U.S. patent application number 16/629779 was filed with the patent office on 2020-07-23 for wireless link to send data between coil tubing and the surface.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Michael Linley FRIPP, Russell Stephen HAAKE, Donald G. KYLE, Adam Harold MARTIN.
Application Number | 20200232318 16/629779 |
Document ID | / |
Family ID | 65811361 |
Filed Date | 2020-07-23 |
United States Patent
Application |
20200232318 |
Kind Code |
A1 |
FRIPP; Michael Linley ; et
al. |
July 23, 2020 |
Wireless Link To Send Data Between Coil Tubing And The Surface
Abstract
A well system and method for wirelessly communicating in a
wellbore. The well system may comprise a coil tubing, a
transceiver, a secondary transceiver, and an information handling
system, wherein the information handling system is configured to
record information from the transceiver. A method for wirelessly
communicating in a wellbore may comprise disposing a coil tubing
into the wellbore, recording a measurement with the transceiver,
communicating the measurement from the transceiver to a secondary
transceiver, transmitting the measurement from the secondary
transceiver to one or more additional secondary transceivers, and
retrieving the measurement from the one or more additional
secondary transceivers by an information handling system.
Inventors: |
FRIPP; Michael Linley;
(Carrollton, TX) ; KYLE; Donald G.; (Plano,
TX) ; MARTIN; Adam Harold; (Addison, TX) ;
HAAKE; Russell Stephen; (Dallas, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
65811361 |
Appl. No.: |
16/629779 |
Filed: |
September 19, 2017 |
PCT Filed: |
September 19, 2017 |
PCT NO: |
PCT/US2017/052142 |
371 Date: |
January 9, 2020 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/16 20130101;
E21B 47/12 20130101; E21B 49/081 20130101 |
International
Class: |
E21B 47/16 20060101
E21B047/16; E21B 49/08 20060101 E21B049/08 |
Claims
1. A well system comprising a coil tubing: a transceiver, wherein
the transceiver is disposed about an end of the coil tubing
opposite a surface; a secondary transceiver, wherein the secondary
transceiver is disposed on a casing; and an information handling
system, wherein the information handling system is configured to
record information from the transceiver.
2. The well system of claim 1, wherein the transceiver further
comprise a sensor, wherein the sensor configured to take
measurements in a wellbore.
3. The well system of claim 1, wherein a downhole tool is disposed
at the end of the coil tubing opposite the surface.
4. The well system of claim 3, wherein the transceiver is disposed
on the downhole tool.
5. The well system of claim 1, wherein the transceiver is operable
to communicate with the secondary transceiver wirelessly.
6. The well system of claim 1, wherein the transceiver is operable
to communicate with the secondary transceiver through an acoustic
pathway.
7. The well system of claim 1, further comprising a downhole tool,
wherein the downhole tool is a sampler, gauge, plug, shut-in tool,
or triggering mechanism.
8. The well system of claim 1, further comprising a knuckle joint,
a trigger, and a sampler.
9. The well system of claim 8, wherein the transceiver is disposed
on the trigger.
10. The well system of claim 1, further comprising a plurality of
transceivers disposed on the coil tubing and a plurality of
secondary transceivers disposed on the casing.
11. A method for wirelessly communicating in a wellbore comprising:
disposing a coil tubing into the wellbore, wherein a transceiver is
disposed about an end of the coil tubing opposite a surface;
recording a measurement with the transceiver, wherein the
transceiver comprises a sensor; communicating the measurement from
the transceiver to a secondary transceiver; transmitting the
measurement from the secondary transceiver to one or more
additional secondary transceivers; and retrieving the measurement
from the one or more additional secondary transceivers by an
information handling system.
12. The method of claim 11, wherein the communicating the
measurement from the transceiver to a secondary transceiver is
performed wirelessly.
13. The method of claim 11, wherein the communicating the
measurement from the transceiver to a secondary transceiver is
performed through an acoustic pathway.
14. The method of claim 11, further comprising pulling up the coil
tubing with the hoist to transmit the measurement.
15. The method of claim 11, wherein a triggering mechanism and a
sampler are connected to the coil tubing through a knuckle
joint.
16. The method of claim 15, further comprising transmitting a
command from the information handling system to the triggering
mechanism and triggering the sampler.
17. The method of claim 11, wherein the communicating the
measurement is performed real time during a drill string test.
18. The method of claim 11, wherein the communicating the
measurement is performed real time during a production logging
test.
19. The method of claim 11, further comprising attaching a downhole
tool to the coil tubing.
20. The method of claim 19, wherein the transceiver is disposed on
the downhole tool.
Description
BACKGROUND
[0001] A common problem associated with stimulating a wellbore is
that a coil tubing system may stimulate the wellbore but a wireline
system may be required to determine the effects of the work
performed on the wellbore by the coil tubing system. Traditionally,
a dedicated run from the wireline system is required to determine
efficacy of stimulation, however this cost considerable time,
money, and effort. For example, not only is time, money, and effort
spent to rig up the coil tubing to stimulate the well, time, money,
and effort is used to rig down the coil tubing so a wireline system
may be rigged up to determine the effects of the work on the
wellbore. If the effects on the wellbore are not satisfactory, even
more time, money, and effort will be exerted to rig down the
wireline and repeat the process. Examples of common types of
operations in which this may occur are stimulation of the wellbore,
cleanup, and/or acidizing and nitrogen lift.
[0002] Additionally, downhole tools disposed at the end of a
wireline may record information and data that may not be accessible
until the wireline is removed from the wellbore. This may lead to
delay in retrieving and/or processing recorded information. After
processing the recorded information the wireline may be disposed
back into wellbore to retrieve more information. This may increase
the time, money, and effort associated with a wireline system.
Communication with downhole tools disposed at the end of a coil
tubing may also be hampered by a lack of ability to communicate
with an operator at the surface. Downhole tools may perform
operation based off timing mechanisms, which may rush the operation
leading to ineffective results. This may also lead to excessive
amounts of lost time, money, and effort to achieve a desired result
within the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] These drawings illustrate certain aspects of some examples
of the present invention, and should not be used to limit or define
the invention.
[0004] FIG. 1 is an example of a well system comprising a
transceiver and a secondary transciever;
[0005] FIG. 2 is an example of a well system further comprising a
downhole tool; and
[0006] FIG. 3 is an example of a well system further comprising a
knuckle joint, a triggering mechanism, and a sampler.
DETAILED DESCRIPTION
[0007] Disclosed are a system and method that relate to the real
time wireless communication between tools disposed at an end of
coil tubing and the surface. During operations with coil tubing,
tools utilized with the coil tubing record information and
measurements during the operation. The recorded information and
measurements may not be communicated to the surface due to physical
restrictions within a wellbore. Thus, the information and
measurements may be retrieved when the coil tubing is removed from
the wellbore. It is often costly to remove the coil tubing and
access the stored information and measurements. Additionally, if
the measurements and information indicate further work may need to
be performed additional cost may be incurred to re-insert the coil
tubing into the wellbore. This process may be repeated multiple
times until a satisfactory result is recorded and reported to
operators on the surface. The disclosed apparatus and method
described below seeks to prevent the removal of coil tubing until
all work has been satisfactorily completed. Real time wireless
communication may be utilized to transmit information and
measurements to the surface in real time.
[0008] FIG. 1 illustrates an example well system 100 for use with a
subterranean well. In the illustrated embodiment, well system 100
may be used to stimulate a formation 102 (e.g., fracking, acid
matrix stimulation, etc.) through coil tubing 104. In examples,
coil tubing 104 may be disposed within conduits (e.g., first casing
106, second casing 108, etc.) The conduits may comprise a suitable
material, such as steel, chromium, or alloys. As illustrated, a
wellbore 110 may extend through formation 102 and/or a plurality of
formations 102. While wellbore 110 is shown extending generally
vertically into formation 102, the principles described herein are
also applicable to wellbores that extend at an angle through
formation 102, such as horizontal and slanted wellbores. For
example, although FIG. 1 shows a vertical or low inclination angle
well, high inclination angle or horizontal placement of the well
and equipment is also possible. It should further be noted that
while FIG. 1 generally depicts a land-based operation, those
skilled in the art will readily recognize that the principles
described herein are equally applicable to subsea operations that
employ floating or sea-based platforms and rigs, without departing
from the scope of the disclosure.
[0009] As illustrated on FIG. 1, one or more conduits, shown here
as first casing 106 and second casing 108 may be disposed in the
wellbore 110. First casing 106 may be in the form of an
intermediate casing, a production casing, a liner, or other
suitable conduit, as will be appreciated by those of ordinary skill
in the art. Second casing 108 may be in the form of a surface
casing, intermediate casing, or other suitable conduit, as will be
appreciated by those of ordinary skill in the art. While not
illustrated, additional conduits may also be installed in the
wellbore 110 as desired for a particular application. In the
illustrated embodiment, first casing 106 and the second casing 108
may be cemented to the walls of wellbore 110 by cement 112. Without
limitation, one or more centralizers 114 may be attached to either
first casing 106 and/or the second casing 108, for example, to
centralize the respective conduit in wellbore 110, as well as
protect additional equipment (e.g., electromagnetic field sensors,
not illustrated).
[0010] In the illustrated embodiment, well system 100 may comprise
a hoist 116 and a transciever 118. Without limitation, transciever
118 may be disposed about the end of coil tubing 104. In examples,
coil tubing 104 may be spooled within hoist 116. In examples, hoist
116 may be used to raise and/or lower coil tubing 104, which may
comprise transciever 118, in wellbore 110. Hoist 116 may attach to
transciever 118 through coil tubing 104. Coil tubing 104 may be any
suitable tubing that may support transciever 118. Coil tubing 104
may also deliver fluids, proppants, and/or the like downhole to
formation 102. As discussed below, there may be additional tools
that may be disposed on coil tubing 104.
[0011] Well system 100 may further comprise an information handling
system 120. Information handling system 100 may be in signal
communication with the transceiver 118. Without limitation, signals
from transceiver 118 may be transmitted through secondary
transceivers 122a-122d which may be disposed on first casing 106.
As discussed below, transceiver 118 and secondary transceivers
122a-122d may operate to pass information and/or measurements to
information handling system 120. As illustrated, information
handling system 120 may be disposed at surface 124. In examples,
information handling system 120 may be disposed downhole. Any
suitable technique may be used for transmitting signals from coil
tubing 104 to information handling system 120. As illustrated, a
communication link 126 (which may be wired or wireless, for
example) may be provided that may transmit data from secondary
transceivers 122a-122d to information handling system 120. Without
limitation in this disclosure, information handling system 120 may
include any instrumentality or aggregate of instrumentalities
operable to compute, classify, process, transmit, receive,
retrieve, originate, switch, store, display, manifest, detect,
record, reproduce, handle, or utilize any form of information,
intelligence, or data for business, scientific, control, or other
purposes. For example, information handling system 120 may be a
personal computer, a network storage device, or any other suitable
device and may vary in size, shape, performance, functionality, and
price. Information handling system 120 may include random access
memory (RAM), one or more processing resources (e.g. a
microprocessor) such as a central processing unit 128 (CPU) or
hardware or software control logic, ROM, and/or other types of
nonvolatile memory. Additional components of information handling
system 120 may include one or more of a monitor 130, an input
device 132 (e.g., keyboard, mouse, etc.) as well as computer media
134 (e.g., optical disks, magnetic disks) that may store code
representative of the above-described methods. Information handling
system 120 may also include one or more buses (not shown) operable
to transmit communications between the various hardware components.
Information handling system 120 may be adapted to receive signals
from transceiver 118 that may be representative of measurements
from a tool disposed on coil tubing 104. Information handling
system 120 may act as a data acquisition system and possibly a data
processing system that analyzes measurements, for example, to
derive one or more properties of formation 102, measurements and/or
information from tool, and/or analyzing measurements on work
performed by well system 100.
[0012] As mentioned above transceiver 118 may be disposed about an
end of coil tubing 104 opposite surface 124, as illustrated in FIG.
1. In examples, transceiver 118 may be disposed at any suitable
location along coil tubing 104. An additional examples, there may
be any number of transceivers 118 disposed at an end of coil tubing
104 opposite surface 124 which may communicate with each other
before communicating with secondary transceivers 122a-122d or
communicate separately to secondary transceivers 122a-122d.
Transceiver 118 may communicate (e.g., wirelessly) with tools, not
illustrated, that may be attached to coil tubing 104 and/or
wellbore 110. Furthermore, transceiver 118 may comprise sensors
that may take measurements and/or record information. Information
and/or measurements recorded and/or stored on transceiver 118 may
be performed by an information handling system 120 disposed within
transceiver 118, not illustrated. As transceiver 118 traverses down
wellbore 110, transceiver 118 may communicate with secondary
transceivers 122a-122d, which may be disposed on first casing 106
and/or second casing 108. During operations, transceiver 118 may
wirelessly transmit information and/or recorded measurements to a
secondary transceivers 122a-122d which may be closest to
transceiver 118. As coil tubing 104 traverses wellbore 110,
transceiver 118 may communicate with different secondary
transceivers 122a-122d as a second secondary transceiver 122b comes
closer to transceiver 118 than a first secondary transceiver 122a.
In examples, transceiver 118 may have physical contact with the
tubing wall adjacent to coil tubing 104 (e.g. first casing 106).
This may be accomplished through one and/or more centralizer,
decentralizer, and/or relying on the inherent eccentricity of
running coil tubing 106 to create an acoustic pathway. Passing
information, measurements, and/or recordings to secondary
transceivers 122a-122d from transceiver 118, the information
measurements, and/or recordings may be transmitted through a chain
of secondary transceivers 122a-122d to information handling system
120, which may be disposed on surface 124.
[0013] Secondary transceivers 122a-122d may communicate with each
other wirelessly through acoustic energy to bring information,
measurements, and/or recordings to information handling system 120
disposed on surface 124. Specifically, secondary transceivers
122a-122d may utilize acoustic energy through a medium they may be
disposed on to communicate information, measurements, and/or
recordings from transceiver 118. For example, a first secondary
transceiver 122a, which may be disposed on first casing 106 may
broadcast acoustic energy through first casing 106 to second
secondary transceiver 122b which may be disposed closer to surface
124 than first secondary transceiver 122a. The acoustic energy may
comprise information, measurements, and/or recordings from
transceiver 118. Second secondary transceiver 122b may capture then
acoustic energy and re-broadcast the acoustic energy to a third
secondary transceiver 122c. This process may be repeated any number
of times until the information and measurements transmitted from
transceiver 118 may be recorded by a final secondary transceiver
122d, which may be attached to information handling system 120
through communication link 126. It should be noted that coil tubing
104 may be pulled up toward surface 124 by hoist 116 before
transmitting information and/or measurements between transceiver
118 and secondary transceiver 122a-122d. This may increase
communication flow during Production Logging Testing (PLT) and may
reduce communication interference. Which may be prevalent in
offshore environments, wherein abrasion between coil tubing 104,
tool, and first casing 106 may occur to do marine heave, which may
hinder communication.
[0014] Well system 100 comprising transceiver 118 and at least one
secondary transceiver 122a-122d may allow an operator to wirelessly
collect PLT (Production Logging Testing) data from wellbore 110
while wellbore 110 may be stimulated with coil tubing 104. This may
allow an operator to evaluate the success of stimulation work in
well system 100 in real time without removing coil tubing 106 from
wellbore 110, which may be expensive and time consuming. Wireless
data collection may be performed numerous times in a single
operation and may be run in tandem with other systems (not
illustrated) in wellbore 110. Obtaining production data and/or
downhole samples in real-time from a flowing well while coil tubing
104 is disposed in wellbore 110 may allow for a faster, cheaper,
and better understanding of formation 102. Utilizing transceiver
118 and secondary transceivers 122a-122d, may allow for real time
two-way data transmission from an end of coil tubing 104 opposite
surface 124. This may allow for two-way communication with any
combination of tools such as PLT, samplers, gauges, plugs, shut-in
tools, and/or the like. Two-way communication may be useful during
stimulation operations within wellbore 110, for example, during a
stimulation operation comprising fracking.
[0015] FIG. 1 further illustrate well system 100 operation to
introduce a fluid into fractures 136. Well system 100 may include a
fluid handling system 138, which may include fluid supply 140,
mixing equipment 142, and pumping equipment 144 which may be
connected to coil tubing 104. Pumping equipment 144 may be fluidly
coupled with the fluid supply 140 and coil tubing 104 to
communicate a fracturing fluid 146 into wellbore 110. Fluid supply
140 and pumping equipment 144 may be above surface 124 while
wellbore 110 is below surface 124.
[0016] Well system 100 may also be used for the injection of a pad
or pre-pad fluid into formation 102 at an injection rate above the
fracture gradient to create at least one fracture 136 in formation
100. Well system 100 may then inject fracturing fluid 146 into
formation 102 surrounding wellbore 110 through perforation 148.
Perforations 148 may allow communication between wellbore 110 and
formation 102. As illustrated, perforations 148 may penetrate first
casing 106 and cement 112 allowing communication between interior
of first casing 106 and fractures 136. A plug 150, which may be any
type of plug for oilfield applications (e.g., bridge plug), may be
disposed in wellbore 110 below perforations 148.
[0017] In accordance with systems, methods, and/or compositions of
the present disclosure, fracturing fluid 146 may be pumped via
pumping equipment 144 from fluid supply 140 down the interior of
first casing 106 through coil tubing 104 and into formation 102 at
or above a fracture gradient of formation 102. Pumping fracturing
fluid 146 at or above the fracture gradient of formation 102 may
create (or enhance) at least one fracture (e.g., fractures 136)
extending from the perforations 148 into formation 102. During
fracking operations, transceiver 118 may record information and
measurements regarding the progression of the fracking operations.
Recorded information and measurements may be communicated to an
operator on the surface from transceiver 118 through secondary
transceivers 122 as detailed above.
[0018] FIG. 2 illustrates an example in which a downhole tool 200
may be disposed at the end of coil tubing 104. In examples,
downhole tool 200 may be any type of tool that may be utilized with
coil tubing 104. For example, tools may be utilized with coil
tubing 104 to stimulate wellbore 110 prior to flowing wellbore 110
during a Drill String Test (DST). Downhole tool 200 disposed at an
end of coil tubing 104 opposite surface 124 may be beneficial if
paired with transceiver 118. This may allow for data and/or samples
to be read in real-time and/or about real-time from a flowing well
while coil tubing 104 may be disposed in wellbore 110 during a DST.
Currently, it is necessary to pull coil tubing 104 out of wellbore
110 and use a wireline to obtain this data. A transceiver 118
communicating with secondary transceivers 122a-122d may form a
real-time two-way data transmission from downhole tool 200. In
examples, downhole tool 200 may comprise samplers, gauges, plugs,
shut-in tools, and/or the like. It should be noted that multiple
downhole tools 200 may be paired with individual transceiver 118
and/or a shared transceiver 118. This may allow an operator on the
surface to control and/or receiver information from any number of
downhole tools 200. As stated above, transceiver 118 may
communicate to the surface through secondary transceivers
122a-122d.
[0019] FIG. 3 illustrate an example in which a sampler 300 may be
disposed at an end of coil tubing 104 opposite surface 124. As
discussed above, sampler 300 may be disposed at the end of coil
tubing 104 during a DST. During a DST it may be desirable to take
single-phase fluid samples.
[0020] Sampler 300 may be provided by a battery, by a mud turbine,
or through a wired pipe from the surface, or through some other
conventional means. In a wireline or slickline environment, power
may be provided by a battery or by power provided from the surface
through the wired drill pipe, wireline, coil tubing, or slickline,
or through some other conventional means.
[0021] Sampler 300 may include transceiver 118, through which
sampler 300 communicate with other actuators and sensors disposed
on coil tubing 104 and/or secondary transceivers 122a-122d. In
examples, transceiver 118 may also be the port through which the
various actuators (e.g. valves) and sensors (e.g., temperature and
pressure sensors) in sampler 300 may be controlled and monitored.
As discussed above, transceiver 118 may include information
handling system 120 that may exercise control and monitoring
functions. The control and monitoring functions may be performed by
information handling system 120 in another part of coil tubing 104
(not shown) or by information handling system 102 disposed on
surface 124.
[0022] Sampler 300 may include a formation probe section, which may
extract fluid from wellbore 110, as described in more detail below,
and may deliver it to a channel (not illustrated) that may extend
from one end of sampler 300 to the other. The channel may be
connected to other downhole tools. Sampler 300 may also include a
quartz gauge section (not illustrated), which may include sensors
to allow measurement of properties, such as temperature and
pressure, of the fluid in the channel. Sampler 300 may include a
flow-control pump-out section (not illustrated), which may include
a high-volume bidirectional pump (not illustrated) for pumping
fluid through the channel. Sampler 300 may include at least one
sample chamber sections (not illustrated) for testing fluid in
wellbore 110.
[0023] Currently, sampling fluid may be performed by a wireline in
which a triggering mechanism 304 and sampler 300 are attached to
the wireline (not illustrated). In examples, information handling
system 120 may send a command through secondary transceivers
122a-122d to transceiver 118, which may be connected to triggering
mechanism 304. For example, a command may be to activate sampler
300. Triggering mechanism may 304 activate sampler 300 through a
timing mechanism and/or acoustic telemetry. As disclosed, sampler
300 may attach to coil tubing 104 through knuckle joint 302.
Transceiver 118 may be disposed on sampler 300 and/or communicate
with sampler 300 from coil tubing 104. Such communication may be
performed wirelessly and/or through a hard connection, such as
wires. This may allow samples to be taken by sampler 300 during a
DST, stimulation, cleanup, and/or an acidizing and nitrogen lift.
Information and/or measurements taken by sampler 300 may be stored
in information handling system 120, which may be disposed downhole
with transceiver 118. In examples, transceiver may transmit the
recorded information and/or measurements to surface 124 through
secondary transceivers 122a-122d, as discussed above. As discussed
above, a two-way communication may be formed utilizing a
transceiver 118 and secondary transceivers 122a-122d. This may
allow an operator to activate sampler 300 at any desirable location
within wellbore 110.
[0024] This method and system may include any of the various
features of the compositions, methods, and system disclosed herein,
including one or more of the following statements.
[0025] Statement 1: A well system comprising a coil tubing: a
transceiver, wherein the transceiver is disposed about an end of
the coil tubing opposite a surface; a secondary transceiver,
wherein the secondary transceiver is disposed on a casing; and an
information handling system, wherein the information handling
system is configured to record information from the
transceiver.
[0026] Statement 2: The well system of statement 1, wherein the
transceiver further comprise a sensor, wherein the sensor
configured to take measurements in a wellbore.
[0027] Statement 3: The well system of statement 1 or statement 2,
wherein a downhole tool is disposed at the end of the coil tubing
opposite the surface.
[0028] Statement 4: The well system of any previous statement,
wherein the transceiver is disposed on the downhole tool.
[0029] Statement 5: The well system of any previous statement,
wherein the transceiver is operable to communicate with the
secondary transceiver wirelessly.
[0030] Statement 6: The well system of any previous statement,
wherein the transceiver is operable to communicate with the
secondary transceiver through an acoustic pathway.
[0031] Statement 7: The well system of any previous statement,
further comprising a downhole tool, wherein the downhole tool is a
sampler, gauge, plug, shut-in tool, or triggering mechanism.
[0032] Statement 8: The well system of any previous statement,
further comprising a knuckle joint, a trigger, and a sampler.
[0033] Statement 9: The well system of any previous statement,
wherein the transceiver is disposed on the trigger.
[0034] Statement 10: The well system of any previous statement,
further comprising a plurality of transceivers disposed on the coil
tubing and a plurality of secondary transceivers disposed on the
casing.
[0035] Statement 11: A method for wirelessly communicating in a
wellbore comprising: disposing a coil tubing into the wellbore,
wherein a transceiver is disposed about an end of the coil tubing
opposite a surface; recording a measurement with the transceiver,
wherein the transceiver comprises a sensor; communicating the
measurement from the transceiver to a secondary transceiver;
transmitting the measurement from the secondary transceiver to one
or more additional secondary transceivers; and retrieving the
measurement from the one or more additional secondary transceivers
by an information handling system.
[0036] Statement 12: The method of statement 11, wherein the
communicating the measurement from the transceiver to a secondary
transceiver is performed wirelessly.
[0037] Statement 13: The method of statement 11 or statement 12,
wherein the communicating the measurement from the transceiver to a
secondary transceiver is performed through an acoustic pathway.
[0038] Statement 14: The method of statement 11-statement 13,
further comprising pulling up the coil tubing with the hoist to
transmit the measurement.
[0039] Statement 15: The method of statement 11-statement 14,
wherein a triggering mechanism and a sampler are connected to the
coil tubing through a knuckle joint.
[0040] Statement 16: The method of statement 11-statement 15,
further comprising transmitting a command from the information
handling system to the triggering mechanism and triggering the
sampler.
[0041] Statement 17: The method of statement 11-statement 16,
wherein the communicating the measurement is performed real time
during a drill string test.
[0042] Statement 18: The method of statement 11-statement 17,
wherein the communicating the measurement is performed real time
during a production logging test.
[0043] Statement 19: The method of statement 11-statement 18,
further comprising attaching a downhole tool to the coil
tubing.
[0044] Statement 20: The method of statement 11-statement 19,
wherein the transceiver is disposed on the downhole tool.
[0045] The preceding description provides various embodiments of
the systems and methods of use disclosed herein which may contain
different method steps and alternative combinations of components.
It should be understood that, although individual embodiments may
be discussed herein, the present disclosure covers all combinations
of the disclosed embodiments, including, without limitation, the
different component combinations, method step combinations, and
properties of the system. It should be understood that the
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. 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.
[0046] For the sake of brevity, only certain ranges are explicitly
disclosed herein. However, ranges from any lower limit may be
combined with any upper limit to recite a range not explicitly
recited, as well as, ranges from any lower limit may be combined
with any other lower limit to recite a range not explicitly
recited, in the same way, ranges from any upper limit may be
combined with any other upper limit to recite a range not
explicitly recited. Additionally, whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range are 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 even if not explicitly recited. Thus,
every point or individual value may serve as its own lower or upper
limit combined with any other point or individual value or any
other lower or upper limit, to recite a range not explicitly
recited.
[0047] Therefore, the present embodiments 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, and may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Although individual
embodiments are discussed, the disclosure covers all combinations
of all of the embodiments. Furthermore, no limitations are intended
to the details of construction or design herein shown, other than
as described in the claims below. Also, the terms in the claims
have their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. It is therefore evident that the
particular illustrative embodiments disclosed above may be altered
or modified and all such variations are considered within the scope
and spirit of those embodiments. If there is any conflict in the
usages of a word or term in this specification and one or more
patent(s) or other documents that may be incorporated herein by
reference, the definitions that are consistent with this
specification should be adopted.
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