U.S. patent application number 14/395045 was filed with the patent office on 2015-05-14 for method and apparatus for monitoring a downhole tool.
The applicant listed for this patent is WEATHERFORD/LAMB, INC.. Invention is credited to Francis Bostick, III, Sean M. Christian, Brian Keith Drakeley, Dean Taylor Lehner, Jeffrey John Lembcke, Lev Ring.
Application Number | 20150134253 14/395045 |
Document ID | / |
Family ID | 48325877 |
Filed Date | 2015-05-14 |
United States Patent
Application |
20150134253 |
Kind Code |
A1 |
Ring; Lev ; et al. |
May 14, 2015 |
METHOD AND APPARATUS FOR MONITORING A DOWNHOLE TOOL
Abstract
A telemetry system and method configured to communicate a
wellbore parameter such as fluid composition, temperature, and
pressure. In one embodiment, a plurality of tracers is stored
downhole, and each of the tracers represents a different value of
the wellbore parameter. After measuring the wellbore parameter, the
measured value is correlated to one or more of the plurality of
tracers that is equivalent to the measured value of the downhole
parameter. The one or more tracers representing the measured value
are then released from their respective containers to travel
upstream. A sensor located upstream may detect the one or more
tracers, which are then correlated back to obtain the measured
value of the wellbore parameter. In another embodiment, ratiometric
amounts of the tracers may be used to represent additional values
of the wellbore parameter.
Inventors: |
Ring; Lev; (Houston, TX)
; Lembcke; Jeffrey John; (Cypress, TX) ; Lehner;
Dean Taylor; (Katy, TX) ; Bostick, III; Francis;
(Houston, TX) ; Drakeley; Brian Keith; (Humble,
TX) ; Christian; Sean M.; (Sparrows Point,
MD) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
WEATHERFORD/LAMB, INC. |
Houston |
TX |
US |
|
|
Family ID: |
48325877 |
Appl. No.: |
14/395045 |
Filed: |
April 16, 2013 |
PCT Filed: |
April 16, 2013 |
PCT NO: |
PCT/US2013/036839 |
371 Date: |
October 16, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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61800614 |
Mar 15, 2013 |
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61798767 |
Mar 15, 2013 |
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61650421 |
May 22, 2012 |
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61624850 |
Apr 16, 2012 |
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Current U.S.
Class: |
702/6 |
Current CPC
Class: |
E21B 47/11 20200501;
E21B 47/12 20130101 |
Class at
Publication: |
702/6 |
International
Class: |
E21B 47/12 20060101
E21B047/12 |
Claims
1. A method of communicating a wellbore parameter from a downhole
tool, comprising: providing a plurality of tracers for representing
a value of the wellbore parameter; measuring the wellbore parameter
using a sensor; correlating the wellbore parameter to a value
represented by one or more of the plurality of tracers; releasing
the one or more of the plurality of tracers to travel upstream;
detecting presence of the one or more of the plurality of tracers;
and determining the wellbore parameter from the detected one or
more of the plurality of tracers.
2. The method of claim 1, wherein each of the plurality of tracers
is assigned a different value.
3. The method of claim 1, wherein each of the plurality of tracers
comprises a chemical.
4. A system for communicating a wellbore parameter from a downhole
tool, comprising: a plurality of tracers for representing a value
of the wellbore parameter; a plurality of containers for storing
the plurality of tracers; a first sensor for measuring the wellbore
parameter; a downhole controller configured to correlate the
wellbore parameter to one or more of the plurality of tracers and
configured to release the one or more of the plurality of the
tracers; an second sensor for detecting presence of the one or more
of the plurality of tracers; and an uphole controller configured to
determine the wellbore parameter from the detected one or more of
the plurality of tracers.
5. The system of claim 4, wherein each of the plurality of tracers
is assigned a different value.
6. The system of claim 4, wherein each of the plurality of tracers
comprises a chemical.
7. The system of claim 4, wherein the container is pressurized.
8. The system of claim 4, wherein the first sensor is located
downhole and the second sensor is located uphole.
9. A method of communicating a wellbore parameter from multiple
downhole tools, comprising: associating a first set of tracers to a
first downhole tool; associating a second set of tracers to a
second downhole tool, wherein the first and second set of tracers
represent a value of the wellbore parameter; measuring the wellbore
parameter using a sensor of the first downhole tool; correlating
the wellbore parameter to a value represented by one or more of the
first set of tracers; releasing the one or more of the first set of
tracers to travel upstream; detecting presence of the one or more
of the first set of tracers; determining the wellbore parameter
from the detected one or more of the first set of tracers; and
determining the one or more of the first set of tracers was sent
from the first downhole tool.
10. The method of claim 9, wherein each of the first set of tracers
is assigned a different value.
11. The method of claim 9, wherein each of the first set of tracers
comprises a chemical.
12-22. (canceled)
23. A method of communicating a wellbore parameter from a downhole
tool, comprising: providing a plurality of tracer chemicals,
whereby a code comprising a plurality of code elements correlates
to a release of a single tracer chemical or a unique combination of
a subset of the plurality of tracer chemicals to a specific value
or a range of values of the wellbore parameter; measuring a value
of the wellbore parameter using a sensor; ascribing the measured
value to a code element; releasing one or more of the plurality of
tracer chemicals corresponding to the code element; detecting the
presence of the one or more of the plurality of tracer chemicals;
and determining the specific value or range of values of the
measured wellbore parameter from the detection of the one or more
of the plurality of tracer chemicals.
24. The method of claim 23, wherein ascribing the measured value to
a code element is performed downhole.
25. The method of claim 23, wherein detecting the presence of one
or more of the plurality of tracer chemicals is performed at a
surface of the wellbore.
26-29. (canceled)
30. A method of communicating a wellbore parameter from a downhole
tool, comprising: providing a plurality of tracers for representing
a value of the wellbore parameter; measuring the wellbore parameter
using a sensor; correlating the wellbore parameter to a value
represented by a ratiometric amount of one or more of the plurality
of tracers; releasing the ratiometric amount of one or more of the
plurality of tracers to travel upstream; detecting presence of the
ratiometric amount one or more of the plurality of tracers; and
determining the wellbore parameter from the detected ratiometric
amount of one or more of the plurality of tracers.
31. The method of claim 30, further comprising releasing a
calibration dosage of the plurality of tracers.
32. The method of claim 30, wherein each ratiometric amount of the
plurality of tracers is assigned a different value.
33. The method of claim 30, wherein each of the plurality of
tracers comprises a chemical.
34. The method of claim 30, wherein each tracer is released from a
container storing the tracer.
35. The method of claim 34, further comprising opening the
container using a mechanical actuator.
36-44. (canceled)
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of U.S. Provisional Patent
Application No. 61/624,850, filed Apr. 16, 2012; U.S. Provisional
Patent Application No. 61/650,421, filed May 22, 2012; U.S.
Provisional Patent Application No. 61/798,767, filed Mar. 15, 2013;
and U.S. Provisional Patent Application No. 61/800,614, filed Mar.
15, 2013; which applications are incorporated herein by reference
in their entirety.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the present invention generally relate to a
telemetry system for communicating information from a downhole
tool. Particularly, embodiments of the invention relate to a
chemical telemetry system for communicating information from a
downhole tool.
[0004] 2. Description of the Related Art
[0005] Optimal oil production from the reservoir depends upon
reliable knowledge of the reservoir characteristics. Traditional
methods for reservoir monitoring include seismic log
interpretation, well pressure testing, production fluid analysis,
and production history matching. Due to the complexity of the
reservoir, all information available is valuable in order to give
the operator the best possible knowledge about the dynamics in the
reservoir.
[0006] Fiber or electrical cables with a sensor have been used in
the industry to communicate information to and from a downhole
tool. However, one drawback of cable is that it requires a direct
connection with the downhole tool. This direct connection increases
the cost of the operation.
[0007] There is a need, therefore, for a telemetry system to
communicate information about the wellbore from a downhole
tool.
SUMMARY OF THE INVENTION
[0008] In one embodiment, a method of communicating a wellbore
parameter from a downhole tool includes providing a plurality of
tracers for representing a value of the wellbore parameter;
measuring the wellbore parameter using a sensor; correlating the
wellbore parameter to a value represented by one or more of the
plurality of tracers; releasing the one or more of the plurality of
tracers to travel upstream; detecting presence of the one or more
of the plurality of tracers; and determining the wellbore parameter
from the detected one or more of the plurality of tracers.
[0009] In another embodiment, a system for communicating a wellbore
parameter from a downhole tool includes a plurality of tracers for
representing a value of the wellbore parameter; a plurality of
containers for storing the plurality of tracers; a first sensor for
measuring the wellbore parameter; a downhole controller configured
to correlate the wellbore parameter to one or more of the plurality
of tracers and configured to release the one or more of the
plurality of the tracers; an second sensor for detecting presence
of the one or more of the plurality of tracers; and an uphole
controller configured to determine the wellbore parameter from the
detected one or more of the plurality of tracers.
[0010] In one or more of the embodiment disclosed herein, each of
the plurality of tracers represents a different value of the
wellbore parameter.
[0011] In one or more of the embodiment disclosed herein, each of
the plurality of tracers comprises a chemical.
[0012] In another embodiment, a method of communicating a wellbore
parameter from a downhole tool includes providing a plurality of
tracers for representing a value of the wellbore parameter;
measuring the wellbore parameter using a sensor; correlating the
wellbore parameter to a value represented by a ratiometric amount
of one or more of the plurality of tracers; releasing the
ratiometric amount of one or more of the plurality of tracers to
travel upstream; detecting presence of the ratiometric amount of
one or more of the plurality of tracers; and determining the
wellbore parameter from the detected ratiometric amount of one or
more of the plurality of tracers.
[0013] In one or more of the embodiment disclosed herein, the
method further includes releasing a calibration dosage of the
plurality of tracers.
[0014] In another embodiment, a method of monitoring status of a
downhole tool includes providing a plurality of tracers for
representing a status of the downhole tool; changing the status of
the downhole tool; and releasing a tracer representing the changed
status of the downhole tool. In another embodiment, changing the
status of the downhole tool comprises moving a component of the
downhole tool. In yet another embodiment, the tracer is released in
response to movement of the component.
[0015] In another embodiment, a method of monitoring a downhole
tool includes storing the plurality of tracers in a plurality of
chambers, wherein the tracers in each of the plurality of chambers
represent a different position of a component of the downhole tool;
moving the component to change the position of the component;
sequentially opening the plurality of chambers as the component is
being moved, thereby releasing the tracers from the opened
chambers; detecting the tracers being released; and determining the
position of the component. In another embodiment, the plurality of
chambers are closed by the component. In yet another embodiment,
the plurality of chambers are closed by a respective cover that is
coupled to the component.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0017] FIG. 1 shows an exemplary embodiment of a telemetry
system.
[0018] FIG. 2 is a table showing the exemplary values of the
tracers B1, B2, B3 in the first zone of the telemetry system of
FIG. 1.
[0019] FIG. 3 shows an exemplary embodiment of a telemetry system
for use with a multilateral wellbore.
[0020] FIG. 4 shows an exemplary embodiment of a telemetry system
for use in a fracturing operation. FIG. 4A illustrates an exemplary
embodiment of a container.
[0021] FIG. 5 shows an exemplary embodiment of a telemetry system
for use with a subsurface valve.
[0022] FIG. 6 shows an exemplary embodiment of a telemetry system
for use with a downhole pump.
[0023] FIG. 7 shows an exemplary embodiment of a telemetry system
for use with a steam assisted gravity drainage system.
[0024] FIGS. 8A-B illustrate another embodiment of a chemical
communication system for monitoring a downhole tool.
[0025] FIG. 9 illustrates a partial view of another embodiment of a
valve.
[0026] FIG. 10 is an exemplary graph showing measured values of
tracers released in ratiometric amounts.
[0027] FIG. 11 is an exemplary graph showing measured values of one
tracer released as a function of time.
[0028] FIG. 12 is an exemplary graph showing measured values of one
tracer released as a function of time and concentration.
DETAILED DESCRIPTION
[0029] Embodiments of the present invention relate to a telemetry
system and method for communicating a wellbore parameter such as
fluid composition, temperature, and pressure. In one embodiment, a
plurality of tracers is stored downhole, and each of the tracers
represents a different value of the wellbore parameter. After
measuring the wellbore parameter, the measured value is correlated
to one or more of the plurality of tracers that is equivalent to
the measured value of the downhole parameter. The one or more
tracers representing the measured value are then released from
their respective containers to travel upstream. A sensor located
upstream may detect the one or more tracers, which are then
correlated back to obtain the measured value of the wellbore
parameter.
[0030] In one embodiment, a code may be used to convey information
about a wellbore parameter, such as fluid composition, temperature,
and pressure. The code may include a plurality of code elements.
Each of the code elements may represent a different value of the
wellbore parameter. The value represented may be a single value or
a range of values. The code may be presented by a plurality of
tracers, where each of the code elements is represented by a tracer
or a combination of different tracers. In one embodiment, each of
the plurality of tracers is initially stored in its respective
container.
[0031] In operation, after obtaining a measured value of the
wellbore parameter, the measured value is then ascribed to a code
element CE1 in the code. The tracer or combination of tracers
representing the code element is then released from its container.
For example, if the plurality of tracers include Z1, Z2, and Z3,
and the code element is represented by tracer Z1; then tracer Z1
will be released from its container and allowed to travel uphole. A
sensor located uphole may detect the presence of tracer Z1 and
determine the specific value or range of values of the wellbore
parameter as a result of detecting the tracer Z1. In another
example, the measured value may be ascribed to a different code
element CE2 which may be represented by a combination of Z2 and Z3.
In this instance, both tracer Z2 and tracer Z3 will be released
from their respective container. When the uphole sensor detects the
presence of both tracers, it may determine the specific value or
range of values of the wellbore parameter. In another embodiment,
the combination of tracers may be released simultaneously or
sequentially. For example, tracers Z2 and Z3 may be released at the
same time or sequentially.
[0032] In this respect, the number of tracers required to represent
a set of code elements will be less than the number of code
elements in the code. In the current example, three tracers may be
used to represent a set of seven different code elements. In
another example, two tracers may be used to represent a set of
three code elements. Another advantage of this system is that the
measured value is not communicated using the concentration of the
tracer released into the wellbore. Instead, the measured value is
communicated by the tracer or combination of different tracers
released. As a result, in some embodiments, only the smallest
amount of tracer needed for detection is required to be released.
This advantage allows the container to be configured for a known
number of releases. It is contemplated that communication using the
code may be applicable in each of the embodiments described
herein.
[0033] In one embodiment, the plurality of tracers may be used to
convey information about a wellbore parameter, such as fluid
composition, temperature, and pressure. Each of the tracers Z1, Z2,
Z3 may represent a different value of the wellbore parameter. The
value may be a specific value or a range. The plurality of tracers
may be used in combination to represent a value that is outside of
the value of an individual tracer. In one embodiment, each of the
plurality of tracers is initially stored in its respective
container. In operation, after obtaining a measured value of the
wellbore parameter, the measured value is then correlated to an
equivalent value represented by one or more of the tracers. For
example, if the value represented by tracer Z1 is equivalent to the
measured value; then tracer Z1 will be released from its container
and allowed to travel uphole. A sensor located uphole may detect
the presence of tracer Z1 and determine that the value of the
wellbore parameter is within the value represented by tracer Z1. In
another example, the measured value may be represented by a
combination of the tracers. In this instance, the measured value
may be represented by the total value represented by tracer Z2 and
tracer Z3. In this respect, both tracer Z2 and tracer Z3 will be
released from their respective container. When the uphole sensor
detects the presence of both tracers, it will determine that the
measured value is within a range represented by the combined value
of tracers Z1 and Z2. In this respect, the number of tracers
required to represent a set of values will be less than the number
of values in the set. In the current example, three tracers may be
used to represent a set of seven different values. In another
example, two tracers may be used to represent a set of three
different values. Another advantage of this system is that the
measured value is not correlated to the concentration of the tracer
released into the wellbore. Instead, the measured value is
correlated to the tracer or combination of different tracers
released. As a result, in some embodiment, only the smallest amount
needed for detection is required to be released. This advantage
allows the container to be configured for a known number of
releases.
[0034] In one embodiment, the tracers may be chemicals that can
travel in the wellbore without being consumed, and therefore,
detected at another location. In another embodiment, the tracers
may be chemicals not naturally found in the wellbore. Suitable
chemicals may include radioactive or non-radioactive isotopes.
Suitable non-radioactive tracers include salts of
naphthalenesulfonic acids, salts of amino naphthalenesulfonic
acids, fluorescein and fluorinated benzoic acids. .sup.3H-labelled
or .sup.14C-labelled tracers of the same kind of components may
also be applied. Radioactive tracers such as beta emitters may also
be used. Exemplary tracers include chemicals that can be detected
using spectroscopic or electromagnetic means, such as radiometric,
magnetic, or optical devices. Additionally, particle size detection
using tracers such as silicon or other nanoparticles is also
contemplated. Other exemplary chemicals include fluorobenzoates,
chlorobenzoates, fluoromethylbenzoates, perfluoroaliphatic acids,
etc. Depending upon the natural chemistry of the wellbore and the
types of chemicals being introduced for stimulation, remediation,
fracturing, etc. the selection of chemicals for the tracer may be
different.
[0035] FIG. 1 shows an exemplary embodiment of a telemetry system
100. The telemetry system 100 is provided in a wellbore 20 for
producing hydrocarbon. The wellbore 20 includes a plurality of
packers 21, 22, 23 positioned to isolate a plurality of production
zones 31, 32. The telemetry system 100 includes a first downhole
sensor 41 configured to measure a wellbore parameter associate with
the first zone 31. For example, the first downhole sensor 41 may be
configured to measure the amount of water in the fluid produced at
the first zone 31, which may also be referred to as "water cut." A
plurality of containers 51, 52, 53 may be used to store tracers B1,
B2, B3, respectively. In one embodiment, the containers 51, 52, 53
may be pressurized and may be operated by a downhole controller 61.
The controller 61 is also connected to the first downhole sensor 41
and may receive signals from the sensor 41 regarding the measured
value of the wellbore parameter. The controller 61 is configured to
correlate the measured value to the tracers B1, B2, B3, or
combination of tracers that represent the measured value. The
system 100 also includes a detection system 80 configured to detect
the released tracers B1, B2, B3, and configured to determine the
measured value or range of the wellbore parameter based on the
detected tracers B1, B2, B3. In one embodiment, the detection
system 80 may include a tracer sensor for detecting the tracers and
a controller for correlating the detected tracers to the value of
the wellbore parameter. In another embodiment, the tracer sensor
may be a single tracer sensor adapted to detect each of the sensors
or a plurality of sensors which are each adapted to detect a
different tracer. In another embodiment, the measured values may be
ascribed to a code element in a code, and each code element is
assigned to a tracer of combination of tracers.
[0036] FIG. 2 is a table showing the exemplary values of the
tracers B1, B2, B3 in the containers 51, 52, 53 of the telemetry
system 100. In the example, the tracers represent a water cut
range. As shown, the tracers B1, B2, B3 represent water cut ranges
1, 2, and 4, respectively. Each of the values of ranges 3, 5, and 6
are represented by a combined release of two of the tracers. The
value of range 7 is represented by a combined release of all three
tracers. Thus, if all three tracers are detected, it can be
determined that the water cut range is between 0.875 and 1.0. It
must be noted that values in the FIG. 2 are only examples. The
tracers may be assigned to any suitable range of values to
communicate the measured downhole parameter. For example, the
tracers B1, B2, B3 may be used to represent a total water cut range
between 0.25 to 0.75. In addition, although FIG. 2 shows the
tracers have equal units of values (i.e., 0.125), it is
contemplated that the tracers may be assigned to values that are
not equal units; for example, B2 may represent a range of 0.25
instead of 0.125.
[0037] Referring back to FIG. 1, the system 100 may optionally
include another set of tracers C1, C2, C3 for communicating
information about the second production zone 32, such as the water
cut in the zone 32. The tracers C1, C2, C3 may be separately stored
in containers 61, 62, 63. The tracers C1, C2, C3 for the second
zone 32 should be different from the tracers B1, B2, B3 of the
first zone 31 to help identify the zone from which the tracers are
sent. A second sensor 42 is used to measure the wellbore parameter
of the second zone 2. The second sensor 42 and the containers 61,
62, 63 may be controlled by the controller 61 or a second
controller.
[0038] In one embodiment, the controller 61 may be configured to
send information about the water cut or other wellbore parameter at
predetermined time periods. For example, the controller 61 may be
configured to release the tracers daily, weekly, monthly,
quarterly, or any suitable time frame. The controller 61 may be
configured to release an amount of tracer that is sufficient for
detection by the detection system 80. Because only a low amount of
power is required to read the sensors, open and close the
container, and operate the internal clock, the battery life of the
system is increased. Thus, the telemetry system 100 may be a low
power system that has a long life, or large number of iterations,
or both.
[0039] In operation, the telemetry system 100 may be used to
communicate a wellbore parameter such as the water cut of the
wellbore fluid. In one embodiment, the controller 61 may be
configured to communicate the water cut on a daily basis. To that
end, the controller 61 may obtain the value of the water cut from
the first sensor 41. The controller 61 may then correlate the
measured value to the tracers that represent the measured value. In
one example, if the measured value is 0.35, then the controller 61
may determine that the measured value is within the range
represented by tracer B2 and then release tracer B2 from its
container 52. The tracer B2 travels uphole to the surface and is
detected by the detection system 80. The detection of tracer B2
communicates to the detection system 80 that the water cut in the
first zone is between 0.25 and 0.375. One day later, the controller
61 may receive another measured value of the water cut from the
first sensor 41. In another example, if the measured value of the
water cut has increased to 0.4, then the controller 61 may
correlate that to a value represented by a combination of tracers
B1 and B2. As a result, the controller 61 will release tracers B1
and B2 from their respective containers 51, 52. The detection of
tracers B1 and B2 communicates to the detection system 80 that the
water cut in the first zone is between 0.375 and 0.5. In one
embodiment, the tracers B1 and B2 may be released in a unique
pattern. For example, tracer B1 and tracer B2 may be released
sequentially or simultaneously. In another embodiment, the
controller 61 may also communicate the water cut of the second zone
32 by obtaining the measured value from the second sensor 42 and
releasing the equivalent tracers C1, C2, C3 of the second zone 32.
The tracers selected for the second zone 32 are different from the
tracers of the first zone 31 to help distinguish the zones 31, 32.
The tracers of the second zone 32 may also be released on a daily
basis. In one embodiment, the tracers of the second zone 32 are
released at a different time during the day than the first zone 31.
For example, the tracers of the second zone 32 may be released 12
hours after the first zone 31. The tracers C1, C2, C3 may be
assigned the same water cut values as the tracers B1, B2, B3 from
the first zone. The detection system 80 may be configured to detect
the tracers C1, C2, C3 and determine the water cut value from the
tracers. In another embodiment, the telemetry system 100 may
include one or more groups of sensors and tracers for measuring
other wellbore parameters such as temperature and pressure. In one
example, tracers for conveying temperature may be released on a
weekly basis, while tracers for conveying pressure may be released
on a daily basis.
[0040] Although FIG. 1 shows a single wellbore system, in another
embodiment, the telemetry system may be used in a multilateral
wellbore system. The laterals may include one or more tracers and
sensors to communicate information regarding operation or
production of various zones of the laterals. As shown in FIG. 3,
each lateral 110, 120, 130 may include two sets of sensors and
tracers at each inflow control device. The first lateral 110 may
include two inflow control devices 111, 112 for two different
production zones. An exemplary inflow control device may be a
sliding sleeve valve. Each inflow control device 111, 112 may be
equipped with a sensor to measure a wellbore parameter and a set of
tracers for communicating the measured values in a similar manner
as shown in FIG. 1. For example, the first inflow control device
111 may be associated with a downhole sensor 41 and tracers B1, B2,
B3, and the second inflow control device 112 may be associated with
downhole sensor 42 and tracers C1, C2, C3. Each of the sensors 41,
42 may be adapted to measure a wellbore parameter such as flow
rate, fluid composition, temperature, and pressure. In one
embodiment, each of the inflow control devices may be provided with
additional sensors to measure additional parameters. For example,
one or more of the inflow control devices may be equipped a first
sensor for measuring fluid composition and a second sensor for
measuring temperature. The second lateral 120 may also include two
inflow control devices 121, 122, each with its own sensor and set
of tracers. Similarly, the third lateral 130 may include two inflow
control devices 131, 132, each with its own sensor and set of
tracers. The uniqueness of each tracer assists with identification
of the particular inflow control device associated with the tracer.
In this respect, the tracer may communicate information to surface
regarding the particular inflow control device. For example, the
tracers B1, B2, B3 may communicate the flow rate of the fluid
flowing through the first inflow control device 111 in the first
lateral 110. In addition to communicating the measured flow rate,
the tracers B1, B2, B3 also indicate that the inflow control device
111 is in operation. In another example, a failure to detect
tracers from inflow control device 132 may indicated that the
inflow control device 132 is closed or is experiencing a problem.
It must be noted that each lateral may include more than two inflow
control devices, such as five, ten, fifteen, or any suitable number
of inflow control devices. In another embodiment, the measured
values may be ascribed to a code element in a code, and each code
element is assigned to a tracer of combination of tracers.
[0041] In another embodiment, the telemetry system may be used in a
fracturing operation. FIG. 4 illustrates a wellbore 140 having
multiple fracture sleeves 141, 142, 143 that are sequentially
opened to allow fracturing fluid to flow out of the wellbore and
fracture the formation. The fracture sleeves 141, 142, 143 are
associated with a set of tracers to communicate whether the
respective fracture sleeve was opened during the fracturing
operation. In some operations, the fracture fluid is continuously
injected into the wellbore during the fracture operation. In such
operations, the release of chemical tracers is delayed until the
fluid flow direction is up the wellbore. In one exemplary
embodiment, each of the tracers associated with the second fracture
sleeve 142 may be stored in a container 150 having a gate valve 152
and a check valve 154, as shown in FIG. 4A. The gate valve 152
opens in response to opening of the fracture sleeve 142. The check
valve 154 opens when the annulus pressure is greater than the
wellbore pressure. An exemplary check valve is a one way valve such
as a flapper valve or a poppet valve.
[0042] In operation, when the fracture sleeve 142 opens, the
controller opens the gate valve 152 in response. However, the
tracer is not released until the check valve 154 is opened. While
the fracturing fluid is being injected, the check valve 154 remains
closed because the wellbore pressure generated by the fracturing
fluid is greater than the annulus pressure. When the injection
ceases and the wellbore pressure drops below annulus pressure, the
check valve 154 opens to release the tracer from the container 150.
The tracer is released into the wellbore and is carried up to the
surface. Detection of the tracer at the surface indicates that the
fracture sleeve 142 opened during the operation. However, if no
tracers for a particular fracture sleeve are detected, then it is
an indication that the particular fracture sleeve may have failed
to open. In another embodiment, the measured values may be ascribed
to a code element in a code, and each code element is assigned to a
tracer of combination of tracers.
[0043] In another embodiment, the tracers may be used to indicate
the open status of a sliding sleeve or other valve devices. For
example, a valve may be controlled from surface between open,
close, or partially open positions. However, it is generally
difficult to determine the extent to which the valve is partially
open. In one embodiment, the valve may include a sensor configured
to measure the extent of opening of the valve. A plurality of
containers may be used to store tracers E1, E2, E3, respectively,
to communicate the status of the valve. In one embodiment, the
containers may be pressurized and may be operated by a downhole
controller. The controller is also connected to the sensor and may
receive signals from the sensor regarding the extent of valve
opening. The controller is configured to correlate the measured
value to the tracers E1, E2, E3, or combination of tracers that
represent the measured value. In one example, the tracers E1, E2,
E3 may be used to represent ranges 1-7 as shown in FIG. 1. The
system also includes a detection system configured to detect the
released tracers E1, E2, E3, and configured to determine the status
of the valve based on the detected tracers E1, E2, E3.
[0044] In operation, a signal may be sent to the valve to at least
partially open the valve, for example, 60% open. The sensor
measures the amount of opening of the valve and communicates the
data to the controller. In turn, the controller releases one or
more tracers to communicate to the surface the extent of the valve
opening. For example, the controller may determine that the
measured value of 60% open is within the range represented by
tracer E3 and thus, release tracer E3 from its container. The
tracer E3 travels up the wellbore and is detected by the detection
system. The detection of tracer E3 communicates to the detection
system that the valve is 50% to 62.5% open. Later, the controller
may receive another measured value of the valve, for example, 70%
open. Then, the controller may correlate the measured value to a
value represented by a combination of tracers E1 and E3. As a
result, the controller releases tracers E1 and E3 from their
respective containers. The detection of tracers E1 and E3 indicates
that the valve is opened in a range between 62.5% and 75%. In this
manner, the tracers may be used as an encoding to communicate the
status of the valve. It must be noted that the range designations
of the tracers may be different from the ranges in FIG. 1. It also
must be noted that additional tracers may be used to further define
the possible ranges represented by the tracers. In another
embodiment, the measured values may be ascribed to a code element
in a code, and each code element is assigned to a tracer of
combination of tracers.
[0045] In another embodiment, the release of the tracers may be
coupled directly to the opening of the sleeve of the downhole
valve. In one example, the tracers may be stored in sequential
chambers of a container or containers that are closed by the
sleeve. Each chamber may store a different tracer or combination of
tracers, which represents the open status of the sleeve. As the
sleeve moves to open the downhole valve, it will sequentially
uncover one or more of the chambers. The tracers in the chambers
opened by the sleeve will be released into the flow stream, such as
the tubing, the annulus between the tubing and casing, a hydraulic
line, and combinations thereof. When detected, the tracers will be
analyzed at surface to determine the valve position. In another
embodiment, the sleeve may be coupled to a cover of the chambers.
As the sleeve moves, it will also move the cover to open the
respective chambers to release the tracers. Although the
description relates to a downhole valve, it is contemplated that
the system may be used to indicate the position status of any
suitable downhole tool. In another embodiment, the chemical
communication system may be used to communicate the position of a
component of a downhole tool.
[0046] In one exemplary operation, five chambers may be used to
represent the position of the sleeve in twenty percent increments.
FIG. 8A is a partial view of the interior of an exemplary
embodiment of a downhole valve 400. The valve 400 includes a
tubular body 410 and a sliding sleeve 420 disposed adjacent the
tubular body 410. The sleeve 420 may include an extension cover 425
that seals off the five chambers 431-435, which are shown as a
hidden view with dash lines. Initially, a signal is sent to at
least partially open the valve 400, for example, 40% open. As the
sleeve 400 opens, it will also sequentially uncover the chambers
431, 432. After reaching the 40% open position, the first two
chambers 431, 432 will have been opened. The tracers representing
20% and 40% open positions will be released. The detection system
at the surface detects the presence of the tracer or combination of
tracers representing 40% open and confirms the sleeve 400 is at
least 40% open. If a second signal is later sent to open the valve
400 further, for example to 60%, then the sleeve 420 will uncover
the next chamber 433, and the tracers representing 60% open status
will be released. When the detection system detects the presence of
these tracers, the proper open position of the valve 400 is
confirmed. FIG. 8B shows the sliding sleeve 420 has moved up to
expose slots 428 in the valve 400 for fluid communication. Also,
the first three chambers 431-433 have been opened as a result of
the extension cover 425 also moving up. The fourth and fifth
chambers 434, 435 are still blocked by the extension cover, as
shown by the dash lines.
[0047] In another embodiment, the release of the tracers may be
controlled by a command such as receiving the command from the
surface or from a controller. For example, after opening the sleeve
opens three of the chambers 431-433, the release of the tracers may
be delayed until a command is received. In one example, a
controller may instruct all of the chambers 431-435 to release
their tracers. However, only the tracers in chambers 431-433 will
release into the flow stream because those chambers have been
opened. The tracers in chambers 434-435 cannot release into the
flow stream because those chambers are still blocked by the sleeve
400.
[0048] FIG. 9 illustrates a partial view of another embodiment of a
valve 450. As shown, the extension cover 465 of a sliding sleeve
460 is configured to block off four of the seven chambers 451-457.
Particularly, the extensive cover 465 is blocking off chambers
453-455, while chamber 451, 452, 456, and 457 are open to allow
release of the tracers. In this respect, the valve 450 is partially
open as demonstrated by the chambers 451 and 452 being open. Upon
receiving a command to release the tracers, all of the chambers
will release their tracers. However, only the tracers from chambers
451, 452, 456, 457 are open to allow the tracers to flow into the
flow stream such as inside a tubing. The absence of the tracers
from chambers 453-455 at surface will indicate that those chambers
are closed and therefore, the position of the sleeve can be
determined. If a command to partially close the sleeve 460 is
received, then the sleeve 460 will move to close off the second
chamber 452, while leaving chambers 451, and 455-457 open. To
signal the sleeve 460 has partially closed, another command may be
sent to instruct the release of the tracers in the chambers
451-457. As a result, only the tracers in chambers 451 and 455-457
are released and detected at surface, and the tracers from chambers
452-454 would be absent. As a result, partial closure of the sleeve
460 is confirmed.
[0049] In another embodiment, the valves may be configured to send
a chemical signal even though it is closed. For example, referring
back to FIG. 3, if the valve 112 in the first lateral 110 is open
and the upstream valve 111 is closed, then fluid entering the
downstream valve 112 will flow past the upstream valve 111 on its
way to surface. The upstream valve 111 may be preprogrammed to
release a tracer to indicate that it is closed. The released tracer
may be carried to surface by the fluid entering the downstream
valve 112. In another embodiment, the upstream valve 111 may be
commanded to release the tracer or released the tracer at preset
time intervals.
[0050] In another embodiment, the telemetry system may be used to
communicate the status of a subsurface safety valve. For example, a
subsurface safety valve 200 may include a flapper 210 biased in a
normally closed position. During operation, a shift sleeve 215 may
be used to open the flapper 210 and lock the flapper 210 in the
open position, as shown in FIG. 5. In one embodiment, a tracer may
be released from a container 220 to indicate that the flapper 210
has opened. For example, after the shift sleeve 215 has moved
axially to open the flapper 210 and lock the flapper 210, the shift
sleeve 215 may trigger the release of the tracer. FIG. 5 shows the
flapper 210 in the locked, open position. In one embodiment, the
shift sleeve 215 may engage a piston 225 to cause the release of
the tracer from its container 220. In this manner, the telemetry
system may be used to confirm the flapper 210 is in the locked,
open position.
[0051] In another embodiment, the telemetry system may be used to
facilitate control of a downhole pump by communicating wellbore
condition adjacent the downhole pump. FIG. 6 shows a wellbore 160
having a progressive cavity pump ("PCP") for pumping wellbore
fluids to surface. In one embodiment, the PCP is an insertable PCP
170 attached to the production tubing 165 in the wellbore. The
insertable PCP 170 includes a rotor 171 releasably coupled to the
stator 172. In turn, the stator 172 is releasably coupled to the
tubing 165 using a latch 167. The insertable PCP may be raised or
lowered using a sucker rod 169. In one embodiment, a sensor 180 for
measuring the hydrostatic head in the wellbore may be attached to
the PCP 170. The PCP 170 may also include the containers 185 for
separately storing tracers F1, F2, F3 for communicating the
measured value to surface. Each of the tracers may represent a
particular value, and two or more of the tracers may be combined to
represent different values. The tracers may periodically
communicate information about the hydrostatic head in the wellbore.
For example, the controller may release the tracers on an hourly,
daily, or weekly basis. After the sensor measures the hydrostatic
head, then the controller will release the tracer or tracers that
represent the measured value. If the hydrostatic head is too high,
then the motor speed may be increased to produce more fluid.
However, if the hydrostatic head is too low, then the motor speed
may be decreased to ensure the fluid column is above the inlet of
the PCP 170. In this manner, the PCP 170 may be operated to control
the fluid at level close to the inlet of the PCP, thereby
increasing efficiency of the pump. In another embodiment, the
sensor and tracers may be attached to the rotor and may,
optionally, extend below the stator. It is contemplated that
additional sensors and tracers may be used to measure and
communicate other wellbore parameters such as temperature and
composition. In another embodiment, the measured values may be
ascribed to a code element in a code, and each code element is
assigned to a tracer of combination of tracers.
[0052] In another embodiment, the telemetry system may be used to
convey information regarding a steam assisted gravity drainage
system ("SAGD"). FIG. 7 shows a first wellbore 310 having a first
outflow valve 311 and a second outflow valve 312 connected to a
first tubular for injecting steam into the formation 305. The steam
and other formation fluids may enter a second wellbore 320 and sent
to the surface via a first inflow valve 321 and a second inflow
valve 322 that are connected via a second tubular. In one
embodiment, the steam leaving the first outflow valve 311 may be
supplied with a tracer or combination of tracers assigned to the
first outflow valve. Similarly, the tracer or combination of
tracers assigned to the second outflow valve 312 may be added to
the steam leaving the second outflow valve 312. After the steam
enters the inflow valves 321, 322 and sent uphole, the detection
sensor may identify the tracers in the steam and determine the
source of the tracers, i.e., from the first outflow valve 311 or
second outflow valve 312. In another embodiment, the inflow valves
321, 322 may be provided with the appropriate sensors and tracers
to determine the flow rate, temperature, pressure, and/or
composition of the fluids flowing into the second wellbore 320.
[0053] In another embodiment, the chemical communication system may
be configured to release ratiometric amounts of a tracer to convey
information about a wellbore parameter or a downhole tool. For
example, each tracer may be released in ratiometric amounts such as
a quarter dosage, half dosage, or full dosage. Each ratiometric
dosage may represent a different value. In this respect, use of
ratiometric dosage effectively increases the range or resolution of
values represented by the tracer. It must be noted that the dosages
are not limited to a quarter dosage or a half dosage, but can be in
any suitable amounts, such as one third, one fifth, or one sixth.
In one embodiment, each of the ratiometric dosage may represent
equal values. For example, if only one tracer is used, each quarter
dosage may represent a value of 0.1 such that the full dosage may
represent a value of 0.4. If multiple tracers are used, then
ratiometric amounts of one tracer may be combined with ratiometric
amounts of one or more other tracers to represent a value. In
another embodiment, each partial ratiometric dosage may represent a
smaller value within a range of values represented by the full
dosage, thereby providing a higher resolution of the measured
value. For example, if the full dosage represents a range between
0.2 to 0.3, then each quarter dosage may be 25% of the range.
[0054] The system may release a calibration dosage in order to
determine the environmental effects on the tracer. The calibration
dosage may be used to normalize the data for the ratiometric
values. In this instance, the calibration dosage may be referred to
as a normalization dosage. In one embodiment, the normalization
dosage may be a full dosage of the tracer. The value measured at
the surface for the full dosage may be used to determine the
ratiometric dosage of the tracer released either after or before
the normalization dosage. For example, if the measured value of the
ratiometric dosage is about 33% of the measured value of the
calibration dosage, then the ratiometric dosage released is a
one-third dosage. After determining the ratiometric dosage, the
represented value may be obtained. The normalization dosage may be
released at any time such as before and/or after releasing the
ratiometric dosage. The frequency of release of normalization
dosage may be controlled based on time intervals, such as hourly,
daily, or weekly. The normalization dosage may also be released
based on a particular event, such as prior to measurement, upon
receipt of a command sent downhole, or upon measurement of a
particular range where a more specific value is desirable. In
another embodiment, a unique code represented by the tracers may be
released to signal a normalization dosage will be sent.
[0055] FIG. 10 is an exemplary graph showing the measured values of
three tracers T1, T2, T3 released in ratiometric amounts compared
to a normalization dosage of the tracers T1, T2, T3. For each of
the tracers, a normalization dosage is released followed by a
ratiometric dosage. In this example, the tracers T1, T2, T3 are
released in ratiometric amounts of 0.7, 0.4, and 0.5,
respectively.
[0056] In another embodiment, the tracers may be modulated as a
function of time, e.g, width modulation. FIG. 11 is an exemplary
graph showing the measured values of one tracer released as a
function of time. It must be noted that only one tracer is shown
for sake of clarity. It is contemplated that any number of tracers
may be modulated as a function of time. In FIG. 11, the tracer is
released for a period of about ten minutes as a normalization
dosage followed by five minutes as a ratiometric dosage. In another
embodiment, the tracers may be modulated using a combination of
concentration and time to represent a value. In FIG. 12, the tracer
is released at 60% dosage for 5 minutes followed by 40% dosage for
5 minutes. At surface, the detection system can correlate this
result to a predetermined value.
[0057] In one exemplary embodiment, the system shown in FIG. 1 may
be modified such that the tracers B1, B2, B3 may be released in
ratiometric amounts such as half dosage and full dosage. In this
embodiment, the half dosage may represent 50% of the range of the
full dosage, which is equal to 0.0625. Thus, a half dosage may
represent the range between 0.25 to 0.3125, and the full dosage may
represent the range between 0.3125 to 0.375. In operation, the
controller 61 is programmed to release a normalization dosage
before measuring the wellbore parameter. The normalization dosage
is detected at surface and used to determine any ratiometric
dosages. After obtaining the value of the water cut from the first
sensor 41, the controller 61 then correlates the measured value to
the tracers that represent the measured value. In one example, if
the measured value is 0.28, then the controller 61 may determine
that the measured value is within the range represented by a half
dosage of tracer B2. As a result, a half dosage of tracer B2 is
released from its container 52. In one embodiment, the container 52
is opened and tracer released using a mechanically actuated device
such as a piston, lever, or a screw. The tracer B2 travels uphole
to the surface and is detected by the detection system 80. The
detected value of the tracer B2 is then compared to the value of
the calibration dosage. The result of the comparison indicates that
a half dosage of tracer B2 was released, which communicates to the
detection system 80 that the water cut in the first zone is between
0.25 and 0.3125.
[0058] In another embodiment, the ratiometric values may be used to
further define a range, i.e., to obtain a higher resolution of the
measured value. For example, each of the tracers B1, B2, B3
represents a range of 0.125 in to FIG. 2. The half dosage of each
tracer and combination of tracers can be used to represent a value
in that range. The following example uses the range of B2, which is
0.25 to 0.375, the values of the half dosage of the tracers B1, B2,
B3 may be assigned as follows: [0059] half B1=0.25-0.275 [0060]
half B2=0.275-0.3 [0061] half B3=0.3-0.325 [0062] half B1+half
B2=0.325-0.35 [0063] half B1+half B3=0.35-0.375
[0064] In operation, if the water cut value is 0.33, then the
controller 61 will release a normal dose of tracer B2 into the
wellbore. At surface, the detection system will determine the water
cut range is between 0.25 and 0.375, as represented by the
detection of a full dosage of tracer B2. Thereafter, the detection
system may send a command to the controller 61 to communicate a
more specific value. In response, the controller 61 may initially
release a calibration dosage of each of the tracers B1, B2, B3 into
the wellbore. The value of the calibration dosage measured by the
detection system may be used to determine the ratiometric value of
the tracers. The controller 61 will then release a half dosage of
each of tracer B1 and tracer B2 to represent the more specific
value of the water cut. Upon detection by the detection system, the
value of the tracers is compared to the value of the calibration
dosage. The determination is then made that only half dosage of
each of tracers B1, B2 has been released, thereby representing a
water cut in the range of 0.325-0.35. In this manner, a more
specific value of a wellbore parameter, e.g., water cut, can be
obtained using a chemical communication system.
[0065] It is contemplated that chemical communication involving
ratiometric amounts and/or time based modulation can be used by any
suitable downhole tool, including any downhole tool described
herein. For example, the position of the sleeve of a downhole valve
as described above may be communicated using ratiometric or time
based modulation.
[0066] In another embodiment, the chemical communication system may
be configured to communicate data in portions, which when combined,
represents the full data. In one embodiment, the chemical
communication system can be used to serially communicate a digit of
a value. For example, to communicate a value, one or more tracers
may be used to represent numbers 0 to 9. If four tracers are used,
they may be assigned the numbers as follows: [0067] F1=0 [0068]
F2=1 [0069] F3=2 [0070] F4=3 [0071] F1+F2=4 [0072] F1+F3=5 [0073]
F1+F4=6 [0074] F2+F3=7 [0075] F2+F4=8 [0076] F3+F4=9
[0077] To communicate a pressure of 356 psi, the controller may
initially release tracer F4 to represent the number 3 for the first
digit in the pressure value. After waiting a period of time
sufficient to avoid overlap of tracers between releases, the
controller will release tracers F1 and F3 to represent the number 5
for the second digit of the pressure value. Thereafter, the
controller will release tracers F1 and F4 to represent the number 6
for the third digit. At surface, the detection system will detect
these tracers in the sequence that they are released and determine
the digit represented by each tracer or combination of tracers.
From the release sequence of the tracers, the detection system will
determine the actual value communicated is 356 psi. Optionally, the
release of the tracers may be repeated to obtain a second reading
to verify the actual value. Another normalization dosage may be
optionally released in between the first and second readings to
renormalize the tracers' values. In yet another embodiment, the
normalization dosage may be sent at the end of the communication to
verify the data. In another embodiment, the digits may be
communicated in reverse order, such as, units, then tenth, then
hundredth, and thousandth.
[0078] In another embodiment, each of the digits may be represented
by at least two tracers, as follows: [0079] G1+G2=0 [0080] G1+G3=1
[0081] G1+G4=2 [0082] G1+G5=3 [0083] G2+G3=4 [0084] G2+G4=5 [0085]
G2+G5=6 [0086] G3+G4=7 [0087] G3+G5=8 [0088] G4+G5=9
[0089] In another embodiment, the numbers may be represented by
ratiometric dosages of the tracer, thereby reducing the number of
tracers necessary for communication. [0090] G1+0.25 G2=0 [0091]
G1+0.5 G2=1 [0092] G1+0.75 G2=2 [0093] G1+G2=3 [0094] 0.25 G1+0.25
G2=4 [0095] 0.25 G1+0.5 G2=5 [0096] 0.25 G1+0.75 G2=6 [0097] 0.25
G1+G2=7 [0098] 0.5 G1+0.5 G2=8 [0099] 0.5 G1+G2=9
[0100] Embodiments of the chemical communication system may be used
for communication between two downhole devices. In one embodiment,
referring back to FIG. 3, the chemical communication system allows
the inflow control device 112 to communication with the upstream
inflow control device 111 in the first lateral 110 or the inflow
control devices in other laterals. For example, when the downstream
inflow control device 112 releases the tracers representing the
water cut value (or other wellbore parameter) measured by its
sensor, the tracers will travel upstream to the detection system at
surface. In this embodiment, the upstream inflow control device 111
may be equipped with a detection system for detecting the tracers
released by the downstream inflow control device 112 or other
devices. If the upstream device 111 determines the released tracers
represent a high water cut value, the controller may close the
upstream device 111 to prevent inflow of water.
[0101] In another embodiment, a command signal such as a coded
fluid pressure pulse targeting a specific device may be used to
sample one or more devices in a wellbore. Referring again to FIG.
3, a command signal targeting the downstream inflow control device
112 in the first lateral 110 may be sent to trigger the downstream
device 112 to convey information about a wellbore parameter or the
device 112 by releasing a tracer or combination of tracers. After
sampling the downstream device 112, the upstream device 111 can be
sampled. A second command signal targeting the upstream inflow
control device 111 in the first lateral 110 is sent to trigger the
upstream device 111 to convey information about the wellbore
parameter or the device 111 by releasing the tracer or combination
of tracers. If the tracers in each device 111, 112 are the same,
then the command signals may be sent at predetermined time
intervals to avoid confusion. The time interval may be minimal or
not necessary if the tracers in each device 111, 112 are unique to
that device 111, 112. This process may be performed to sample other
inflow control devices in the second and third laterals 120,
130.
[0102] In yet another embodiment, tracers may be released from the
surface to communicate with one or more downhole device. The
tracers may be coded to communicate with a particular device or a
group of devices. The downhole devices may be equipped with a
detection system to detect the tracers released from surface. For
example, a tracer or combination tracers targeting inflow control
device 111 may be released from the surface. Upon detection of the
tracers, the inflow control device 111 may be triggered to
communicate a wellbore parameter or data about itself. Because the
tracers are coded for the inflow control device 111, the other
inflow control devices will ignore the tracers and not respond. In
this manner, two-way communication using the tracers may be
performed.
[0103] In another embodiment, the chemical communication system may
be used to communicate information about a downhole device. For
example, the tracers may be used to communicate the condition of a
battery in the downhole device. In one example, the tracers or
combination of tracers may be used to represent the percentage of
battery life remaining. [0104] G1=20%<life<30% [0105]
G2=10%<life<20% [0106] G1+G2=life<10% Thus, the controller
may release tracer G2 to communicate the battery life remaining is
less than 20%. In another embodiment, ratiometric amounts of the
tracers or combination of tracers may be used to communicate the
life of the battery. In another embodiment, for multiple devices,
each of the devices may be equipped with its unique set of
tracers.
[0107] In another embodiment, the chemical communication system may
be used to communicate information about the fluid regime in the
wellbore. For example, a tracer may be released multiple times to
travel uphole toward the detection system. The measured value of
each release may be compared against the measured value of another
release. If the measured values of the releases are consistent,
then it may be an indication that the fluid regime in the wellbore
is laminar. However, if the measured values of the releases vary,
then it may be an indication that the fluid regime in the wellbore
is turbulent or an indication that a leakage has occurred.
[0108] In another embodiment, a method of communicating a wellbore
parameter from a downhole tool includes providing a plurality of
tracers to represent a code for communicating a value of the
wellbore parameter, wherein the code includes a plurality of code
elements and wherein each code element is represented by a tracer
or a combination of different tracers; measuring the value of the
wellbore parameter using a sensor; correlating the measured value
of the wellbore parameter to a code element; releasing the tracer
or combination of different tracers representing the code element
to travel upstream; detecting presence of the tracer or combination
of different tracers; and determining the specific value or range
of values of the wellbore parameter from the detected tracer or
combination of different tracers.
[0109] In another embodiment, a method of communicating a wellbore
parameter from a downhole tool includes providing a plurality of
tracer chemicals, whereby a code comprising a plurality of code
elements correlates to a release of a single tracer chemical or a
unique combination of a subset of the plurality of tracer chemicals
to a specific value or a range of values of the wellbore parameter;
measuring a value of the wellbore parameter using a sensor;
ascribing the measured value to a code element; releasing one or
more of the plurality of tracer chemicals corresponding to the code
element; detecting the presence of the one or more of the plurality
of tracer chemicals; and determining the specific value or range of
values of the measured wellbore parameter from the detection of the
one or more of the plurality of tracer chemicals.
[0110] In one or more of the embodiments described herein,
ascribing the measured value to a code element is performed
downhole.
[0111] In one or more of the embodiments described herein,
detecting the presence of one or more of the plurality of tracer
chemicals is performed at a surface of the wellbore.
[0112] In another embodiment, a method of communicating a wellbore
parameter from a downhole tool includes generating a code
comprising a plurality of code elements, wherein each discrete code
element correlates a specific value or a range of values of the
wellbore parameter to a unique pattern of releasing one or more of
a plurality of tracer chemicals; providing the plurality of tracer
chemicals at a location in a wellbore; measuring a value of the
wellbore parameter using a sensor; ascribing the measured value to
a discrete code element of the code; releasing one or more of the
plurality of tracer chemicals in a unique pattern corresponding to
the discrete code element; detecting the presence of the one or
more of the plurality of tracer chemicals in the unique pattern;
and determining the specific value or range of values of the
measured wellbore parameter from the detection of the one or more
of the plurality of tracer chemicals.
[0113] In one or more of the embodiments described herein, the
pattern comprises a simultaneous release of two or more of the
plurality of tracer chemicals.
[0114] In one or more of the embodiments described herein, the
pattern comprises a sequential release of two or more of the
plurality of tracer chemicals.
[0115] In another embodiment, a method of communicating a wellbore
parameter from a downhole tool includes providing the plurality of
tracer chemicals at a downhole location in a wellbore; measuring a
value of the wellbore parameter using a sensor; releasing one or
more of the plurality of tracer chemicals in a unique pattern
corresponding to the measured value of the wellbore parameter;
detecting at a surface location of the wellbore the presence of the
one or more of the plurality of tracer chemicals in the unique
pattern; and determining the specific value or range of values of
the measured wellbore parameter from the detection of the one or
more of the plurality of tracer chemicals.
[0116] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
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