tubular.
7. The method of claim 1 wherein the mark is or comprises a visual
feature that is painted on an outer surface of the first
tubular.
8. The method of claim 1 wherein the mark is or comprises a visual
feature that is etched on an outer surface of the first
tubular.
9. The method of claim 1 wherein the mark is or comprises a visual
feature that is affixed to an outer surface of the first
tubular.
10. A method comprising: operating a video camera to generate a
video signal comprising images encompassing a mark located on an
uppermost tubular of a tubular string comprising a plurality of
tubulars extending within a wellbore at an oil and gas wellsite;
and determining a depth (D) at which the tubular string is stuck
within the wellbore by: pulling the tubular string while
determining a resulting amount of stretch (S) of the uppermost
tubular; and determining D based at least partially on the
determined S.
11. The method of claim 10 wherein: determining D at which the
tubular string is stuck within the wellbore further comprises,
before pulling the tubular string while determining the resulting
amount of S of the uppermost tubular: pulling the tubular string to
its neutral weight; and determining an overpull force (F) based on
a weight per unit length (W) of each tubular of the tubular string;
pulling the tubular string while determining the resulting amount
of S of the uppermost tubular comprises pulling the tubular string
with the determined F while determining the resulting amount of S
of the uppermost tubular; and determining D based at least
partially on the determined S comprises determining D based on a
predetermined relationship between D, F, W, and S.
12. The method of claim 11 wherein the predetermined relationship
is D=(S.times.W)/F.
13. The method of claim 10 wherein determining the resulting amount
of S comprises determining a change in position of the mark within
the images.
14. The method of claim 13 wherein determining the change in
position of the mark within the images comprises operating a
processing system comprising a processor and a memory storing
computer program code.
15. The method of claim 13 wherein determining the change in
position of the mark within the images comprises determining a
quantity of video pixels interposing respective first and second
positions of the mark within corresponding first and second
images.
16. The method of claim 15 further comprising converting the
determined quantity of video pixels to a physical measurement to
determine the resulting amount of S based on a relationship
between: the determined quantity of video pixels; a radial distance
of the uppermost tubular from the video camera; and a focal length
of the video camera.
17. The method of claim 10 wherein the mark is or comprises a
physical feature of the uppermost tubular.
18. The method of claim 10 wherein the mark is or comprises a
visual feature that is painted on an outer surface of the uppermost
tubular.
19. The method of claim 10 wherein the mark is or comprises a
visual feature that is etched on an outer surface of the uppermost
tubular.
20. The method of claim 10 wherein the mark is or comprises a
visual feature that is affixed to an outer surface of the uppermost
tubular.
Description
BACKGROUND OF THE DISCLOSURE
[0001] Wells are generally drilled into the ground or ocean bed to
recover natural deposits of oil, gas, and other materials that are
trapped in subterranean formations. Well construction operations
(e.g., drilling operations) may be performed at a wellsite by a
drilling system having various surface and subterranean equipment
operating in a coordinated manner. The wellsite equipment may be
grouped into various subsystems, wherein each subsystem performs a
different operation controlled by a corresponding local and/or a
remotely located controller.
[0002] A video system, such as a CCTV system, comprising a
plurality of video cameras distributed at various locations at a
wellsite is utilized to display selected wellsite equipment on one
or more video monitors to facilitate viewing of the wellsite
equipment and progress of the well construction operations. For
example, a human wellsite operator (e.g., a driller) may utilize
the video system to visually monitor and confirm successive
operational stages of the well construction operations and/or to
identify operational and safety events associated with the wellsite
equipment. After visually confirming an operational stage or a
safety event, the wellsite operator may then permit the well
construction operations to proceed to a subsequent operational
stage or initiate processes to counteract a detected safety event.
The video system may also be utilized for security and/or
surveillance purposes at the wellsite.
[0003] A video system is primarily used as a supervisory tool to
help wellsite operators to view and, thus, manage operations of
wellsite equipment captured by the video cameras. However, images
(or video frames) of the wellsite equipment captured by the video
cameras also comprise information indicative of certain physical
characteristics and/or operational status of such wellsite
equipment that may not be recognized or otherwise appreciated by
the wellsite operators viewing the images on a video monitor. Thus,
computer vision technology can be utilized to acquire, process,
analyze, and understand the images captured by the video cameras to
determine such physical characteristics and/or operational status,
present the determined physical characteristics and/or operational
status to the wellsite operators, and/or automate selected wellsite
operations based on the determined physical characteristics and/or
operational status of the wellsite equipment. The physical
characteristics and operational status of the wellsite equipment
that may be monitored via the video cameras include, for example,
length, distance, position, and orientation of the wellsite
equipment, maintenance (e.g., wear) status of the wellsite
equipment, and health, safety, and environmental (HSE) regulation
compliance of the wellsite equipment and/or by the wellsite
operators.
SUMMARY OF THE DISCLOSURE
[0004] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify indispensable
features of the claimed subject matter, nor is it intended for use
as an aid in limiting the scope of the claimed subject matter.
[0005] The present disclosure introduces an apparatus including a
first downhole tubular configured for threadedly coupling with a
second downhole tubular and conveyance within a wellbore by an oil
and/or gas drilling rig. An outer surface of the first downhole
tubular includes a geometric pattern for determining azimuthal
orientation of the first downhole tubular.
[0006] The present disclosure also introduces a method including
imparting a geometric pattern onto an outer surface of a downhole
tubular. The geometric pattern is for determining azimuthal
orientation of the downhole tubular while the downhole tubular is
threadedly coupled with another downhole tubular for conveyance
within a wellbore.
[0007] The present disclosure also introduces a method including
operating a video camera to generate a signal related to images of
a geometric pattern on an outer surface of a first downhole tubular
while the first downhole tubular is being threadedly coupled with a
second downhole tubular at an oil and gas wellsite. A processing
system is operated to process the signal to determine an azimuthal
orientation of the first downhole tubular based on the images of
the geometric pattern.
[0008] The present disclosure also introduces a method that
includes operating a video camera to generate a video signal
associated with images encompassing a top of a tubular extending
above an elevator of a drill rig at an oil and gas wellsite while
the tubular is retained by the elevator. A processing system is
operated to process the video signal to determine a height of the
top of the tubular relative to the rig floor of the drill rig.
[0009] The present disclosure also introduces a method that
includes operating a video camera to generate a video signal
related to images encompassing at least a portion of a crown block
of a hoisting system of an oil and gas drill rig. A processing
system is operated to process the video signal to determine when a
traveling block or elevator of the hoisting system is within a
threshold distance from the crown block.
[0010] The present disclosure also introduces a method that
includes operating a video camera to generate a video signal
pertaining to images encompassing at least a portion of a drawworks
of a hoisting system of an oil and gas drill rig. A processing
system is operated to process the video signal to determine when a
traveling block or elevator of the hoisting system is within a
threshold distance from the crown block.
[0011] The present disclosure also introduces a method including
monitoring alignment between a pin end of an upper tubular and a
box end of a lower tubular during tubular make up operations at an
oil and gas wellsite. The monitoring is performed by operating a
first video camera to generate a first video signal related to
first images encompassing the pin end of the upper tubular and the
box end of the lower tubular, and by operating a second video
camera to generate a second video signal related to second images
encompassing the pin end of the upper tubular and the box end of
the lower tubular. The first and second video cameras are directed
at the pin end of the upper tubular and the box end of the lower
tubular from different angles. A processing system is operated to
process the first and second video signals to determine an amount
of misalignment between the pin end of the upper tubular and the
box end of the lower tubular captured in the first and second
images.
[0012] The present disclosure also introduces a method that
includes operating a video camera to generate a signal associated
with an image of at least a portion of a drill bit for drilling a
wellbore. A processing system is operated to process the signal to
determine an amount of wear experienced by the drill bit.
[0013] The present disclosure also introduces a method that
includes operating a video camera at an oil and gas wellsite to
generate a signal related to images encompassing safety regulation
compliance indicators. A processing system is operated to process
the signal to determine compliance with the safety regulations at
the oil and gas wellsite, and to initiate an alarm when the
processed signal is indicative of noncompliance with one or more of
the safety regulations.
[0014] The present disclosure also introduces a method that
includes operating a video camera to capture a first image of a
mark located on a first tubular while the first tubular is engaged
by a top drive and a second tubular coupled with the first tubular
is engaged by slips of a drilling rig including the top drive, and
to capture a second image of the mark while the first tubular
remains engaged by the top drive and the second tubular is not
engaged by the slips. The method also includes determining an
amount of stretch of the first tubular by determining a change in
position of the mark among the first and second images. Determining
the mark position change among the first and second images includes
operating a processing system having a processor and a memory
storing computer program code.
[0015] The present disclosure also introduces a method that
includes operating a video camera to generate a video signal
pertaining to images encompassing a mark located on an uppermost
tubular of a tubular string extending within a wellbore at an oil
and gas wellsite. A depth at which the tubular string is stuck
within the wellbore is determined by pulling the tubular string
while determining a resulting amount of stretch of the uppermost
tubular, and determining the depth based at least partially on the
determined stretch.
[0016] These and additional aspects of the present disclosure are
set forth in the description that follows, and/or may be learned by
a person having ordinary skill in the art by reading the material
herein and/or practicing the principles described herein. At least
some aspects of the present disclosure may be achieved via means
recited in the attached claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] The present disclosure is understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0018] FIG. 1 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0019] FIG. 2 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0020] FIG. 3 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0021] FIG. 4 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0022] FIG. 5 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0023] FIG. 6 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0024] FIG. 7 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0025] FIG. 8 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0026] FIG. 9 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0027] FIG. 10 is a perspective view of a portion of the apparatus
shown in FIG. 9 according to one or more aspects of the present
disclosure.
[0028] FIG. 11 is a perspective view of a portion of the apparatus
shown in FIG. 10 according to one or more aspects of the present
disclosure.
[0029] FIG. 12 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0030] FIG. 13 is a perspective view of a portion of the apparatus
shown in FIG. 12 according to one or more aspects of the present
disclosure.
[0031] FIG. 14 is a perspective view of a portion of the apparatus
shown in FIG. 13 according to one or more aspects of the present
disclosure.
[0032] FIG. 15 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0033] FIG. 16 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0034] FIG. 17 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0035] FIG. 18 is a chart related to one or more aspects of the
present disclosure.
[0036] FIG. 19 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
[0037] FIG. 20 is an enlarged view of a portion of the apparatus
shown in FIG. 19 according to one or more aspects of the present
disclosure.
[0038] FIG. 21 is a view of the apparatus shown in FIG. 20 in
another operational state according to one or more aspects of the
present disclosure.
[0039] FIG. 22 is a schematic view of at least a portion of an
example implementation of apparatus according to one or more
aspects of the present disclosure.
DETAILED DESCRIPTION
[0040] It is to be understood that the following disclosure
provides many different embodiments, or examples, for implementing
different features of various embodiments. Specific examples of
components and arrangements are described below to simplify the
present disclosure. These are, of course, merely examples and are
not intended to be limiting. In addition, the present disclosure
may repeat reference numerals and/or letters in the various
examples. This repetition is for simplicity and clarity, and does
not in itself dictate a relationship between the various
embodiments and/or configurations discussed.
[0041] Systems and methods (e.g., processes, operations) according
to one or more aspects of the present disclosure may be utilized or
otherwise implemented in association with an automated well
construction system at an oil and gas wellsite, such as for
constructing a wellbore to obtain hydrocarbons (e.g., oil and/or
gas) from a subterranean formation. However, one or more aspects of
the present disclosure may be utilized or otherwise implemented in
association with other automated systems in the oil and gas
industry and other industries. For example, one or more aspects of
the present disclosure may be implemented in association with
wellsite systems for performing fracturing, cementing, acidizing,
chemical injecting, and/or water jet cutting operations, among
other examples. One or more aspects of the present disclosure may
also be implemented in association with mining sites, building
construction sites, and/or other work sites where automated
machines or equipment are utilized.
[0042] FIG. 1 is a schematic view of at least a portion of an
example implementation of a well construction system 100 according
to one or more aspects of the present disclosure. The well
construction system 100 represents an example environment in which
one or more aspects of the present disclosure described below may
be implemented. Although the well construction system 100 is
depicted as an onshore implementation, the aspects described below
are also applicable to offshore implementations.
[0043] The well construction system 100 is depicted in relation to
a wellbore 102 formed by rotary and/or directional drilling from a
wellsite surface 104 and extending into a subterranean formation
106. The well construction system 100 includes surface equipment
110 located at the wellsite surface 104 and a drill string 120
suspended within the wellbore 102. The surface equipment 110 may
include a mast, a derrick, and/or another support structure 112
disposed over a rig floor 114. The drill string 120 may be
suspended within the wellbore 102 from the support structure 112.
The support structure 112 and the rig floor 114 are collectively
supported over the wellbore 102 by legs and/or other support
structures (not shown).
[0044] The drill string 120 may comprise a bottom-hole assembly
(BHA) 124 and means 122 for conveying the BHA 124 within the
wellbore 102. The conveyance means 122 may comprise drill pipe,
heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough
logging condition (TLC) pipe, coiled tubing, and/or other means for
conveying the BHA 124 within the wellbore 102. A downhole end of
the BHA 124 may include or be coupled to a drill bit 126. Rotation
of the drill bit 126 and the weight of the drill string 120
collectively operate to form the wellbore 102. The drill bit 126
may be rotated from the wellsite surface 104 and/or via a downhole
mud motor (not shown) connected with the drill bit 126.
[0045] The BHA 124 may also include various downhole tools 180,
182, 184. One or more of such downhole tools 180, 182, 184 may be
or comprise an acoustic tool, a density tool, a directional
drilling tool, an electromagnetic (EM) tool, a formation sampling
tool, a formation testing tool, a gravity tool, a monitoring tool,
a neutron tool, a nuclear tool, a photoelectric factor tool, a
porosity tool, a reservoir characterization tool, a resistivity
tool, a rotational speed sensing tool, a sampling-while-drilling
(SWD) tool, a seismic tool, a surveying tool, a torsion sensing
tool, and/or other measurement-while-drilling (MWD) or
logging-while-drilling (LWD) tools.
[0046] One or more of the downhole tools 180, 182, 184 may be or
comprise an MWD or LWD tool comprising a sensor package 186
operable for the acquisition of measurement data pertaining to the
BHA 124, the wellbore 102, and/or the formation 106. One or more of
the downhole tools 180, 182, 184 and/or another portion of the BHA
124 may also comprise a telemetry device 187 operable for
communication with the surface equipment 110, such as via mud-pulse
telemetry. One or more of the downhole tools 180, 182, 184 and/or
another portion of the BHA 124 may also comprise a downhole
processing device 188 operable to receive, process, and/or store
information received from the surface equipment 110, the sensor
package 186, and/or other portions of the BHA 124. The processing
device 188 may also store executable computer programs (e.g.,
program code instructions), including for implementing one or more
aspects of the operations described herein.
[0047] The support structure 112 may support a driver, such as a
top drive 116, operable to connect (perhaps indirectly) with an
uphole end of the conveyance means 122, and to impart rotary motion
117 and vertical motion 135 to the drill string 120 and the drill
bit 126. However, another driver, such as a kelly and rotary table
(neither shown), may be utilized instead of or in addition to the
top drive 116 to impart the rotary motion 117. The top drive 116
and the connected drill string 120 may be suspended from the
support structure 112 via hoisting equipment, which may include a
traveling block 118, a crown block (not shown), and a drawworks 119
storing a support cable or line 123. The crown block may be
connected to or otherwise supported by the support structure 112,
and the traveling block 118 may be coupled with the top drive 116,
such as via a hook. The drawworks 119 may be mounted on or
otherwise supported by the rig floor 114. The crown block and
traveling block 118 comprise pulleys or sheaves around which the
support line 123 is reeved to operatively connect the crown block,
the traveling block 118, and the drawworks 119 (and perhaps an
anchor). The drawworks 119 may thus selectively impart tension to
the support line 123 to lift and lower the top drive 116, resulting
in the vertical motion 135. The drawworks 119 may comprise a drum,
a frame, and a prime mover (e.g., an engine or motor) (not shown)
operable to drive the drum to rotate and reel in the support line
123, causing the traveling block 118 and the top drive 116 to move
upward. The drawworks 119 may be operable to release the support
line 123 via a controlled rotation of the drum, causing the
traveling block 118 and the top drive 116 to move downward.
[0048] The top drive 116 may comprise a grabber, a swivel (neither
shown), a tubular handling assembly links 127 terminating with an
elevator 129, and a drive shaft 125 operatively connected with a
prime mover (not shown), such as via a gear box or transmission
(not shown). The drill string 120 may be mechanically coupled to
the drive shaft 125 with or without a sub saver between the drill
string 120 and the drive shaft 125. The prime mover may be
selectively operated to rotate the drive shaft 125 and the drill
string 120 coupled with the drive shaft 125. Hence, during drilling
operations, the top drive 116 in conjunction with operation of the
drawworks 119 may advance the drill string 120 into the formation
106 to form the wellbore 102. The tubular handling assembly links
127 and the elevator 129 of the top drive 116 may handle tubulars
(e.g., drill pipes, drill collars, casing joints, etc.) that are
not mechanically coupled to the drive shaft 125. For example, when
the drill string 120 is being tripped into or out of the wellbore
102, the elevator 129 may grasp the tubulars of the drill string
120 such that the tubulars may be raised and/or lowered via the
hoisting equipment mechanically coupled to the top drive 116. The
grabber may include a clamp that clamps onto a tubular when making
up and/or breaking out a connection of a tubular with the drive
shaft 125. The top drive 116 may have a guide system (not shown),
such as rollers that track up and down a guide rail on the support
structure 112. The guide system may aid in keeping the top drive
116 aligned with the wellbore 102, and in preventing the top drive
116 from rotating during drilling by transferring reactive torque
to the support structure 112.
[0049] The well construction system 100 may further include a well
control system for maintaining well pressure control. For example,
the drill string 120 may be conveyed within the wellbore 102
through various blowout preventer (BOP) equipment disposed at the
wellsite surface 104 on top of the wellbore 102 and perhaps below
the rig floor 114. The BOP equipment may be operable to control
pressure within the wellbore 102 via a series of pressure barriers
(e.g., rams) between the wellbore 102 and the wellsite surface 104.
The BOP equipment may include a BOP stack 130, an annular preventer
132, and/or a rotating control device (RCD) 138 mounted above the
annular preventer 132. The BOP equipment 130, 132, 138 may be
mounted on top of a wellhead 134. The well control system may
further include a BOP control unit 137 (i.e., a BOP closing unit)
operatively connected with the BOP equipment 130, 132, 138 and
operable to actuate, drive, operate or otherwise control the BOP
equipment 130, 132, 138. The BOP control unit 137 may be or
comprise a hydraulic fluid power unit fluidly connected with the
BOP equipment 130, 132, 138 and selectively operable to
hydraulically drive various portions (e.g., rams, valves, seals) of
the BOP equipment 130, 132, 138.
[0050] The well construction system 100 may further include a
drilling fluid circulation system operable to circulate fluids
between the surface equipment 110 and the drill bit 126 during
drilling and other operations. For example, the drilling fluid
circulation system may be operable to inject a drilling fluid from
the wellsite surface 104 into the wellbore 102 via an internal
fluid passage 121 extending longitudinally through the drill string
120. The drilling fluid circulation system may comprise a pit, a
tank, and/or other fluid container 142 holding the drilling fluid
(i.e., mud) 140, and a pump 144 operable to move the drilling fluid
140 from the container 142 into the fluid passage 121 of the drill
string 120 via a fluid conduit 146 extending from the pump 144 to
the top drive 116 and an internal passage extending through the top
drive 116. The fluid conduit 146 may comprise one or more of a pump
discharge line, a stand pipe, a rotary hose, and a gooseneck (not
shown) connected with a fluid inlet of the top drive 116. The pump
144 and the container 142 may be fluidly connected by a fluid
conduit 148, such as a suction line.
[0051] During drilling operations, the drilling fluid may continue
to flow downhole through the internal passage 121 of the drill
string 120, as indicated by directional arrow 158. The drilling
fluid may exit the BHA 124 via ports 128 in the drill bit 126 and
then circulate uphole through an annular space 108 ("annulus") of
the wellbore 102 defined between an exterior of the drill string
120 and the wall of the wellbore 102, such flow being indicated by
directional arrows 159. In this manner, the drilling fluid
lubricates the drill bit 126 and carries formation cuttings uphole
to the wellsite surface 104. The returning drilling fluid may exit
the annulus 108 via the RCD 138 and/or via a spool, a wing valve, a
bell nipple, or another ported adapter 136, which may be located
below one or more portions of the BOP stack 130.
[0052] The drilling fluid exiting the annulus 108 via the RCD 138
may be directed into a fluid conduit 160 (e.g., a drilling pressure
control line), and may pass through various wellsite equipment
fluidly connected along the conduit 160 prior to being returned to
the container 142 for recirculation. For example, the drilling
fluid may pass through a choke manifold 162 (e.g., a drilling
pressure control choke manifold) connected along the conduit 160.
The choke manifold 162 may include at least one choke and a
plurality of fluid valves (neither shown) collectively operable to
control the flow through and out of the choke manifold 162.
Backpressure may be applied to the annulus 108 by variably
restricting flow of the drilling fluid or other fluids flowing
through the choke manifold 162. The greater the restriction to flow
through the choke manifold 162, the greater the backpressure
applied to the annulus 108.
[0053] The drilling fluid may also or instead exit the annulus 108
via the ported adapter 136 and into a fluid conduit 171 (e.g., rig
choke line), and may pass through various equipment fluidly
connected along the conduit 171 prior to being returned to the
container 142 for recirculation. For example, the drilling fluid
may pass through a choke manifold 173 (e.g., a rig choke manifold)
connected along the conduit 171. The choke manifold 173 may include
at least one choke and a plurality of fluid valves (neither shown)
collectively operable to control the flow through the choke
manifold 173. Backpressure may be applied to the annulus 108 by
variably restricting flow of the drilling fluid or other fluids
flowing through the choke manifold 173.
[0054] Before being returned to the container 142, the drilling
fluid returning to the wellsite surface 104 may be cleaned and/or
reconditioned via drilling fluid reconditioning equipment 170,
which may include one or more of liquid gas separators, shale
shakers, centrifuges, and other drilling fluid cleaning equipment.
The liquid gas separators may remove formation gasses entrained in
the drilling fluid discharged from the wellbore 102 and the shale
shakers may separate and remove solid particles 141 (e.g., drill
cuttings) from the drilling fluid. The drilling fluid
reconditioning equipment 170 may further comprise equipment
operable to remove additional gas and finer formation cuttings from
the drilling fluid and/or modify physical properties or
characteristics (e.g., rheology) of the drilling fluid. For
example, the drilling fluid reconditioning equipment 170 may
include a degasser, a desander, a desilter, a mud cleaner, and/or a
decanter, among other examples. Intermediate tanks/containers (not
shown) may be utilized to hold the drilling fluid while the
drilling fluid progresses through the various stages or portions of
the drilling fluid reconditioning equipment 170. The
cleaned/reconditioned drilling fluid may be transferred to the
fluid container 142, the solid particles 141 removed from the
drilling fluid may be transferred to a solids container 143 (e.g.,
a reserve pit), and/or the removed gas may be transferred to a
flare stack 172 via a conduit 174 (e.g., a flare line) to be burned
or to a container (not shown) for storage and removal from the
wellsite.
[0055] The surface equipment 110 may include tubular handling
equipment operable to store, move, connect, and disconnect tubulars
(e.g., drill pipes) to assemble and disassemble the conveyance
means 122 of the drill string 120 during drilling operations. For
example, a catwalk 131 may be utilized to convey tubulars from a
ground level, such as along the wellsite surface 104, to the rig
floor 114, permitting the tubular handling assembly links 127 to
grab and lift the tubulars above the wellbore 102 for connection
with previously deployed tubulars. The catwalk 131 may have a
horizontal portion and an inclined portion that extends between the
horizontal portion and the rig floor 114. The catwalk 131 may
comprise a skate 133 movable along a groove (not shown) extending
longitudinally along the horizontal and inclined portions of the
catwalk 131. The skate 133 may be operable to convey (e.g., push)
the tubulars along the catwalk 131 to the rig floor 114. The skate
133 may be driven along the groove by a drive system (not shown),
such as a pulley system or a hydraulic system. Additionally, one or
more racks (not shown) may adjoin the horizontal portion of the
catwalk 131.
[0056] An iron roughneck 151 may be positioned on the rig floor
114. The iron roughneck 151 may comprise a torqueing portion 153,
such as may include a spinner and a torque wrench comprising a
lower tong and an upper tong. The torqueing portion 153 of the iron
roughneck 151 may be moveable toward and at least partially around
the drill string 120, such as may permit the iron roughneck 151 to
make up and break out connections of the drill string 120. The
torqueing portion 153 may also be moveable away from the drill
string 120, such as may permit the iron roughneck 151 to move clear
of the drill string 120 during drilling operations. The spinner of
the iron roughneck 151 may be utilized to apply low torque to make
up and break out threaded connections between tubulars of the drill
string 120, and the torque wrench may be utilized to apply a higher
torque to tighten and loosen the threaded connections.
[0057] Reciprocating slips 161 may be located on the rig floor 114,
such as may accommodate therethrough the downhole tubulars during
make up and break out operations and during the drilling
operations. The reciprocating slips 161 may be in an open position
during drilling operations to permit advancement of the drill
string 120 therethrough, and in a closed position to clamp an upper
end of the conveyance means 122 (e.g., assembled tubulars) to
thereby suspend and prevent advancement of the drill string 120
within the wellbore 102, such as during the make up and break out
operations.
[0058] During drilling operations, the hoisting equipment lowers
the drill string 120 while the top drive 116 rotates the drill
string 120 to advance the drill string 120 downward within the
wellbore 102 and into the formation 106. During the advancement of
the drill string 120, the reciprocating slips 161 are in an open
position, and the iron roughneck 151 is moved away or is otherwise
clear of the drill string 120. When the upper portion of the
tubular in the drill string 120 that is made up to the drive shaft
125 is near the reciprocating slips 161 and/or the rig floor 114,
the top drive 116 ceases rotating and the reciprocating slips 161
close to clamp the tubular made up to the drive shaft 125. The
grabber (not shown) of the top drive 116 then clamps the upper
portion of the tubular made up to the drive shaft 125, and the
drive shaft 125 rotates in a direction reverse from the drilling
rotation to break out the connection between the drive shaft 125
and the made up tubular. The grabber of the top drive 116 may then
release the tubular of the drill string 120.
[0059] Multiple tubulars may be loaded on the rack of the catwalk
131 and individual tubulars (or stands of two or three tubulars)
may be transferred from the rack to the groove in the catwalk 131,
such as by the spinner unit. The tubular positioned in the groove
may be conveyed along the groove by the skate 133 until an end of
the tubular projects above the rig floor 114. The elevator 129 of
the top drive 116 then grasps the protruding end, and the drawworks
119 is operated to lift the top drive 116, the elevator 129, and
the new tubular.
[0060] The hoisting equipment then raises the top drive 116, the
elevator 129, and the tubular until the tubular is aligned with the
upper portion of the drill string 120 clamped by the slips 161. The
iron roughneck 151 is moved toward the drill string 120, and the
lower tong of the torqueing portion 153 clamps onto the upper
portion of the drill string 120. The spinning system rotates the
new tubular (e.g., a threaded male end) into the upper portion of
the drill string 120 (e.g., a threaded female end). The upper tong
then clamps onto the new tubular and rotates with high torque to
complete making up the connection with the drill string 120. In
this manner, the new tubular becomes part of the drill string 120.
The iron roughneck 151 then releases and moves clear of the drill
string 120.
[0061] The grabber of the top drive 116 may then clamp onto the
drill string 120. The drive shaft 125 (e.g., a threaded male end)
is brought into contact with the drill string 120 (e.g., a threaded
female end) and rotated to make up a connection between the drill
string 120 and the drive shaft 125. The grabber then releases the
drill string 120, and the reciprocating slips 161 are moved to the
open position. The drilling operations may then resume.
[0062] The tubular handling equipment may further include a pipe
handling manipulator (PHM) 163 disposed in association with a
fingerboard 165. Although the PHM 163 and the fingerboard 165 are
shown supported on the rig floor 114, one or both of the PHM 163
and fingerboard 165 may be located on the wellsite surface 104 or
another area of the well construction system 100. The fingerboard
165 provides storage (e.g., temporary storage) of tubulars (or
stands of two or three tubulars) 111 during various operations,
such as during and between tripping out and tripping in the drill
string 120. The PHM 163 may be operable to transfer the tubulars
111 between the fingerboard 165 and the drill string 120 (i.e.,
space above the suspended drill string 120). For example, the PHM
163 may include arms 167 terminating with clamps 169, such as may
be operable to grasp and/or clamp onto one of the tubulars 111. The
arms 167 of the PHM 163 may extend and retract, and/or at least a
portion of the PHM 163 may be rotatable and/or movable toward and
away from the drill string 120, such as may permit the PHM 163 to
transfer the tubular 111 between the fingerboard 165 and the drill
string 120.
[0063] To trip out the drill string 120, the top drive 116 is
raised, the reciprocating slips 161 are closed around the drill
string 120, and the elevator 129 is closed around the drill string
120. The grabber of the top drive 116 clamps the upper portion of
the tubular made up to the drive shaft 125. The drive shaft 125
then rotates in a direction reverse from the drilling rotation to
break out the connection between the drive shaft 125 and the drill
string 120. The grabber of the top drive 116 then releases the
tubular of the drill string 120, and the drill string 120 is
suspended by (at least in part) the elevator 129. The iron
roughneck 151 is moved toward the drill string 120. The lower tong
clamps onto a lower tubular below a connection of the drill string
120, and the upper tong clamps onto an upper tubular above that
connection. The upper tong then rotates the upper tubular to
provide a high torque to break out the connection between the upper
and lower tubulars. The spinning system then rotates the upper
tubular to separate the upper and lower tubulars, such that the
upper tubular is suspended above the rig floor 114 by the elevator
129. The iron roughneck 151 then releases the drill string 120 and
moves clear of the drill string 120.
[0064] The PHM 163 may then move toward the drill string 120 to
grasp the tubular suspended from the elevator 129. The elevator 129
then opens to release the tubular. The PHM 163 then moves away from
the drill string 120 while grasping the tubular with the clamps
169, places the tubular in the fingerboard 165, and releases the
tubular for storage in the fingerboard 165. This process is
repeated until the intended length of drill string 120 is removed
from the wellbore 102.
[0065] The surface equipment 110 of the well construction system
100 may also comprise a control center 190 from which various
portions of the well construction system 100, such as the top drive
116, the hoisting system, the tubular handling system, the drilling
fluid circulation system, the well control system, the BHA 124,
among other examples, may be monitored and controlled. The control
center 190 may be located on the rig floor 114 or another location
of the well construction system 100, such as the wellsite surface
104. The control center 190 may comprise a facility 191 (e.g., a
room, a cabin, a trailer, etc.) containing a control workstation
197, which may be operated by a human wellsite operator 195 to
monitor and control various wellsite equipment or portions of the
well construction system 100. The control workstation 197 may
comprise or be communicatively connected with a processing device
192 (e.g., a controller, a computer, etc.), such as may be operable
to receive, process, and output information to monitor operations
of and provide control to one or more portions of the well
construction system 100. For example, the processing device 192 may
be communicatively connected with the various surface and downhole
equipment described herein, and may be operable to receive signals
from and transmit signals to such equipment to perform various
operations described herein. The processing device 192 may store
executable program code, instructions, and/or operational
parameters or set-points, including for implementing one or more
aspects of methods and operations described herein. The processing
device 192 may be located within and/or outside of the facility
191.
[0066] The control workstation 197 may be operable for entering or
otherwise communicating control commands to the processing device
192 by the wellsite operator 195, and for displaying or otherwise
communicating information from the processing device 192 to the
wellsite operator 195. The control workstation 197 may comprise a
plurality of human-machine interface (HMI) devices, including one
or more input devices 194 (e.g., a keyboard, a mouse, a joystick, a
touchscreen, etc.) and one or more output devices 196 (e.g., a
video monitor, a touchscreen, a printer, audio speakers, etc.).
Communication between the processing device 192, the input and
output devices 194, 196, and the various wellsite equipment may be
via wired and/or wireless communication means. However, for clarity
and ease of understanding, such communication means are not
depicted, and a person having ordinary skill in the art will
appreciate that such communication means are within the scope of
the present disclosure.
[0067] Well construction systems within the scope of the present
disclosure may include more or fewer components than as described
above and depicted in FIG. 1. Additionally, various equipment
and/or subsystems of the well construction system 100 shown in FIG.
1 may include more or fewer components than as described above and
depicted in FIG. 1. For example, various engines, motors,
hydraulics, actuators, valves, and/or other components not
explicitly described herein may be included in the well
construction system 100, and are within the scope of the present
disclosure.
[0068] The well construction system 100 also includes stationary
and/or mobile video cameras 198 disposed or utilized at various
locations within the well construction system 100. The video
cameras 198 capture videos of various portions, equipment, or
subsystems of the well construction system 100, and perhaps the
wellsite operators 195 and the actions they perform, during or
otherwise in association with the wellsite operations, including
while performing repairs to the well construction system 100 during
a breakdown. For example, the video cameras 198 may capture digital
images (or video frames) of the entire well construction system 100
and/or specific portions of the well construction system 100, such
as the top drive 116, the iron roughneck 151, the PHM 163, the
fingerboard 165, and/or the catwalk 131, among other examples. The
video cameras 198 generate corresponding video signals (i.e.,
feeds) comprising or otherwise indicative of the captured digital
images. The video cameras 198 may be in signal communication with
the processing device 192, such as may permit the video signals to
be processed and transmitted to the control workstation 197 and,
thus, permit the wellsite operators 195 to view various portions or
components of the well construction system 100 on one or more of
the output devices 196. The processing device 192 or another
portion of the control workstation 197 may be operable to record
the video signals generated by the video cameras 198.
[0069] The present disclosure further provides various
implementations of systems and/or methods for controlling one or
more portions of the well construction system 100. FIG. 2 is a
schematic view of at least a portion of an example implementation
of a control system 200 for controlling the well construction
system 100 according to one or more aspects of the present
disclosure. The following description refers to FIGS. 1 and 2,
collectively.
[0070] The control system 200 may be in real-time communication
with and utilized to monitor and/or control various portions,
components, and equipment of the well construction system 100
described herein. The equipment of the well construction system 100
may be grouped into several subsystems, each operable to perform a
corresponding operation and/or a portion of the well construction
operations described herein. The subsystems may include a rig
control (RC) system 211, a fluid circulation (FC) system 212, a
managed pressure drilling control (MPDC) system 213, a choke
pressure control (CPC) system 214, a well pressure control (WC)
system 215, and a closed-circuit television (CCTV) system 216. The
control workstation 197 may be utilized to monitor, configure,
control, and/or otherwise operate one or more of the well
construction subsystems 211-216.
[0071] The RC system 211 may include the support structure 112, a
drill string hoisting system or equipment (e.g., the drawworks
119), a drill string rotational system (e.g., the top drive 116
and/or the rotary table and kelly), the reciprocating slips 161,
the drill pipe handling system or equipment (e.g., the catwalk 131,
the PHM 163, the fingerboard 165, and the iron roughneck 151),
electrical generators, and other equipment. Accordingly, the RC
system 211 may perform power generation controls and drill pipe
handling, hoisting, and rotation operations. The RC system 211 may
also serve as a support platform for drilling equipment and staging
ground for rig operations, such as connection make up and break out
operations described above. The FC system 212 may include the
drilling fluid 140, the pumps 144, drilling fluid loading
equipment, the drilling fluid reconditioning equipment 170, the
flare stack 172, and/or other fluid control equipment. Accordingly,
the FC system 212 may perform fluid operations of the well
construction system 100. The MPDC system 213 may include the RCD
138, the choke manifold 162, downhole pressure sensors 186, and/or
other equipment. The CPC system 214 may comprise the choke manifold
173, and/or other equipment, and the WC system 215 may comprise the
BOP equipment 130, 132, 138, the BOP control unit 137, and a BOP
control station (not shown) for controlling the BOP control unit
137. The CCTV system 216 may include the video cameras 198 and
corresponding actuators (e.g., motors) for moving or otherwise
controlling direction of the video cameras 198. The CCTV system 216
may be utilized to capture real-time video of various portions or
subsystems 211-215 of the well construction system 100 and display
video signals from the video cameras 198 on the video output
devices 196 to display in real-time the various portions or
subsystems 211-215. Each of the well construction subsystems
211-216 may further comprise various communication equipment (e.g.,
modems, network interface cards, etc.) and communication conductors
(e.g., cables), communicatively connecting the equipment (e.g.,
sensors and actuators) of each subsystem 211-216 with the control
workstation 197 and/or other equipment. Although the wellsite
equipment listed above and shown in FIG. 1 is associated with
certain wellsite subsystems 211-216, such associations are merely
examples that are not intended to limit or prevent such wellsite
equipment from being associated with two or more wellsite
subsystems 211-216 and/or different wellsite subsystems
211-216.
[0072] The control system 200 may also include various local
controllers 221-226 associated with corresponding subsystems
211-216 and/or individual pieces of equipment of the well
construction system 100. As described above, each well construction
subsystem 211-216 includes various wellsite equipment comprising
corresponding actuators 241-246 for performing operations of the
well construction system 100. Each subsystem 211-216 further
includes various sensors 231-236 for monitoring operational status
of the well site equipment of each subsystem 211-216.
[0073] The processing device 192 may be communicatively connected
with the local controllers 221-226, sensors 231-236, and actuators
241-246. For example, the local controllers may be in communication
with the sensors 231-236 and actuators 241-246 of the corresponding
subsystems 211-216 via local communication networks (e.g., field
buses, not shown) and the processing device 192 may be in
communication with the subsystems 211-216 via a communication
network 209 (e.g., data bus, a wide-area-network (WAN), a
local-area-network (LAN), etc.). Sensor measurement data (e.g.,
signals, information, etc.) generated by the sensors 231-236 of the
subsystems 211-216 may be made available for use by processing
device 192 and/or the local controllers 221-226. Similarly, control
commands (e.g., signals, information, etc.) generated by the
processing device 192 and/or the local controllers 221-226 may be
automatically communicated to the various actuators 241-246 of the
subsystems 211-216, perhaps pursuant to predetermined programming,
such as to facilitate well construction operations and/or other
operations described herein.
[0074] The sensors 231-236 and actuators 241-246 may be monitored
and/or controlled by the processing device 192. For example, the
processing device 192 may be operable to receive sensor data from
the sensors 231-236 of the wellsite subsystems 211-216 in
real-time, and to provide real-time control commands to the
actuators 241-246 of the subsystems 211-216 based on the received
sensor data. However, certain operations of the actuators 241-246
may be controlled by the local controllers 221-226, which may
control the actuators 241-246 based on sensor data received from
the sensors 231-236 and/or based on control commands received from
the processing device 192.
[0075] The processing device 192, the local controllers 221-226,
and other controllers or processing devices operable to receive
program code instructions and/or sensor data from sensors (e.g.,
sensors 231-236), process such information, and/or generate control
commands to operate controllable equipment (e.g., actuators
241-246) may individually or collectively be referred to
hereinafter as equipment controllers. Equipment controllers within
the scope of the present disclosure can include, for example,
programmable logic controllers (PLCs), industrial computers (IPCs),
personal computers (PCs), soft PLCs, variable frequency drives
(VFDs) and/or other controllers or processing devices operable to
receive sensor data and/or control commands and cause operation of
controllable equipment based on such sensor data and/or control
commands.
[0076] The present disclosure is further directed to selectively
positioned video cameras, such as the video cameras 198, and
equipment controller(s) operable acquire, process, analyze, and
understand digital images of the wellsite equipment captured by the
video cameras to determine physical characteristics and/or
operational status of wellsite equipment captured by the video
cameras. The video cameras may be operable to generate
corresponding video signals (i.e., feeds), each comprising the
digital images captured by the video camera. The equipment
controller(s) may utilize computer vision technology, including
machine learning techniques, to help in the well construction
operations, such as by automating or changing selected wellsite
operations based on the determined physical characteristics and/or
operational status. Thus, the present disclosure is further
directed to vision systems, such as those comprising one or more
portions of the control system 200 and the CCTV system 216,
operable to monitor and control selected wellsite equipment of one
or more of the well construction subsystems 211-215 of the well
construction system 100. The vision systems within the scope of the
present disclosure may utilize the video signals generated by the
video cameras as feedback to monitor or otherwise determine the
physical characteristics and/or operational status of the selected
wellsite equipment and control the selected wellsite equipment
based on the determined physical characteristics and/or operational
status of the wellsite equipment. Such vision systems may be
operable to process the digital images captured by the video
cameras to, for example, detect edges of an object, determine
physical characteristics (e.g., shape, texture) of an object,
identify color of an object, and determine orientation of an object
with or without tilting, moving, or otherwise adjusting view of the
video camera(s). The vision systems within the scope of the present
disclosure may be further operable to determine lengths of
components or wellsite equipment at the well construction system
100, determine relative position or distance between components or
wellsite equipment at the well construction system 100, determine
maintenance status of the wellsite equipment, and/or determine HSE
compliance at the wellsite.
[0077] Vision systems and methods utilizing such vision systems may
be implemented, at least in part, via machine learning programs,
such as deep neural networks for video and image processing. Such
programs may be implemented at different levels of TOT
infrastructure, for example at the edge (a resource close to the
equipment that can collect, process, and analyze video signals or
data) or the Fog (an intermediary stage where data is processed on
smart devices like routers and gateways, thereby reducing traffic
flow to the cloud and is complementary in nature to cloud
computing). However, the video signals generated by video cameras
can be pushed straight into the cloud where the video and/or image
processing is performed and the machine learning programs are
implemented.
Determining Stretch of a Drill Pipe
[0078] An example implementation of apparatus and methods according
to one or more aspects of the present disclosure may be utilized to
measure or otherwise determine the amount of stretch drill pipes
experience during drilling and other wellsite operations. Drill
pipes can be subjected or otherwise caused to stretch due to the
weight of a drill string connected below. Drill pipes can also
experience stretching, for example, when the drill string is pulled
to determine depth of a stuck point of the drill string.
[0079] FIG. 3 is a schematic view of at least a portion of an
example implementation of a vision system 300 operable to determine
the amount of stretch drill pipes experience during drilling and
other wellsite operations according to one or more aspects of the
present disclosure. The vision system 300 may be a portion of a
well construction system, such as the well construction system 100
shown in FIG. 1, and may be disposed or otherwise utilized in
association with other portions of the well construction system
100, including where identified by the same numerals. The vision
system 300 may be a portion of a control system, such as the
control system 200 shown in FIG. 2, and/or a CCTV system, such as
the CCTV system 216 shown in FIGS. 1 and 2. Thus, the vision system
300 may be communicatively connected with a processing device, such
as the processing device 192 shown in FIGS. 1 and 2. Accordingly,
the following description refers to FIGS. 1-3, collectively.
[0080] The vision system 300 may comprise a video camera 302
positioned above the rig floor 114 along the support structure 112
and directed or aimed toward a drill pipe 175 (or a stand of drill
pipes 175) such that an intended portion of the drill pipe 175 is
within a field of view 314 of the camera 302 while the drill pipe
175 is supported by the elevator 129 of the top drive 116 and
coupled with another drill pipe 176 extending from the wellbore
102. Such positioning and direction may permit the camera 302 to
capture digital images (or video frames) of an intended portion of
the drill pipe 175 encompassed within the field of view 314 during
drilling and other wellsite operations. The camera 302 may be in
signal communication with the processing device 192 of the control
system 200. A video signal comprising the captured digital images
may be generated by the camera 302 and received by the processing
device 192, which may then process and analyze the digital images
to determine position and changes in the determined position (i.e.,
movement) of a visual indicator 304 located on the drill pipe 175
or of a selected portion of the drill pipe 175. The visual
indicator 304 may be or comprise one or more visual marks, such as
dots, lines, or other two or three dimensional geometric shapes
located at predetermined position(s) along the drill pipe 175. The
visual indicator 304 may be, for example, imprinted (e.g., painted)
onto the drill pipe 175, etched (e.g., carved) into the drill pipe
175, or affixed (e.g., welded) onto the drill pipe 175. The visual
indicator 304 may instead be or comprise a physical or otherwise
distinguishable feature of the drill pipe 175, such as a shoulder
178 or another portion of a tool joint or upset of the drill pipe
175 that can be captured by the camera 302.
[0081] The vision system 300 may be operable to measure or
otherwise determine amount of stretch drill pipes experience during
drilling and other wellsite operations, such as by identifying and
tracking downward movement of the visual indicator 304 between an
initial position 310 and a final position 312, as indicated by
arrow 316. The vision system 300 may track the movement of the
visual indicator 304, for example, by tracking or otherwise
determining the quantity (i.e., number) of video pixels the visual
indicator 304 moves by within the digital image(s) captured by the
camera 302. The determined quantity video pixels may then be
converted into physical measurements by utilizing Equation (1).
? = ( p .times. P ) .times. ( D .times. S h f .times. F h ) ( 1 ) ?
indicates text missing or illegible when filed ##EQU00001##
[0082] where is change in height 306 of the visual indicator 304, p
is the quantity of video pixels between the initial 310 and final
312 positions of the visual indicator 304 on the drill pipe 175, P
is the pixel pitch, D is the distance 308 (i.e., working distance)
of the visual indicator 304 from the video camera 302, S.sub.h is
the height of the image sensor (not shown) of the camera 302, f is
the focal length of the camera 302, and F.sub.h is the frame height
of the digital image(s) captured by the camera 302.
[0083] Equation (1) may be contained within or captured by program
code instructions, which may be executed or otherwise processed by
a processing device, such as the processing device 192, to
determine the physical change in height 306 of the visual indicator
304. Equation parameters, such as the pixel pitch P, the distance D
308 of the visual indicator 304 from the video camera 302, the
height of the image sensor S.sub.h of the camera 302, the focal
length f of the camera 302, and the frame height F.sub.h may be
entered into a memory device (e.g., a memory buffer of the
processing device) to configure Equation (1) prior to utilizing the
vision system 300 during the wellsite operations. During the
wellsite operations, the quantity of pixels p between the initial
and final positions 310, 312 of the visual indicator 304 may be
counted or otherwise determined by the processing device, which may
then utilize such information and the entered equation parameters
to execute the program code instructions comprising Equation (1)
and output the physical change in height 306 of the visual
indicator 304.
Determining Depth of a Free Portion of a Stuck Drill String
[0084] The vision system 300 may be further operable to determine
depth of a free portion (or depth of a stuck portion) of the drill
string 120 stuck within the wellbore 102 based on physical change
in height 306 of a visual indicator 304. For example, the free
point or the point at which the drill string 120 is stuck within
the wellbore 102 may be determined by pulling the drill string 120
to the drill string's neutral weight (i.e., the combined weight of
the traveling block 118, the top drive 116, and the entire drill
string 120). Thereafter, an initial position P.sub.1 312 of the
visual indicator 304 along the drill pipe 175 may be identified or
otherwise determined via the video camera 302. The initial position
P.sub.1 312 of the visual indicator 304 may be located at the top
of a rotary table or the reciprocating slips 161 along the rig
floor 114. An overpull force F.sub.o may then be determined based
on drill pipe weight per unit length W.sub.dp (e.g., pounds per
foot) and applied (i.e., pulled) by the hoisting system without
exceeding the yield strength of the drill string 120. Application
of the overpull force F.sub.o may cause the drill string 120 to
stretch and the visual indicator 304 to move upwardly, as indicated
by arrow 318, to a final or otherwise new position P.sub.2 310. The
initial P.sub.1 312 and final P.sub.2 310 positions may be measured
with respect to a frame edge of the digital image(s) captured by
the camera 302 or a stationary member located within the field of
view 314. The amount of stretch S 306 may be determined by
utilizing Equation (1) listed above and/or Equation (2).
S=abs(P.sub.2P.sub.1) (2)
[0085] After the amount of stretch S 306 is determined, depth of
the free point D.sub.f of the drill string 120 from the rig floor
114 may be determined via Equation (3).
D f = SW d p F o ( 3 ) ##EQU00002##
[0086] Similarly as described above with respect to Equation (1),
Equations (2) and (3) may be contained within or captured by
program code instructions, which may be executed or otherwise
processed by a processing device, such as the processing device
192, to determine the depth of the free point D.sub.f of the drill
string 120. During the wellsite operations, the stretch S 306 of
the drill string 120 may be determined based on the initial
position P.sub.1 312 and final position P.sub.2 310 of the visual
indicator 304 and fed to or otherwise saved onto a memory device
(e.g., a memory buffer of the processing device). Equation
parameters, such as the weight per unit length W.sub.dp and
overpull F.sub.o may also be entered into the memory device. After
Equation (3) is configured with each equation parameter, the
processing device may execute the program code instructions
comprising Equation (3) and output the depth of the free point
D.sub.f of the stuck drill string 120.
Determining Height of a Drill Pipe from a Rig Floor
[0087] An example implementation of apparatus and methods according
to one or more aspects of the present disclosure may be utilized to
measure or otherwise determine height (i.e., position) of the top
of a drill pipe (or stand) from a rig floor after the drill pipe
has been raised. Drill pipes are hollow, steel or aluminum alloy
piping used on drilling rigs. Each drill pipe comprises a box end
(a female threadform), a pin end (male threadform), and a middle
tube extending between the box and pin ends. Typically, drill pipes
are coupled with each other such that the pin end of the drill pipe
is facing or directed downward (i.e., downhole) and the box end is
facing or directed upward (i.e., uphole). Depending on the size of
a drill rig, two or three drill pipes coupled together may form a
drill pipe stand and be handled as a unit for faster drilling
operations. Whether the drill rig is tripping or drilling using
single drill pipes or stands of drill pipe, the box end is directed
upwardly and the pin end is directed downwardly. As described
above, to make up a connection between two drill pipes (or stands)
on the rig floor, the box end may be latched into an elevator and
raised along a mast or derrick to permit a connection to be made
between the pin end of a new drill pipe and the box end of a
previously connected drill pipe.
[0088] FIG. 4 is a schematic view of at least a portion of an
example implementation of a vision system 400 operable to determine
the height of the top of a drill pipe (or stand) from a rig floor
during drilling and other wellsite operations according to one or
more aspects of the present disclosure. The vision system 400 may
be a portion of a well construction system, such as the well
construction system 100 shown in FIG. 1, and may be disposed or
otherwise utilized in association with other portions of the well
construction system 100, including where identified by the same
numerals. The vision system 400 may be a portion of a control
system, such as the control system 200 shown in FIG. 2, and/or a
portion of a CCTV system, such as the CCTV system 216 shown in
FIGS. 1 and 2. Thus, the vision system 400 may be communicatively
connected with a processing device, such as the processing device
192 shown in FIGS. 1 and 2. Accordingly, the following description
refers to FIGS. 1, 2, and 4, collectively.
[0089] The vision system 400 may comprise a video camera 402
directed or aimed toward the elevator top drive 116 such that a box
end 177 of the drill pipe 175 is within the field of view 406 of
the camera 402 when the drill pipe 175 is raised. Such positioning
and direction may permit the camera 402 to capture digital images
(or video frames) of the intended portion of the drill pipe 175
encompassed within the field of view 406 during drilling and other
wellsite operations. The camera 402 may be in signal communication
with the processing device 192 of the control system 200. A video
signal comprising the digital images may be generated by the camera
402 and received by the processing device 192, which may then
process and analyze the digital images captured by the camera
402.
[0090] By knowing the position and orientation of the camera 402
with respect to the rig floor 114, height 418 of the top of the box
end 177 of the drill pipe 175 from the rig floor 114 can be
calculated. The height 418 can also or instead be calculated using
a block position, which may be or comprise the height above the rig
floor 114 of a predetermined reference point located at a known
position on the traveling block 118 or the top drive 116. The block
position may be determined, for example, by measuring the quantity
(i.e., number) of rotations of the drawworks 119, such as with an
encoder, and calculating the length of support line 123 that is
spooled out with the movement of the drawworks 119. The block
position may be at a known distance from the bottom of the elevator
116, such that the distance between the bottom of the elevator 116
and the rig floor 114 is also known.
[0091] The block position may be a height or position of a visual
mark or indicator 404 on the top drive 116 or travelling block 118
and indicated by distance P.sub.b 416 above the rig floor 114.
Distance l.sub.a 410 between upper eyes 152 of the tubular handling
assembly links 127 and the visual indicator 404 may be known or
determined based on manufacturing drawings or by physically
measuring such distance. Similarly, distance l.sub.b 412 between
the upper eyes and lower eyes 154 may be known or determined based
on manufacturer drawings of the elevator links 127 or by physically
measuring such distance. Distance l.sub.c 414 between the lower
eyes 154 and top of the elevator 129 may be known or determined
based on manufacturer drawings of the elevator 129 or by physically
measuring such distance. Distance T.sub.b 418 between the top of
the box end 177 of the drill pipe 175 and the drill floor 114 may
then be determined by utilizing Equation (4).
T.sub.b=(P.sub.b+((l.sub.c+l.sub.d)(l.sub.a+l.sub.b))) (4)
[0092] The visual system 400 may be utilized to determine distance
l.sub.d 420 of the top of the box end 177 of the drill pipe 175
above the elevator 129, which may then permit Equation (4) to be
solved to determine the distance T.sub.b 418. For example, the
vision system 400 may determine the distance l.sub.d 420 by
counting or otherwise determining the quantity of video pixels
between the top of the drill pipe 175 and the top of the elevator
129. The video pixels may be converted into physical measurements
by utilizing Equation (5).
l d = ( P i ) .times. ( D .times. S h f .times. F h ) ( 5 )
##EQU00003##
where P.sub.i is the pixel size (e.g., quantity of pixels) spanning
between the top of the drill pipe 175 and the top of the elevator
129, D is a radial distance 422 (i.e., working distance) of the
drill pipe 175 from the camera 402, S.sub.h is the height of the
image sensor of the camera 402, f is the focal length of the camera
402, and F.sub.h is a frame height of the digital image(s) captured
by the camera 402.
[0093] Although the visual indicator 404 is shown located on a main
body or upper portion of the top drive 116, the visual indicator
404 may be located on other portions of the top drive 116 or on the
travelling block 118. Furthermore, portions of the top drive 116 or
the travelling block 118 may also or instead be utilized as a
visual indicator or reference point for measuring relative
distances. For example, the bottom (edge) of the elevator 116 may
be utilized as a reference point to compute or otherwise determine
the length of the drill pipe 175 above the elevator 116. Also,
instead of utilizing manufacturer drawings of the top drive 116,
the various distances l.sub.a 410, l.sub.b 412, and l.sub.c 414 may
be determined by the vision system 400 by counting or otherwise
determining the quantity of video pixels between the features
defining such distances.
[0094] After the distance T.sub.b 418 of the top of the box end 177
of the drill pipe 175 from the rig floor 114 can be continually
tracked such that the drilling or tripping of the drill pipe 175
(or a stand) is completed, resulting in an intended (e.g.,
constant) stick up distance 424 from the rig floor 114. The stick
up distance 424 may be governed by the height of tongs or the
height of the torqueing portions 153 of the iron roughneck 151 such
that the connection can be made between the drill pipe 176 that was
just drilled or tripped and the new drill pipe 175 that was lifted
by the hoisting system. The control system 200 of the well
construction system 100 may be utilized to control movement of the
top drive 116 during drilling and tripping operations such that the
stick up distance 424 from the rig floor 114 is substantially
constant and repeatable. Another video camera 408 may also be
directed at the box end 177 of the drill pipe 176 at the rig floor
114 to measure the stick up distance 424 in a similar manner at the
camera 402 is utilized to measure the distance T.sub.b 418 of the
drill pipe 175.
[0095] Similarly as described above with respect to Equations (1)
and (2), Equations (4) and (5) may be contained within or captured
by program code instructions, which may be executed or otherwise
processed by a processing device, such as the processing device
192. During the wellsite operations Equation (5) may be utilized to
determine the distance l.sub.d 420 based on the previously entered
equation parameters radial distance D 422, the height of the image
sensor S.sub.h, the focal length f, and the frame height F.sub.h,
and the determined pixel size P.sub.i. The determined distance
l.sub.d 420 may be saved onto a memory device (e.g., a memory
buffer of the processing device) and utilized along with the
previously entered distances l.sub.a 410, l.sub.b 412, l.sub.c 414,
and T.sub.b 418 to determine the distance T.sub.b 418.
[0096] When the well construction system 100 causes the stick up
distance 424 to be maintained at a constant known level during
drilling or tripping operations, the length 426 of each drill pipe
175 going into the drill string 120 can then be determined by
subtracting the known stick up distance 424 from the previously
determined distance T.sub.b 418 of the top of the drill pipe 175
from the rig floor 114. Furthermore, although the vision systems
300 and 400 are shown and described above being utilized during
drilling and drill pipe tripping operations, the vision systems 300
and 400 and operations described herein may be utilized to measure
lengths and distances not just of drill pipes 175 and stands of
drill pipes 175, but also to measure lengths and distances of other
tubulars, such as casing joints, that may be tripped downhole.
Determining Casing Alignment During Casing Running Operations
[0097] After a wellbore is drilled, a casing string may be ran into
the wellbore and cemented therein to protect the wellbore from
damage over time. Each casing joint (tubular) is threaded, such as
may facilitate connection between adjacent casing joints to
assemble the casing string. During casing running operations, new
casing joints are coupled with the casing string that is assembled
in the wellbore. The top of the casing string may be locked in
position or engaged by a set of slips to prevent the casing string
from falling into the wellbore. To make up a connection on the rig
floor, the lower end of the casing joint suspended above the rig
floor by a hoisting system is aligned with the upper end of the
casing string projecting from the wellbore and then rotated with
tongs. Such alignment may be performed manually or with a casing
alignment tool (or a casing running tool). Each alignment has to be
properly performed, as misalignment can cause cross threading that
can damage the threads and prevent a fluid seal from forming
between the casing joints. High pressure and heat within a well may
cause an improperly formed fluid seal to lose integrity or
fail.
[0098] FIG. 5 is a schematic view of at least a portion of an
example implementation of a vision system 500 operable to monitor
or otherwise determine alignment of a new casing joint 502 with
respect to a casing joint 504 previously coupled with the casing
string and extending from a wellbore during casing running
operations according to one or more aspects of the present
disclosure. Although the vision system 500 is shown utilized to
monitor alignment of casing joints, it is to be understood that the
vision system 500 may be utilized to monitor alignment of other
tubulars, such as drill pipe, drill collars, pup joints, and
production tubing, among other examples.
[0099] The vision system 500 may be a portion of a well
construction system, such as the well construction system 100 shown
in FIG. 1, and may be disposed or otherwise utilized in association
with other portions of the well construction system 100, including
where identified by the same numerals. The vision system 500 may be
a portion of a control system, such as the control system 200 shown
in FIG. 2, and/or a portion of a CCTV system, such as the CCTV
system 216 shown in FIGS. 1 and 2. Thus, the vision system 500 may
be communicatively connected with a processing device, such as the
processing device 192 shown in FIGS. 1 and 2. Accordingly, the
following description refers to FIGS. 1, 2, and 5,
collectively.
[0100] The vision system 500 may comprise video cameras 506, 508
directed or aimed toward the casing joints 502, 504 to capture the
pin and box ends of the casing joints 502, 504, respectively,
within corresponding fields of view 510, 512 of the cameras 506,
508 while the upper (new) casing joint 502 approaches the lower
(previously connected) casing joint 504. The cameras 506, 508 may
be positioned or directed along different (e.g., perpendicular)
planes 514, 516 such that the corresponding fields of view 510, 512
extend along different planes. Such positioning and direction may
permit the cameras 506, 508 to capture digital images (or video
frames) of the pin and box ends of the casing joints 502, 504
encompassed within the fields of view 510, 512 from different
(e.g., perpendicular) angles during casing running operations. The
cameras 506, 508 may be in signal communication with the processing
device 192 of the control system 200. A video signal comprising the
captured digital images may be generated by each camera 506, 508
and received by the processing device 192, which may then process
and analyze the digital images. For example, the vision system 500
may be operable to process and analyze the digital images to
determine presence and/or amount of misalignment between the pin
end of the upper casing joint 502 and the box end of the lower
casing joint 504. The vision system 500 may be operable to detect
relative positions (e.g., relative distances) of the casing joints
502, 504, such as by detecting relative positions of edge(s) 522 of
the pin end of the casing joint 502 with respect to edge(s) 524 of
the box end of the casing joint 504, and determining if the edges
522, 524 are substantially aligned with each other along the
horizontal axes within the digital images captured by the cameras
506, 508 to permit proper threaded engagement between the casing
joints 502, 504. The edges 522, 524 of the casing joints 502, 504
may be or comprise opposing edges of profiles of the casing joints
502, 504 in the digital images.
[0101] Horizontal distances between the edge(s) 522 of the pin end
of the upper casing joint 502 and the edge(s) 524 of the box end of
the lower casing joint 504 may be determined, for example, by
tracking quantity of pixels spanning between the edges 522, 524 of
the pin and box ends of the casing joints 502, 504 along
corresponding horizontal axes in the digital images captured by the
cameras 506, 508. The tracked quantity of pixels for each digital
image may then be converted to physical dimensions to determine
actual horizontal distances between edges 522, 524 of the casing
joints 502, 504, such as by utilizing one or more of Equations (1)
and (5). The vision system 500 may also measure amount of
misalignment, such as based on video pixel tracking. The
misalignment measurements performed by the vision system 500 may be
utilized to automatically initiate a visual and/or audio alarm when
misalignment exists between the pin end of the upper casing joint
502 and the box end of the lower casing joint 504 or if the
determined amount of misalignment exceeds a predetermined
threshold. The misalignment measurements performed by the vision
system 500 may also or instead be utilized as feedback to the
control system 200 to automatically and in real-time cause one or
more portions of the RC system 211 to adjust the position of the
casing joint 502 to substantially align the casing joint 502 with
the casing joint 504.
Determining Position of the Travelling Block
[0102] A crown saving system may be utilized to prevent the
traveling block from hitting the crown block during tubular raising
operations. The crown saving system may include block position
control via the drill rig control system and may utilize proximity
sensors on the drill rig support structure (e.g., mast) and/or
mechanical toggle valves on the drawworks. The drill rig control
system may receive block position measurements computed from an
encoder on the shaft of the drawworks to determine position of the
traveling block with respect to the crown block. Use of the encoder
and/or proximity sensors permits the slowing down of the traveling
block before it comes to a complete stop. Use of the mechanical
toggle, however, causes sudden locking down of mechanical brakes
via pneumatic cylinders.
[0103] FIGS. 6 and 7 are schematic views of at least a portion of
example implementations of vision systems 600, 700 operable to
monitor or otherwise determine and control vertical position of a
traveling block with respect to a crown block during tubular
lifting and/or lowering operation according to one or more aspects
of the present disclosure. The vision systems 600, 700 may each be
a portion of a well construction system, such as the well
construction system 100 shown in FIG. 1, and disposed or otherwise
utilized in association with other portions of the well
construction system 100, including where identified by the same
numerals. The vision systems 600, 700 may each be a portion of a
control system, such as the control system 200 shown in FIG. 2,
and/or a CCTV system, such as the CCTV system 216 shown in FIGS. 1
and 2. Thus, the vision systems 600, 700 may each be
communicatively connected with a processing device, such as the
processing device 192 shown in FIGS. 1 and 2. Accordingly, the
following description refers to FIGS. 1, 2, 6, and 7,
collectively.
[0104] The vision system 600 may comprise a video camera 602
directed toward the crown block 115 such that at least a portion of
the crown block 115 is within the field of view 606 of the camera
602 while the traveling block 118 and the top drive 116 are moved
vertically, such as during drilling or other wellsite operations.
Such positioning and direction may permit the camera 602 to capture
digital images (or video frames) of the crown block 115 and the
travelling block 118 encompassed within the field of view 606 when
the traveling block 118 is near the crown block 115. The camera 602
may be in signal communication with the processing device 192 of
the control system 200. A video signal comprising the captured
digital images may be generated by the camera 602 and received by
the processing device 192, which may then process and analyze the
digital images to determine relative position between the crown
block 115 and the travelling block 118 and prevent the traveling
block 118 from hitting the crown block 115 when the traveling block
118 moves upward, as indicated by arrow 604. Such operation may be
achieved by setting one or multiple threshold distances 608 of the
travelling block 118 from the crown block 115, which when crossed
by the traveling block 118, may cause a controlled movement or a
complete stop of the traveling block 118.
[0105] Vertical distance between the crown block 115 and the
traveling block 118 may be determined, for example, by tracking
quantity of pixels spanning between the crown block 115 and the
traveling block 118 in the digital images while the traveling block
118 is moving. The determined quantity of pixels in each digital
image may then be converted to physical dimensions to determine
actual vertical distances between the crown block 115 and the
traveling block 118, such as by utilizing one or more of Equations
(1) and (5). The vertical distance measurements performed by the
vision system 600 may be utilized as real-time feedback to the
control system 200 to automatically initiate slowdown or stop
operations of the traveling block 118 when the traveling block 118
is within the threshold distance 608 from the crown block 115. The
vision system 600 may implement a machine learning model to train
the vision system 600 to identify the top of the traveling block or
the top drive 116 (or another portion of the traveling block 118 or
top drive 116) against which the position threshold 608 can be
set.
[0106] The vision system 700 may comprise a video camera 702
directed toward the drawworks 119 such that a drum 139 of the
drawworks 119 is within the field of view 706 of the camera 702
while the drawworks 119 winds and unwinds the support line 123
during drilling or other wellsite operations. Such positioning and
direction may permit the camera 702 to capture digital images (or
video frames) of the drum 139 and the support line 123 wrapped
around the drum 139 encompassed within the field of view 706 during
operations. The camera 702 may be in signal communication with the
processing device 192 of the control system 200. A video signal
comprising the capture digital images may be generated by the
camera 702 and received by the processing device 192, which may
then process and analyze the digital images to monitor or otherwise
determine the amount of support line 123 wrapped on the drum
139.
[0107] The support line 123 may be anchored on one side of the drum
139 and each loop (i.e., wrap) of the support line 123 moves
sequentially to the opposite side of the drum 139. At the end of
one layer of the support line 123, direction of wrapping changes to
start forming another layer of the support line 123. A threshold of
height 708 of completed support line layers on the drum 139 and/or
a threshold of width 710 of an unfinished layer of the support line
123 being formed on the drum 139 may be set to prevent the
traveling block 118 from hitting the crown block 115 when the
traveling block 118 moves upward 604. Either through calculations,
physically checking, and/or machine learning, the threshold height
708 and width 710 of the support line 123 can be set to or
otherwise associated with a safety threshold distance (such as the
threshold distance 608 shown in FIG. 6) between the traveling block
118 and the crown block 115. Machine learning may be utilized to
train to identify, for example, the support line 123 and keep track
of the quantity of loops and layers of the support line 123 around
the drum 139 to determine the length of the support line 123
wrapped around the drum 139, which may be utilized to determine the
distance between the traveling block 118 and the crown block 115.
The support line 123 may be or comprise a cable or wire rope
comprising strands of metal wire twisted (laid) into a helix. The
support line 123 can be identified by identifying one or more of
its features, such as the quantity and pattern of wire strands,
identifying construction (e.g., lay) of the support line 123,
and/or by identifying the contour of the support line 123. Thus,
when a threshold 708 is triggered, the vision system 700 may then
cause a controlled movement or complete stop of the traveling block
118.
[0108] The height 708 and width 710 of the support line 123 wrapped
around the drum 139 may be determined, for example, by tracking
quantity of pixels spanning the height 708 and the width 710 in the
digital images while the drum 139 rotates. The determined quantity
of pixels in each digital image may then be converted to physical
dimensions to determine the amount of support line 123 on the drum
139 and, thus, the actual vertical distances between the crown
block 115 and the traveling block 118, such as by utilizing one or
more of Equations (1) and (5). The measurements performed by the
vision system 700 may be utilized as real-time feedback to the
control system 200 to automatically initiate slowdown or stop
operations of the traveling block 118 when the traveling block 118
is within the threshold distance from the crown block 115.
Determining Orientation of Tubulars During Make-Up Operations
[0109] During some well construction operations, such as
directional drilling with a downhole motor, a bent sub or housing
of such motor may be used for steering (i.e., guiding) a drill bit
in a predetermined (i.e., planned) azimuthal direction. The
downhole motor may be steered in an intended azimuthal direction,
for example, by controlling azimuthal (i.e., angular) orientation
of an obtuse angle of the bent sub or housing with respect to the
high side (i.e., side of the wellbore opposite to the direction of
gravity) of the wellbore. The azimuthal orientation of the bent sub
or housing may be set at the wellsite surface before subsequent
downhole tools are run downhole. The azimuthal orientation may be
maintained during make up operations, for example, by arresting or
otherwise preventing rotation of the drill string when it is run
downhole. Azimuthal orientation between the bent sub or housing and
a downhole tool may be monitored or otherwise tracked, for example,
if a magnetic sensor for measuring the azimuthal orientation of the
bent sub or housing is located close to magnetic material (e.g.,
casing material) that interferes with measurements.
[0110] FIG. 8 is a schematic view of at least a portion of an
example implementation of a vision system 800 operable to determine
(e.g., monitor, track) azimuthal orientation of downhole tubulars
while downhole by determining the azimuthal orientation of the
downhole tubulars at the wellsite surface while the downhole
tubulars are run into the wellbore. The vision system 800 may be a
portion of a well construction system, such as the well
construction system 100 shown in FIG. 1, and may be disposed or
otherwise utilized in association with other portions of the well
construction system 100, including where identified by the same
numerals. The vision system 800 may be a portion of a control
system, such as the control system 200 shown in FIG. 2, and/or a
portion of a CCTV system, such as the CCTV system 216 shown in
FIGS. 1 and 2. Thus, the vision system 800 may be communicatively
connected with a processing device, such as the processing device
192 shown in FIGS. 1 and 2. Accordingly, the following description
refers to FIGS. 1, 2, and 8, collectively.
[0111] The vision system 800 may comprise video cameras 802, 804,
each directed or aimed toward a corresponding downhole tubular 806,
808 (e.g., mud motor, downhole tools, drill pipe, casing joints,
etc.) being made up just above the rig floor 114 and deployed
within the wellbore. Each downhole tubular 806, 808 that is made up
and conveyed downhole, may be marked by, carry, or otherwise
comprise one or more geometric patterns 810, 812 imparted onto an
outer surface of the downhole tubular 806, 808. The lower camera
804 may be directed toward the lower tubular 808 to capture the
geometric pattern 812 of the lower tubular 808 within the field of
view 816 of the lower camera 804 while the lower tubular 808 is
locked in position and suspended within the wellbore via the
reciprocating slips 161. The upper camera 802 may be directed
toward the upper tubular 806 to capture the geometric pattern 810
of the upper tubular 806 within the field of view 814 of the upper
camera 802 while the upper tubular is being rotated, as indicated
by arrow 815, to make up a connection with the lower tubular 808.
Each camera 802, 804 may capture digital images (or video frames)
of the corresponding downhole tubular 806, 808 and geometric
pattern 810, 812 encompassed within its field of view 814, 816. The
cameras 802, 804 may be in signal communication with the processing
device 192 of the control system 200. Each camera 802, 804 may be
further operable to generate a corresponding video signal
comprising the captured digital images, which may be received,
processed, and analyzed by the processing device 192 to determine
the azimuthal orientation of each downhole tubular 806, 808 based
on the geometric pattern 810, 812 captured in the digital
images.
[0112] FIG. 9 is a side view of a box end 826 of a downhole tubular
824 (e.g., downhole tool, drill pipe, casing joint, etc.)
comprising an example implementation of a geometric pattern 820
according to one or more aspects of the present disclosure. FIG. 10
is a perspective view of a portion of the downhole tubular 824
shown in FIG. 9 comprising the geometric pattern 820. FIG. 11 is a
perspective view of the geometric pattern 820 shown in FIG. 10, but
shown without the tubular 824 for clarity and ease of
understanding. FIG. 12 is a side view of a pin end 828 of the
downhole tubular 824 comprising an example implementation of a
geometric pattern 822 according to one or more aspects of the
present disclosure. FIG. 13 is a perspective view of a portion of
the downhole tubular 824 shown in FIG. 12 comprising the geometric
pattern 822. FIG. 14 is a perspective view of the geometric pattern
822 shown in FIG. 13, but shown without the tubular 824 for clarity
and ease of understanding. The following description refers to
FIGS. 1, 2, and 8-14, collectively.
[0113] The geometric pattern 820 may be imparted onto an outer
surface of the tubular 824 near or adjacent the box end 826 of the
tubular 824 such that the camera 804 can capture the geometric
pattern 820 within its field of view 816 while the tubular 824 is
locked in position and suspended within the wellbore 102. The
geometric pattern 822 may be imparted onto the outer surface of the
tubular 824 near or adjacent the pin end 828 of the tubular 824
such that the camera 802 can capture the geometric pattern 822
within its field of view 814 while the tubular 824 is being rotated
to make up a connection with a previously connected tubular
suspended within the wellbore. The geometric pattern 820 may be
located at a close distance to the box end 826, such that the
geometric pattern 820 is above the rig floor 114 and can be viewed
by the camera 804 when the tubular 824 is suspended within the
wellbore 102 via the slips 161. The geometric pattern 822 may be
located at a predetermined distance 830 from the pin end 828, such
as to permit tongs or another mechanical wrench to rotate the
tubular 824 without obstructing the camera's 802 view of the
geometric pattern 822.
[0114] Each geometric pattern 820, 822 may wrap or otherwise extend
around the tubular 824. Each geometric pattern 820, 822 may be or
comprise a surface finish or a plurality of two or three
dimensional visual marks (e.g., dots, lines) arranged in a
predetermined geometric pattern or shape. Each geometric pattern
820, 822 may be, for example, imprinted (e.g., painted) onto the
outer surface of the tubular 824, etched (e.g., carved) into the
outer surface of the tubular 824, or affixed (e.g., welded) onto
the outer surface of the tubular 824. The surface finish forming
the geometric patterns 820, 822 may be or comprise surface polish
having a high reflective co-efficient. However, one of the
geometric patterns 820, 822 may comprise a higher reflective
coefficient and the other of the geometric patterns 820, 822 may
comprise a lower reflective coefficient. The difference in the
surface finish may cause difference in coefficient of friction or
adhesion of mud that may be perceived or identified by the cameras
802, 804 when the tubular 824 is covered in mud. The geometric
pattern 820 associated with the box end 826 of the tubular 824 may
be or comprise a different geometric shape than the geometric
pattern 822 associated with the pin end 826 of the tubular 824. The
geometric patterns 820, 822 may be or comprise the same, but
reversed or inverted geometric shapes. Example implementation of
the geometric patterns 820, 822 may be or comprise a triangle
(e.g., a right triangle, an isosceles triangle, etc.) wrapped or
extending around the outer surface of the tubular 824. However, the
geometric patterns 820, 822 may be or comprise other geometric
shapes having a changing vertical dimension (e.g., height, width,
length, etc.) while the tubular 824 rotates.
[0115] The vision system 800 may be operable to capture and process
digital images of the geometric patterns 820, 822 to track (i.e.,
monitor) or otherwise determine azimuthal orientations of downhole
tubulars 824 by determining azimuthal orientations of the geometric
patterns 820, 822 while the tubulars 824 are made up at the rig
floor 114. For example, the vision system 800 may be operable to
determine vertical lengths 832, 834 of the geometric patterns 820,
822 along one or both edges 844, 846 of each tubular 824 being made
up to determine the azimuthal orientation of each geometric pattern
820, 822 and, thus, the azimuthal orientation of each tubular 824
being made up. The edges 844, 846 of the tubular 824 may be or
comprise opposing edges of the profile of the tubular 824 in the
digital images captured by the cameras 802, 804. Each edge 844, 846
may be associated with a corresponding edge line 841, 843 extending
between a central axis 845 (i.e., axis of rotation) of the tubular
824 and the corresponding edge 844, 846. The lengths 832, 834 of
the geometric patterns 820, 822 along the edges 844, 846 of the
tubular 824 change by a known amount while the tubular 824 is
rotated. Thus, by determining the lengths 832, 834 of the geometric
patterns 820, 822, the azimuthal orientation of the geometric
patterns 820, 822 and, thus, of the tubulars 824 can be determined.
The lengths 832, 834 of the geometric patterns 820, 822 along the
edges 844, 846 of the tubulars 824 may be determined, for example,
by tracking the quantity of vertical pixels spanning across the
geometric patterns 820, 822 along the edges 844, 846 of the
tubulars 824 in the digital images captured by the cameras 802,
804. The determined quantity of pixels spanning across the
geometric patterns 820, 822 along the edges 844, 846 of the
tubulars 824 may then be converted to physical lengths.
[0116] Azimuthal orientation of the tubular 824 may be, comprise,
or be based on the azimuthal orientation of each edge line 841, 843
with respect to a reference point 850 or line 851 of the geometric
pattern 820, which may be determined by utilizing equations (6) and
(7).
.theta. 1 = l 1 .times. 2 tan ( .varies. ) .times. D ( 6 )
##EQU00004##
where l.sub.1 is the length 832 of the geometric pattern 820 along
the left edge 844 of the tubular 824, .varies. is the angle 836 of
the geometric pattern edge, D is the diameter 838 of the tubular
824, and .theta..sub.1 is the azimuthal orientation 840 of the left
edge line 841 with respect to the reference point 850 or line 851
of the geometric pattern 820 at the box end 826 of the tubular
824.
.theta. 2 = l 2 .times. 2 tan ( .varies. ) .times. D ( 7 )
##EQU00005##
where l.sub.2 is the length 834 of the geometric pattern 820 along
the right edge 846 of the tubular 824, .varies. is the angle 836 of
the geometric pattern edge, D is the diameter 838 of the tubular,
and .theta..sub.2 is the azimuthal orientation 842 of the right
edge line 843 with respect to the reference point 850 or line 851
of the geometric pattern 820 at the box end of the tubular 824.
Azimuthal orientation O.sub.pb of the box end 826 (pipe-box end) of
the tubular 824 may be or comprise the azimuthal orientation
.theta..sub.1 840 or the azimuthal orientation .theta..sub.2 842,
as indicated by Equation (8).
O.sub.pb=(.theta..sub.1;.theta..sub.2) (8)
[0117] Equations (6) and (7) may also be utilized to determine
azimuthal orientations .theta..sub.3 852 and .theta..sub.4 854 of
the left and right edge lines 841, 843 with respect to the
reference point 850 or line 851 of the geometric pattern 822 at the
pin end 828 of the tubular 824. Azimuthal orientation O.sub.pp of
the pin end 828 (pipe-pin end) of the tubular 824 may be or
comprise the azimuthal orientation .theta..sub.3 852 and the
azimuthal orientation .theta..sub.4 854, as indicated by Equation
(9).
O.sub.pp=(.theta..sub.3;.theta..sub.4) (9)
[0118] Azimuthal orientation offset O.sub.OL between the reference
point 850 or line 851 of the geometric pattern 820 at the box end
826 of the tubular 824 and the reference point 850 or line 851 of
the geometric pattern 822 at the pin end 828 of the tubular 824
measured with respect to the left edge line 841 of the tubular 824
may be determined by utilizing equation (10).
O.sub.OL=(.theta..sub.1.theta..sub.3) (10)
[0119] The azimuthal orientation offset O.sub.OR between the
reference point 850 or line 851 of the geometric pattern 820 at the
box end 826 of the tubular 824 and the reference point 850 or line
851 of the geometric pattern 822 at the pin end 828 of the tubular
824 measured with respect to the right edge line 843 of the tubular
824 may be determined by utilizing equation (11).
O.sub.R=(.theta..sub.2.theta..sub.4) (11)
[0120] FIG. 15 is another schematic view of at least a portion of
the vision system 800 shown in FIG. 8 and operable to track,
monitor, or otherwise determine azimuthal orientations (O.sub.pb
and/or O.sub.pp) of downhole tubulars while downhole by monitoring
the azimuthal orientation of the downhole tubulars at the wellsite
surface while the downhole tubulars are run into the wellbore 102.
The following description refers to FIGS. 8-15, collectively.
[0121] During tubular string assembly operations (e.g., drilling
operations, drill pipe running operations, casing running
operations, etc.) current (i.e., present) azimuthal orientation 871
of a first tubular 861 (e.g., mud motor, a BHA sub, casing joint,
etc.) of a tubular string 870 (e.g., drilling string, casing
string, etc.) may be determined based on the azimuthal orientation
of a geometric pattern (e.g., geometric pattern 820, 822) (not
shown in FIG. 15) on the first tubular 861 with respect to left or
right edge of the first tubular 861 while the first tubular 861 is
inserted into the wellbore 102. Azimuthal orientations 872-876 of
each subsequent tubular 862-866 coupled above the first (e.g.,
lowermost) tubular 861 may also be determined based on azimuthal
orientations of geometric patterns on the subsequent tubulars
862-866 with respect to left or right edges of the subsequent
tubulars 862-866 while each subsequent tubular 862-866 is coupled
with a previously coupled tubular. By tracking the azimuthal
orientation of each subsequent tubular 862-866, the current
azimuthal orientation of the first tubular 861 and/or another
previously coupled tubular (e.g., sensor sub) with respect to a
newly coupled tubular 866 or otherwise with respect to another
reference (e.g., rig floor) can be tracked or otherwise
determined.
[0122] The azimuthal orientation of a selected tubular of the
tubular string 870 with respect to left or right edge (or another
reference point) of the newly coupled tubular 866 may be determined
by aggregating or totaling the azimuthal orientations of the
selected tubular and the tubulars coupled above the selected
tubular. If an azimuthal orientation offset (e.g., O.sub.OL or
O.sub.OR) exists between the box end 826 geometric pattern and the
pin end 826 geometric pattern of one or more of the tubulars
862-866, then such offset may be aggregated with the azimuthal
orientations 872-876 of the tubulars 862-866 to determine the
current azimuthal orientation of the first tubular 861 and/or
another selected tubular.
[0123] Azimuthal orientation of each new tubular (tubular 866 in
FIG. 15) being coupled with the previously coupled tubular (tubular
865 in FIG. 15) during tubular string assembly operations may be
tracked via the upper camera 802 by tracking the orientation of the
lower geometric pattern located adjacent the pin end of the new
tubular. Although the tool string 870 is locked in position by
reciprocating slips or another device, during tubular string
assembly operations the tool string 870 may slip or otherwise
slightly rotate, such as when the new tubular is tightened against
the previously coupled tubular and/or when the tubular string 870
(including the coupled new tubular) is moved downhole. Accordingly,
azimuthal orientation of each previously coupled tubular during
tubular string assembly operations may be tracked or confirmed via
the lower camera 804 by tracking the orientation of the upper
geometric pattern located adjacent the box end of the previously
coupled tubular.
[0124] Similarly as described above with respect to Equations
(1)-(5), Equations (6)-(11) may be contained within or captured by
program code instructions, which may be executed or otherwise
processed by a processing device, such as the processing device
192. During the wellsite operations, Equations (6) and (7) may be
utilized to determine the azimuthal orientations .theta..sub.1 840,
.theta..sub.2 842, .theta..sub.3 852, .theta..sub.4 854 based on
the previously entered equation parameters, such as the angle
.varies. 836 of the geometric pattern edge, the diameter D 838 of
the tubular 880, and the measured lengths l.sub.1 832 and l.sub.2
834 of the geometric patterns 820, 822. The determined azimuthal
orientations .theta..sub.1 840, .theta..sub.2 842, .theta..sub.3
852, .theta..sub.4 854 for each tubular connected to a tubular
string may be saved onto a memory device (e.g., a memory buffer of
the processing device). The determined azimuthal orientations may
then be aggregated to determine the current orientation of the
first 861 (i.e., bottom) or another 862-865 tubular along the
tubular string 870 with respect to the last (i.e., uppermost)
tubular 866. Equations (10) and (11) may be utilized to determine
the azimuthal orientation offsets O.sub.OL and O.sub.OL.
Determining Tool Face Offset
[0125] Tool face offset is the azimuthal (i.e., angular)
orientation relationship between a bent sub or housing of a
downhole motor and a directional sensor that may be housed within a
downhole sub (e.g., tool), such as a universal bottom hole
orienting sub (UBHO) or a drill collar. The drill collar may be
that of an MWD mud pulser tool. The tool face offset is measured,
for example, between a reference point on the bent housing and on
the UBHO or MWD tool, which contains the directional sensor at a
known azimuthal orientation with respect to the reference point.
The tool face offset may be measured during make-up of a BHA at a
wellsite surface, such that the azimuthal orientation of the bent
housing of the motor can be determined while downhole when the
orientation of the directional sensor is sent to the wellsite
surface. The tool face offset can be different for each BHA as the
quantity of collar connections, threading tolerance, and torque on
each of the connections between the bent housing and the UBHO or
MWD tool can be different for each job. Hence, knowing the tool
face offset helps to determine the azimuthal orientation of the
downhole motor with respect to the high side of a wellbore during
directional drilling.
[0126] One or more geometric patterns, such as the geometric
patterns 820, 822 described above and shown in FIGS. 9-14, may be
imparted onto or otherwise utilized in association with each
tubular of a BHA to facilitate tracking of the tool face offset
while the BHA is assembled at the wellsite surface. FIG. 16 is a
perspective view of at least a portion of a downhole tubular 880 of
a BHA comprising the geometric pattern 820 described above and
shown in FIGS. 9-11 according to one or more aspects of the present
disclosure. The geometric pattern 820 may be imparted at the box
end of the tubular 880. If the tubular 880 comprises a pin end, a
geometric pattern (not shown in FIG. 16), such as the geometric
pattern 822, may also be imparted at the pin end of the tubular
880. The tubular 880 may be or comprise, for example, a downhole
motor, an MWD tool, and/or a UBHO.
[0127] As shown in FIG. 16, the geometric pattern 820 on the
tubular 880 may be oriented such that the reference point 850 or
line 851 of the geometric pattern 820 coincides with, intercepts,
or lies along the same vertical line as a reference point 882 of
the tubular 880. However, the reference point 850 or line 851 of
the geometric pattern 820 may be azimuthally offset from the
reference point 882 of the tubular 880 by a known angle, such that
azimuthal orientation of the reference point 850 or line 851 is
indicative of the azimuthal orientation of the reference point 882.
Such angular relationship can be established with the vision system
800 or the angular relationship may be physically measured and
considered in the calculations. If the tubular 880 is or comprises
a motor bent sub, the reference point 882 may be or comprise a
scribe line indicative of the bent sub tool face. If the tubular
880 is or comprises an MWD tool, the reference point 882 may be or
comprise location of a directional sensor of the MWD tool. If the
tubular 880 is or comprises a UBHO, the reference point 880 may be
or comprise location of a key of the UBHO sleeve.
[0128] For a BHA comprising a downhole motor and an MWD tool, the
tool face offset (i.e., angular difference) between the reference
point 882 of the motor bent sub and the reference point 882 of the
MWD tool and/or the UBHO may be determined by utilizing Equations
(6) and (7) as described above. For example, Equation (6) may be
utilized to determine the azimuthal orientation .theta..sub.1 840
of the left edge line 841 with respect to the reference point 850
or line 851 of the geometric pattern 820 and, thus, the reference
point 882 (e.g., scribe line), at the box end of the motor.
Equation (7) may be utilized to determine the azimuthal orientation
.theta..sub.2 842 of the right edge line 843 with respect to the
reference point 850 or line 851 of the geometric pattern 820 and,
thus, the reference point 882, at the box end of the motor.
Azimuthal orientation O.sub.mb of the box end (motor-box end) of
the motor may be or comprise the azimuthal orientation
.theta..sub.1 840 or the azimuthal orientation .theta..sub.2 842,
as indicated by Equation (12).
O.sub.mb=(.theta..sub.1;.theta..sub.2) (12)
[0129] The MDW tool and/or the UBHO may further comprise a
geometric pattern, such as the geometric pattern 822, shown in
FIGS. 12-14, which may be imparted on the pin end of the MDW tool
and/or the UBHO. The geometric pattern 822 may be oriented such
that the reference point 850 or line 851 of the geometric pattern
822 coincides with, intercepts, or lies along the same vertical
line as a reference point 882 of the MDW tool and/or the UBHO. For
example, the reference point 882 may be or comprise location of a
directional sensor of the MWD tool. The reference point may also or
instead be or comprise location of a key of the UBHO sleeve.
[0130] Equations (6) and (7) may also be utilized to determine
azimuthal orientations .theta..sub.3 852 and .theta..sub.4 854 of
the left and right edge lines 841, 843 with respect to the
reference point 850 or line 851 of the geometric pattern 822 and,
thus, the reference point 882 (e.g., location of a directional
sensor), at the pin end of the MWD (or the UBHO). Azimuthal
orientation O.sub.pp of the pin end (MWD-pin end) of the MWD may be
or comprise the azimuthal orientation .theta..sub.3 852 and the
azimuthal orientation .theta..sub.4 854, as indicated by Equation
(13).
O.sub.mp=(.theta..sub.3;.theta..sub.4) (13)
[0131] Azimuthal orientation offset O.sub.OL between the reference
point 882 (e.g., the scribe line) at the box end of the motor and
the reference point 882 (e.g., the location of the directional
sensor) at the pin end of the MWD measured with respect to the left
edge line 841 motor-MWD connection may be determined by utilizing
equation (10). The azimuthal orientation offset O.sub.OR between
the reference point 882 (e.g., the scribe line) at the box end of
the motor and the reference point 882 (e.g., the location of the
directional sensor) at the pin end of the MWD measured with respect
to the right edge line 843 of the motor-MWD connection may be
determined by utilizing equation (11). One or both azimuthal
orientation offsets O.sub.OL and O.sub.OR may be calculated to
determine the tool face offset. The tool face offset may be
measured in the clockwise direction from the MWD reference point
882 (e.g., the location of the directional sensor) to the motor
reference point 882 (e.g., scribe line) while looking downhole.
[0132] Equations (6)-(13) may be contained within or captured by
program code instructions, which may be executed or otherwise
processed by a processing device, such as the processing device
192. During the wellsite operations, Equations (6) and (7) may be
utilized to determine the azimuthal orientations .theta..sub.1 840,
.theta..sub.2 842, .theta..sub.3 852, .theta..sub.4 854 based on
the previously entered equation parameters, such as the angle
.varies. 836 of the geometric pattern edge, the diameter D 838 of
the downhole motor, the MWD tool, and/or the UBHO, and the measured
lengths l.sub.1 832 and l.sub.2 834 of the geometric patterns 820,
822. The determined azimuthal orientations .theta..sub.1 840,
.theta..sub.2 842, .theta..sub.3 852, .theta..sub.4 854 may be
saved onto a memory device (e.g., a memory buffer of the processing
device). The determined azimuthal orientations of subsequent
tubulars may be tracked and aggregated to determine the orientation
of the downhole motor, the MWD tool, and/or the UBHO with respect
to the last (i.e., uppermost) tubular. Equations (10) and (11) may
then be utilized to determine the azimuthal orientation offsets
O.sub.OL and O.sub.OL.
[0133] In the above example, it has been assumed that the MWD tool
or the UBHO is directly coupled to the motor bent sub. However, if
other tubulars (e.g., collars) are coupled there between, the
angular relationship at each intermediate connection will have to
be taken into account during the computation of the tool face
offset. Moreover, the angular relationship between each connection
from the BHA to a tubular at the wellsite surface can be tracked,
such as to facilitate control of the orientation of the motor, for
example, when a downhole directional sensor is unable to provide
measurement in areas of magnetic interference.
[0134] If no geometric patterns are imparted on the tubulars 880 of
the BHA, the vision system 800 may be configured or otherwise
operable to detect the motor reference line and the MWD/UBHO
reference points. After the BHA has been made up and the motor
reference line has been detected, the BHA would may be lowered into
the wellbore while not being rotated. When the MWD/UBHO reference
point reaches the same level as that of the motor reference line
previously detected, the BHA can be rotated such that the MWD/UBHO
reference point coincides with the previous position of the motor
reference line. The amount of rotation of the BHA will be
indicative of the tool face offset.
Determining Grading of a Drill Bit
[0135] Each time a drill bit is pulled out to the wellsite surface
after a run, the drill bit is inspected and graded based on its
characteristics. Such grading may be performed pursuant to the
International Association of Drilling Contractors (IADC)
classification nomenclature and a report indicative of the drill
bit grading may be prepared.
[0136] FIG. 17 is a schematic view of at least a portion of example
implementations of vision systems 900 operable to determine level
of wear of a drill bit according to one or more aspects of the
present disclosure. The vision system 900 may be a portion of a
well construction system, such as the well construction system 100
shown in FIG. 1, and may be disposed or otherwise utilized in
association with other portions of the well construction system
100, including where identified by the same numerals. The vision
system 900 may be communicatively connected with a processing
device, such as the processing device 192 shown in FIGS. 1 and
2.
[0137] The vision system 900 may be operable to identify various
characteristics of the drill bit, such as may permit the vision
system 900 to automatically generate a drill bit grading report.
The vision system 900 or another system communicatively connected
with that vision system 900 may compile or otherwise comprise a
database of images of different variations of each characteristic
of a drill bit. The vision system 900 may utilize machine learning
to compare digital images of a drill bit that was pulled to the
wellsite surface with the images compiled in the database. In
addition, a comparison can be made between the condition of a drill
bit before it goes into the hole and the condition after it comes
out of the hole, such as to improve grading.
[0138] FIG. 18 is a chart 920 comprising a plurality of images of
cutter faces 922, each having a different level of wear
characterized by the relative location of a wear line 924 along
each cutter face 922. The chart 920 further comprises a grade
rating 926 and amount of wear 928 associated with a threshold
location 930 of the wear line 924 along each cutter face 922. A
database of drill bits within the scope of the present disclosure
may comprise the chart 920 or other images of cutter faces 922
having different levels of wear and grade ratings associated with
each image of cutter face 922. The vision system 900 may, for
example, compare digital images (or video frames) of cutters of a
drill bit that was pulled to the wellsite surface with the images
of the cutter faces 922 in the database.
[0139] The vision system 900 may comprise a camera 902 directed
toward a drill bit such that one or more drill bit cutters 904
(e.g., polycrystalline diamond compact (PDC) cutters) are within a
field of view 906 of the camera 902. The camera 902 may be directed
toward the cutters 904 such that corresponding faces 908 of the
cutters 904 are within the field of view 906.
[0140] Such positioning and direction may permit the camera 902 to
capture digital images (or video frames) of one or more cutters 904
encompassed within the field of view 906. The camera 902 may be in
signal communication with a processing device. A video signal
comprising the captured digital images may be generated by the
camera 902 and received by the processing device, which may then
process and analyze the digital images. For example, the vision
system 900 may be operable to process and analyze the digital
images to measure or otherwise determine dimensions of certain
features of the cutters 904 and compare such dimensions to those of
cutters in images stored in the database. For example, the vision
system 900 may determine diameter 910 of the cutter face 908 of the
drill bit being graded, length 914 of a wear line 916 along the
cutter face 908, and/or location of the wear line 916 along the
cutter face 908, such as by measuring distance 918 between the wear
line 916 and an opposing edge of the cutter face 908 and/or by
determining a proportion or fraction of the distance 918 to the
diameter 910 of the cutter face 908.
[0141] Such measurements may be performed by tracking the quantity
of video pixels spanning such features or measurements of the
cutter 904. A correlation factor can be developed between the
pixels in the captured digital images to the actual dimensions of
the cutter 904 and/or drill bit. Such correlation factor can be
utilized to account for attributes, such as height of the camera
902 with respect the cutter 904 and/or drill bit, the angle of the
camera 902 with respect to the cutter 904 and/or drill bit, and the
distance of the camera 902 from the cutter 904 and/or drill bit.
After measuring or determining the pixels in the captured images,
the correlation factor may be utilized to convert the determined
quantity of pixels spanning across the features of the cutter in
the digital images to actual physical dimensions, such as by
utilizing one or more of Equations (1) and (5). The vision system
900 may then utilize the actual physical dimensions to determine
drill bit characteristics, such as drill bit grade and/or level of
wear of the drill bit. The vision system 900 may automatically
generate a drill bit grading report based on the determined drill
bit characteristics.
Determining Safety Regulation Compliance
[0142] Attention to safety is paramount on drilling rigs. Besides
local practices that may be followed by each drilling company,
standards and directives are mandated by regulatory authorities,
such as OSHA and ANSI. Well construction systems (e.g., drill rigs)
often utilize marking and color coding procedures for lifting
systems and accessories (e.g., tubular hoisting systems, slings).
Lifting accessories and portions of the lifting systems are
inspected and if found compliant for purpose, may be painted or
otherwise marked with a predetermined color. The color markings may
indicate that an inspection was performed, validating use of the
lifting systems and accessories for a fixed interval of time (e.g.,
a month or three months), after which the lifting systems and
accessories will again be inspected. Personal protection equipment
(PPE) regulations are also enforced at well construction systems.
Some PPE regulations vary based on the area of the drill rig a
wellsite operator is working. For example, high noise areas, such
as the pump room, mandate double ear protection, but the rig floor
may not. Furthermore, trainees may be given different colored hats
(e.g., green) when working on the drill rig. Oftentimes, trainees
have to be accompanied by senior personnel in certain sections of
the drill rig.
[0143] FIG. 19 is a schematic view of at least a portion of example
implementations of a vision system 1000 operable to determine
compliance with safety regulations, safety standards, and/or top
practices according to one or more aspects of the present
disclosure. The vision system 1000 may be a portion of a well
construction system, such as the well construction system 100 shown
in FIG. 1, and may be disposed or otherwise utilized in association
with other portions of the well construction system 100, including
where identified by the same numerals. The vision system 1000 may
be a portion of a control system, such as the control system 200
shown in FIG. 2, and/or a portion of a CCTV system, such as the
CCTV system 216 shown in FIGS. 1 and 2. The vision system 1000 may
be communicatively connected with a processing device, such as the
processing device 192 shown in FIGS. 1 and 2.
[0144] The vision system 1000 may comprise a plurality of video
cameras 1002 distributed at various locations of the well
construction system 100 and directed or aimed toward various
lifting equipment of the well construction system 100, such as may
permit the cameras 1002 to capture digital images of such equipment
to monitor compliance with safety regulations at the well
construction system 100. For example, the cameras 1002 may be
directed toward selected portions of a winch system 1004 for
lifting various tools and equipment 1006 above the rig floor 114.
The winch system 1004 may comprise a winch 1008 operatively
connected to a hook 1010 via a line 1012. The cameras 1002 may also
or instead be directed toward selected lifting accessories, such as
lifting slings 1014 utilized to lift the equipment 1006 at the well
construction system 100. The equipment 1006 (e.g., downhole
tubulars) may be connected directly with the hook 1010 or
indirectly via a sling 1014. A lifting cap 1016 or another
connector may be utilized to connect some equipment 1006 with the
hook 1010 or the sling 1014. The vision system 1000 may also be
utilized, for example, to determine if a swivel end of a rotary
hose (not shown) is fastened to the swivel with a cable or
chain.
[0145] Such positioning and direction of the cameras 1002 may
permit the cameras 1002 to capture digital images (or video frames)
of the winch system 1004 and/or the lifting slings 1014 before
and/or during lifting operations. Video signals comprising the
digital images generated by the cameras 1002 may be received by the
processing device 192, which may then process the digital images to
determine mechanical status and/or colors of the winch system 1004
and/or lifting slings 1014 and, thus, determine if the winch system
1004 and lifting slings 1014 are being operated safely and/or if
safety regulations are complied with based on the determined
colors. Each different color of the hook 1010 and sling 1014 may
indicate, for example, validity of a safety inspection for a
predetermined period of time. If the processing device 192
determines that the winch system 1004 is operating in an unsafe
manner and/or a safety regulation is not complied with, the
processing device 192 may automatically initiate an alarm (e.g., a
visual and/or audio alarm) indicative of unsafe operation and/or
noncompliance with one or more of the safety regulations. Machine
learning programs may be implemented to identify unsafe operation
and/or safety regulation noncompliance.
[0146] The cameras 1002 may also or instead be directed toward the
rig floor 114, such as may permit the cameras 1002 to capture
digital images of the wellsite operators 195 and the PPE equipment
1015 (e.g., hard hats, ear protections, eye protection, overalls,
safety vests, gloves, safety shoes, etc.) worn by the wellsite
operators 195, which may indicate compliance with safety
regulations by the wellsite operators 195. The PPE equipment 1015
may, thus, also be referred to as "safety regulation compliance
indicators 1015."
[0147] Such positioning and direction may permit the cameras 1002
to capture digital images (or video frames) of the PPE equipment
1015 before and/or during drilling and other wellsite operations.
Video signals comprising the digital images generated by the
cameras 1002 may be received by the processing device 192, which
may then process the digital images to determine if the wellsite
operators 195 are wearing the mandated PPE equipment 1015. The
processing device 192 may also or instead monitor color of selected
PPE equipment 1015 (e.g., hard hats), wherein each different color
may indicate, for example, if the wellsite operator 195 is working
in an assigned or permitted area (e.g., the rig floor 114) of the
well construction system 100. If the processing device 192
determines that a wellsite operator 195 is not wearing mandated PPE
equipment 1015 or if the wellsite operator 195 is present in an
unassigned or forbidden area of the well construction system 100,
the processing device 192 may automatically initiate an alarm
(e.g., a visual and/or audio alarm). Machine learning programs may
be implemented to identify safety regulation noncompliance.
[0148] FIGS. 20 and 21 are enlarged views of a portion of the winch
system 1004 shown in FIG. 19 according to one or more aspects of
the present disclosure. FIG. 20 shows the hook 1010 mechanically
coupled with the sling 1014 in a proper (and safe) manner, wherein
an eye 1024 (e.g., a loop) of the sling 1014 is fully engaged by
the hook 1010 and locked on the hook 1010 by a safety latch 1018 to
prevent accidental release of the sling 1014. FIG. 21 shows the
hook 1010 mechanically coupled with the sling 1014 in an improper
(and unsafe) manner, wherein the eye 1024 of the sling 1014 is not
fully engaged by the hook 1010 and not locked on the hook 1010 by
the safety latch 1018. The hook 1010 may further comprise a rope
socket or another connector 1020 configured to connect the hook
1010 with the line 1012. The sling 1014 may comprise opposing
crimped sleeves or other fasteners 1022 configured to form or
otherwise facilitate the eyes 1024 of the sling 1014. The connector
1020, the fasteners 1022, and/or safety inspection tags 1026 (or
zip ties) connected with the hook 1010 and/or sling 1014 may be
painted or otherwise comprise a selected color indicative of
compliance with safety regulations associated with such piece of
equipment. Each different color may indicate, for example, validity
of a safety inspection of the associated piece of equipment for a
predetermined period of time. The colored (e.g., painted) connector
1020, fasteners 1022, and/or tags 1026 may, thus, be referred to as
"safety regulation compliance indicators 1020, 1022, 1026."
[0149] The cameras 1002 may be directed toward the hook 1010 and
the sling 1014, such as may permit the cameras 1002 to capture
digital images (or video frames) of the hook 1010 and the sling
1014. Video signals comprising the digital images generated by the
cameras 1002 may be received by the processing device 192, which
may then process the digital images to determine whether the hook
1010 and the sling 1014 are mechanically coupled in the proper
manner, wherein the eye 1024 of the sling 1014 is locked by the
safety latch 1018. The processing device 192 may also or instead
determine the color of the safety regulation compliance indicators
1020, 1022, 1026 to determine if the safety regulations are
complied with. If the processing device 192 determines that the
winch system 1004 is operating in an unsafe manner and/or one or
more safety regulations are not complied with, the processing
device 192 may automatically initiate an alarm (e.g., a visual
and/or audio alarm) indicative of unsafe operation and/or
noncompliance with the safety regulations. Machine learning
programs may be implemented to identify unsafe operation and/or
safety regulation noncompliance.
[0150] FIG. 22 is a schematic view of at least a portion of an
example implementation of a processing system 1100 (or device)
according to one or more aspects of the present disclosure. The
processing system 1100 may be or form at least a portion of one or
more equipment controllers and/or other electronic devices shown in
one or more of the FIGS. 1-21. Accordingly, the following
description refers to FIGS. 1-22, collectively.
[0151] The processing system 1100 may be or comprise, for example,
one or more processors, controllers, special-purpose computing
devices, PCs (e.g., desktop, laptop, and/or tablet computers),
personal digital assistants, smartphones, IPCs, PLCs, servers,
internet appliances, and/or other types of computing devices. The
processing system 1100 may be or form at least a portion of the
processing device 192. The processing system 1100 may be or form at
least a portion of the local controllers 221-226. The processing
system 1100 may form at least a portion of the cameras 198, 302,
402, 506, 508, 602, 702, 802, 804, 902, 1002. Although it is
possible that the entirety of the processing system 1100 is
implemented within one device, it is also contemplated that one or
more components or functions of the processing system 1100 may be
implemented across multiple devices, some or an entirety of which
may be at the wellsite and/or remote from the wellsite.
[0152] The processing system 1100 may comprise a processor 1112,
such as a general-purpose programmable processor. The processor
1112 may comprise a local memory 1114, and may execute
machine-readable and executable program code instructions 1132
(i.e., computer program code) present in the local memory 1114
and/or another memory device. The processor 1112 may execute, among
other things, the program code instructions 1132 and/or other
instructions and/or programs to implement the example methods
and/or operations described herein. The program code instructions
1132 stored in the local memory 1114, when executed by the
processor 1112 of the processing system 1100, may cause one or more
portions or pieces of wellsite equipment of a well construction
system to perform the example methods and/or operations described
herein. The processor 1112 may be, comprise, or be implemented by
one or more processors of various types suitable to the local
application environment, and may include one or more of
general-purpose computers, special-purpose computers,
microprocessors, digital signal processors (DSPs),
field-programmable gate arrays (FPGAs), application-specific
integrated circuits (ASICs), and processors based on a multi-core
processor architecture, as non-limiting examples. Examples of the
processor 1112 include one or more INTEL microprocessors,
microcontrollers from the ARM and/or PICO families of
microcontrollers, embedded soft/hard processors in one or more
FPGAs.
[0153] The processor 1112 may be in communication with a main
memory 1116, such as may include a volatile memory 1118 and a
non-volatile memory 1120, perhaps via a bus 1122 and/or other
communication means. The volatile memory 1118 may be, comprise, or
be implemented by random access memory (RAM), static random access
memory (SRAM), synchronous dynamic random access memory (SDRAM),
dynamic random access memory (DRAM), RAMBUS dynamic random access
memory (RDRAM), and/or other types of random access memory devices.
The non-volatile memory 1120 may be, comprise, or be implemented by
read-only memory, flash memory, and/or other types of memory
devices. One or more memory controllers (not shown) may control
access to the volatile memory 1118 and/or non-volatile memory
1120.
[0154] The processing system 1100 may also comprise an interface
circuit 1124, which is in communication with the processor 1112,
such as via the bus 1122. The interface circuit 1124 may be,
comprise, or be implemented by various types of standard
interfaces, such as an Ethernet interface, a universal serial bus
(USB), a third generation input/output (3GIO) interface, a wireless
interface, a cellular interface, and/or a satellite interface,
among others. The interface circuit 1124 may comprise a graphics
driver card. The interface circuit 1124 may comprise a
communication device, such as a modem or network interface card to
facilitate exchange of data with external computing devices via a
network (e.g., Ethernet connection, digital subscriber line (DSL),
telephone line, coaxial cable, cellular telephone system,
satellite, etc.).
[0155] The processing system 1100 may be in communication with
various video cameras, sensors, actuators, equipment controllers,
and other devices of the well construction system via the interface
circuit 1124. The interface circuit 1124 can facilitate
communications between the processing system 1100 and one or more
devices by utilizing one or more communication protocols, such as
an Ethernet-based network protocol (such as ProfiNET, OPC, OPC/UA,
Modbus TCP/IP, EtherCAT, UDP multicast, Siemens S7 communication,
or the like), a proprietary communication protocol, and/or another
communication protocol.
[0156] One or more input devices 1126 may also be connected to the
interface circuit 1124. The input devices 1126 may permit human
wellsite operators 195 to enter the program code instructions 1132,
which may be or comprise control commands, operational settings and
set-points, processing routines, Equations (1)-(13), and/or various
numerical parameters of the Equations (1)-(13), such as the pixel
pitch P, the distance D 308 of the visual indicator from the video
camera, the height of the image sensor S.sub.h of the video camera,
the focal length f of the video camera, the image frame height
F.sub.h, the weight per unit length W.sub.dp, the overpull force
F.sub.o, and the distances l.sub.a 410, l.sub.b 412, l.sub.c 414,
and T.sub.b 418, among other examples. The input devices 1126 may
be, comprise, or be implemented by a keyboard, a mouse, a joystick,
a touchscreen, a track-pad, a trackball, an isopoint, and/or a
voice recognition system, among other examples. One or more output
devices 1128 may also be connected to the interface circuit 1124.
The output devices 1128 may permit for visualization or other
sensory perception of various data, such as sensor data, status
data, and/or other example data. The output devices 1128 may be,
comprise, or be implemented by video output devices (e.g., an LCD,
an LED display, a CRT display, a touchscreen, etc.), printers,
and/or speakers, among other examples. The one or more input
devices 1126 and the one or more output devices 1128 connected to
the interface circuit 1124 may, at least in part, facilitate the
HMIs described herein.
[0157] The processing system 1100 may comprise a mass storage
device 1130 for storing data and program code instructions 1132.
The mass storage device 1130 may be connected to the processor
1112, such as via the bus 1122. The mass storage device 1130 may be
or comprise a tangible, non-transitory storage medium, such as a
floppy disk drive, a hard disk drive, a compact disk (CD) drive,
and/or digital versatile disk (DVD) drive, among other examples.
The processing system 1100 may be communicatively connected with an
external storage medium 1134 via the interface circuit 1124. The
external storage medium 1134 may be or comprise a removable storage
medium (e.g., a CD or DVD), such as may be operable to store data
and program code instructions 1132.
[0158] As described above, the program code instructions 1132 may
be stored in the mass storage device 1130, the main memory 1116,
the local memory 1114, and/or the removable storage medium 1134.
Thus, the processing system 1100 may be implemented in accordance
with hardware (perhaps implemented in one or more chips including
an integrated circuit, such as an ASIC), or may be implemented as
software or firmware for execution by the processor 1112. In the
case of firmware or software, the implementation may be provided as
a computer program product including a non-transitory,
computer-readable medium or storage structure embodying computer
program code instructions 1132 (i.e., software or firmware) thereon
for execution by the processor 1112.
[0159] The control system 1100 may be operable to receive the
program code instructions 1132. The control system 1100 may be
communicatively connected with and operable to receive information
(e.g., sensor data, signals, digital images, or other information,
etc.) indicative of physical characteristics and/or operational
status of various equipment or equipment systems of the well
construction system. The control system 1100 may be communicatively
connected with a database containing digital images of drill bits
having different wear characteristic and the associated wear
grading. The control system 1100 may be further operable to process
the program code instructions 1132 and the operational status
information to generate and output corresponding control commands
to one or more pieces of equipment or other controllable devices of
the well construction system and, thereby, cause or otherwise
implement at least a portion of one or more of the example methods,
processes, and/or operations described herein.
[0160] In view of the entirety of the present disclosure, including
the figures and the claims, a person having ordinary skill in the
art will readily recognize that the present disclosure introduces
an apparatus comprising a first downhole tubular configured for
threadedly coupling with a second downhole tubular and conveyance
within a wellbore by an oil and/or gas drilling rig, wherein an
outer surface of the first downhole tubular comprises a geometric
pattern for determining azimuthal orientation of the first downhole
tubular.
[0161] The geometric pattern may be or comprise a geometric
shape.
[0162] The geometric pattern, viewed from a side of the first
downhole tubular, may be indicative of the azimuthal orientation of
the first downhole tubular.
[0163] The geometric pattern may wrap around the outer surface of
the first downhole tubular.
[0164] A length of the geometric pattern, viewed along an edge of
the first downhole tubular, may change with rotation of the first
downhole tubular. In such implementations, among others within the
scope of the present disclosure, the length of the geometric
pattern viewed along the edge of the first downhole tubular may be
indicative of the azimuthal orientation of the first downhole
tubular.
[0165] The geometric pattern may be or comprise a triangle wrapped
around the outer surface of the first downhole tubular.
[0166] The geometric pattern may be painted, etched, and/or affixed
to the outer surface of the first downhole tubular.
[0167] The geometric pattern may be a first geometric pattern
located closer to a box end of the first downhole tubular, the
outer surface of the first downhole tubular may comprise a second
geometric pattern located closer to a pin end of the first downhole
tubular, and the second geometric pattern may be indicative of the
azimuthal orientation of the first downhole tubular.
[0168] The apparatus may further comprise: a video camera operable
to generate a video signal comprising images of the geometric
pattern; and a processing system comprising a processor and a
memory storing a computer program code which, when executed, causes
the processing system to determine the azimuthal orientation of the
first downhole tubular based on the images of the geometric
pattern. The processing system may be operable to determine
azimuthal orientation of the first downhole tubular based on: a
length of the geometric pattern viewed along an edge of the first
downhole tubular; and/or an angle of the geometric pattern. The
processing system may be operable to determine the azimuthal
orientation of the first downhole tubular by determining a length
of the geometric pattern viewed along an edge of the first downhole
tubular, and the length of the geometric pattern may be indicative
of the azimuthal orientation of the first downhole tubular. The
processing system may be operable to determine the length of the
geometric pattern viewed along the edge of the first downhole
tubular by determining a quantity of video pixels spanning the
length of the geometric pattern viewed along the edge of the first
downhole tubular, and the determined quantity of video pixels may
be indicative of the length of the geometric pattern viewed along
the edge of the first downhole tubular. The processing system may
be operable to convert the determined quantity of video pixels to
physical measurements to determine the length of the geometric
pattern viewed along the edge of the first downhole tubular
utilizing a relationship between: the quantity of video pixels
spanning the length of the geometric pattern viewed along the edge
of the first downhole tubular; a radial distance of the first
downhole tubular from the video camera; a height of an image sensor
of the video camera; a focal length of the video camera; heights of
the images; and the length of the geometric pattern viewed along
the edge of the first downhole tubular.
[0169] The geometric pattern may be a first geometric pattern, the
azimuthal orientation may be a first azimuthal orientation, an
outer surface of the second downhole tubular may comprise a second
geometric pattern for determining second azimuthal orientation of
the second downhole tubular, and the first and second azimuthal
orientations may be collectively indicative of relative azimuthal
orientation between the first and second downhole tubulars. In such
implementations, among others within the scope of the present
disclosure, the apparatus may further comprise: (A) a first video
camera operable to generate a first video signal comprising first
images of the first geometric pattern on the first downhole tubular
while the first tubular extends out of the wellbore; (B) a second
video camera operable to generate a second video signal comprising
second images of the second geometric pattern on the second
downhole tubular while the second tubular is being threadedly
coupled with the first tubular; and (C) a processing system
comprising a processor and a memory storing a computer program code
which, when executed, causes the processing system to determine:
(i) the first azimuthal orientation based on the first images of
the first geometric pattern after the second downhole tubular is
threadedly coupled with the first downhole tubular; (ii) the second
azimuthal orientation based on the second images of the second
geometric pattern after the second downhole tubular is threadedly
coupled with the first downhole tubular; and (iii) the relative
azimuthal orientation of the first and second downhole tubulars
based on the determined first and second azimuthal orientations.
The first downhole tubular may comprise a downhole motor, the first
azimuthal orientation may be an azimuthal orientation of a tool
face of a bent sub of the downhole motor, the second downhole
tubular may comprise an MWD tool, the second azimuthal orientation
may be an azimuthal orientation of a directional sensor associated
with the MWD tool, and the relative azimuthal orientation may be or
comprise a tool face offset between the tool face of the bent sub
of the downhole motor and the location of the directional
sensor.
[0170] The first downhole tubular may be or comprise a drill pipe,
a casing joint, a downhole sub, a UBHO sub, an MWD tool, and/or a
downhole motor.
[0171] The geometric pattern may comprise a reference point
azimuthally aligned with or at a known azimuthal offset from a
reference point of the first downhole tubular. In such
implementations, among others within the scope of the present
disclosure, the first downhole tubular may comprise a downhole
motor, and the reference point of the first downhole tubular may be
or comprise a scribe line indicative of a tool face of a bent sub
of the downhole motor. The first downhole tubular may be or
comprise an MWD tool, and the reference point of the first downhole
tubular may be or comprise a location of a directional sensor of
the MWD tool. The first downhole tubular may be or comprise a UBHO
sub, and the reference point of the first downhole tubular may be
or comprise a location of a key of a UBHO sleeve.
[0172] The present disclosure also introduces a method comprising
imparting a geometric pattern onto an outer surface of a downhole
tubular, wherein the geometric pattern is for determining azimuthal
orientation of the downhole tubular while the downhole tubular is
threadedly coupled with another downhole tubular for conveyance
within a wellbore.
[0173] The geometric pattern may be or comprise a geometric
shape.
[0174] The geometric pattern viewed from a side of the downhole
tubular may be indicative of the azimuthal orientation of the
downhole tubular.
[0175] The geometric pattern may wrap around the downhole
tubular.
[0176] A length of the geometric pattern viewed along an edge of
the downhole tubular may change with rotation of the downhole
tubular. In such implementations, among others within the scope of
the present disclosure, the length of the geometric pattern viewed
along the edge of the downhole tubular may be indicative of the
azimuthal orientation of the downhole tubular.
[0177] The geometric pattern may be or comprise a triangle wrapped
around the outer surface of the first downhole tubular.
[0178] Imparting the geometric pattern onto the outer surface of
the downhole tubular may comprise painting, etching, and/or
affixing the geometric pattern onto the outer surface of the
downhole tubular.
[0179] The geometric pattern may be a first geometric pattern
located closer to a pin end of the downhole tubular, the method may
comprise imparting a second geometric pattern onto the outer
surface of the downhole tubular at a location closer to a box end
of the downhole tubular, and the second geometric pattern may be
for determining the azimuthal orientation of the downhole tubular
while the downhole tubular is threadedly coupled with another
downhole tubular.
[0180] The downhole tubular may be or comprise a drill pipe, a
casing joint, a downhole sub, a UBHO sub, an MWD tool, and/or a
downhole motor.
[0181] The geometric pattern may comprise a reference point, and
the geometric pattern may be imparted onto the outer surface of the
downhole tubular such that the reference point of the geometric
pattern is azimuthally aligned with or at a known azimuthal offset
from a reference point of the downhole tubular. The downhole
tubular may be or comprise a downhole motor, and the reference
point of the downhole tubular may be or comprise a scribe line
indicative of a tool face of a bent sub of the downhole motor. The
downhole tubular may be or comprise an MWD tool, and the reference
point of the downhole tubular may be or comprise a location of a
directional sensor of the MWD tool. The downhole tubular may be or
comprise a UBHO sub, and the reference point of the downhole
tubular may be or comprise a location of a key of a UBHO
sleeve.
[0182] The present disclosure also introduces a method comprising:
operating a video camera to generate a signal comprising images of
a geometric pattern on an outer surface of a first downhole tubular
while the first downhole tubular is being threadedly coupled with a
second downhole tubular at an oil and gas wellsite; and operating a
processing system to process the signal to determine an azimuthal
orientation of the first downhole tubular based on the images of
the geometric pattern.
[0183] The geometric pattern may be or comprise a geometric
shape.
[0184] The geometric pattern viewed from a side of the first
downhole tubular may be indicative of the azimuthal orientation of
the first downhole tubular.
[0185] The geometric pattern may wrap around the outer surface of
the first downhole tubular.
[0186] A length of the geometric pattern viewed along an edge of
the first downhole tubular may change with rotation of the first
downhole tubular. The length of the geometric pattern viewed along
the edge of the first downhole tubular may be indicative of the
azimuthal orientation of the first downhole tubular.
[0187] The geometric pattern may be or comprise a triangle wrapped
around the outer surface of the first downhole tubular.
[0188] The geometric pattern may be painted, etched, and/or affixed
to the outer surface of the first downhole tubular.
[0189] The geometric pattern may be a first geometric pattern
located closer to a box end of the first downhole tubular, the
outer surface of the first downhole tubular may comprise a second
geometric pattern located closer to a pin end of the first downhole
tubular, and the second geometric pattern may be indicative of the
azimuthal orientation of the first downhole tubular.
[0190] Operating the processing system to determine the azimuthal
orientation of the first downhole tubular may comprise determining
a length of the geometric pattern viewed along an edge of the first
downhole tubular, and the length of the geometric pattern may be
indicative of the azimuthal orientation of the first downhole
tubular.
[0191] Determining the length of the geometric pattern viewed along
the edge of the first downhole tubular may comprise determining a
quantity of video pixels spanning the length of the geometric
pattern viewed along the edge of the first downhole tubular, and
the determined quantity of video pixels may be indicative of the
length of the geometric pattern viewed along the edge of the first
downhole tubular. Determining the length of the geometric pattern
viewed along the edge of the first downhole tubular may comprise
converting the determined quantity of video pixels to physical
measurements based on a relationship between: the quantity of video
pixels spanning the length of the geometric pattern viewed along
the edge of the first downhole tubular; a radial distance of the
first downhole tubular from the video camera; a height of an image
sensor of the video camera; a focal length of the video camera;
heights of the images; and the length of the geometric pattern
viewed along the edge of the first downhole tubular.
[0192] The method may further comprise: (A) for each subsequent
downhole tubular threadedly coupled above the first downhole
tubular, generating a signal comprising images of a geometric
pattern on an outer surface of each subsequent downhole tubular;
and (B) operating the processing system to: (i) process each signal
to determine an azimuthal orientation of each subsequent downhole
tubular; and (ii) determine a current azimuthal orientation of the
first downhole tubular based on the first azimuthal orientation and
the azimuthal orientation of each subsequent downhole tubular.
[0193] The signal may be a first signal, the geometric pattern may
be a first geometric pattern, the azimuthal orientation may be a
first azimuthal orientation, and the method may further comprise:
(A) operating the video camera to generate a second signal
comprising images of a second geometric pattern on an outer surface
of the second downhole tubular; and (B) operating the processing
system to: (i) process the second signal to determine a second
azimuthal orientation of the second downhole tubular; and (ii)
determine a current azimuthal orientation of the first downhole
tubular based on the first and second azimuthal orientations.
[0194] The geometric pattern may be a first geometric pattern, the
azimuthal orientation may be a first azimuthal orientation, an
outer surface of the second downhole tubular may comprise a second
geometric pattern for determining second azimuthal orientation of
the second downhole tubular, and the first and second azimuthal
orientations may be collectively indicative of relative azimuthal
orientation between the first and second downhole tubulars. The
video camera may be a first video camera, the signal may be a first
signal, the images may be first images, operating the first video
camera may be performed while the first tubular extends out of the
wellbore, and the method may further comprise: (A) operating a
second video camera to generate a second signal comprising second
images of the second geometric pattern on the second downhole
tubular while the second tubular is being threadedly coupled with
the first tubular; and (B) operating the processing system to
determine: (i) the first azimuthal orientation based on the first
images of the first geometric pattern after the second downhole
tubular is threadedly coupled with the first downhole tubular; (ii)
the second azimuthal orientation based on the second images of the
second geometric pattern after the second downhole tubular is
threadedly coupled with the first downhole tubular; and (iii) the
relative azimuthal orientation of the first and second downhole
tubulars based on the determined first and second azimuthal
orientations. The first downhole tubular may comprise a downhole
motor, the first azimuthal orientation may be an azimuthal
orientation of a tool face of a bent sub of the downhole motor, the
second downhole tubular may comprise an MWD tool, the second
azimuthal orientation may be an azimuthal orientation of a
directional sensor associated with the MWD tool, and the relative
azimuthal orientation may be or comprise a tool face offset between
the tool face of the bent sub of the downhole motor and the
location of the directional sensor.
[0195] The first downhole tubular may be or comprise a drill pipe,
a casing joint, a downhole sub, a UBHO sub, an MWD tool, and/or a
downhole motor.
[0196] The geometric pattern may comprise a reference point
azimuthally aligned with or at a known azimuthal offset from a
reference point of the first downhole tubular. The first downhole
tubular may comprise a downhole motor, and the reference point of
the first downhole tubular may be or comprise a scribe line
indicative of a tool face of a bent sub of the downhole motor. The
first downhole tubular may be or comprise an MWD tool, and the
reference point of the first downhole tubular may be or comprise a
location of a directional sensor of the MWD tool. The first
downhole tubular may be or comprise a UBHO sub, and the reference
point of the first downhole tubular may be or comprise a location
of a key of a UBHO sleeve.
[0197] The present disclosure also introduces a method comprising:
operating a video camera to generate a video signal comprising
images encompassing a top of a tubular extending above an elevator
of a drill rig at an oil and gas wellsite while the tubular is
retained by the elevator; and operating a processing system to
process the video signal to determine a height of the top of the
tubular relative to the rig floor of the drill rig, wherein the
processing system comprises a processor and a memory storing a
computer program code.
[0198] The tubular may be a section of drill pipe and/or
casing.
[0199] Operating the processing system may comprise determining a
distance between the top of the tubular and the top of the elevator
by determining a quantity of video pixels spanning between the top
of the tubular box end and the top of the elevator, and the
determined quantity of video pixels may be indicative of the
distance between the top of the tubular and the top of the
elevator. Determining the distance between the top of the tubular
and the top of the elevator may comprise converting the determined
quantity of video pixels to physical measurements. Converting the
determined quantity of video pixels to physical measurements may be
based on a radial distance of the drill pipe from the video camera,
a height of an image sensor of the video camera, a focal length of
the video camera, and height of the images.
[0200] Determining the height of the top of the tubular from the
rig floor may be based on: a block position having a known distance
between a predetermined reference point of a traveling block or top
drive of the drill rig and the rig floor; a distance between upper
eyes of tubular handling assembly links of the top drive; a
distance between lower eyes of the tubular handling assembly links
and the top of the elevator; and a distance between the upper eyes
and the lower eyes.
[0201] The tubular may be an upper tubular threadedly coupled with
a lower tubular extending from a wellbore to a stick up height, and
the method may further comprise determining length of the upper
tubular based on the stick up height and the determined height of
the top of the upper tubular from the rig floor.
[0202] The video camera may be a first video camera, the video
signal may be a first video signal, and the method may further
comprise: (A) tripping the tubular within a wellbore; (B) operating
a second video camera to generate a second video signal comprising
images encompassing the top of the tubular extending above the
elevator while the tubular is retained by the elevator; and (C)
operating a processing system to: (i) process the second video
signal to determine the height of the top of the tubular relative
to the rig floor of the drill rig; and (ii) cause the tripping of
the tubular within the wellbore to stop when the determined height
of the top of the tubular reaches a predetermined stick up
height.
[0203] The present disclosure also introduces a method comprising:
operating a video camera to generate a video signal comprising
images encompassing at least a portion of a crown block of a
hoisting system of an oil and gas drill rig; and operating a
processing system to process the video signal to determine when a
traveling block or elevator of the hoisting system is within a
threshold distance from the crown block, wherein the processing
system comprises a processor and a memory storing a computer
program code.
[0204] Operating the processing system may comprise determining a
distance between the crown block and the traveling block or
elevator by determining a quantity of video pixels spanning between
the crown block and the traveling block or elevator, and the
determined quantity of video pixels may be indicative of the
distance between the crown block and the traveling block or
elevator. The method may further comprise converting the determined
quantity of video pixels to physical measurements to determine the
distance between the crown block and the traveling block or
elevator by utilizing a relationship between: the quantity of video
pixels spanning between the crown block and the traveling block or
elevator; a radial distance of the crown block from the video
camera; a height of an image sensor of the video camera; a focal
length of the video camera; heights of the images; and the distance
between the crown block and the traveling block or elevator.
[0205] Operating the processing system may comprise automatically
causing the traveling block to stop or reduce speed of upward
movement when the traveling block or elevator is within the
threshold distance from the crown block.
[0206] Operating the processing system may comprise automatically
initiating a visual and/or audio alarm when the traveling block or
elevator is within the threshold distance from the crown block.
[0207] The present disclosure also introduces a method comprising:
operating a video camera to generate a video signal comprising
images encompassing at least a portion of a drawworks of a hoisting
system of an oil and gas drill rig; and operating a processing
system to process the video signal to determine when a traveling
block or elevator of the hoisting system is within a threshold
distance from the crown block, wherein the processing system
comprises a processor and a memory storing a computer program
code.
[0208] Operating the processing system may comprise determining a
length of cable wrapped around a drum of the drawworks, and the
determined length of the cable may be indicative of distance
between the crown block and the traveling block or elevator.
Determining the length of cable wrapped around the drum may
comprise determining a quantity of layers and/or wraps of the cable
around the drum. Determining the quantity of layers and/or wraps of
the cable wrapped around the drum may comprise determining height
and/or width of the cable wrapped around the drum.
[0209] Operating the processing system may comprise automatically
causing the traveling block to stop or reduce speed of upward
movement when the traveling block or elevator is within the
threshold distance from the crown block.
[0210] The present disclosure also introduces a method comprising
monitoring alignment between a pin end of an upper tubular and a
box end of a lower tubular during tubular make up operations at an
oil and gas wellsite by: operating a first video camera to generate
a first video signal comprising first images encompassing the pin
end of the upper tubular and the box end of the lower tubular;
operating a second video camera to generate a second video signal
comprising second images encompassing the pin end of the upper
tubular and the box end of the lower tubular, wherein the first and
second video cameras are directed at the pin end of the upper
tubular and the box end of the lower tubular from different angles;
and operating a processing system to process the first and second
video signals to determine an amount of misalignment between the
pin end of the upper tubular and the box end of the lower tubular
captured in the first and second images, wherein the processing
system comprises a processor and a memory storing a computer
program code.
[0211] Operating the processing system to process the first and
second video signals may comprise determining relative positions of
edges of the pin end of the upper tubular and edges of the box end
of the lower tubular captured in the first and second images.
[0212] Operating the processing system to process the first and
second video signals to determine the amount of misalignment
between the pin end of the upper tubular and the box end of the
lower tubular may comprise determining horizontal distances between
edges of the pin end of the upper tubular and edges of the box end
of the lower tubular captured in the first and second images.
Determining horizontal distances between the edges of the pin end
of the upper tubular and the edges of the box end of the lower
tubular captured in the first and second images may comprise:
determining a first quantity of video pixels spanning horizontally
between a first of the edges of the pin end of the upper tubular
and a first of the edges of the box end of the lower tubular
captured in the first images, wherein the determined first quantity
of video pixels may be indicative of a first of the horizontal
distances between the first edge of the pin end of the upper
tubular and the first edge of the box end of the lower tubular; and
determining a second quantity of video pixels spanning horizontally
between a second of the edges of the pin end of the upper tubular
and a second of the edges of the box end of the lower tubular
captured in the second images, wherein the determined second
quantity of video pixels may be indicative of a second of the
horizontal distances between the second edge of the pin end of the
upper tubular and the second edge of the box end of the lower
tubular. The method may further comprise converting the determined
first and second quantities of video pixels to physical
measurements to determine the first and second horizontal
distances, for each one of the first and second cameras, based on a
relationship between: the determined quantity of video pixels; a
radial distance of the lower tubular from that camera; a height of
the image sensor of that camera; a focal length of that camera; a
height of the images; and the corresponding first or second
horizontal distance.
[0213] Operating the processing system may comprise automatically
initiating a visual and/or audio alarm when the determined amount
of misalignment between the pin end of the upper tubular and the
box end of the lower tubular exceeds a predetermined threshold.
[0214] The first and second tubulars may be drill pipes, drill
collars, or casing joints.
[0215] The present disclosure also introduces a method comprising:
operating a video camera to generate a signal comprising an image
of at least a portion of a drill bit for drilling a wellbore; and
operating a processing system to process the signal to determine an
amount of wear experienced by the drill bit, wherein the processing
system comprises a processor and a memory storing a computer
program code.
[0216] Operating the processing system may comprise: comparing the
image with those in a database of images of other drill bits each
associated with a known amount of wear; and determining the amount
of wear experienced by the drill bit by assigning to the drill bit
the known amount of wear associated with one of the other drill
bits from the images in the database that most closely resembles
the drill bit.
[0217] Operating the processing system may comprise: measuring a
dimension of a feature of a cutter of the drill bit; and
determining the amount of wear experienced by the drill bit based
on the measured dimension of the feature of the cutter. The feature
may be or comprise a wear line along a face of the cutter, and the
dimension may comprise a length of the wear line. The feature may
be or comprise a wear line along a face of the cutter, and the
dimension may comprise a distance between the wear line and an edge
of the face of the cutter. The feature may be or comprise a face of
the cutter, and the dimension may comprise diameter of the face of
the cutter. Measuring the feature of the cutter may comprise
determining quantity of video pixels spanning the dimension of the
feature of the cutter. The method may further comprise converting
the determined quantity of video pixels to physical measurements
based on a relationship between: the quantity of video pixels
spanning the dimension of the feature of the cutter; a distance of
the drill bit from the video camera; a height of an image sensor of
the video camera; a focal length of the video camera; a height of
the image; and the length of the dimension of the feature of the
cutter.
[0218] The method may comprise automatically generating a report
comprising grading of the drill bit based on the determined amount
of wear experienced by the drill bit.
[0219] The present disclosure also introduces a method comprising:
(A) operating a video camera at an oil and gas wellsite to generate
a signal comprising images encompassing safety regulation
compliance indicators; and (B) operating a processing system to:
(i) process the signal to determine compliance with the safety
regulations at the oil and gas wellsite; and (ii) initiate an alarm
when the processed signal is indicative of noncompliance with one
or more of the safety regulations.
[0220] Operating the processing system to process the signal to
determine compliance with the safety regulations may comprise
determining presence and/or color of the safety regulation
compliance indicators.
[0221] The safety regulation compliance indicators may comprise
PPE. The PPE may comprise at least one of overalls, safety shoes,
gloves, ear protection, eye protection, and hard hats.
[0222] The safety regulation compliance indicators may comprise
color of a portion of a lifting system, color of a portion of a
lifting sling, and/or color of a safety inspection tag. Each
different color of the safety regulation compliance indicators may
indicate validity of a safety inspection for a predetermined period
of time, and the alarm may be initiated when the determined color
of one or more of the safety regulation compliance indicators
indicate that a safety inspection for a current period of time was
not performed.
[0223] The present disclosure also introduces a method comprising:
(A) operating a video camera to capture: (i) a first image of a
mark located on a first tubular while the first tubular is engaged
by a top drive and a second tubular coupled with the first tubular
is engaged by slips of a drilling rig comprising the top drive; and
(ii) a second image of the mark while the first tubular remains
engaged by the top drive and the second tubular is not engaged by
the slips; and (B) determining an amount of stretch of the first
tubular by determining a change in position of the mark among the
first and second images, wherein determining the mark position
change among the first and second images comprises operating a
processing system comprising a processor and a memory storing
computer program code.
[0224] Determining the mark position change among the first and
second images may comprise determining a quantity of video pixels
interposing respective first and second positions of the mark in
the first and second images. Determining the stretch amount may be
based on the determined quantity of video pixels and a
predetermined relationship. The method may further comprise
converting the determined quantity of video pixels to a physical
measurement to determine the stretch amount based on a relationship
between: the determined quantity of video pixels; a radial distance
of the first tubular from the video camera; and a focal length of
the video camera.
[0225] The method may further comprise: operating the video camera
to capture additional images of additional marks on additional
tubulars as each additional tubular is added to a string of
tubulars comprising the first and second tubulars; determining an
amount of stretch of each additional tubular by determining a
change in position of the additional mark among the first and
second images of that additional tubular; and determining an amount
of stretch of the string of tubulars based on the determined amount
of stretch of each individual tubular.
[0226] The mark may be or comprise a physical feature of the first
tubular.
[0227] The mark may be or comprise a visual feature that is painted
on an outer surface of the first tubular.
[0228] The mark may be or comprise a visual feature that is etched
on an outer surface of the first tubular.
[0229] The mark may be or comprise a visual feature that is affixed
to an outer surface of the first tubular.
[0230] The present disclosure also introduces a method comprising:
(A) operating a video camera to generate a video signal comprising
images encompassing a mark located on an uppermost tubular of a
tubular string comprising a plurality of tubulars extending within
a wellbore at an oil and gas wellsite; and (B) determining a depth
(D) at which the tubular string is stuck within the wellbore by:
(i) pulling the tubular string while determining a resulting amount
of stretch (S) of the uppermost tubular; and (ii) determining D
based at least partially on the determined S.
[0231] Determining D at which the tubular string is stuck within
the wellbore may further comprise, before pulling the tubular
string while determining the resulting amount of S of the uppermost
tubular: (i) pulling the tubular string to its neutral weight; and
(ii) determining an overpull force (F) based on a weight per unit
length (W) of each tubular of the tubular string. Pulling the
tubular string while determining the resulting amount of S of the
uppermost tubular may comprise pulling the tubular string with the
determined F while determining the resulting amount of S of the
uppermost tubular, and determining D based at least partially on
the determined S may comprise determining D based on a
predetermined relationship between D, F, W, and S. The
predetermined relationship may be D=(S.times.W)/F.
[0232] Determining the resulting amount of S may comprise
determining a change in position of the mark within the images.
Determining the change in position of the mark within the images
comprises operating a processing system comprising a processor and
a memory storing computer program code. Determining the change in
position of the mark within the images may comprise determining a
quantity of video pixels interposing respective first and second
positions of the mark within corresponding first and second images.
The method may further comprise converting the determined quantity
of video pixels to a physical measurement to determine the
resulting amount of S based on a relationship between: the
determined quantity of video pixels; a radial distance of the
uppermost tubular from the video camera; and a focal length of the
video camera.
[0233] The mark may be or comprise a physical feature of the
uppermost tubular.
[0234] The mark may be or comprise a visual feature that is painted
on an outer surface of the uppermost tubular.
[0235] The mark may be or comprise a visual feature that is etched
on an outer surface of the uppermost tubular.
[0236] The mark may be or comprise a visual feature that is affixed
to an outer surface of the uppermost tubular.
[0237] The foregoing outlines features of several embodiments so
that a person having ordinary skill in the art may better
understand the aspects of the present disclosure. A person having
ordinary skill in the art should appreciate that they may readily
use the present disclosure as a basis for designing or modifying
other processes and structures for carrying out the same functions
and/or achieving the same benefits of the embodiments introduced
herein. A person having ordinary skill in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
[0238] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn. 1.72(b) to permit the reader to
quickly ascertain the nature of the technical disclosure. It is
submitted with the understanding that it will not be used to
interpret or limit the scope or meaning of the claims.
* * * * *