Note: Descriptions are shown in the official language in which they were submitted.
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CEMENT HEAD REMOTE CONTROL AND TRACKING
BACKGROUND
[0001] The present disclosure is related to wellbore servicing tools used
in the oil and gas industry and, more particularly, to remote control and
tracking
of cement head operations.
[0002] During completion of oil and gas wells, cement is often used to
solidify a well casing within the newly drilled wellbore. To accomplish this,
cement slurry is first pumped through the inner bore of the well casing and
either out its distal end or through one or more ports defined in the well
casing
at predetermined locations. Cement slurry exits the well casing into the
annulus
formed between the well casing and the wellbore and is pumped back up toward
the surface within the annulus. Once the cement hardens, it forms a seal
between the well casing and the wellbore to protect oil producing zones and
non-
oil producing zones from contamination. In addition, the cement bonds the
casing to the surrounding rock formation, thereby providing support and
strength to the casing and also preventing blowouts and protecting the casing
from corrosion.
[0003] Prior to cementing, the wellbore and the well casing are typically
filled with drilling fluid or mud. A cementing plug is then pumped ahead of
the
cement slurry in order to prevent mixing of the drilling mud already disposed
within the wellbore with the cement slurry. When the cementing plug reaches a
collar or shoulder stop arranged within the casing at a predetermined
location,
the hydraulic pressure of the cement slurry ruptures the plug and enables the
cement slurry to pass through the plug and then through either the distal end
of
the casing or the side ports and into the annulus. Subsequently, another
cementing plug is pumped down the casing to prevent mixing of the cement
slurry with additional drilling mud that will be pumped into the casing
following
the cement slurry. When the top cementing plug lands on the collar or stop
shoulder, the pumping of the cement slurry ceases.
[0004] To perform the aforementioned cementing operations, a cement
head or cementing head is usually employed. The cement head is arranged at
the surface of the wellbore and the cementing plugs are held within the cement
head until the cementing operation requires their deployment. Various valves
associated with the cement head are required to be manipulated in order to
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perform the required tasks of the cement head. Such valves are typically
manipulated manually, thereby requiring rig personnel to be in close proximity
to the cement head and other wellbore equipment. In some cases, rig hands are
required to be strapped and suspended in the air in order to operate the
valves.
As can be appreciated, this presents a potential safety hazard.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] The following figures are included to illustrate certain aspects of
the present disclosure, and should not be viewed as exclusive embodiments.
The subject matter disclosed is capable of considerable modifications,
alterations, combinations, and equivalents in form and function, without
departing from the scope of this disclosure.
[0006] FIG. 1A is an isometric view of a cement head that embodies
principles of the present disclosure, according to one or more embodiments.
[0007] FIG. 1B is a cross-sectional view of a cement head that
embodies principles of the present disclosure, according to one or more
embodiments.
[0008] FIG. 1C is a cross-sectional view of a cement head that
embodies principles of the present disclosure, according to one or more
embodiments.
[0009] FIG. 1D is an isometric view of a cement head that embodies
principles of the present disclosure, according to one or more embodiments.
[0010] FIG. 2 is a front view of a cement head that embodies principles
of the present disclosure, according to one or more embodiments.
[0011] FIG. 3 is a side view of a cement head that embodies principles
of the present disclosure, according to one or more embodiments.
[0012] FIG. 4 is an isometric view of a cement head that embodies
principles of the present disclosure, according to one or more embodiments.
[0013] FIG. 5 is a schematic view of a communication system that
embodies principles of the present disclosure, according to one or more
embodiments.
[0014] FIG. 6 is a block diagram of a communication system that
embodies principles of the present disclosure, according to one or more
embodiments.
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[0015] FIG. 7 is a block diagram of a communication system that
embodies principles of the present disclosure, according to one or more
embodiments.
[0016] FIG. 8 is a flow chart showing steps performed by components
of a communication system that embodies principles of the present disclosure,
according to one or more embodiments.
DETAILED DESCRIPTION
[0017] The present disclosure is related to wellbore servicing tools used
in the oil and gas industry and, more particularly, to remote control and
tracking
of components of a cement head.
[0018] The present disclosure provides an ability to operate valves of a
cement head remotely. By reducing or eliminating the need for personnel to be
physically present during operation of a cement head or other wellbore
equipment, the exposure of such personnel to injury or harm that may occur
during operation is reduced or eliminated. The present disclosure also
describes
an ability to sense parameters of a cement head or other wellbore equipment
during operation. These parameters can be remotely recorded for further
analysis. Signals may be received from both (1) a control device operated
remotely by a user and (2) an onboard device responsive to operation of the
control device. These signals can be received by a tracking device remotely
separated from both the remote control device and the onboard control device.
As a result, various aspects of job performance with respect to multiple
devices
may be recorded. Performance, measured parameters, and status reported at
various stages of an operation allow a well operator to review and analyze
such
data after completion of a job. Such analysis may prove advantageous in
yielding valuable information to well operators regarding performance
characteristics and needed optimizations. Moreover, the present disclosure
describes embodiments to operate valves of a cement head from a variety of
remote locations without requiring relocation of an associated tracking
device. A
mobile and portable control device may be operated from a variety of locations
within a communication range of the cement head and the tracking device.
[0019] Referring to FIG. 1A, illustrated is a cement head 100 that may
embody one or more principles of the present disclosure, according to one or
more embodiments. While the cement head 100 is shown as having a particular
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configuration and design, those skilled in the art will readily recognize that
other
types and designs of cement heads may equally be used and otherwise employ
the principles of the present disclosure. The cement head 100 is generally a
multi-function device used inline with a work string associated with a
wellbore in
a hydrocarbon fluid production well. Most generally, the cement head 100 is
used to deliver cement or other wellbore servicing fluids and/or mixtures to a
wellbore through the work string to which the cement head 100 is attached. The
cement head 100 is also capable of delivering darts and/or balls for
activating or
initiating some function of a tool or structure associated with the work
string.
[0020] In one embodiment of the present disclosure, the cement head
100 includes an output module 102, two intermediate modules 104, and an
input module 106. Each of the output module 102, intermediate modules 104,
and input module 106 have a substantially cylindrical outer profile and each
lie
substantially coaxial with a central axis 128 that extends generally along the
length of the cement head 100 and is generally located centrally within cross-
sections of the cement head 100 that are taken orthogonal to the central axis
128. Each intermediate module 104 includes a launch valve 112 (discussed
infra) while the output module 102 includes a launch port 114 and a launch
Indicator 116 (each discussed infra). The cement head 100 may further include
safety modules 130, 134 with embedded safety valves 132, 136, discussed in
more detail below.
[0021] Referring now to FIG. 1B, a cross-sectional view of the cement
head 100 in a fully assembled state is shown. This view shows that the cement
head 100 includes primary fluid flow bores 166 extending through each module
102, 104, 106 along the central axis 128. Also shown is that the cement head
100 includes bypass fluid flow bores 168 within each intermediate module 104.
The input module 106 includes a conical header 170 into which fluid Is passed
and from which each of the primary fluid flow bores 166 and bypass fluid flow
bores 168 are in fluid communication with, depending on the operational
positions of the launch valves 112. The bypass fluid flow path 168 generally
begins at the interface between the input module 106 and the adjacent
intermediate module 104, so that fluid exiting the input module 106 and
entering the adjacent intermediate module 104 is capable of passing through
either the primary fluid flow bore 166 or the bypass fluid flow bore 168,
depending on the operational orientation of launch valves 112.
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[0022] The cement head 100 may be used to perform a variety of
functions that are generally known in the art, some of which are described
herein. Generally, flow through the cement head 100 would be from the left
hand side of FIG. 18 to the right hand side of FIG. 1B. When the cement head
100 is installed in a work string, the input module 106 is located higher than
the
output module 102 so that flow through the cement head 100 would be
generally from top to bottom from the input module 106 to the output module
102. Flow through the cement head 100 enters either through the upper work
string interface 110 or mixture ports 176, which are fluidly coupled to the
primary fluid flow bore 166 of the input module 106, and exits through the
lower
work string interface 108. Additionally, the cement head 100 is capable of
retaining and launching darts.
[0023] The launch valves 112 operate in two positions. The first
position is a bypass position where the launch valve prevents fluid flow
directly
through a primary fluid flow bore 166, but instead, allows fluid to flow from
a
bypass fluid flow bore 168 to a primary flow bore 166 on the downstream side
of
the launch valve 112. The second position is a primary position where the
launch valve 112 allows fluid flow directly from a position upstream from the
launch valve 112 in a primary fluid flow bore 166 to a position downstream
from
the launch valve 112 in a primary fluid flow bore 166.
[0024] The primary position is a position in which a dart, ball, or other
member to be launched is allowed to pass through the launch valve 112 from
the upstream side of the launch valve 112 to the downstream side of the launch
valve 112. The launch valves 112 of FIG. 1B are positioned so that a dart,
ball,
or other member to be launched is free to pass through the downstream launch
valve 112 (on the right side of the drawing). To aid in pushing the dart or
other
object through the downstream launch valve 112 (on the right side of the
drawing), the upstream launch valve 112 is positioned in the bypass position
so
that fluid can flow from the bypass fluid flow bore 168 into the primary fluid
flow
bore 166 located upstream from the downstream launch valve 112.
[0025] With the launch valves 112 in these positions, the upstream
launch valve 112 could be holding a second dart or other object to be
launched.
With the downstream launch valve 112 in the primary position, the upstream
launch valve 112 may be rotated one-quarter rotation from the bypass position
to the primary position, thereby allowing passage of the dart and fluids
through
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the primary fluid flow bores 166. Launch port 114 offers convenient access to
a
primary fluid flow bore 166 for allowing the insertion of a ball to be dropped
through the primary fluid flow bore 166. Launch indicator 116 uses lever arms
to interfere with balls and/or darts that pass by the launch indicator 116,
resulting in a rotation of an indicator portion of the launch indicator 116 to
signify whether a dart, ball, or other object has passed by the launch
indicator
116. In this embodiment, no part of the launch valves 112 extend radially
beyond the full diameter sections 134, thereby reducing the chance of
Inadvertently breaking portions of the launch valves 112.
[0026] While not shown in this embodiment, alternative embodiments
of a cement head may integrate a safety valve (i.e., a ball valve having a
full
bore inside diameter, sometimes referred to as a TIW or Texas Iron Works
valve) into one or more of the input module 106, intermediate modules 104,
and/or output module 102.
[0027] An embodiment of a cement head including safety valves is
shown in FIG. 1C. The cement head 100 may further include safety modules
130, 134. More particularly, a lower safety module 130 is connected to the
output module 102, while an upper safety module 134 is connected to the input
module 106 or the upper work string interface 110. The safety modules 130,
134 are also connected to the work string or other tools and selectively allow
a
fluid connection between the safety modules 130, 134. Specifically, each
safety
module 130, 134 includes a safety valve 132, 136, respectively, that operates
to
selectively restrict fluid flow through the safety modules 130, 134.
[0028] Referring now to FIG. 1D, the cement head 100 may also
include an internal control line 162 that extends at least through adjacent
intermediate modules 104. In this embodiment, the internal control line 162 is
well suited for communicating pneumatic control pressure/signals to launch
valves, such as the launch valves 112 of FIGS. 1A and 1B, thereby allowing
remote control of the launch valves 112. While only one internal control line
162
is shown, it should be understood that in alternative embodiments, additional
control lines may be used to control additional launch valves, with at least
one
internal control line being associated with the control of each launch valve.
By
placing the internal control line 162 inside the cement head 100 rather than
external to the modules, the chances for inadvertent damage to the internal
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control line 162 is minimized. Also shown in FIG. 1D are the primary fluid
flow
bore 166 and the bypass fluid flow bore 168.
[0029] FIG. 2 shows a front view of the cement head 100 in a fully
assembled state. FIG. 3 shows a side view of the cement head 100 in a fully
assembled state, including wrenches 190 provided for manual or mechanical
actuation of each launch valve 112, the lower safety valve 132, the upper
safety
valve 136, and the mixture valves 178. Manual operation of such valves
requires the presence of rig personnel to actuate or control one or more of
these
valves. An aspect of the present disclosure provides an ability to operate the
valves of the cement head 100 remotely.
[0030] Referring now to FIG. 4, an isometric view of the cement head
100 in a fully assembled state is shown. Various onboard devices 200 (referred
to as devices 200a, 200b, 200c, 200d, 200e, and 200f) are shown as being
connected to the cement head 100. One or more of onboard devices 200a-f are
operably connected to one or more mechanical devices of the cement head 100.
Mechanical devices may include valves, levers, plungers, and the like. A first
onboard device 200a may be operably connected to the upper safety valve 136
of the upper safety module 134. A second onboard device 200b may be
operably connected to a mixture port 176 of the input module 106. Additional
onboard devices (not shown) may be provided to one or more of the other
mixture ports 176 shown in FIG. 4. A third onboard device 200c may be
operably connected to the first launch valve 112 of the first intermediate
module
104. Likewise, a fourth onboard device 200d may be operably connected to the
second launch valve 112 of the second intermediate module 104. A fifth
onboard device 200e may be operably connected to the launch port 114 of the
output module 102. A sixth onboard device 200f may be operably connected to
the lower safety valve 132 of the lower safety module 130.
[0031] As shown in FIG. 4, the first, second, and sixth onboard devices
200a, 200b, 200f may each be housed in independent enclosures. As further
shown in FIG. 4, the third, fourth, and fifth onboard devices 200c, 200d, and
200e may be housed in a single enclosure. The enclosures may be attached to
portions of the cement head 100. Alternatively, all or a portion of any of the
onboard devices 200a-f may be integrated within the main body of the cement
head 100.
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[0032] Referring now to FIG. 5, with continued reference to FIG. 4, a
schematic view of a communication system 500 is shown. It will be appreciated
that items depicted in FIG. 5 are not necessarily shown to scale. The
communication system 500 may include the cement head 100, a control device
300, and a tracking device 400. The control device 300 may be operable by a
user, such as a well operator or rig hand. One or more inputs 314 are provided
in the control device 300 for operation by the user, with each of the inputs
314
having an associated function. For example, one of the inputs 314 may be
associated with a specific operation of a certain onboard device 200a-f; e.g.,
open, partially open, close, partially close, activate, deactivate, etc.
Various
operations and modes of the mechanical devices (e.g., valves) of the cement
head 100 are disclosed herein.
[0033] The control device 300 further includes one or more displays
312 for providing information to the user. The display 312 may be associated
with the current state of the control device 300, one of the inputs 314,
and/or
the onboard devices 200a-f. In operation, the control device 300 may be
configured to transmit first command signals 390 to one or more of the onboard
devices 200a-f. According to some embodiments, the control device 300 may be
further configured to transmit second command signals 392 to the tracking
device 400. The first and second command signals 390, 392 may be transmitted
either wired or wirelessly. In embodiments where the signals are 390, 392 are
transmitted wirelessly, the control device 300 may include a wireless
transmitter, as described in more detail below.
[0034] The first and/or second command signals may encompass a user
command (i.e., a user command indicator) provided by the user using one of the
inputs 314. In some embodiments, the user command indicator may include a
time that the control device 300 transmits the user command indicator. As used
herein, an indicator including a time may have a timestamp corresponding to a
time or span of time for an operation. The user command indicator may include
instructions for an onboard device 200 to operate an associated mechanical
device.
[0035] According to some embodiments, the onboard devices 200a-f
may be configured to receive the first command signals 390 from the control
device 300. In embodiments where the first command signals 390 are wireless
signals, the onboard devices 200a-f may each Include a wireless receiver or
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transceiver configured to receive and process the first command signals 390,
as
described in more detail below. The onboard devices 200a-f may be configured
to operate their corresponding mechanical devices in response to the first
command signals 390 from the control device 300. In some embodiments, the
onboard devices 200a-f may be further configured to operate one or more
sensors in response to the signals received from the control device 300.
[0036] According to some embodiments, the onboard devices 200a-f
may be further configured to transmit report signals 290 to the tracking
device
400 either wired or wirelessly. In embodiments where the report signals 290
signals are transmitted wirelessly, the onboard devices 200a-f may include
wireless transmitters or transceivers, as described in more detail below. The
report signals 290 may contain an indication of a state (i.e., a status
indicator)
of the particular onboard device 200a-f, an associated mechanical devices,
and/or the cement head 100. In some embodiments, the status indicator may
include a time that a command indicator was received by an onboard device
200, a time that an onboard device 200 commences operation, and/or a time
that an onboard device 200 ceases operation. In some embodiments, the status
indicator may include a parameter sensed by a sensor of the onboard device
200, and the status indicator may include a time that the onboard device 200
transmits the report signal 290.
[0037] According to some embodiments, the tracking device 400 may
be configured to receive the second command signals 392 from the control
device 300. According to some embodiments, the tracking device 400 may
further be configured to receive report signals 290 from the onboard devices
200. The tracking device 400 may be configured to record and store the second
command signals 392 and the report signals 290, along with any associated
information or data.
[0038] Accordingly, the communication system 500 provides three
communication pathways interconnecting the control device 300, the onboard
devices 200a-f, and the tracking device 400. As such, each component is
communicatively linked to the others while potentially being disposed at
separate and remote locations. For instance, the onboard devices 200a-f may
be located at a wellbore site for operation of the cement head 100 in
conjunction
with other wellbore equipment. The control device 300 may be operated
remotely and at a distance away from the cement head 100 and the onboard
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devices 200a-f. Accordingly, the user of the control device 300 may operate to
control device 300 from a safe distance away from the cement head 100 and
other wellbore equipment.
[0039] Similarly, the tracking device 400 may operate at a location that
is remote relative to the onboard devices 200a-f and the control device 300.
The location of the tracking device 400 may include any equipment useful for
the
operation of the tracking device 400, such as components for storing,
uploading,
or analyzing data collected by the tracking device 400. Because the control
device 300 and the tracking device 400 are separate components, they may be
located separately and remotely away from each other while maintaining a
communication link. Accordingly, a user operating the control device 300 may
be able to position or move the control device 300 to a variety of locations
without correspondingly moving the tracking device 400. Thus, the mobility and
portability of the control device 300 is enhanced by separation thereof from
the
tracking device 400. As mentioned above, signals between the control device
300, the onboard devices 200a-f, and the tracking device 400 may be
transmitted wirelessly to further enhance mobility.
[0040] According to some embodiments, the tracking device 400
includes one or more interfaces 416 for communicating stored data to other
devices. Data received, collected, and stored on the tracking device 400 may
be
accessible to a user during or after a procedure involving the cement head
100.
Information collected from the control device 300 via command signals 392, and
from the onboard devices 200 via the report signals 290, may be correlated and
compared in a meaningful way. For example, a user may analyze timing of
commands and actuation of valves, levers, and/or plungers. The time span
between the transmission of a user command from a control device 300 and the
completion of an associated operation by the onboard device 200a-f may be
determined and analyzed. For instance, a user may be able to compare the
period of time from when a wellbore projectile (i.e., dart, ball, plug, etc.)
is
released from the cement head 100 to a pressure spike once the wellbore
projectile lands on a downhole tool, shoulder, or obstruction. Commands and
operations may also be compared with sensed parameters, such as pressure or
temperature at or near one or more valves, levers, and/or plungers. The
analysis may identify proper or improper operation, as well as any needed
optimizations to improve performance of the cement head 100.
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[0041] Referring now to FIG. 6, with continued reference to FIG. 5, a
conceptual block diagram of the communication system 500 is shown. The
control device 300 is configured to transmit the first command signals 390,
shown as command signals 390a, 390b, 390c, 390d, 390e, and 390f. Each of
the command signals 390a-f may be associated with a respective onboard device
200a-f. For example, the first command signal 390a carries a user command
indicator relating to operation of the first onboard device 200a. Data carried
on
a given command signal 390 may contain a reference identifier indicating which
of the onboard devices 200 is intended to respond to the given command signal
390. Data carried on a given command signal 390 may contain an instruction
that the intended onboard device 200 is to execute.
[0042] The control device 300 is also configured to transmit the second
command signals 392, shown as command signals 392a, 392b, 392c, 392d,
392e, and 392f. Each of the command signals 392a-f may be associated with a
respective onboard device 200a-f. Moreover, each of the command signals
392a-f may be transmitted for reception by the tracking device 400. In some
embodiments, a given pair of command signals 390 and 392 may carry the
same user command indicator. For example, the given pair of command signals
390 and 392 are transmitted at or about the same time. In some embodiments,
a pair of command signals 390 and 392 may be separate propagations of a
single signal. For example, the pair of command signals 390 and 392 may be
different directional components of a multi-directional broadcast.
[0043] The onboard devices 200a-f may be configured to transmit the
report signals 290a-f, respectively. Each of the report signals 290a-f may
carry
Information associated with the corresponding onboard device 200a-f.
Moreover, each of the report signals 290a-f may be received by the tracking
device 400. A given report signal (e.g., report signal 290a) may be correlated
with a corresponding command signal (e.g., command signal 392a).
[0044] Referring now to FIG. 7, with continued reference to FIGS. 5 and
6, a conceptual block diagram of the communication system 500 is shown. The
control device 300 may include a processing system 302. The processing
system 302 is capable of communication with a transmitter 309 through a bus
304 or other structures or devices. The processing system 302 can generate
commands and/or other types of data to be provided to the transmitter 309 for
communication by command signals 390, 392. In some embodiments, the
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control device 300 may also include a receiver (not shown) and a power source
(not shown).
[0045] The processing system 302 may include a processor for
executing instructions and may further include a non-transitory machine-
readable medium 319, such as a volatile or non-volatile memory, for storing
data and/or instructions for software programs. The instructions may be
executed by the processing system 302 to control and manage access to the
various networks, as well as provide other communication and processing
functions. The instructions may also include instructions executed by the
processing system 302 for various components of the control device 300, such
as a display 312, an input 314, and an interface 316.
[0046] The onboard device 200 shown in FIG. 7 is representative of any
one of the onboard devices 200a-f of FIGS. 4-6. The onboard device 200 may
include a processing system 202 capable of communication with a receiver 206
and a transmitter 209 through a bus 204 or other structures or devices. The
processing system 202 can acquire, record, and generate data to be provided to
the transmitter 209 for communication as the report signal 290. In addition,
commands and/or other types of data, communicated as the command signal
390, can be received at the receiver 206 and processed by the processing
system 202. A transceiver block 207 may represent one or more transceivers,
and each transceiver may include a receiver 206 and a transmitter 209. 207
[0047] The processing system 202 may include a processor for
executing instructions and may further include a non-transitory machine-
readable medium 219, such as a volatile or non-volatile memory, for storing
data and/or instructions for software programs. The instructions, which may be
stored in the machine-readable medium 219, may be executed by the
processing system 202 to control and manage access to the various networks,
as well as provide other communication and processing functions. The
instructions may also include instructions executed by the processing system
202 for various components of the onboard device 200, such as an onboard
control 214 and one or more sensors 216.
[0048] According to some embodiments, the onboard device 200 may
be configured to operate a corresponding mechanical device to which it is
operably connected. For example, each onboard device 200 includes an onboard
control 214 configured to open, partially open, close, partially close,
activate,
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and/or deactivate a corresponding valve. Such actions may be achieved by
rotating or moving the valve. For example, the onboard device 200 may include
a pneumatic actuator that operates a cell, canister, or tank of a compressible
fluid for operation of a valve. The compressible fluid may include nitrogen,
oxygen, air, or any compressible gas. At least a portion of the pneumatic
actuator may connect to a chamber of the cement head 100, such as the
internal control line 162 shown in FIG. 1D. In other embodiments, the onboard
device 200 may include any other type of actuating device capable of
manipulating a corresponding valve including, but not limited to, mechanical
actuators, electromechanical actuators, hydraulic actuators, piston and
solenoid
assemblies, combinations thereof, and the like. By further example, such
actions may be applied to other mechanical devices of the cement head 100,
such as levers and/or plungers.
[0049] According to some embodiments, the onboard device 200 may
further be configured to sense, detect, and/or measure one or more parameters
of a corresponding mechanical device to which it is operably connected or one
or
more parameters of the cement head 100. For example, the sensors 216 may
be sensitive to a state of the mechanical device (e.g., open, partially open,
closed, partially closed, present, absent, and the like). For example, the
sensors
216 may detect a time at which a mechanical device changes from one state
(e.g., open) to another state (e.g., closed). The sensors 216 may detect the
presence, absence, or motion of a plunger and an associated time. For example,
one or more sensors 216 may detect a time at which a plunger is released and a
time that the plunger arrives at a given location after release. The sensors
216
may further be sensitive to conditions within the cement head 100 (e.g.,
pressure, flow rate, temperature, proximity sensors, and the like). As will be
appreciated, multiple sensors may be provided in or otherwise associated with
each onboard device 200, each having a distinct sensitivity and function. In
at
least one embodiment, one or more sensors may also be installed in wellbore
projectiles to be launched from the cement head 100.
[0050] According to some embodiments, the onboard device 200 may
include a power source 212 for operation. For example, the power source 212
powers operation of the onboard control 214, the sensors 216, the receiver
206,
the transmitter 209, and/or the processing system 202. The power source 212
may include a battery (e.g., a rechargeable battery), a generator, a solar
panel,
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and/or combinations thereof. As will be appreciated, a single power source 212
may be configured to provide power to more than one onboard device 200.
[0051] The tracking device 400 may include a processing system 402.
The processing system 402 is capable of communication with a receiver 406
through a bus 404 or other structures or devices. Reports and/or other types
of
data, communicated as the report signal 290, can be received at the receiver
406 and processed by the processing system 402. The tracking device 400 may
also include a transmitter (not shown). The tracking device 400 may also
include
a power source (not shown).
[0052] The processing system 402 may include a processor for
executing instructions and may further include a non-transitory machine-
readable medium 419, such as a volatile or non-volatile memory, for storing
data and/or instructions for software programs. The instructions, which may be
stored in a non-transitory machine-readable medium 410 and/or 419, may be
executed by the processing system 402 to control and manage access to the
various networks, as well as provide other communication and processing
functions. The instructions may also include instructions executed by the
processing system 402 for various components of the tracking device 400, such
as an interface 416 and the machine-readable medium 419. The machine-
readable medium 419 provides storage of data apart from the processing system
402. For example, data communicated as the report signal 290 may be
recorded or otherwise stored in the machine-readable medium 419. The data
may be further communicated between the tracking device 400 and another
device, such as a computer, a server, or a hand-held device, for display,
review,
analysis, or manipulation.
[0053] The processing systems 202, 302, 402 may be implemented
using software, hardware, or a combination of both. By way of example, the
processing systems 202, 302, 402 may each be implemented with one or more
processors. A processor
may be a general-purpose microprocessor, a
microcontroller, a Digital Signal Processor (DSP), an Application Specific
Integrated Circuit (ASIC), a Field Programmable Gate Array (FPGA), a
Programmable Logic Device (PLD), a controller, a state machine, gated logic,
discrete hardware components, or any other suitable device that can perform
calculations or other manipulations of information.
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[0054] A machine-readable medium can be one or more machine-
readable media. Software shall be construed broadly to mean instructions,
data,
or any combination thereof, whether referred to as software, firmware,
middleware, microcode, hardware description language, or otherwise.
Instructions may include code (e.g., in source code format, binary code
format,
executable code format, or any other suitable format of code).
[0055] Machine-readable media (e.g., 219, 319, 419) may include
storage integrated into a processing system, such as might be the case with an
ASIC. Machine-readable media (e.g., 410) may also include storage external to
a processing system, such as a Random Access Memory (RAM), a flash memory,
a Read Only Memory (ROM), a Programmable Read-Only Memory (PROM), an
Erasable PROM (EPROM), registers, a hard disk, a removable disk, a CD-ROM, a
DVD, or any other suitable storage device. Those skilled in the art will
recognize
how best to implement the described functionality for the processing systems
202, 302, 402. According to one aspect of the disclosure, a machine-readable
medium is a computer-readable medium encoded or stored with instructions and
is a computing element, which defines structural and functional
interrelationships between the instructions and the rest of the system, which
permit the instructions' functionality to be realized. In one aspect, a
machine-
readable medium is a non-transitory machine-readable medium, a machine-
readable storage medium, or a non-transitory machine-readable storage
medium. In one aspect, a computer-readable medium is a non-transitory
computer-readable medium, a computer-readable storage medium, or a non-
transitory computer-readable storage medium. Instructions may be executable,
for example, by a client device or server or by a processing system of a
client
device or server. Instructions can be, for example, a computer program
including code.
[0056] The interfaces 316, 416 may be any type of interface and may
reside between any of the components shown in FIG. 7. The interfaces 316, 416
may also be, for example, an interface to the outside world (e.g., an Internet
network interface). A functionality implemented in a processing system may be
implemented in a portion of a receiver, a portion of a transmitter, a portion
of a
machine-readable medium, a portion of a display, a portion of a keypad, or a
portion of an interface, and vice versa.
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[0057] As mentioned above, components (he., transmitters, receivers)
of the onboard device 200, the control device 300, and the tracking device 400
may be configured to perform wired or wireless communication. The
transmitters and receivers may send and receive radio frequency (RE) signals,
infrared (IR) frequency signals, or other electromagnetic signals. Any of a
variety of modulation techniques may be used to modulate data on a respective
electromagnetic carrier wave. Alternatively, wired communications may also be
performed. Communications protocols for managing communication are known,
and may include IEEE 802.11, IEEE 802.3, USB-compatible, Bluetooth, etc.
[0058] Referring now to FIG. 8, a flow chart illustrating a method 800 is
shown. Various steps performed by the control device 300, the onboard device
200, and the tracking device 400 are illustrated.
[0059] As shown in FIG. 8, a user may provide a user command to the
control device 300, as at 802. In response, the control device 300 transmits a
user command indicator via a first command signal 390 and a second command
signal 392, as at 804. In response to the first command signal 390, the
onboard
device 200 may operate a mechanical device, such as a valve, a lever, or a
plunger, as at 806, and/or sense a parameter, as at 808. Furthermore, the
onboard device 200, in response to the first command signal 390 or an
additional command signal, may cease operation of the mechanical device, as at
810, and/or sense an additional parameter, as at 812. Each
operation
performed or parameter sensed by the onboard device 200 may generate a
status indicator transmitted via a report signal 290, as at 814. Multiple
report
signals 290 may be transmitted or a single report signal 290 containing
multiple
data values may be transmitted.
[0060] As further shown in FIG. 8, the tracking device 400 receives the
second command signal 392 and its associated user command Indicator. In
response, the tracking device 400 records the user command indicator, as at
816. Further, the tracking device 400 receives the report signal 290 and its
associated status indicator from the onboard device 200. In response, the
tracking device 400 records the status indicator, as at 818.
[0061] Additional user commands may be provided to the control device
300 at any time during the operation described and illustrated in FIG. 8. The
additional user commands may the control device 300, the onboard device 200,
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and/or the tracking device 400 to perform additional operations subsequent to
or
simultaneous with previously initiated operations.
[0062] The steps illustrated, a subset of the steps illustrated, or
additional steps may be performed in any order. Any two or more steps may be
performed in series or in parallel (e.g., simultaneously). Furthermore,
operations associated with the control device 300, the onboard device 200, or
the tracking device 400 as illustrated in FIG. 8 may be performed by a device
other than the device as shown in FIG. 8. Multiple methods 800 may be
performed in series or In parallel. For example, a method 800, or portions
thereof, may be performed for each of a plurality of onboard devices 200.
[0063] Embodiments disclosed herein include:
[0064] A. A system that includes a control device configured to
transmit user command indicators in the form of first command signals and
second command signals, an onboard device operably connected to a mechanical
device of a cement head and configured to receive the first command signals
from the control device and operate the mechanical device in response thereto,
the onboard device being further configured to prepare and transmit a report
signal, wherein the report signal encompasses a status indicator of the cement
head, and a tracking device configured to receive the second command signals
from the control device and the status indicator from the onboard device, the
tracking device being further configured to record the user command indicators
and the status indicator.
[0065] B. A method that includes transmitting a first command signal
to an onboard device from a control device, operating a mechanical device of a
cement head with the onboard device in response to the first command signal,
transmitting a report signal to a tracking device, the report signal
encompassing
a status indicator of the cement head, recording the status indicator from the
onboard device with the tracking device, transmitting the user command
indicator from the control device to the tracking device via a second command
signal, and recording the user command indicator with the tracking device.
[0066] C. A method that includes transmitting a first command signal
to an onboard device with a control device, transmitting a second command
signal to a tracking device with the control device, operating a mechanical
device
of a cement head with the onboard device in response to the first command
signal, transmitting a status indicator of the cement head from the onboard
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device to the tracking device via a report signal, and recording the status
indicator and the second command signal with the tracking device.
[0067] Each of embodiments A, B, and C may have one or more of the
following additional elements in any combination: Element 1: wherein the user
command indicator comprises a time that the control device transmits the user
command indicator. Element 2: wherein the status indicator comprises a time
that the onboard device receives the first command signals, a parameter sensed
by a sensor of the onboard device, a time that the onboard device commences
an operation of the mechanical device, or a time that the onboard device
ceases
an operation of the mechanical device. Element 3: further comprising a report
signal wherein the first command signal, the second command signal, and the
report signal are wireless signals. Element 4: wherein the control device
comprises a wireless transmitter, the onboard device comprises a wireless
receiver and a wireless transmitter, and the tracking device comprises a
wireless
receiver. Element 5: wherein the onboard device comprises a sensor configured
to sense one or more parameters of the cement head. Element 6: wherein the
mechanical device is a valve, a lever, or a plunger.
[0068] Therefore, the disclosed systems and methods are well adapted
to attain the ends and advantages mentioned as well as those that are inherent
therein. The particular embodiments disclosed above are illustrative only, as
the
teachings of the present disclosure may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having the benefit
of
the teachings herein. Furthermore, no limitations are intended to the details
of
construction or design herein shown, other than as described in the claims
below. It is therefore evident that the particular illustrative embodiments
disclosed above may be altered, combined, or modified and all such variations
are considered within the scope of the present disclosure. The systems and
methods illustratively disclosed herein may suitably be practiced in the
absence
of any element that is not specifically disclosed herein and/or any optional
element disclosed herein. While compositions and methods are described in
terms of "comprising," "containing," or "including" various components or
steps,
the compositions and methods can also "consist essentially of" or "consist of"
the
various components and steps. All numbers and ranges disclosed above may
vary by some amount. Whenever a numerical range with a lower limit and an
upper limit is disclosed, any number and any included range falling within the
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range is specifically disclosed. In particular, every range of values (of the
form,
"from about a to about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be understood
to
set forth every number and range encompassed within the broader range of
values. Also, the terms in the claims have their plain, ordinary meaning
unless
otherwise explicitly and clearly defined by the patentee. Moreover, the
indefinite
articles "a" or "an," as used in the claims, are defined herein to mean one or
more than one of the element that it introduces. If there is any conflict in
the
usages of a word or term in this specification and one or more patent or other
documents, the definitions that are consistent with this specification should
be
adopted.
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