Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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METHOD AND APPARATUS FOR MONITORING A DOWNHOLE TOOL
CROSS-REFERENCE TO RELATED APPLICATIONS
[0ool]
This application claims benefit of U.S. Provisional Patent Application No.
61/624,850, filed April 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
March
15, 2013; and U.S. Provisional Patent Application No. 61/800,614, filed March
15,
2013; which applications are incorporated herein by reference in their
entirety.
BACKGROUND OF THE INVENTION
Field of the Invention
[0on] 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.
Description of the Related Art
[0003] 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.
[0004]
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.
[0005] There is a need, therefore, for a telemetry system to communicate
information about the wellbore from a downhole tool.
SUMMARY OF THE INVENTION
[0006]
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
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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.
[0007] 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.
[0008] In one or more of the embodiment disclosed herein, each of the
plurality of
tracers represents a different value of the wellbore parameter.
[0009] In one or more of the embodiment disclosed herein, each of the
plurality of
tracers comprises a chemical.
[0010] 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.
[0011] In one or more of the embodiment disclosed herein, the method
further
includes releasing a calibration dosage of the plurality of tracers.
[0012] 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;
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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.
[0013] 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
[0014] 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.
[0015] Figure 1 shows an exemplary embodiment of a telemetry system.
[0016] Figure 2 is a table showing the exemplary values of the tracers B1,
B2, B3
in the first zone of the telemetry system of Figure 1.
[0017] Figure 3 shows an exemplary embodiment of a telemetry system for
use
with a multilateral wellbore.
[0018] Figure 4 shows an exemplary embodiment of a telemetry system for
use in
a fracturing operation. Figure 4A illustrates an exemplary embodiment of a
container.
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[0019] Figure 5 shows an exemplary embodiment of a telemetry system for
use
with a subsurface valve.
[0020] Figure 6 shows an exemplary embodiment of a telemetry system for
use
with a downhole pump.
[0021] Figure 7 shows an exemplary embodiment of a telemetry system for use
with a steam assisted gravity drainage system.
[0022] Figures 8A-B illustrate another embodiment of a chemical
communication
system for monitoring a downhole tool.
[0023] Figure 9 illustrates a partial view of another embodiment of a
valve.
[0024] Figure 10 is an exemplary graph showing measured values of tracers
released in ratiometric amounts.
[0025] Figure 11 is an exemplary graph showing measured values of one
tracer
released as a function of time.
[0026] Figure 12 is an exemplary graph showing measured values of one
tracer
released as a function of time and concentration.
DETAILED DESCRIPTION
[0027] 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.
[0028] 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
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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
5 in its respective container.
[0029] 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.
[0030] 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.
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[0031] 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.
[0032] 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. 3H-
labelled or 14C-labelled tracers of the same kind of components may also be
applied.
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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.
[0033] Figure 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.
[0034] Figure 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
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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
1Ø It
must be noted that values in the Figure 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 Figure 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.
[0035] Referring back to Figure 1, the system 100 may optionally include
another
set of tracers Cl, 02, 03 for communicating information about the second
production
zone 32, such as the water cut in the zone 32. The tracers Cl, 02, 03 may be
separately stored in containers 61, 62, 63. The tracers Cl, 02, 03 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.
[0036] 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.
[0037] 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.
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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 Cl, 02, 03 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 Cl, 02, 03 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 Cl, 02, 03 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.
[0038] Although Figure 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
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operation or production of various zones of the laterals. As shown in Figure
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
5 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 Figure 1. For example, the
first
inflow control device 111 may be associated with a down hole sensor 41 and
tracers
B1, B2, B3, and the second inflow control device 112 may be associated with
10 downhole sensor 42 and tracers Cl, 02, 03. 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.
[0039] In another embodiment, the telemetry system may be used in a
fracturing
operation. Figure 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
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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 Figure 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.
[0040] 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.
[0041] 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
El, 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
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regarding the extent of valve opening. The controller is configured to
correlate the
measured value to the tracers El, E2, E3, or combination of tracers that
represent the
measured value. In one example, the tracers El, E2, E3 may be used to
represent
ranges 1-7 as shown in Figure 1. The system also includes a detection system
configured to detect the released tracers El, E2, E3, and configured to
determine the
status of the valve based on the detected tracers El, E2, E3.
[0042] 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 El and E3.
As a
result, the controller releases tracers El and E3 from their respective
containers. The
detection of tracers El 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 Figure 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.
[0043] 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
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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.
[0044] In one exemplary operation, five chambers may be used to
represent the
position of the sleeve in twenty percent increments. Figure 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. Figure
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.
[0045] 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,
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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.
[0046] Figure 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.
[0047] In another embodiment, the valves may be configured to send a
chemical
signal even though it is closed. For example, referring back to Figure 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.
[0048] 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
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open position, as shown in Figure 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. Figure 5
shows the
5 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.
[0049] In another embodiment, the telemetry system may be used to
facilitate
10 control of a downhole pump by communicating wellbore condition adjacent
the
downhole pump. Figure 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,
15 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
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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.
[0050] In another embodiment, the telemetry system may be used to convey
information regarding a steam assisted gravity drainage system ("SAGD").
Figure 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 updhole, 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.
[0051] 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
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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.
[0052]
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.
[0053]
Figure 10 is an exemplary graph showing the measured values of three
tracers Ti, T2, T3 released in ratiometric amounts compared to a normalization
dosage of the tracers Ti, T2, T3. For each of the tracers, a normalization
dosage is
released followed by a ratiometric dosage. In this example, the tracers Ti,
T2, T3 are
released in ratiometric amounts of 0.7, 0.4, and 0.5, respectively.
[0054]
In another embodiment, the tracers may be modulated as a function of
time, e.g, width modulation. Figure 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 Figure 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 Figure 12, the tracer is
released at
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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.
[0055] In one exemplary embodiment, the system shown in Figure 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.
[0056] 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 Figure 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:
half B1 = 0.25 ¨ 0.275
half B2 = 0.275 ¨ 0.3
half B3 = 0.3 ¨ 0.325
half B1+half B2 = 0.325 ¨ 0.35
half B1+half B3 = 0.35 ¨ 0.375
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[0057] 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.
[0058] 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.
[0059] 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:
F1 = 0
F2 = 1
F3 = 2
F4 = 3
F1+F2 = 4
F1+F3 = 5
F1+F4 = 6
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F2+F3 = 7
F2+F4 = 8
F3+F4 = 9
5 pow 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
10 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
15 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
20 thousandth.
[0061] In another embodiment, each of the digits may be represented by
at least
two tracers, as follows:
G1+G2 = 0
G1+G3 = 1
G1+G4 = 2
G1+G5 = 3
G2+G3 = 4
G2+G4 = 5
G2+G5 = 6
G3+G4 = 7
G3+G5 = 8
G4+G5 = 9
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[0062] In another embodiment, the numbers may be represented by
ratiometric
dosages of the tracer, thereby reducing the number of tracers necessary for
communication.
G1-F 0.25 G2 = 0
G1-F 0.5 G2 = 1
G1+ 0.75 G2 = 2
G1-F G2 = 3
0.25 G1+ 0.25 G2 = 4
0.25 G1+ 0.5 G2 = 5
0.25 G1+ 0.75 G2 = 6
0.25 G1-F G2 = 7
0.5 G1+ 0.5 G2 = 8
0.5 G1-F G2 = 9
[0063] Embodiments of the chemical communication system may be used for
communication between two downhole devices. In one embodiment, referring back
to
Figure 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.
[0064] 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 Figure 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
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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.
[0065] 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.
[0066] 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.
G1 = 20%< life <30%
G2 = 10%< life <20%
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.
[0067] In another embodiment, the chemical communication system may be
used
to communicate information about the fluid regime in the wellbore. For
example, a
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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.
[0068]
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.
[0069]
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.
[0070]
In one or more of the embodiments described herein, ascribing the
measured value to a code element is performed downhole.
[0071] 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.
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[0072] 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.
[0073] 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.
[0074] 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.
[0075] 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.
[0076] 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.
