Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR COMMUNICATION WITH A DOWNHOLE TOOL
BACKGROUND OF THE INVENTION
1. Field of the Invention
The invention relates to oil and gas
exploration/production. More particularly, the invention
relates to a method and apparatus for improved communication
techniques between an uphole apparatus and a downhole tool.
2. State of the Art
Logging-while-drilling (LWD) or measurement-while-
drilling (MWD) involves the transmission to the earth's
surface of downhole measurements taken during drilling. The
measurements are generally taken by instruments mounted
within drill collars above the drill bit in order to obtain
information such as the position of the bit, oil/gas
composition/quality, pressure, temperature and other
geophysical and geological conditions. Indications of the
measurements must then be transmitted uphole to the earth's
surface. It has been one longstanding objective to develop
data transmission systems which do not require the
utilization of electrical conductors. The utilization of
electrical conductors has several serious disadvantages
including: (1) since most wellbores include regions which
are exposed to corrosive fluids and high temperatures, a
long service life cannot be expected from a data
transmission system which utilizes electrical conductors;
(2) since most wellbores extend for substantial distances,
data transmission systems which utilize electrical
conductors are not generally considered to be cost
effective, particularly when such systems are utilized only
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infrequently, or in a limited manner; (3) since all
wellbores define fairly tight operating clearances,
utilization of a wireline conductor to transmit data may
reduce or diminish the operating clearance through which
other wellbore operations are performed; and (4) since
wellbores typically utilize a plurality of threaded tubular
members to make up tubular strings, utilization of an
electrical conductor to transmit data within the wellbore
complicates the
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make-up and break-up of the tubular string during conventional operations.
Accordingly, the oil and gas industry has moved away from the utilization of
electrical conductor data transmission systems (frequently referred to as
"hardwire" or
"wireline" systems), and toward the utilization of wireless systems to
transmit data within the
wellbore. The most common scheme for transmitting measurement information
utilizes the
drilling fluid within the borehole as a transmission medium for acoustic waves
modulated to
represent the measurement information. Typically, drilling fluid or "mud" is
circulated
downward through the drill string and drill bit and upward through the annulus
defined by
the portion of the borehole surrounding the drill string. The drilling fluid
not only removes
drill cuttings and maintains a desired hydrostatic pressure in the borehole,
but cools the drill
bit. In a species of the technique referred to above, a downhole acoustic
transmitter known
as a rotary valve or "mud siren", repeatedly interrupts the flow of the
drilling fluid, and this
causes a varying pressure wave to be generated in the drilling fluid at a
frequency that is
proportional to the rate of interruption. Logging data is transmitted by
modulating the
acoustic carrier as a function of the downhole measured data.
One type of MWD technique called Vertical Seismic Profiling (VSP) involves the
use
of a seismic source and sensors, together with a memory and calculation device
for storing
and processing the received seismic signals. U.S. Patent Number 5,585,556
describes a
method and apparatus for performing VSP-measurements where the seismic source
is placed
at or in the vicinity of the surface of the earth (or water). Signals
generated by the source are
detected by hydrophones or geophones located in the vicinity of the source at
the surface and
in the drill string. The geophones or the hydrophones in the drill string
transmit the detected
signals to a memory and calculation unit in the drill string that processes
and transmits the
signals completely or partly to a central data processing unit on the rig. The
hydrophones or
the geophones at the surface simultaneously transmit the detected signals to
the central data
processing unit at the surface, while chronometers showing identical times,
connected to the
source and to the memory and calculation device in the drill string make
possible a precise
calculation of the travel time of the seismic signal between the source and
the geophones or
the hydrophones in the drill string.
According to the preferred embodiment of the '556 patent, circulation of the
drilling
fluid is interrupted as the sensors in the drill string are activated for the
registration of sound
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signals discharged from the seismic source. In the following 60-120 seconds
the memory
and calculation unit will acquire all signals from the sensors in the drill
string. The signals
contain both the transmitted and the reflected waveforms. The sources must be
discharged
within a fixed interval of time. After this time interval, the content of the
memory unit is
S copied to the calculation unit and is processed to determine the number of
shots, the mean
arnval time, and the mean amplitude of the first arrived signals. This
information may be
returned to the surface using MWD telemetry while the drilling fluid is put
into circulation
again. Alternatively, the information may be stored in memory and retrieved
when the tool is
tripped out of the borehole.
A disadvantage of the method disclosed by the '556 patent is that there is no
disclosed method of communicating with the downhole tool to indicate to the
downhole tool
that VSP shots are commencing. Since the downhole data acquisition is non-
discriminatory
when circulation is stopped, i.e., most of the data recorded does not include
useful signal
information; the downhole tool continuously receives and stores acoustic
waveforms without
any disclosed discrimination. Since MWD telemetry has a very small bandwidth,
e.g., one
bit per second, transmission of useless information can delay the transmission
of valuable
data from other LWD tools. Ultimately, time is wasted and since the cost of
rig time,
particularly offshore rig time, is extremely expensive, time is of the essence
when acquiring
downhole measurement information. Moreover, while it is possible to store all
of the
acquired data in downhole memory, most of the memory will be wasted and the
tool will
need to be withdrawn more frequently than desired.
U.S. Patent Number 5,579,283 describes a method and apparatus for
communicating
coded messages in a well bore. The method uses transmitting and receiving
apparatus that
are in contact with the well bore fluid to send coded pressure pulses to
downhole tools. A
disadvantage of the method described by the '283 patent is that the
communication technique
alters the operating state of the downhole tool.
Thus, there remains a need for a technique to communicate with a downhole tool
in
an efficient manner that discriminates between signal data, representative of
a true signal
originating from a selected signal source, and useless data.
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SUMMARY OF THE INVENTION
It is therefore an object of the invention to provide methods and apparatus
for
improved communication with a downhole tool from a signal source located
uphole or at a
remote location.
It is also an object of the invention to provide methods and apparatus for
acquiring
signal data in a downhole tool which discriminates between data representative
of a true
source signal and useless data.
It is another object of the invention to provide methods for making VSP
measurements which are better and more time efficient than the prior methods.
It is still another object of the invention to provide methods for instructing
a
downhole tool to perform a specific action or process by means of effective
communication.
In accord with these objects which will be discussed in detail below, the
apparatus of
the present invention includes uphole and downhole equipment. The uphole
equipment
includes a signal source, such as a seismic source, (or array) coupled to a
programmable
triggering or firing system and a clock. Optionally, the uphole equipment may
include
receivers (such as acoustic receivers) for capturing reference signals near
the source and may
include telemetry equipment for receiving MWD signals from the downhole
equipment. The
downhole equipment includes one or more receivers, preferably acoustic
receivers, signal
processing equipment, memory, and a clock. Optionally, the downhole equipment
may also
include other sensors such as flow sensors and motion sensors, as well as MWD
telemetry
equipment for transmitting data to the surface.
The communication methods of the present invention include the initiation of
an
uphole signal that will be recognized by the downhole tool. Once the signal is
recognized,
the downhole tool then performs a specific action or process in response. The
invention
includes, but is not limited to, tightly synchronizing the recordation of
signals detected
downhole with the firing of the signal source (on the surface or at a remote
location) and
processing the recorded signal data to eliminate useless information. Downhole
recording of
signal data may be continuous or individual time records may be captured
according to a
schedule that is associated with the schedule of possible source activation.
According to one aspect of the invention, it is assumed that no signal data
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measurements will be made while drilling, while drill pipe is moving, or while
mud is
circulating. According to this aspect, downhole flow sensors and motion
sensors enable the
signal processing equipment to determine when signal data representative of
true signals
originating from the source are to be recorded. When the downhole flow sensors
and motion
sensors indicate that drilling has stopped and the circulation of mud flow has
been
interrupted, the signal processing equipment will begin to acquire signal data
received from
the receivers. However, since it cannot be assumed that signal measurements
will be
performed every time drilling is stopped and mud circulation is interrupted,
the invention
provides additional means to communicate with the downhole tool that signal
measurements
are intended to be made.
The methods of the invention present several algorithms for true source signal
recognition, whereby actual signal data information is extracted from the
recordings of the
receivers so that the ultimate stored data is compact and virtually 100%
useful. This
elimination of useless data conserves valuable telemetry time and/or enables
longer operation
of the apparatus before tripping out to retrieve stored data.
According to the methods of the invention, sequentially recorded signal data
from the
receivers are compared to each other to determine whether they "look similar."
Sequentially
recorded signal data may be derived by extracting record samples from a moving
time
window on a continuous recording, or by capturing individual time records
according to a
schedule that is synchronized with a schedule of possible source activation.
It is not
necessary to have a catalogue of "useful" or "useless" signal data downhole
because
sequentially recorded signal data can be made to intentionally look similar
with repeated
activation of the surface source according to a predetermined schedule that is
known to the
downhole tool.
According to another aspect of the invention, similarity measurements are
further
processed to give values between 0 and 1 (a first probability) and a
probabilistic analysis is
utilized to determine whether a record represents a true source signal.
According to another aspect of the invention, record selection is enhanced by
breaking each record into multiple time windows. Each record is preferably
broken into two
time windows, one of which contains noise and the other of which may contain a
true source
signal. This is implemented by tightly synchronizing the downhole and surface
clocks for
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accurate partitioning of the downhole recordings. The "energy" contained in
each window is
calculated and the energies are combined in such a way that a second signal
probability is
obtained. The first probability and second probability are multiplied to
obtain a third
probability which is used to determine the presence or absence of a true
signal.
The invention provides an apparatus for communication with a downhole tool.
The
apparatus includes an uphole signal source; a programmable triggering system
coupled to
said uphole signal source; an uphole clock coupled to said programmable
triggering system;
a downhole receiver within the downhole tool; downhole signal processing means
coupled to
said downhole receiver for processing signal data received by said receiver;
downhole
memory coupled to said signal processing means; and a downhole clock coupled
to said
signal processing means, wherein said signal processing means includes means
for recording
signal data received by said receiver into said memory and comparison means
for
determining whether recorded signal data represents a true source signal.
The invention also provides a method for communication with a downhole tool.
The
method including firing an uphole signal source according to a schedule;
receiving signal
data at the downhole tool according to the schedule; comparing said signal
data to each other
to determine whether said signal data represents a true source signal; and
processing the
signal data which are determined to represent true source signals.
The invention further provides another method for communicating with a
downhole
tool. The method including firing a signal source from a remote location;
receiving signal
data associated with said signal at the downhole tool; segmenting said signal
data into events
defined by a time period; comparing said segmented signal data to determine
whether said
signal data represents a true source signal; and processing the signal data
determined to
represent a true source signal.
Additional objects and advantages of the invention will become apparent to
those
skilled in the art upon reference to the detailed description taken in
conjunction with the
provided figures.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a schematic illustration of an exemplary offshore installation
incorporating
the invention.
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Figure 2 is a simplified block diagram of the surface equipment of the
apparatus of
the invention.
Figure 3 is a simplified block diagram of the downhole equipment of the
apparatus of
the invention.
Figure 4 is an example of selected signal data during a typical drilling
operation
showing traces with signal and noise according to the invention.
Figure 5 is a schematic diagram of a signal data correlation technique
according to the
invention.
Figure 6 is an example of correlated signal data according to the invention.
Figure 7 is an example of the output of a coherence calculation according to
the
invention.
Figure 8 is an example of signal and noise estimates according to the
invention.
Figure 9 is a flow chart of a method of the invention.
Figure 10 is a graph of the probability calculations on the traces of Figure 4
according
to the invention.
DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS
Referring now to Figures 1 through 3, an apparatus of the invention includes
uphole
equipment 10 and downhole equipment 12. The uphole equipment includes a signal
source
(or array) 14 coupled to a firing system 16, a programmable processor 18, and
a clock 20
coupled to the processor. One embodiment of the invention comprises a seismic
signal
source 14. In the illustration of Figure 1, the firing system, processor, and
clock are located
on an off shore rig 22 and the seismic array 14 is deployed near the rig,
close to the surface
of the water. Preferably, the uphole equipment 10 also includes acoustic
receivers 24 and a
recorder 26 for capturing reference signals near the source. The uphole
equipment 10 further
preferably includes telemetry equipment 28 for receiving MWD signals from the
downhole
equipment. The telemetry equipment 28 and the recorder 26 are preferably
coupled to the
processor 18 so that recordings may be synchronized using the clock 20.
The downhole equipment 12 includes one or more receivers 30, signal processing
equipment 32, memory 34, and a clock 36. One embodiment of the invention
comprises
acoustic receivers 30. The receivers 30, clock 36 and memory 34 are coupled to
the signal
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processor 32 so that recordings may be made of signals detected by the
receivers in
synchronization with the firing of the signal source 14. Preferably, the
downhole equipment
12 also includes a motion sensor 31, a mud flow sensor 33, and MWD telemetry
equipment
38 for transmitting data to the uphole equipment 10. As illustrated in Figure
1, the downhole
equipment 12 is housed in a downhole tool 40 forming part of a drill string,
which is shown
traversing a borehole beneath the ocean bed. The clocks 20 and 36 are
preferably accurate
enough so that they remain within a few milliseconds of each other so long as
the apparatus
is in operation.
The communication techniques of the invention include identifying the signal
data
(such as acoustic waveforms) detected downhole with the firing of the signal
source 14 and
processing the waveforms to eliminate useless information. This is
accomplished by
segmenting the detected signal data into time windows or traces of finite
duration and
comparing the data. In other words, the detected signal data is partitioned or
broken into
specific events defined by a specific time period. Although the length of the
period may be
varied, each trace is preferably defined by an equal time period associated
with the firing
schedule of the signal source 14.
The processor 18 is programmed to cause the firing system 16 to activate the
signal
source 14 according to a schedule that is known to the downhole equipment 12.
For
example, as described below with reference to Figure 4, the firing system 16
will
consecutively activate the signal source 14 sixteen times with a fifteen
second pause between
each firing and then not again until the downhole system has been moved to a
different
depth. The downhole system acquires data periodically with three-second
recordings
scheduled fifteen seconds apart. Each acquisition is, therefore, at a
predefined time when
there is a possibility for source 14 activation to occur.
The methods of the invention also include several algorithms for signal
recognition
whereby true signal information is extracted from the recordings of the
receivers 30 so that
the ultimate stored data is compact and virtually 100% useful. This
elimination of useless
data conserves valuable telemetry time and/or enables longer operation of the
apparatus
before tripping out to retrieve stored data by using memory efficiently. As
mentioned above,
and depending on the accuracy of the signal recognition algorithm, it may be
preferable to
perform signal processing only when the motion and flow sensors indicate that
drilling has
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stopped and the mud flow has been interrupted.
Figure 5 illustrates a true signal recognition technique of the invention. A
correlation
algorithm is used to compare sequentially recorded signal data from the
receivers 30. Each
recorded trace (1, 2, 3, 4...) is a time interval, e.g., three seconds, which
is synchronized to
the schedule of the uphole firing system 16 so that if a signal is being
generated, it will be
captured in a recording. Accurate synchronization is only necessary if
absolute timing
information is needed. Otherwise, basic communication may be achieved by
simply
segmenting a continuous recording into consecutive time windows with duration
equal to the
period of source 14 activation. Preferably, the first sample of a segmented
trace should
immediately follow the last sample of the previous trace. Correlation concepts
are further
described in A. V. OPPENHEIM AND R. W. SCHAFER, DIGITAL SIGNAL PROCESSING 556
Prentice-Hall 1975.
The basic correlation technique is to correlate signal data from sequentially
recorded
traces, for example traces ("x") and ("y"). The first trace x can be a stack
or average of
accumulated signal data waveforms which have been determined to have true
signal content
(by the iterative techniques of the invention described below) prior to the
accumulation of
trace y. For the case where there are only two traces x and y, the method
accepts x as a single
recorded trace and also reverts to this case after a trace with no true signal
content has been
recorded. Additionally, the traces x, y are taken as inputs to coherence and
signal-noise
decomposition schemes. In the following, the traces x, y are written as x; and
y;, where i is a
time index.
For N samples of traces x, y, the correlation is calculated as shown in
equation (1)
below.
N-I m~-1
Cxy (fYl) - ~ xn+l yn+m+1 ( 1 )
n=0
Applying this equation to a set of recordings obtained from the receivers 30
downhole yields
a waveform of the type shown in Figure 6. The correlation waveform illustrated
in Figure 6
shows a true signal portion in the time window TS and a noise portion in the
time window Tn.
The likelihood of true source signal content being present in the TS time
window is measured
by calculating the ratio of root-mean-square (RMS) amplitude within the two
windows as
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shown in equation (2) below and expressing it as a probability P.
~Cz
r L. xy
P - ' T z (2)
CxY
r
The probability P is compared to a predetermined threshold to determine if
source 14
activation has occurred. If the probability exceeds the threshold value, the
downhole
processor 32 can take appropriate action, and basic communication has been
achieved.
According to another aspect of the invention, the traces x, y from the
sequentially
recorded signal data are analyzed for "coherence", a known measure of
similarity.
Coherence analysis is further described in S.L. MARPLE ,IR., DIGITAL SPECTRAL
ANALYSIS
wITH APPLICATIONS 390 Prentice-Hall 1987. The coherence function is shown
below as
equation (3) where Pte, is the power spectral density (as known to those
skilled in the art), and
f is frequency. The coherence function is calculated for every frequency and
returns a value
between 0 and l, indicating how well the input x corresponds to the input y at
each
frequency.
I PY(f'12 (3)
CoxY (.~) = p~ (f )PYY ~)
Figure 7 illustrates a typical coherence function. As the function varies
between 0
and 1, it can be used to determine the probability of true signal content in a
recording. The
probability that sequential recordings contain a true signal rather than noise
is calculated
according to equation (4) below, which is an average of the coherence function
within a
frequency band ~f.
P - ~r ~C°Xy(.~ (4)
The frequency band Of is chosen according to known characteristics of the
particular signal
being generated from the signal source 14, e.g., seismic signal
characteristics. As in the
correlation technique of the invention, the probability P is compared to a
predetermined
threshold to determine if source 14 activation has occurred. If the
probability P exceeds the
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threshold value, the downhole processor 32 can take appropriate action, and
basic
communication has been achieved.
Still another aspect of the invention is based on signal and noise
decomposition. It is
assumed that each recording contains a true signal component and a noise
component.
According to this technique, the signal is estimated by taking the sum of the
x and y traces
and the noise is estimated by taking the difference between the x and y
traces. Figure 8
illustrates the results of these sum and difference calculations. The top
signal s is the sum of
the x and y traces and the bottom signal n is the difference between the x and
y traces.
The signal and noise decomposition technique is refined by selecting a time
window
(Ts in Figure 8) within which a true signal is expected (it is known that some
early part of the
signal data waveform can not possibly have signal content because of the close
synchronization of surface and downhole systems), by calculating the signal
energy using
equation (5) below,
S-T ~sz
T
by calculating a first noise energy using equation (6) below,
N~ - 1 ~ n z (6)
Ts r,
and by finding a first probability of true signal content using equation (7)
below, which is the
ratio of true signal to true signal plus noise.
_ S ()
S + N,
The signal and noise decomposition technique, as well as any of the other
techniques
described above, is further enhanced by calculating the signal energy in the
expected noise
window T" as shown in equation (8) below.
Nz = 1 ~sz (8)
T" T"
With equations (5) and (8), a second probability of true signal content is
calculated using
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equation (9) below.
_ S ()
Pz S+NZ 9
Those skilled in the art will appreciate that the overall probability of true
signal content in the
recordings is found by taking the product of Pl and P2. The method thus
described may be
used to compare two signal data waveforms at a time. As will be described in
more detail
below, the invention enables the comparison of multiple waveforms at a time.
As shown in Figure 9, a communication method of the invention begins with
accumulation of recordings of signal data at 110. Signal data may be
immediately discarded
if sensors indicate mud flow at 112 or motion at 114. Figure 4 illustrates a
selection of signal
data waveforms recorded in accord with the invention. In particular, Figure 4
shows
recordings numbered 260 through 300, each being a three second recording.
Those skilled in
the art will appreciate that recordings 260 through 272 and recordings 289
through 300 do
not contain any true signal and are only noise. Recordings 273 through 288
clearly indicate
that they contain true source signals. Because of the tight synchronization of
the source and
recorders (described above) it is known in this example that a true signal
should not be
detected until one second of recording. Similarly, the first one second of
each recording
should contain noise. After all of the recordings are accumulated (or after a
sufficient
number of recordings are accumulated), each recording is divided into two time
windows Tn
(the first one second) and TS (the remainder of the recording) as shown at
step 116 in Figure
9. The following steps are performed for each sliding group of M recordings as
indicated at
118 in Figure 9.
As shown at 120 in Figure 9, a calculation of semblance (P~) is performed only
in the
TS windows with a sliding group of M number of traces according to equation
(10). Further
description of semblance calculations may be found in N. S. Neidall and M. T.
Taper,
Semblance and Other Coherency Measures for Multichannel Data, 34 GEOPHYSICS,
1971,
482-97.
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M \z
~~~x; I~
P = r. ~_~ (10)
1 M
M~~xz
=i r
The next step at 122 is to calculate the noise energy N* in the noise windows
Tn
according to equation (11) and at 124 to calculate the signal energy S* in the
true signal
window TS according to equation ( 12), as shown below.
M 2
N* 1 ~ ~xi (11)
Tn n i=1
S* _ ~. ~ L..xr z (12)
s r.
The next step at 126 is to calculate the ratio of the true signal energy to
true signal energy
plus noise energy to obtain a second probability, as shown in equation (13),
and then at 128
to calculate the product of P~ and PZ.
Pz = S* +*N* (13)
Figure 10 illustrates the product of P~ and P2 over the range of recordings
shown in
Figure 4 where calculations were made using M=3 (i.e., calculations were made
using a
sliding group of three recordings at a time). The numbers on the X-axis in
Figure 10
correspond to the numbers on the Y-axis of Figure 4, less 259, i.e., trace 260
in Figure 4
corresponds to trace number 1 in Figure 10. According to the invention, a
predetermined
threshold P value (e.g., 0.7) is used to decide, from the results pictured in
Figure 10, which of
the records contain true source signals. As shown at 130 in Figure 9, each
obtained product
is compared to the threshold. If it exceeds the threshold, the recording is
stored at 132. If it
does not exceed the threshold, the recording is discarded at 134.
Once it is determined which signal data records represent true source signals,
specific
processing may then be performed on the data representations (i.e., the
waveforms) to
prepare a response to be transmitted to the surface by MWD telemetry or by
other modes as
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known in the art. Hence, the activation of the source 14 according to a
predetermined
schedule establishes basic communication that indicates to the downhole tool
40 that it
should perform a specific action or process. As shown in Figure 9, the
algorithm operates in
a loop, repeating as new signal data is acquired.
It will be appreciated by those skilled in the art having the benefit of this
disclosure,
that the communication techniques of the invention are not limited to any one
particular type
of signal transmission between uphole and downhole equipment. A system in
accord with
the invention may be implemented utilizing various means of signal
generation/transmission,
including seismic, EM telemetry, or pressure variations in the drill pipe.
For the purposes of this specification it will be clearly understood that the
word
"comprising" means "including but not limited to," and that the word
"comprises" has a
corresponding meaning.
There have been described and illustrated herein several embodiments of
methods
and apparatus for efficient communication with a downhole tool. While
particular
embodiments of the invention have been described, it is not intended that the
invention be
limited thereto, as it is intended that the invention be as broad in scope as
the art will allow
and that the specification be read likewise. It will therefore be appreciated
by those skilled in
the art that yet other modifications could be made to the provided invention
without deviating
from its scope as so claimed.
