U.S. patent application number 17/071790 was filed with the patent office on 2021-08-05 for method and system to conduct measurement while cementing.
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 John Laureto Maida, JR., Neal Gregory Skinner, Christopher Lee STOKELY.
Application Number | 20210238979 17/071790 |
Document ID | / |
Family ID | 1000005166443 |
Filed Date | 2021-08-05 |
United States Patent
Application |
20210238979 |
Kind Code |
A1 |
STOKELY; Christopher Lee ;
et al. |
August 5, 2021 |
METHOD AND SYSTEM TO CONDUCT MEASUREMENT WHILE CEMENTING
Abstract
A system is provided for cementing a wellbore having a casing
string disposed in the wellbore. The system includes a cement tool
operable to be deployed down the wellbore through the casing string
from a surface during cementing process of the wellbore, a fiber
optic cable, and a computing device. The fiber optic cable is
coupled with the cement tool such that the fiber optic cable spans
the wellbore from the cement tool to the surface. The computing
device is communicatively coupled with the fiber optic cable and is
operable to receive and process signals from the fiber optic cable
during the cementing process.
Inventors: |
STOKELY; Christopher Lee;
(Houston, TX) ; Maida, JR.; John Laureto;
(Houston, TX) ; Skinner; Neal Gregory;
(Lewisville, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
1000005166443 |
Appl. No.: |
17/071790 |
Filed: |
October 15, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62969016 |
Jan 31, 2020 |
|
|
|
62969012 |
Jan 31, 2020 |
|
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/005 20200501;
E21B 47/12 20130101; E21B 47/107 20200501 |
International
Class: |
E21B 47/005 20060101
E21B047/005; E21B 47/107 20060101 E21B047/107; E21B 47/12 20060101
E21B047/12 |
Claims
1. A system for cementing a wellbore having a casing string
disposed in the wellbore, the system comprising: a cement tool
operable to be deployed down a wellbore through a casing string
from a surface during cementing process of the wellbore; a fiber
optic cable coupled with the cement tool such that the fiber optic
cable spans the wellbore from the cement tool to the surface; and a
computing device communicatively coupled with the fiber optic
cable, the computing device operable to receive and process signals
from the fiber optic cable during the cementing process.
2. The system of claim 1, wherein the fiber optic cable is a
distributed acoustic sensor, wherein the fiber optic cable
acoustically detects cement properties of the cementing
process.
3. The system of claim 2, wherein the cement properties include
wellbore leak, the wellbore leak including one or more of the
following: gas leak, water leak, hydrocarbon leak, and/or cement
leak.
4. The system of claim 2, wherein the cement properties include one
or more of the following: flow detection external to the wellbore,
cement frothing, activity outside of the wellbore during cement
curing, one or more thief zones, cement integrity, and/or cement
quantity.
5. The system of claim 1, further comprising one or more external
sensors disposed inside and/or outside of the wellbore, the
external sensors operable to acoustically transmit external sensor
data to the fiber optic cable, the computing device receiving the
external sensor data via the fiber optic cable.
6. The system of claim 1, wherein the cement tool includes a cement
plug and/or a dart operable to be received by a lower cement plug
disposed in the wellbore.
7. The system of claim 1, wherein the cement tool is deployed down
the wellbore by injection of displacement fluid from the
surface.
8. A cementing device comprising: a cement tool operable to be
deployed down a wellbore from a surface during cementing process of
the wellbore; and a fiber optic cable coupled with the cement tool
such that the fiber optic cable spans the wellbore from the cement
tool to the surface.
9. The cementing device of claim 8, wherein the fiber optic cable
is a distributed acoustic sensor, wherein the fiber optic cable
acoustically detects cement properties of the cementing
process.
10. The cementing device of claim 9, wherein the cement properties
include wellbore leak, the wellbore leak including one or more of
the following: gas leak, water leak, hydrocarbon leak, and/or
cement leak.
11. The cementing device of claim 9, wherein the cement properties
include one or more of the following: flow detection external to
the wellbore, cement frothing, activity outside of the wellbore
during cement curing, one or more thief zones, cement integrity,
and/or cement quantity.
12. The cementing device of claim 8, wherein the fiber optic cable
is communicatively coupled with a computing device which is
operable to receive and process signals from the fiber optic
cable.
13. The cementing device of claim 12, further comprising one or
more external sensors disposed inside and/or outside of the
wellbore, the external sensors operable to acoustically transmit
external sensor data to the fiber optic cable, the computing device
receiving the external sensor data via the fiber optic cable.
14. The cementing device of claim 8, wherein the cement tool
includes a cement plug and/or a dart operable to be received by a
lower cement plug disposed in the wellbore.
15. The cementing device of claim 8, wherein the cement tool is
deployed down the wellbore by injection of displacement fluid from
the surface.
16. A method comprising: deploying a cementing device down a
wellbore from a surface during cementing process of the wellbore,
the cementing device including: a cement tool; and a fiber optic
cable coupled with the cement tool such that the fiber optic cable
spans the wellbore from the cement tool to the surface;
acoustically detecting, by the fiber optic cable, cement properties
of the cementing process; receiving, by a computing device
communicatively coupled with the fiber optic cable, signals from
the fiber optic cable during the cementing process; and processing,
by the computing device, the signals from the fiber optic
cable.
17. The method of claim 16, wherein the fiber optic cable is a
distributed acoustic sensor.
18. The method of claim 16, wherein the cement tool includes a
cement plug and/or a dart operable to be received by a lower cement
plug disposed in the wellbore.
19. The method of claim 16, further comprising: measuring, by one
or more external sensors disposed inside and/or outside of the
wellbore, parameters of the wellbore and/or the cementing process;
acoustically transmitting, from the one or more external sensors,
external sensor data to the fiber optic cable; receiving, by the
computing device, the external sensor data via the fiber optic
cable.
20. The method of claim 16, further comprising: injecting
displacement fluid into the wellbore from the surface to deploy the
cement tool.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 62/969,016, filed in the U.S. Patent and
Trademark Office on Jan. 31, 2020, and U.S. Provisional Patent
Application No. 62/969,012, filed in the U.S. Patent and Trademark
Office on Jan. 31, 2020, each of which is incorporated herein by
reference in its entirety for all purposes.
FIELD
[0002] The present disclosure relates generally to a system and
method to conduct measurement while cementing. In at least one
example, the present disclosure relates to a system and method to
utilize a fiber optic cable to conduct distributed acoustic sensing
while cementing.
BACKGROUND
[0003] Wellbores are drilled into the earth for a variety of
purposes including tapping into hydrocarbon bearing formations to
extract the hydrocarbons for use as fuel, lubricants, chemical
production, and other purposes.
[0004] During completion of the wellbore, the annular space between
the wellbore wall and a casing string (or casing) can be filled
with cement. This process can be referred to as "cementing" the
wellbore. A lower plug can be inserted into the casing string after
which cement can be pumped into the casing string. An upper plug
can be inserted into the wellbore after a desired amount of cement
has been injected. The upper plug, the cement, and the lower plug
can be forced downhole by injecting displacement fluid into the
casing string. Receiving measurements during cementing can prevent
damage to the well or other errors in the cementing process.
Improving the cement casing can increase the integrity of the
well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] Implementations of the present technology will now be
described, by way of example only, with reference to the attached
figures, wherein:
[0006] FIG. 1 illustrates a diagram of a system for preparation and
delivery of a cement composition to a wellbore in accordance with
aspects of the present disclosure.
[0007] FIG. 2A illustrates a diagram of surface equipment that may
be used in placement of a cement composition in a wellbore in
accordance with aspects of the present disclosure.
[0008] FIG. 2B illustrates a diagram of placement of a cement
composition into a wellbore annulus in accordance with aspects of
the present disclosure.
[0009] FIG. 3A illustrates a diagram of a system deploying a
cementing device including a fiber optic cable using a cement
tool.
[0010] FIG. 3B illustrates a diagram of another example of a system
deploying a cementing device including a fiber optic cable using a
cement tool.
[0011] FIG. 3C illustrates a diagram of another example of a system
deploying a cementing device including a fiber optic cable using a
cement tool.
[0012] FIG. 4A illustrates a diagram of a dart.
[0013] FIG. 4B illustrates a diagram of another example of a
dart.
[0014] FIG. 5 illustrates a diagram of a computing device which may
be employed as shown in FIGS. 3A-3C.
[0015] FIG. 6 is a flow chart of a method for generating a model of
properties and identification of deposits.
DETAILED DESCRIPTION
[0016] It will be appreciated that for simplicity and clarity of
illustration, where appropriate, reference numerals have been
repeated among the different figures to indicate corresponding or
analogous elements. In addition, numerous specific details are set
forth in order to provide a thorough understanding of the examples
described herein. However, it will be understood by those of
ordinary skill in the art that the examples described herein can be
practiced without these specific details. In other instances,
methods, procedures and components have not been described in
detail so as not to obscure the related relevant feature being
described. Also, the description is not to be considered as
limiting the scope of the examples described herein. The drawings
are not necessarily to scale and the proportions of certain parts
may be exaggerated to better illustrate details and features of the
present disclosure.
[0017] This disclosure includes deployment of a fiber optic cable
into a wellbore during a cementing process. The fiber optic cable
is deployed into the wellbore, for example in a casing string, by a
cement tool. The cement tool can include, for example, a cement
plug and/or a dart. In at least one example, the cement tool can be
utilized to displace cement into the annulus of the wellbore as the
cement tool is pushed down the wellbore. In some examples, the
cement tool is forced down the wellbore by injection of
displacement fluid from the surface. The fiber optic cable can be
coupled with the cement tool, and as the cement tool moves down the
wellbore, the fiber optic cable is deployed. Accordingly, the fiber
optic cable can span the wellbore from the surface to the cement
tool.
[0018] The fiber optic cable can function as a distributed acoustic
sensor while in the wellbore. In at least one example, the fiber
optic cable can acoustically measure cementing properties to
monitor the status and progress of the cementing process during the
cementing process. For example, the fiber optic cable as a
distributed acoustic sensor can, during the cementing process,
listen for at least one of the following: wellbore leaks (for
example gas, water, hydrocarbon, cement), flow detection outside of
the wellbore (for example cross zone flow, detection of thief
zones, gas influx, water influx), cement frothing or activity
outside of the wellbore during cement curing, detection of thief
zones, and/or detection of seismic waves (for example from a
vibration truck) to check for cement integrity and/or regions of
large amounts and small amounts of cement.
[0019] In at least one example, the fiber optic cable can also
function as a telemetry system. For example, external sensors
disposed inside and/or outside the wellbore can acoustically
transmit signals and data to be detected by the fiber optic cable.
A computing device communicatively coupled with the fiber optic
cable can then receive and process the signals from the external
sensors.
[0020] The fiber optic cable can survive over great distances, such
as several thousand feet, in the wellbore despite abrasion due to
sand-laden drilling mud, chemical effects, pressure effects, and
the drag on the fiber optic cable due to mud flow down the casing
string. Accordingly, the deployment of the fiber optic cable
utilizes the single trip down the wellbore with a cement tool to be
able to monitor the wellbore and the cementing process during the
cementing process with less cost and less complexity.
[0021] The exemplary cement compositions disclosed herein may
directly or indirectly affect one or more components or pieces of
equipment associated with the preparation, delivery, recapture,
recycling, reuse, and/or disposal of the disclosed cement
compositions. For example, the disclosed cement compositions may
directly or indirectly affect one or more mixers, related mixing
equipment, mud pits, storage facilities or units, composition
separators, heat exchangers, sensors, gauges, pumps, compressors,
and the like used generate, store, monitor, regulate, and/or
recondition the exemplary cement compositions. The disclosed cement
compositions may also directly or indirectly affect any transport
or delivery equipment used to convey the cement compositions to a
well site or downhole such as, for example, any transport vessels,
conduits, pipelines, trucks, tubulars, and/or pipes used to
compositionally move the cement compositions from one location to
another, any pumps, compressors, or motors (e.g., topside or
downhole) used to drive the cement compositions into motion, any
valves or related joints used to regulate the pressure or flow rate
of the cement compositions, and any sensors (i.e., pressure and
temperature), gauges, and/or combinations thereof, and the like.
The disclosed cement compositions may also directly or indirectly
affect the various downhole equipment and tools that may come into
contact with the cement compositions/additives such as, but not
limited to, wellbore casing, wellbore liner, completion string,
insert strings, drill string, coiled tubing, slickline, wireline,
drill pipe, drill collars, mud motors, downhole motors and/or
pumps, cement pumps, surface-mounted motors and/or pumps,
centralizers, turbolizers, scratchers, floats (e.g., shoes,
collars, valves, etc.), logging tools and related telemetry
equipment, actuators (e.g., electromechanical devices,
hydromechanical devices, etc.), sliding sleeves, production
sleeves, plugs, screens, filters, flow control devices (e.g.,
inflow control devices, autonomous inflow control devices, outflow
control devices, etc.), couplings (e.g., electro-hydraulic wet
connect, dry connect, inductive coupler, etc.), control lines
(e.g., electrical, fiber optic, hydraulic, etc.), surveillance
lines, drill bits and reamers, sensors or distributed sensors,
downhole heat exchangers, valves and corresponding actuation
devices, tool seals, packers, cement plugs, bridge plugs, and other
wellbore isolation devices, or components, and the like.
[0022] Referring now to FIG. 1, a system 2 may be used in the
preparation of a cement composition. FIG. 1 illustrates the system
2 for preparation of a cement composition and delivery to a
wellbore in accordance with certain examples. As shown, the cement
composition may be mixed in mixing equipment 4, such as a jet
mixer, re-circulating mixer, and/or a batch mixer, for example, and
then pumped via pumping equipment 6 to the wellbore. In some
examples, the mixing equipment 4 and the pumping equipment 6 may be
disposed on one or more cement trucks. In some examples, a jet
mixer may be used, for example, to continuously mix the
composition, including water, as the cement composition is being
pumped to the wellbore.
[0023] An example technique and system for placing a cement
composition into a subterranean formation is illustrated in FIGS.
2A and 2B. FIG. 2A illustrates surface equipment 10 that may be
used in placement of a cement composition in accordance with
certain examples. It should be noted that while FIG. 2A 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 and/or
sea-based platforms and rigs, without departing from the scope of
the disclosure.
[0024] As illustrated by FIG. 2A, the surface equipment 10 may
include a cementing unit 12, which may include one or more cement
trucks. The cementing unit 12 may include mixing equipment 4 and/or
pumping equipment 6 (for example as shown in FIG. 1). The cementing
unit 12 may pump a cement composition 14 through a feed pipe 16 and
to a cementing head 18 which conveys the cement composition 14
downhole.
[0025] Turning now to FIG. 2B, the cement composition 14 may be
placed into a subterranean formation 20 in accordance with the
disclosure herein. As illustrated, a wellbore 22 may be drilled
into the subterranean formation 20. While wellbore 22 is shown
extending generally vertically into the subterranean formation 20,
the principles described herein are also applicable to wellbores
that extend at an angle through the subterranean formation 20, such
as horizontal, slanted, and/or multilateral wellbores. As
illustrated, the wellbore 22 comprises walls 24. In the illustrated
examples, a surface casing 26 has been inserted into the wellbore
22. The surface casing 26 may be cemented to the walls 24 of the
wellbore 22, for example by cement sheath 28. In the illustrated
example, one or more additional conduits (for example, intermediate
casing, production casing, liners, etc.) shown here as casing
string 30 may also be disposed in the wellbore 22. As illustrated,
a wellbore annulus 32 can be formed between the casing string 30
and the walls 24 of the wellbore 22 and/or the surface casing 26.
In at least one example, one or more centralizers 34 may be
attached to the casing string 30, for example, to maintain the
position of the casing string 30 in the wellbore 22 prior to and/or
during the cementing operation. For example, the centralizers 34
may position the casing string 30 substantially in the center of
the wellbore 22.
[0026] With continued reference to FIG. 2B, the cement composition
14 may be pumped down the interior of the casing string 30. The
cement composition 14 may be allowed to flow down the interior of
the casing string 30 through the casing shoe 42 at the bottom of
the casing string 30 and up around the casing string 30 into the
wellbore annulus 32. The cement composition 14 may be allowed to
set in the wellbore annulus 32, for example, to form a cement
sheath that supports and positions the casing string 30 in the
wellbore 22. While not illustrated, other techniques may also be
utilized for introduction of the cement composition 14. By way of
example, reverse circulation techniques may be used that include
introducing the cement composition 14 into the subterranean
formation 20 by way of the wellbore annulus 32 instead of through
the casing string 30.
[0027] As the cement composition 14 is introduced into the wellbore
22, the cement composition 14 may displace other fluids 36, such as
drilling fluids and/or spacer fluids, that may be present in the
interior of the casing string 30 and/or the wellbore annulus 32. At
least a portion of the displaced fluids 36 may exit the wellbore
annulus 32 via a flow line 38 and be deposited, for example, in one
or more retention pits 40 (for example, a mud pit), as shown on
FIG. 2A. Referring again to FIG. 2B, a bottom plug 44 may be
introduced into the wellbore 22 ahead of the cement composition 14,
for example, to separate the cement composition 14 from the fluids
36 that may be inside the casing string 30 prior to cementing.
After the bottom plug 44 reaches the landing collar 46, a diaphragm
or other suitable device ruptures to allow the cement composition
14 through the bottom plug 44. In FIG. 2B, the bottom plug 44 is
shown on the landing collar 46. In the illustrated example, a top
plug 48 may be introduced into the wellbore 22 behind the cement
composition 14. The top plug 48 may separate the cement composition
14 from a displacement fluid 50 and also push the cement
composition 14 through the bottom plug 44.
[0028] A fiber optic cable can be deployed in the wellbore 22
during cementing. FIGS. 3A-3C illustrate examples of deployment of
cementing device which can include a fiber optic cable and a cement
tool 102 such as a cement plug 116 (shown in FIGS. 3A and 3B)
and/or a dart 306 (shown in FIG. 3C). The cement tool 102 can be
utilized to displace cement 14 into the annulus 32 of the wellbore
22 as the cement tool 102 is pushed down the wellbore 22.
[0029] As illustrated in FIGS. 3A and 3B, a cementing tool 102, for
example a cement plug 116 can be positioned downhole in the casing
string 30. In some examples as illustrated in FIG. 3A, the casing
string 30 can include multiple casing tubes 110 coupled together
end-to-end by casing collars 112. A blowout preventer 107 ("BOP")
can be positioned above a wellhead 109 at the surface 106.
[0030] The cement plug 116 can be an upper cement plug that is
inserted into the casing string 30 after a desired amount of cement
14 has been injected into the casing string 30. In some examples, a
dart (for example as shown in FIG. 3C) for plugging a cement plug
can be used in place of the cement plug 116. The cement plug 116
can be forced downhole by the injection of displacement fluid from
the surface 106. A lower cement plug can be positioned below cement
14 and can be forced downhole until it rests on a floating collar
at the bottom of the casing string 30. In at least one example, the
cement plug 116 can be forced down the wellbore 22 until it
contacts the lower cement plug. In some examples, the cement plug
116 can force the cement 14 down wellbore 22 until the cement plug
116 ruptures the lower cement plug and is forced out of a shoe of
the casing string 30. The cement 14 can flow out of the casing
string 30 and into the annulus 32 of the wellbore 22.
[0031] A fiber optic cable 122 can be coupled to the cement plug
116 and traverse the wellbore 22 from the surface 106 to the
location of the cement plug 116. A light source, for example LED
120, communicatively coupled with the fiber optic cable 122 can
emit a pulse of light (e.g., an optical signal). The LED 120 can
transmit the pulse of light to a receiver 124 positioned the
surface 106. In some examples, the LED 120 can operate at a 1300 nm
wavelength can minimize Rayleigh transmission losses and
hydrogen-induced and coil bend-induced optical power losses. In
some examples, high speed laser diode or other optical sources can
be used in place of the LED 120 and various other optical
wavelengths can be used. For example, wavelengths from about 850 nm
to 5100 nm can make use of the optical low-transmission wavelength
bands in ordinary fused silica multimode and single mode
fibers.
[0032] The pulse of light generated by the LED 120 can be
transmitted to the receiver positioned at the surface 106 using the
fiber optic cable 122. The receiver 124 can be an optical receiver,
for example a photodetector that can convert the optical signal
into electricity.
[0033] In some examples, the receiver 124 can be communicatively
coupled to a computing device 128 by a communication link 130. The
communication link 130 can include a wireless communication link.
The communication link 130 can include wireless interfaces such as
IEEE 802.11, Bluetooth, and/or radio interfaces for accessing
cellular telephone networks (e.g., transceiver/antenna for
accessing a CDMA, GSM, UMTS, and/or other mobile communications
network). In some examples, the communication link 130 may be
wired. A wired communication link can include interfaces such as
Ethernet, USB, IEEE 1394, and/or a fiber optic interface. The
receiver 124 can transmit information related to the optical
signal, for example but not limited to the light pulse count, the
time the light pulse arrived, or other information, to the
computing device 128. In some examples, the receiver 124 can be
coupled to a transmitter that communicates with the computing
device 128.
[0034] In at least one example, the receiver 124 can transmit
information to a computing device 118 communicatively coupled to
the fiber optic cable 122 opposite the receiver 124 via the fiber
optic cable 122. The computing device 118 can receive and/or
demodulate optical signals received through the fiber optic cable
122 from the receiver 124. In some examples, the computing device
118 can be disposed adjacent to the cement plug 116. In some
examples, the computing device 118 can be in communication with
and/or control sensors, motors, or any other suitable downhole
device. For example, the receiver 124 may transmit an optical
signal via the fiber optic cable 122, and the computing device 118
may receive and demodulate the signal to open a valve in a downhole
device.
[0035] In at least one example, the fiber optic cable 122 that
transmits the light pulse to from the LED 120 to receiver 124 can
include an unarmored fiber. The unarmored fiber can include a fiber
core and cladding but no outer buffer. In some examples, the fiber
optic cable 122 can include an armored fiber. The armored fiber can
include a fiber core, a cladding, and an outer buffer. The
inclusion of the outer buffer can increase the diameter of the
fiber optic cable. The fiber optic cable 122 can be a multi-mode or
single-mode optical fiber. The fiber optic cable can include one or
more optical fibers. The fiber optic cable 122 can be a sacrificial
cable that is not retrieved from the wellbore 22 but instead
remains in the wellbore 22 until it destroyed. For example, the
fiber optic cable 122 can be destroyed during stimulation of the
wellbore 22.
[0036] The fiber optic cable 122 can be dispensed from an upper
bobbin or reel 132 positioned within the wellbore 22 proximate to
the surface 106 as the cement plug 116 is forced downhole. In some
examples, the upper reel 132 can be positioned at or adjacent to
the surface 106, for example proximate to the blowout preventer
107. In some examples, the upper reel 132 can be secured within the
wellbore 22 by a securing device, for example by spring loaded
camming feet 136 or other suitable securing mechanisms. The upper
reel 132 can have a zero tension payout that can dispense the fiber
optic cable 122 when there is a tension in the fiber optic cable
122.
[0037] The fiber optic cable 122 can be tensioned by and pulled
along with the displacement fluid being injected into the casing
string 30 to move the cement plug 116 down the wellbore 22. The
upper reel 132 can dispense additional lengths of the fiber optic
cable 122 as the fiber optic cable 122 is tensioned by the
displacement fluid injected into the wellbore 22. In some examples,
the fiber optic cable 122 can spool off the upper reel 132 at the
same rate as the flow of the displacement fluid. The upper reel 132
can prevent the fiber optic cable from breaking or otherwise
becoming damaged as the fiber optic cable 122 and the plug 116
travel downhole.
[0038] In some examples, the fiber optic cable 122 can also be
spooled on and dispensed from a lower bobbin or reel 138 positioned
proximate to the cement plug 116. The lower reel 138 can include a
drag device 139. The drag device 139 can allow the lower reel 138
to dispense the fiber optic cable 122 when a pre-set tension in the
fiber optic cable 122 is reached. The lower reel 138 can prevent
the fiber optic cable from breaking or otherwise becoming damaged
as the fiber optic cable 122 and the cement plug 116 travel down
the wellbore 22. The upper reel 132 and the lower reel 138 can
store greater lengths of unarmored fiber optic cable than armored
fiber optic cable. While FIG. 3A depicts the lower reel 138
positioned below the LED 120 and the computing device 118, In some
examples the lower reel 138 can be positioned elsewhere with
respect to the LED 120 and the computing device 118.
[0039] The fiber optic cable 122 can be dispensed from the upper
reel 132 and/or the lower real 138 in response to the tension in
the fiber optic cable 122 increasing above a pre-set limit. The
upper reel 132 and/or the lower reel 138 can have a zero tension
payout that releases additional lengths of fiber optic cable 122
when the tension in the fiber optic cable 122 increases beyond
zero. In some examples in which an upper reel 132 and a lower reel
138 are both used, the shared fiber payout can minimize potential
fiber over tension or fiber damage from chaffing against the
wellbore or a tubing string. For example, the wellbore 22 can
include a bent or highly deviated heel or can curve and become
horizontal. The upper reel 132 and the lower reel 138 can prevent
the fiber optic cable 122 from breaking, chaffing, or otherwise
becoming damaged as the cement plug 116 and fiber optic cable 122
are forced around a curve into a horizontal or lateral portion of
the wellbore.
[0040] In some examples, the fiber optic cable 122 can be actively
dispensed from the upper reel 132 and/or a lower reel 138 by a
motor. In some examples, one or both of the upper reel 132 and the
lower reel 138 can utilize soft high-temperature rated polymer
cements or binders to hold the fiber optic cable 122 turns together
around the reel. As the fiber optic cable 122 spooled on the
applicable reel is dispensed by the increased tension in the cable,
the fiber optic cable 122 can be peeled from the outermost layer of
the applicable reel.
[0041] FIG. 3B is a schematic diagram of another example of a well
system 100 including a light source that includes a laser 202. The
laser 202 can be positioned at the surface 106 proximate to the BOP
107. The laser 202 can be coupled to the fiber optic cable 122
which can be dispensed at an end by the upper reel 132. The upper
reel 132 can be positioned at the surface 106 proximate to the BOP
107. In some examples, the laser 202 and the upper reel 132 can be
positioned elsewhere at the surface 106 or within the wellbore
22.
[0042] The laser 202 can be a high repetition pulse laser or other
suitable light source. The laser 202 can generate an optical
signal, for example, a series of light pulses that are transmitted
by the fiber optic cable 122. The cement plug 116 can be coupled to
the lower reel 138 and the computing device 118. In some examples,
the computing device 118 can include and/or be coupled to a
modulation device. The modulation device can be, for example but
not limited to, a pendulum switch 204. The pendulum switch 204 can
include a mirror that can be shifted between two positions.
[0043] The optical signal generated by the laser 202 can travel the
length of the fiber optic cable 122 and reach a lower end of the
fiber optic cable 122 proximate to the lower reel 138. The pendulum
switch 204 can be positioned proximate to the lower end of the
fiber optic cable 122. The pendulum switch 204 can modulate the
optical signal (e.g., pulses of light) generated by the laser 202.
In some examples, a piezoelectric sensor, or another suitable
modulation device can be used to modulate the optical signal of the
laser 202. In some examples, the modulation device can modulate,
for example but not limited to, the frequency, amplitude, phase, or
other suitable characteristic of the optical signal.
[0044] In some examples, the pendulum switch 204 can include a
mirror. The position of the mirror of the pendulum switch 204 can
be controlled by the computing device 118. The mirror of the
pendulum switch 204 can have two positions. In a first position,
the mirror of the pendulum switch 204 can reflect the pulse of
light arriving at the lower end of the fiber optic cable 122 away
from the fiber optic cable 122. The pulse of light can fail to be
re-transmitted to the receiver 124 via the fiber optic cable 122.
In a second position, the mirror of the pendulum switch 204 can
reflect the pulse of light arriving at the lower end of the fiber
optic cable 122 back into the fiber optic cable 122. The pulse of
light can be re-transmitted to the receiver 124 via the fiber optic
cable 122. The position of the mirror of the pendulum switch 204
can be controlled by the computing device 118.
[0045] The receiver 124 disposed at or near the surface 106 can
monitor the light pulses transmitted along the fiber optic cable
122. The receiver 124 can detect when a pulse of light transmitted
by the laser 202 is not returned to the receiver 124 via the fiber
optic cable 122. The pulse of light that is transmitted downhole by
the laser 202 but not transmitted back to the surface 106 can
indicate the pendulum switch 204 reflected the light pulse away
from the fiber optic cable 122. In some examples, the receiver 124
can transmit information regarding the light pulses to the
computing device 128. In some examples, the receiver 124 can
include an interferometer. In some examples, the interferometer can
determine the phase of the optical signal.
[0046] FIG. 3C is a schematic diagram of another example of a well
system 100 where the cement device 102 includes a dart 306. A
cement plug 302 having an opening 304 can be lowered into the
wellbore 22 within the casing tube 110 of the casing string 30. The
cement 14 can be pumped into the wellbore 22 and can pass through
the opening 304 of the cement plug 302. After the desired amount of
cement 14 has been pumped into the wellbore 22 a cementing device
102, for example a dart 306, can be launched from the surface to
dock with and seal the opening 304. The dart 306 can be forced
downhole by the injection of the displacement fluid from the
surface.
[0047] FIGS. 4A and 4B illustrate examples of a dart 306. The dart
306 is configured to be utilized during a cementing process. In at
least one example, the dart 306 can abut the walls of the casing
string 30 such that the dart 306 substantially creates a seal
against the walls of the casing string 30. Accordingly, cement does
not pass across the dart 306 as the dart 306 pushes the cement or
any other fluid down the casing string 30 and/or the wellbore 22.
Also, the dart 306 creating the seal permits the displacement fluid
to efficiently and more forcefully push the dart 306 down the
casing string 30 and/or the wellbore 22.
[0048] The computing device 118, the light source 120, and the
lower reel 138 can move downhole with the dart 306. The light
source 120 can generate a pulse of light into the fiber optic cable
122. The pulse of light can be transmitted to the receiver at the
surface by the fiber optic cable 122.
[0049] Once the dart 306 has docked with the cement plug 302, both
devices can be forced downhole by displacement fluid injected from
the surface until the cement plug 302 and dart 306 contact the
lower cement plug.
[0050] In at least one example, one or more additional sensors 312
can be coupled to the fiber optic cable 122 for monitoring one or
more conditions within the wellbore 22. In some examples, the
additional sensor can include a temperature sensor, an acoustic
sensor, a sheer sensor, a pressure sensor, an accelerometer, a
chemical sensor, and/or other suitable sensors. The additional
sensor 312 can monitor one or more conditions within the wellbore
22 and transmit information regarding the condition to the receiver
via the fiber optic cable 122. In some examples, the receiver can
include a transmitter for transmitting commands to the additional
sensor 312 via the fiber optic cable 122.
[0051] The fiber optic cable 122 can function as a sensor. In some
examples, the fiber optic cable 122 can function as a distributed
acoustic sensor. In functioning as the distributed acoustic sensor,
an optical pulse, such as a laser pulse, can be sent along the
fiber optic cable 122. The optical pulse scatters within the fiber
optic cable 122, and changes in the intensity of the reflected
light can be measured. The changes can reflect signals which can be
demodulated by, for example, a computing device 128 to determine
the underlying data or signal. Additionally, the signals can
indicate the location or distance from the receiver 124 which
receives the optical pulse and/or reflections of the optical pulse.
With the fiber optic cable 122 spanning the wellbore 22 from the
surface to the cement tool 102, measurements of the wellbore 22
during cementing process at any location within the span of the
fiber optic cable 122 can be made. Also, the fiber optic cable 122
can survive the span of the wellbore 22 over great distances such
as several thousand feet despite abrasion due to sand-laden
drilling mud, chemical effects, pressure effects, and the drag on
the fiber optic cable 122 due to mud flow down the casing string
30. Additionally, by the fiber optic cable 122 being deployed
within the casing string 30 and/or the wellbore 22 by a cementing
device 102 during the cementing process, a fiber optic cable does
not need to be deployed separately outside of the wellbore 22 which
can be costly. Accordingly, the fiber optic cable 122 can survive,
be cost-efficient, and be effective through completion of the
drilling of the wellbore 22.
[0052] As the distributed acoustic sensor, the fiber optic cable
122 can acoustically detect cement properties of the cementing
process. In at least one example, the cement properties can include
wellbore leak such that the fiber optic cable 122 can detect sounds
that indicate a wellbore leak. Wellbore leaks can include one or
more of the following: gas leak, water leak, hydrocarbon leak,
and/or cement leak. Knowing that there is a rupture or leak in the
wellbore 22 can allow for an early intervention or workover. In
some examples, the cement properties can include one or more of the
following: flow detection external to the wellbore, cement
frothing, activity outside of the wellbore during cement curing,
one or more thief zones, cement integrity, and/or cement quantity.
In some examples, cement integrity can be determined by detection
of seismic waves from a vibration By detection of cement properties
using the fiber optic cable 122, critical items to know at early
stages of a wellbore completion can be detected and allow for the
safe and profitable construction of a wellbore 22.
[0053] As shown in FIGS. 3A-3C, one or more external sensors 300
can be disposed inside and/or outside of the wellbore 22. The
external sensors 300 are operable to measure parameters of the
wellbore 22 and/or the cementing process. For example, external
sensors 300 can include temperature sensors, pressure sensors,
and/or chemical sensors.
[0054] In at least one example, the fiber optic cable 122 can be
utilized for short hop telemetry. The external sensors 300 can be
operable to acoustically transmit external sensor data including
the measured parameters to the fiber optic cable 122. As the fiber
optic cable 122 is functioning as a distributed acoustic sensor,
the acoustic signals sent from the external sensors 300 can then be
wirelessly and inexpensively transmitted to the surface using the
fiber optic cable 122. The computing device 128 can then receive
the external sensor data from the external sensors 300 via the
fiber optic cable 122.
[0055] Short hop acoustic telemetry with the fiber optic cable 122
allows, for example, external sensors 300 placed outside the
wellbore 22 to transmit information to the surface. Also for
example, a casing collar 112 can include a combined telemetry
system with an external sensor 300 and/or a telemetry system for
one or more external sensors 300 disposed in the annulus 32 of the
wellbore 22. The casing collar 112 can acoustically send the
external sensor data to the fiber optic cable 122 in the wellbore
22 which can be monitored at the surface. Also for example, the
external sensors 300 can include RFID sensors disposed in cement
which can acoustically relay external sensor data via the fiber
optic cable 122. In some examples, each of the external sensors 300
can acoustically transmit the external sensor data. In some
examples, a plurality of external sensors 300 may be connected to a
transmission device which can acoustically transmit the external
sensor data to the fiber optic cable 122.
[0056] In some examples, the external sensors 300 can include
permanently installed sensors, and sensors may include, for
example, fiber optic cables cemented in place in the annular space
between the casing and formation. The fiber optic cables may be
clamped to the outside of the casing during the deployment, and
protected by centralizers and cross coupling clamps. Other types of
permanent sensors may include surface and down-hole pressure
sensors, where the pressure sensors may be capable of collecting
data at rates up to 2,000 Hz or even higher.
[0057] The fiber optic cables may house one or several optical
fibers and the optical fibers may be single mode fibers, multi mode
fibers or a combination of single mode and multi mode optical
fibers. The fiber optic sensing systems connected to the optical
fibers may include Distributed Temperature Sensing (DTS) systems,
Distributed Acoustic Sensing (DAS) Systems, Distributed Strain
Sensing (DSS) Systems, quasi-distributed sensing systems where
multiple single point sensors are distributed along an optical
fiber/cable, or single point sensing systems where the sensors are
located at the end of the cable.
[0058] The fiber optic sensing systems may operate using various
sensing principles including but not limited to amplitude based
sensing systems like e.g. DTS systems based on Raman scattering,
phase sensing based systems like e.g. DAS systems based on
interferometric sensing using e.g. homodyne or heterodyne
techniques where the system may sense phase or intensity changes
due to constructive or destructive interference, strain sensing
systems like DSS using dynamic strain measurements based on
interferometric sensors or static strain sensing measurements using
e.g. Brillouin scattering, quasi-distributed sensors based on e.g.
Fiber Bragg Gratings (FBGs) where a wavelength shift is detected or
multiple FBGs are used to form Fabry-Perot type interferometric
sensors for phase or intensity based sensing, or single point fiber
optic sensors based on Fabry-Perot or FBG or intensity based
sensors.
[0059] In some examples, the external sensors 300 can include
electrical sensors. For example, pressure sensors based on quarts
type sensors or strain gauge based sensors or other commonly used
sensing technologies. Pressure sensors, optical or electrical, may
be housed in dedicated gauge mandrels or attached outside the
casing in various configurations for down-hole deployment or
deployed conventionally at the surface well head or flow lines.
[0060] Various hybrid approached where single point or
quasi-distributed or distributed fiber optic sensors are mixed with
e.g. electrical sensors are also anticipated. The fiber optic cable
may then include optical fiber and electrical conductors.
[0061] Temperature measurements from e.g. a DTS system may be used
to determine locations for fluid inflow in the treatment well as
the fluids from the surface are likely to be cooler than formation
temperatures. It is known in the industry to use DTS warm-back
analyses to determine fluid volume placement, this is often done
for water injection wells and the same technique can be used for
fracturing fluid placement. Temperature measurements in observation
wells can be used to determine fluid communication between the
treatment well and observation well, or to determine formation
fluid movement.
[0062] DAS data can be used to determine fluid allocation in
real-time as acoustic noise is generated when fluid flows through
the casing and/or through perforations into the formation. Phase
and intensity based interferometric sensing systems are sensitive
to temperature and mechanical as well as acoustically induced
vibrations. DAS data can be converted from time series date to
frequency domain data using Fast Fourier Transforms (FFT) and other
transforms like wavelet transforms may also be used to generate
different representations of the data. Various frequency ranges can
be used for different purposes and where e.g. low frequency signal
changes may be attributed to formation strain changes or fluid
movement and other frequency ranges may be indicative if fluid or
gas movement. Various filtering techniques may be applied to
generate indicators of events than may be of interest. Indicators
may include formation movement due to growing natural fractures,
formation stress changes during the fracturing operations and this
effect may also be called stress shadowing, fluid seepage during
the fracturing operation as formation movement may force fluid into
and observation well and this may be detected, fluid flow from
fractures, fluid and proppant flow from frac hits. Each indicator
may have a characteristic signature in terms of frequency content
and/or amplitude and/or time dependent behavior, and these
indicators may be. These indicators may also be present at other
data types and not limited to DAS data.
[0063] DAS systems can also be used to detect various seismic
events where stress fields and/or growing fracture networks
generate microseimic events or where perforation charge events may
be used to determine travel time between horizontal wells and this
information can be used from stage to stage to determine changes in
travel time as the formation is fractured and filled with fluid and
proppant. The DAS systems may also be used with surface seismic
sources to generate vertical seismic profiles before, during and
after a fracturing job to determine the effectiveness of the
fracturing job as well as determine production effectiveness.
[0064] DSS data can be generated using various approaches and
static strain data can be used to determine absolute strain changes
over time. Static strain data is often measured using Brillouin
based systems or quasi-distributed strain data from FBG based
system. Static strain may also be used to determine propped
fracture volume by looking at deviations in strain data from a
measured strain baseline before fracturing a stage. It may also be
possible to determine formation properties like permeability,
poroelastic responses and leak off rates based on the change of
strain vs time and the rate at which the strain changes over time.
Dynamic strain data can be used in real-time to detect fracture
growth through an appropriate inversion model, and appropriate
actions like dynamic changes to fluid flow rates in the treatment
well, addition of diverters or chemicals into the fracturing fluid
or changes to proppant concentrations or types can then be used to
mitigate detrimental effects.
[0065] The external sensors 300 may also use Fiber Bragg Grating
based systems for a number of different measurements. FBG's are
partial reflectors that can be used as temperature and strain
sensors, or can be used to make various interferometric sensors
with very high sensitivity. FBG's can be used to make point sensors
or quasi-distributed sensors where these FBG based sensors can be
used independently or with other types of fiber optic based
sensors. FBG's can manufactured into an optical fiber at a specific
wavelength, and other system like DAS, DSS or DTS systems may
operate at different wavelengths in the same fiber and measure
different parameters simultaneously as the FBG based systems using
Wavelength Division Multiplexing (WDM).
[0066] The sensors can be placed in either the treatment well or
monitoring well(s) to measure well communication. The treatment
well pressure, rate, cement composition, proppant concentration,
diverters, fluids and chemicals may be altered to change the
cementing process. These changes may impact the formation responses
in several different ways like e.g.: [0067] stress fields may
change, and this may generate microseismic effects that can be
measured with DAS systems and/or single point seismic sensors like
geophones [0068] the cementing process can generate changes in
measured microseismic events and event distributions over time, or
changes in measured strain using the low frequency portion or the
DAS signal or Brillouin based sensing systems [0069] pressure
changes due to poroelastic effects may be measured in the
monitoring well [0070] pressure data may be measured in the
treatment well and correlated to formation responses [0071] various
changes in treatment rates and pressure may generate events that
can be correlated to the cementing process.
[0072] Several measurements can be combined to determine adjacent
well communication, and this information can be used to change the
cementing process to generate desired outcomes.
[0073] FIG. 5 is a block diagram of an exemplary computing device
118, 128. Computing device 118, 128 is configured to perform
processing of data and communicate with the sensors and/or optical
signals sent and/or received via a fiber optic cable 122, for
example as illustrated in FIGS. 3A-3C. In operation, computing
device 118, 128 communicates with one or more of the
above-discussed components and may also be configured to
communication with remote devices/systems.
[0074] As shown, computing device 118, 128 includes hardware and
software components such as network interfaces 510, at least one
processor 520, sensors 560 and a memory 540 interconnected by a
system bus 550. Network interface(s) 510 can include mechanical,
electrical, and signaling circuitry for communicating data over
communication links, which may include wired or wireless
communication links. Network interfaces 510 are configured to
transmit and/or receive data using any variety of different
communication protocols.
[0075] Processor 520 represents a digital signal processor (e.g., a
microprocessor, a microcontroller, or a fixed-logic processor,
etc.) configured to execute instructions or logic to perform tasks
in a wellbore environment. Processor 520 may include a general
purpose processor, special-purpose processor (where software
instructions are incorporated into the processor), a state machine,
application specific integrated circuit (ASIC), a programmable gate
array (PGA) including a field PGA, an individual component, a
distributed group of processors, and the like. Processor 520
typically operates in conjunction with shared or dedicated
hardware, including but not limited to, hardware capable of
executing software and hardware. For example, processor 520 may
include elements or logic adapted to execute software programs and
manipulate data structures 545, which may reside in memory 540.
[0076] Sensors 560, which may include sensors 300 as disclosed
herein, typically operate in conjunction with processor 520 to
perform measurements, and can include special-purpose processors,
detectors, transmitters, receivers, and the like. In this fashion,
sensors 560 may include hardware/software for generating,
transmitting, receiving, detection, logging, and/or sampling
magnetic fields, seismic activity, and/or acoustic waves, or other
parameters.
[0077] Memory 540 comprises a plurality of storage locations that
are addressable by processor 520 for storing software programs and
data structures 545 associated with the examples described herein.
An operating system 542, portions of which may be typically
resident in memory 540 and executed by processor 520, functionally
organizes the device by, inter alia, invoking operations in support
of software processes and/or services 544 executing on computing
device 118, 128. These software processes and/or services 544 may
perform processing of data and communication with computing device
118, 128, as described herein. Note that while process/service 544
is shown in centralized memory 540, some examples provide for these
processes/services to be operated in a distributed computing
network.
[0078] Other processor and memory types, including various
computer-readable media, may be used to store and execute program
instructions pertaining to the fluidic channel evaluation
techniques described herein. Also, while the description
illustrates various processes, it is expressly contemplated that
various processes may be embodied as modules having portions of the
process/service 544 encoded thereon. In this fashion, the program
modules may be encoded in one or more tangible computer readable
storage media for execution, such as with fixed logic or
programmable logic (e.g., software/computer instructions executed
by a processor, and any processor may be a programmable processor,
programmable digital logic such as field programmable gate arrays
or an ASIC that comprises fixed digital logic. In general, any
process logic may be embodied in processor 520 or computer readable
medium encoded with instructions for execution by processor 520
that, when executed by the processor, are operable to cause the
processor to perform the functions described herein.
[0079] Referring to FIG. 6, a flowchart is presented in accordance
with an example embodiment. The method 600 is provided by way of
example, as there are a variety of ways to carry out the method.
The method 600 described below can be carried out using the
configurations illustrated in FIG. 1-5, for example, and various
elements of these figures are referenced in explaining example
method 600. Each block shown in FIG. 6 represents one or more
processes, methods or subroutines, carried out in the example
method 600. Furthermore, the illustrated order of blocks is
illustrative only and the order of the blocks can change according
to the present disclosure. Additional blocks may be added or fewer
blocks may be utilized, without departing from this disclosure. The
example method 600 can begin at block 602.
[0080] At block 602, a cementing device is deployed down a wellbore
from a surface during cementing process of the wellbore. The
cementing device includes a cement tool and a fiber optic cable
coupled with the cement tool. In at least one example, the cement
tool can include a cement plug and/or a dart operable to be
received by a lower cement plug disposed in the wellbore. The
cement tool can be deployed into the wellbore by injecting
displacement fluid into the wellbore from the surface. As the
cement tool is deployed down the wellbore, for example through a
casing string, the fiber optic cable is dispensed such that the
fiber optic cable spans the wellbore from the cement tool to the
surface.
[0081] At block 604, the fiber optic cable acoustically detects
cement properties of the cementing process. The fiber optic cable
is functioning as a distributed acoustic sensor. As the fiber optic
cable spans the wellbore, the fiber optic cable can acoustically
detect cement properties throughout the wellbore during the
cementing process. In at least one example, the cement properties
can include wellbore leak such that the fiber optic cable can
detect sounds that indicate a wellbore leak. Wellbore leaks can
include one or more of the following: gas leak, water leak,
hydrocarbon leak, and/or cement leak. Knowing that there is a
rupture or leak in the wellbore can allow for an early intervention
or workover. In some examples, the cement properties can include
one or more of the following: flow detection external to the
wellbore, cement frothing, activity outside of the wellbore during
cement curing, one or more thief zones, cement integrity, and/or
cement quantity. In some examples, cement integrity can be
determined by detection of seismic waves from a vibration By
detection of cement properties using the fiber optic cable,
critical items to know at early stages of a wellbore completion can
be detected and allow for the safe and profitable construction of a
wellbore.
[0082] At block 606, a computing device communicatively coupled
with the fiber optic cable receives signals from the fiber optic
cable during the cementing process. At block 608, the computing
device processes the signals from the fiber optic cable. As the
fiber optic cable is disposed either in the wellbore and/or in a
casing string, the measurements taken during the cementing process
can be conducted and processed at the surface with less complexity
and less cost than conventional sensors disposed outside of the
wellbore.
[0083] In at least one example, one or more external sensors
disposed inside and/or outside the wellbore can measure parameters
of the wellbore and/or the cementing process. The fiber optic cable
can be utilized for acoustic short hop telemetry with the external
sensors. External sensor data from the external sensors can be
acoustically transmitted to the fiber optic cable, and the
computing device can then receive the external sensor data via the
fiber optic cable.
[0084] Based on the signals received via the fiber optic cable, the
cementing process can be adjusted as needed. For example, more
cement may be pumped down the wellbore, and/or the cementing
process may be paused.
[0085] Numerous examples are provided herein to enhance
understanding of the present disclosure. A specific set of
statements are provided as follows.
[0086] Statement 1: A system is disclosed for cementing a wellbore
having a casing string disposed in the wellbore, the system
comprising: a cement tool operable to be deployed down a wellbore
through a casing string from a surface during cementing process of
the wellbore; a fiber optic cable coupled with the cement tool such
that the fiber optic cable spans the wellbore from the cement tool
to the surface; and a computing device communicatively coupled with
the fiber optic cable, the computing device operable to receive and
process signals from the fiber optic cable during the cementing
process.
[0087] Statement 2: A system is disclosed according to Statement 1,
wherein the fiber optic cable is a distributed acoustic sensor,
wherein the fiber optic cable acoustically detects cement
properties of the cementing process.
[0088] Statement 3: A system is disclosed according to Statement 2,
wherein the cement properties include wellbore leak, the wellbore
leak including one or more of the following: gas leak, water leak,
hydrocarbon leak, and/or cement leak.
[0089] Statement 4: A system is disclosed according to Statements 2
or 3, wherein the cement properties include one or more of the
following: flow detection external to the wellbore, cement
frothing, activity outside of the wellbore during cement curing,
one or more thief zones, cement integrity, and/or cement
quantity.
[0090] Statement 5: A system is disclosed according to any of
preceding Statements 1-4, further comprising one or more external
sensors disposed inside and/or outside of the wellbore, the
external sensors operable to acoustically transmit external sensor
data to the fiber optic cable, the computing device receiving the
external sensor data via the fiber optic cable.
[0091] Statement 6: A system is disclosed according to any of
preceding Statements 1-5, wherein the cement tool includes a cement
plug and/or a dart operable to be received by a lower cement plug
disposed in the wellbore.
[0092] Statement 7: A system is disclosed according to any of
preceding Statements 1-6, wherein the cement tool is deployed down
the wellbore by injection of displacement fluid from the
surface.
[0093] Statement 8: A cementing device is disclosed comprising: a
cement tool operable to be deployed down a wellbore from a surface
during cementing process of the wellbore; and a fiber optic cable
coupled with the cement tool such that the fiber optic cable spans
the wellbore from the cement tool to the surface.
[0094] Statement 9: A cementing device is disclosed according to
Statement 8, wherein the fiber optic cable is a distributed
acoustic sensor, wherein the fiber optic cable acoustically detects
cement properties of the cementing process.
[0095] Statement 10: A cementing device is disclosed according to
Statement 9, wherein the cement properties include wellbore leak,
the wellbore leak including one or more of the following: gas leak,
water leak, hydrocarbon leak, and/or cement leak.
[0096] Statement 11: A cementing device is disclosed according to
Statements 9 or 10, wherein the cement properties include one or
more of the following: flow detection external to the wellbore,
cement frothing, activity outside of the wellbore during cement
curing, one or more thief zones, cement integrity, and/or cement
quantity.
[0097] Statement 12: A cementing device is disclosed according to
any of preceding Statements 8-11, wherein the fiber optic cable is
communicatively coupled with a computing device which is operable
to receive and process signals from the fiber optic cable.
[0098] Statement 13: A cementing device is disclosed according to
Statement 12, further comprising one or more external sensors
disposed inside and/or outside of the wellbore, the external
sensors operable to acoustically transmit external sensor data to
the fiber optic cable, the computing device receiving the external
sensor data via the fiber optic cable.
[0099] Statement 14: A cementing device is disclosed according to
any of preceding Statements 8-13, wherein the cement tool includes
a cement plug and/or a dart operable to be received by a lower
cement plug disposed in the wellbore.
[0100] Statement 15: A cementing device is disclosed according to
any of preceding Statements 8-14, wherein the cement tool is
deployed down the wellbore by injection of displacement fluid from
the surface.
[0101] Statement 16: A method is disclosed comprising: deploying a
cementing device down a wellbore from a surface during cementing
process of the wellbore, the cementing device including: a cement
tool; and a fiber optic cable coupled with the cement tool such
that the fiber optic cable spans the wellbore from the cement tool
to the surface; and acoustically detecting, by the fiber optic
cable, cement properties of the cementing process; receiving, by a
computing device communicatively coupled with the fiber optic
cable, signals from the fiber optic cable during the cementing
process; and processing, by the computing device, the signals from
the fiber optic cable.
[0102] Statement 17: A method is disclosed according to Statement
16, wherein the fiber optic cable is a distributed acoustic
sensor.
[0103] Statement 18: A method is disclosed according to Statements
16 or 17, wherein the cement tool includes a cement plug and/or a
dart operable to be received by a lower cement plug disposed in the
wellbore.
[0104] Statement 19: A method is disclosed according to any of
preceding Statements 16-18, further comprising: measuring, by one
or more external sensors disposed inside and/or outside of the
wellbore, parameters of the wellbore and/or the cementing process;
acoustically transmitting, from the one or more external sensors,
external sensor data to the fiber optic cable; receiving, by the
computing device, the external sensor data via the fiber optic
cable.
[0105] Statement 20: A method is disclosed according to any of
preceding Statements 16-19, further comprising: injecting
displacement fluid into the wellbore from the surface to deploy the
cement tool.
[0106] The disclosures shown and described above are only examples.
Even though numerous properties and advantages of the present
technology have been set forth in the foregoing description,
together with details of the structure and function of the present
disclosure, the disclosure is illustrative only, and changes may be
made in the detail, especially in matters of shape, size and
arrangement of the parts within the principles of the present
disclosure to the full extent indicated by the broad general
meaning of the terms used in the attached claims. It will therefore
be appreciated that the examples described above may be modified
within the scope of the appended claims.
* * * * *