U.S. patent application number 15/160300 was filed with the patent office on 2016-09-15 for analyzing toolface velocity to detect detrimental vibration during drilling.
The applicant listed for this patent is Precision Energy Services, Inc.. Invention is credited to Roger Bartel, Richard Berns, Charles Mauldin.
Application Number | 20160265335 15/160300 |
Document ID | / |
Family ID | 43728805 |
Filed Date | 2016-09-15 |
United States Patent
Application |
20160265335 |
Kind Code |
A1 |
Mauldin; Charles ; et
al. |
September 15, 2016 |
Analyzing Toolface Velocity to Detect Detrimental Vibration During
Drilling
Abstract
A downhole drilling vibration analysis involves measuring
orientation data in at least two orthogonal axes downhole while
drilling with a drilling assembly. For example, two orthogonal
magnetometers can be used. A toolface of the drilling assembly is
determined using the measured sensor data, and velocity (RPM)
values for the toolface for a plurality of revolutions of the
drilling assembly are determined. From these determined values, a
coefficient of variation for the toolface velocity (RPM) values for
the revolutions of the drilling assembly is calculated. When a
pattern in found in the toolface velocity (RPM) and/or the
calculated coefficient of variations exceed one or more thresholds,
the processing device determines that detrimental vibrations are
occurring in the drilling assembly.
Inventors: |
Mauldin; Charles; (Spring,
TX) ; Bartel; Roger; (Spring, TX) ; Berns;
Richard; (Conroe, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Precision Energy Services, Inc. |
Fort Worth |
TX |
US |
|
|
Family ID: |
43728805 |
Appl. No.: |
15/160300 |
Filed: |
May 20, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12971202 |
Dec 17, 2010 |
9366131 |
|
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15160300 |
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61288933 |
Dec 22, 2009 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 10/00 20130101;
E21B 7/04 20130101; E21B 44/00 20130101; E21B 47/13 20200501; E21B
47/14 20130101; E21B 17/16 20130101; E21B 47/18 20130101; E21B
10/46 20130101; E21B 47/024 20130101; G01V 3/26 20130101; E21B
10/42 20130101; E21B 17/1078 20130101; E21B 4/00 20130101 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 10/00 20060101 E21B010/00; G01V 3/26 20060101
G01V003/26; E21B 17/10 20060101 E21B017/10; E21B 7/04 20060101
E21B007/04; E21B 17/16 20060101 E21B017/16; E21B 47/024 20060101
E21B047/024; E21B 4/00 20060101 E21B004/00 |
Claims
1. A downhole drilling vibration analysis method, comprising:
measuring orientation data of a drilling assembly downhole while
drilling with one or more drilling parameters; determining toolface
orientations of the drilling assembly using the measured
orientation data; determining toolface velocity values for the
toolface orientations for a plurality of revolutions of the
drilling assembly; calculating variation of the toolface velocity
values for the revolutions of the drilling assembly; determining
detrimental vibration in the drilling assembly based on--
determining that the calculated variation for at least some of the
revolutions exceeds at least one threshold, and finding one or more
patterns in at least one of the calculated variation and the
toolface velocity values; and modifying, in response to the
determined detrimental vibration, at least one of the one or more
drilling parameters used while drilling with the drilling
assembly.
2. The method of claim 1, wherein measuring the orientation data
comprises measuring one or more of an axis of a magnetometer, an
axis of an accelerometer, and a position of an encoder.
3. The method of claim 1, wherein determining the toolface
orientations comprises determining orientation of a tool axis
relative to at least one of magnetic north, gravitational
direction, and encoder position.
4. The method of claim 1, wherein determining the toolface velocity
values comprises: dividing each of the revolutions into a plurality
of equal bins for the toolface orientations; counting a number of
detected sensor samples occurring in each of the bins for each of
the revolutions; and correlating the counted number of samples to
the toolface velocity values.
5. The method of claim 1, wherein calculating the variation for the
toolface velocity values for the revolutions of the drilling
assembly comprises calculating a coefficient of variation of the
toolface velocity values for the revolutions.
6. The method of claim 5, wherein the coefficient of variation is a
ratio of a standard deviation of the toolface velocity values
relative to an arithmetic average of the toolface velocity
values.
7. The method of claim 1, wherein determining the detrimental
vibration in the drilling assembly comprises determining that the
drilling assembly exhibits at least one of stick/slip and bit whirl
during one or more of the revolutions.
8. The method of claim 1, wherein determining that the calculated
variation exceeds the at least one threshold and finding the one or
more patterns in the calculated variation comprises determining
that the calculated variation exceeds the at least one threshold at
periodic intervals between the revolutions.
9. The method of claim 8, wherein determining the detrimental
vibration in the drilling assembly comprises determining
detrimental vibration indicative of stick/slip in response to the
exceeded at least one threshold at the periodic intervals.
10. The method of claim 8, further comprising: finding at least one
of the toolface orientations in which a lowest or a highest of the
toolface velocity values for one or more of the revolutions occur
when the at least one threshold is exceeded; and determining that a
lowest or a highest of the toolface velocity values occurs at the
at least one found toolface orientation when the at least one
threshold is exceeded for a subsequent one of the revolutions.
11. The method of claim 1, wherein determining that the calculated
variation for at least some of the revolutions exceeds the at least
one threshold comprises determining that the calculated variation
exceeds the at least one threshold for an extent of the
revolutions.
12. The method of claim 11, wherein finding the one or more
patterns in the toolface velocity values comprises finding one or
more of the toolface orientations in which a lowest of the toolface
velocity values occurs across the extent of the revolutions.
13. The method of claim 12, wherein determining the detrimental
vibration in the drilling assembly comprises determining the
detrimental vibration indicative of bit whirl in response to the
exceeded at least one threshold and in response to the one or more
patterns having more than one of the found toolface orientations in
which the lowest of the toolface velocity values occur across the
extent of the revolutions.
14. The method of claim 13, wherein the one or more found toolface
orientations in which the lowest of the toolface velocity values
occurs corresponds to the one or more lobes of the bit whirl.
15. The method of claim 1, further comprising telemetering
information uphole indicative of the determined detrimental
vibration.
16. The method of claim 15, wherein the information comprises one
or more of: data indicative of vibration, an indication of a type
of detrimental vibration, an alarm condition, an interval between
spikes in the variation exceeding the threshold, a number of lobes
in a bit whirl, and the determined toolface velocity values.
17. The method of claim 1, wherein modifying the at least one of
the one or more drilling parameters in response to the determined
detrimental vibration comprises modifying at least one of a weight
on bit (WOB), drilling collar revolutions, a rotary speed, a
rotational speed, a rotary speed applied to a drilling string, an
energy provided by a rotary drive, a torque, and a pump rate.
18. A downhole drilling vibration analysis method, comprising:
measuring orientation data of a drilling assembly downhole while
drilling with one or more operating parameters; determining, from
the measured orientation data, orientations of the drilling
assembly; determining velocity values at the orientations for a
plurality of revolutions of the drilling assembly; determining that
variation of the velocity values for at least some of the
revolutions exceeds at least one threshold; determining detrimental
vibration in the drilling assembly by finding one or more patterns
in the velocity values at one or more of the orientations at least
in the revolutions exceeding the at least one threshold; and
modifying, in response to the determined detrimental vibration, at
least one of the one or more operating parameters of the drilling
assembly.
19. The method of claim 18, wherein modifying the at least one
operating parameter comprise modifying at least one of a weight on
bit (WOB), drilling collar revolutions, a rotary speed, a
rotational speed, a rotary speed applied to a drilling string, an
energy provided by a rotary drive, a torque, and a pump rate.
20. The system of claim 18, wherein the drilling assembly comprises
one or more of a drill bit, a motor, a drill collar, a stabilizer,
a rotary steerable system, a bent sub, a drill string component, a
bottom hole assembly component, a rotary rig component, and a
drilling fluid system component.
21. The system of claim 18, wherein determining the detrimental
vibration in the drilling assembly comprises determining that the
drilling assembly exhibits at least one of stick/slip and bit
whirl.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This is a continuation of U.S. application Ser. No.
12/971,202, filed 17 Dec. 2010, which is a non-provisional of U.S.
Provisional Appl. Ser. No. 61/288,933, filed 22 Dec. 2009, which is
incorporated herein by reference in its entirety and to which
priority is claimed.
BACKGROUND
[0002] To explore for oil and gas, operator drill a well by
rotating a drillstring having a drill bit and drill collars to bore
through a formation. In a common form of drilling called rotary
drilling, a rotary table or a top drive rotates a drillstring,
which has a bottom hole assembly (BHA) with increased weight to
provide necessary weight on the assembly's bit. During the drilling
operation, vibrations occurring in the drillstring can reduce the
assembly's rate of penetration (ROP). Therefore, it is useful to
monitor vibration of the drillstring, bit, and BHA and to monitor
the drilling assembly's revolutions-per-minute (RPM) to determine
what is occurring downhole during drilling. Based on the monitored
information, a driller can then change operating parameters such as
weight on the bit (WOB), drilling collar RPM, and the like to
increase drilling efficiency.
[0003] Because the drillstring can be of considerable length, it
can undergo elastic deformations, such as twisting, that can lead
to rotational vibrations and considerable variations in the drill
bit's speed. For example, stick-slip is a severe torsional
vibration in which the drillstring sticks for a phase of time as
the bit stops and then slips for a subsequent phase as the
drillstring rotates rapidly. When it occurs, stick-slip can excite
severe torsional and axial vibrations in the drillstring that can
cause damage. In fact, stick-slip can be the most detrimental type
of torsional vibration that can affect a drillstring.
[0004] For example, the drillstring is torsionally flexible so
friction on the drill bit and BHA as the drillstring rotates can
generate stick-slip vibrations. In a cyclic fashion, the bit's
rotational speed decreases to zero. Torque of the drillstring
increases due to the continuous rotation applied by the rotary
table. This torque accumulates as elastic energy in the
drillstring. Eventually, the drill string releases this energy and
rotates at speeds significantly higher than the speed applied by
the rotary table.
[0005] The speed variations can damage the BHA, the bit, and the
like and can reduce the drilling efficiency. To suppress
stick-slip, prior art systems, such as disclosed in EP0 443 689,
have attempted to control the speed imparted at the rig to dampen
any rotational speed variations experienced at the drill bit.
[0006] In whirl vibrations (also called bit whirl), the bit, BHA,
or the drillstring rotates about a moving axis (precessional
movement) with a different rotational velocity with respect to the
borehole wall than what the bit would rotate about if the axis were
stationary. Such precessional movement is called forward whirl when
faster compared to rotation where the bit axis is stationary and is
called backward whirl if slower. Thus, in backward whirl, for
example, friction causes the bit and BHA to precess around the
borehole wall in a direction opposite to the drillstring's actual
rotation. For this reason, backwards whirl can be particularly
damaging to drill bits. Whirl is self-perpetuating once started
because centrifugal forces create more friction. Once whirl starts,
it can continue as long as bit rotation continues or until some
hard contact interrupts it.
[0007] When detrimental vibrations occur downhole during drilling,
operators want to change aspects of the drilling parameters to
reduce or eliminate the vibrations. If left unaddressed, the
vibrations will prematurely wear out the bit, damage the BHA, or
produce other detrimental effects. Typically, operators change the
weight on bit, the rotary speed (RPM) applied to the drilling
string, or some other drilling parameter to deal with vibration
issues.
[0008] Attempts to detect vibrations during drilling have used
accelerometers in a downhole sensor sub to measure lateral
acceleration during drilling and to analyze the frequency and
magnitude of peak frequencies detected. Unfortunately,
accelerometers in the downhole sensor sub are susceptible to
spurious vibrations and can produce a great deal of noise. In
addition, some of the mathematical models for processing
accelerometer data can involve several parameters and can be
cumbersome to calculate in real-time when a drilling operator needs
the information the most. Lastly, the processing capabilities of
hardware used downhole can be somewhat limited, and telemetry of
data uphole to the surface may have low available bandwidth.
[0009] The subject matter of the present disclosure is directed to
overcoming, or at least reducing the effects of, one or more of the
problems set forth above.
SUMMARY
[0010] The teachings of the present disclosure detect and measure
detrimental vibrations from rotary stick/slip and whirl in a
different approach than traditionally used. As noted previously,
the conventional approach for detecting and measuring these
vibrations uses orthogonal X-Y accelerometers that measure
velocities during drilling. The teachings of the present
disclosure, however, use toolface binning to derive the radial
velocity (RPM) at particular radial orientations (or toolfaces)
during drilling in a less complicated and cumbersome model.
Toolface may generally refer to the orientation of a tool relative
to a bend in a bent sub. However, the housing of the tool used in
the present disclosure may not have a bent sub. Instead, the
teachings of the present disclosure, although referred to in terms
of toolface, apply generally to the sensor face of the downhole
tool. The sensor face refers to the orientation of the sensors in
or on the tool to a particular reference point on the tool's
housing.
[0011] In this toolface binning, a histogram of toolfaces is
created for each revolution of the drillstring based upon its
angle. Each bin contains a count of toolface measurements that have
fallen within that bins range. Each bin is equal in span, and the
toolface feed is continuous and periodic. At the conclusion of each
revolution, a composite toolface RPM image can be constructed from
the number of counts in each toolface bin. This velocity
measurement is traditionally presented in revolutions per minute
units (RPM). The number of bins and the feed rate of the streaming
toolface affect the resolution of the composite velocity image.
[0012] In one embodiment, a downhole drilling vibration analysis
system has a plurality of sensors and processing circuitry. The
sensors measure orientation data in two orthogonal axes, and the
processing circuitry is configured to handle and process the
measured orientation data to determine if detrimental vibrations,
such as stick-slip or whirl, are occurring in the drilling assembly
during drilling.
[0013] In use, the sensors measure orientation data in at least two
orthogonal axes downhole while drilling with the drilling assembly,
and the processing circuitry determines a toolface of the drilling
assembly using the measured sensor data and determines RPM values
for the toolface for a plurality of revolutions of the drilling
assembly. Using this information, the processing circuitry
calculates a coefficient of variation for the RPM values for the
revolutions to find if the coefficient exceeds a threshold.
Finally, the processing circuitry may determine that detrimental
vibration is occurring based on the coefficient of variation
exceeding the threshold and based on a pattern found in the
calculated coefficient of variation or in the toolface and RPM
values.
[0014] If aspects of detrimental vibration are encountered, the
processing circuitry can set warnings or alarms and can telemeter
these and particular information uphole to the surface via a
telemetry system. At the surface, a driller can manually adjust
drilling parameters, or a drilling system can automatically
drilling parameters to reduce or eliminate the detrimental
vibration.
[0015] The foregoing summary is not intended to summarize each
potential embodiment or every aspect of the present disclosure.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1 illustrates a drilling system.
[0017] FIGS. 2A-2B illustrate a monitoring tool of a bottomhole
assembly in more detail.
[0018] FIG. 3 shows a conceptual cross-section of a borehole.
[0019] FIG. 4 is a flowchart showing a technique for determining
whether detrimental vibrations are occurring.
[0020] FIG. 5 shows rotation of the monitoring tool conceptually
divided into bins.
[0021] FIG. 6 is a table showing different feed rates and number of
bins for collecting radial velocity at particular tool orientations
(or toolfaces).
[0022] FIG. 7 conceptually shows motion of a bottom hole assembly
in a borehole during stick/slip vibration.
[0023] FIG. 8 conceptually shows motion of a bottom hole assembly
in a borehole during five-lobed whirl vibration.
[0024] FIGS. 9A and 9B show toolface RPM plots for a drilling
assembly operating normally.
[0025] FIGS. 10A, 10B, and 10C show toolface RPM plots for a
drilling assembly operating under stick/slip-like vibration.
[0026] FIGS. 11A, 11B, and 11C show toolface RPM plots for a
drilling assembly operating under whirl-like vibration.
[0027] FIGS. 12A, 12B, and 12C show toolface RPM plots for a
drilling assembly operating under other forms of detrimental
vibration.
DETAILED DESCRIPTION
A. Bottom Hole Assembly
[0028] FIG. 1 shows a borehole assembly (BHA) 10 suspended in a
borehole 2 penetrating an earth formation. The BHA 10 connects to a
drillstring 4, which in turn connects to a rotary drilling rig
uphole (represented conceptually at 5). The BHA 10 includes a drill
bit 16, which may be a polycrystalline diamond compact (PDC) bit, a
rotary drilling bit rotated by a motor and shaft, or any other
suitable type of drill bit. In addition to the drill bit 16, the
BHA 10 can have a drill collar 12, one or more stabilizer 14, and
other conventional components (i.e., motor, rotary steerable
system, etc.).
[0029] During drilling operations, the rotary rig 5 imparts
rotation to the drill bit 16 by rotating the drillstring 4 and BHA
10. Surface equipment 6 typically controls the drillstring's
rotational speed. In addition, a drilling fluid system 8 circulates
drilling fluid or "mud" from the surface downward through the
drillstring 4. The mud exits through the drill bit 16 and then
returns cuttings to the surface via the annulus. If the BHA 10 has
a motor (not shown), such as a "mud" motor, then motor rotation
imparts rotation to the drill bit 16 through a shaft. The motor may
have a bent sub, which can be used to direct the trajectory of the
advancing borehole 2.
[0030] FIG. 2A shows portion of the BHA 10 in more detail. As
shown, the BHA 10 has a monitoring tool 20, components of which are
diagrammatically shown in FIG. 2B. Briefly, the tool 20 has a
sensor section 22, a power section 24, an electronics section 26,
and a telemetry section 28. The sensor section 22 has a directional
sensor element 30, which can include accelerometers 32 and
magnetometers 34 to indicate the orientation (azimuth, inclination,
and toolface) of the BHA 10 within the borehole 2. The sensor
section 22 can also have other sensors used in
Measurement-While-Drilling (MWD) and Logging-While-Drilling (LWD)
operations including, but not limited to, sensors responsive to
gamma radiation, neutron radiation, and electromagnetic fields.
[0031] The electronics section 26 houses electronic circuitry to
operate and control other elements within the BHA 10 and includes
memory 50 for storing measurements made by the sensor section 22
and a processor 40 to process various measurement and telemetry
data. The telemetry section 28 communicates data with the surface
by receiving and transmitting data to an uphole telemetry section
(not shown) in surface equipment 6. Various types of borehole
telemetry systems are applicable including mud pulse systems, mud
siren systems, electromagnetic systems and acoustic systems. The
power section 24 supplies electrical power needed to operate the
other elements within the BHA 10.
[0032] During drilling, the monitoring tool 20 monitors the
revolutions-per-minute (RPM) of the BHA 10 (collar 12, stabilizer
14, drill bit 16, etc.) on the drillstring 4. To monitor the drill
collar's RPM, the tool 20 has the directional sensor element 30
(with accelerometers 32 and magnetometers 34 arranged on two or
more axes) so the sensor element 30 can provide information about
stick-slip and whirl vibrations occurring during drilling. As is
known, a magnetometer 34 is a fluxgate induction device whose
output indicates its orientation with respect to the earth's
magnetic field. Accordingly, the magnetometers 34 can be used to
calculate the azimuth and magnetic toolface of the tool 20.
"Azimuth" refers to an angle in a horizontal plane measured
relative to (true or magnetic) north. Magnetic toolface is
typically measured clockwise from the reference north bearing,
beginning at 0.degree. and continuing through 360.degree..
[0033] The tool 20 can also have the accelerometers 32 arranged
orthogonally and directly coupled to the insert in the tool 20. The
accelerometers 32 are intended to measure acceleration forces
acting on the tool 20. The accelerometers 32 can detect inclination
of the tool 20 and can also detect vibration and shock experienced
by the drillstring 4 downhole. The downhole RPM obtained by the
tool 20 combined with the accelerometer and magnetometer data helps
identify the type of vibrations (e.g., whirl or stick-slip)
occurring downhole. Knowing the type of vibration allows operators
to determine what parameters to change to alleviate the experienced
vibration.
[0034] The tool 20 is programmable at the well site so that it can
be set with real-time triggers that indicate when the tool 20 is to
transmit vibration data to the surface. The tool 20 has memory 50
and has a processor 40 that processes raw data downhole. In turn,
the processor 40 transmits processed data to the surface using the
telemetry system 28. Alternatively, the tool 20 can transmit raw
data to the surface where processing can be accomplished using
surface processing equipment 6 (FIG. 1). The tool 20 can also
record data in memory 50 for later analysis. Each of the processor
40, accelerometers 32, magnetometers 34, memory 50, and telemetry
unit 28 can be those suitable for a downhole tool, such as used in
Weatherford's HEL system.
[0035] During drilling, various forms of vibration may occur to the
drillstring 4 and the BHA 10 (i.e., drill collar 12, stabilizers
14, and drill bit 16 as well as bent sub, motor, rotary steerable
system (not shown), etc.). In general, the vibration may be caused
by properties of the formation being drilled, by the drilling
parameters being applied to the drillstring 4, the characteristics
of the drilling components, and other variables. Regardless of the
cause, the vibration can damage the BHA 10, reducing its
effectiveness and requiring one or more of its components to be
eventually replaced or repaired.
[0036] Several real-time data items and calculations can be used
for analyzing the vibration experienced by the drillstring 4 during
drilling. The real-time data items and calculations are provided by
the monitoring tool 20 of FIGS. 1-2. In one implementation,
real-time data items can cover acceleration, RPM, peak values,
averages, etc. As detailed herein, tracking these real-time data
items along with the vibration calculations helps operators to
monitor drilling efficiency and determine when the drilling
parameters need to be changed.
[0037] To deal with damage and wear on the BHA 10, the techniques
of the present disclosure identify and quantify levels of
stick/slip and/or whirl vibrations. To do this, the tool 20 uses
its x and y-axis magnetometers 34 to measure the radial velocity
the drill string 4 at particular toolface or radial orientations of
the drill string 4. (In general, the magnetometers 34 can at least
be used in a vertical well to determine magnetic toolface, while
other sensor arrangements could be used in vertical wells as well
as other types of wells.) The radial velocity can be measured in
terms of revolutions per minute (RPM) or other such measure.
[0038] The processor 40 then records the radial velocity (RPM) data
in memory 50 at particular toolfaces and processes the toolface RPM
data using calculations as detailed below to determine the type and
extent of vibration. In turn, the processor 40 can transmit the
data itself, some subset of data, or any generated alarm to the
surface. In addition to or in an alternative to processing at the
tool 20, the raw data from the magnetometers 34 and other sensors
30 can be transmitted to the surface where the calculations can be
performed by the surface processing equipment 6 for analysis.
[0039] The tool 20 can store the rotation speed variation responses
within downhole memory 50. Some or all of the information,
depending on the available bandwidth and the type of telemetry, can
be telemetered to the surface for additional processing. At the
tool 20, however, the processor 40 can monitor the data to detect
detrimental vibrations caused by slip/stick and/or whirl. This can
trigger an alarm condition, which is telemetered uphole instead of
the data itself. Based on the alarm condition, operators can adjust
appropriate drilling parameters to remove the detrimental
vibration.
[0040] If stick-slip is detected, for example, drilling operators
may be able to reduce or eliminate stick-slip vibrations by
increasing rotary speed. Alternatively, the drilling operators can
use a controller on the rotary drive that varies the energy
provided by the rotary drive and interrupts the oscillations that
develop. Whirl, however, is self-perpetuating. Therefore, in some
instances, drilling operators may only be able to eliminate whirl
vibration by stopping rotation altogether (i.e., reducing the
rotary speed to zero) as opposed to simply reducing the rotary
speed. Of course, drilling operators can apply these and other
techniques to manage the drilling operation and reduce or eliminate
detrimental vibrations.
B. Discussion of Borehole Angles
[0041] FIG. 3 shows a conceptual cross-section of a borehole 2 to
define certain parameters used herein for characterizing toolface
velocity (RPM) along with stick/slip and whirl. The center 52 of
the borehole is shown as well as a "zero" reference angle 51 for
defining toolface. This reference angle 51 can be defined by
magnetic north, a sensor orientation on the tool (20), a mechanical
encoder's position on the tool (20), etc. depending on how toolface
is determined.
[0042] For purposes of discussion, assume that the drill bit
rotation speed is decreased to a "reduced" value beginning
essentially at speed variation angle .alpha. indicated at 54 and
continued through a "dwell" angle of magnitude 6 indicated at 60.
The position of the variation angle .alpha. is preferably defined
with respect to the reference angle 51. The bit rotation speed then
resumes essentially to a "normal" value for the remainder of the
360-degree rotation cycle.
[0043] The instantaneous and periodic change from the "normal" to
"reduced" speeds can be caused by stick/slip, whirl, or other
vibration. This decrease in cutting power during the dwell angle
.sigma. (shown at 60) will leave a surplus of borehole wall
material essentially at the dwell angle .sigma..quadrature. or will
cause uneven wear on the drill bit, stabilizer, or other component.
This surplus of material naturally causes the drill bit to move
radially to the opposite side of the hole to an arc section
.sigma./2 indicated at 57 that terminates at an angle .beta., where
.beta.=.alpha.-180.degree.+.sigma./2 and .beta. is indicated at 56.
Drill bit rotation speed through the arc .sigma./2 to the angle
.beta. is greater than the RPM imparted to the drillstring. This
results in the removal of a disproportionally large amount of
borehole wall material essentially in the arc 57, which can deviate
the borehole in this direction or disproportionately wear the drill
bit, stabilizer, or other components of the BHA.
C. Discussion of Toolface
[0044] As noted above, the downhole sensor element 30 includes
magnetometers 34 and accelerometers 32 (inclinometers) that provide
azimuth, inclination, and sensor toolface. Usually, the x-axis of
the sensor element 30 is perpendicular to its y-axis, and both the
x and y-axes are perpendicular to the tool axis. Typically, three
magnetometers 34 and three accelerometers 32 are used to measure
the three components of the Earth magnetic field vector and the
gravity vector in the sensor's frame, and the magnetometer and
accelerometer axes are typically aligned. Depending on how it is
obtained, the sensor toolface can be either magnetic toolface or
gravity toolface. For example, the sensor toolface is a measure of
the orientation of the BHA 10 about the tool axis relative to
magnetic north (magnetic toolface), top of the borehole (gravity
toolface), or relative to an encoder position (mechanical
toolface). Typically, the toolface is defined by the angle between
the x-axis and some geometrical direction.
[0045] Measurement of tool's orientation about the tool axis can be
obtained under most situations (vertical, horizontal, or deviated
wells). If the tool 20 is in a horizontal well, for example, then
the x-axis of the directional sensor frame is vertical, and the
sensor toolface is defined as an angle of zero. For a directional
well, orientation is based on gravity toolface, which is defined as
the angle between the x-axis and the line intersect between the x-y
plane and the vertical plane parallel to the tool axis. For a
vertical well, orientation is based on magnetic toolface, which is
defined as the relative angle between the x-axis and the line
intersect between the x-y plane and a vertical plane parallel to
the magnetic north vector. Each magnetometer 34 measures the
magnetic field's strength and direction in the magnetometer's
sensor frame so the magnetic toolface can be derived therefrom. For
purposes of the present disclosure, reference to the tool's
orientation is simply described as the toolface, regardless of how
obtained.
D. Analysis Technique
[0046] FIG. 4 shows an analysis technique 100 according to the
present disclosure in which detrimental vibration of the
drillstring 4 is determined. The technique uses the tool 20 of
FIGS. 2A-2B having the sensor element 30, processor 40, memory 50,
and telemetry unit 28. Initially, the 360-degree rotational cycle
of the BHA 10 is configured into bins or segments to facilitate the
data acquisition (Block 102). During drilling, the tool 20 measures
data from the sensor element 30 (e.g., x and y-axis magnetometers
34) (Block 104). Then, comparing the readings from the sensor
element 30, the processor 40 derives the toolface velocity (RPM) of
the BHA 10 (Block 106).
[0047] As the tool 20 rotates on the BHA 10, data for a streaming
toolface can come from any of a number of sources downhole.
Preferably, the orthogonal magnetometers 34 are used because of
their immunity to noise caused by vibration. However, other sensors
could be used, including gyros and accelerometers 32. Although the
source of the streaming toolface data may vary, the data is
preferably continuous and periodic for proper analysis.
[0048] As noted above, data acquisition of the toolface velocity
uses binning. The rotation of the assembly 10, which totals
360-degrees, is divided into a plurality of bins or segments. The
toolface where particular velocity (RPM) values occur during a
rotation can then be determined from the element (e.g.,
magnetometer) readings and the divided bins.
[0049] As shown in FIG. 5, for example, the rotation of the
assembly 10 can be divided into 24 bins so that each bin spans
15-degrees of the assembly's rotation. In general, the toolface can
be divided into any number of suitable bins depending on the
desired resolution and accuracy of the measurements. However, the
bins preferably encompass equal spans to simplify data acquisition
and processing.
[0050] In the toolface binning used, a histogram of toolfaces is
created for each revolution of the drillstring based upon its
angle. Each bin contains a count of toolface measurements that have
fallen within that bin's range. Each bin is equal in span, and the
toolface feed is continuous and periodic. As the tool rotates, the
sensor element 30 detects toolface orientation at a sample rate
according to the toolface feed. If no toolface measurement falls
within a bin's range (i.e., the sensor element does not detect
orientation in the given bin), then the velocity in that bin is
assumed to be the maximum measureable velocity and is given one
count. If one or more toolface measurement fall within a bin's
range (i.e., the sensor element detects orientation in the given
bin one or more times according to the toolface feed), then a count
for that bin is given by the number of tool measurements in that
bin.
[0051] At the conclusion of each revolution, a composite toolface
velocity image can be constructed from the bins of the count of
toolface measurements. This velocity measurement is traditionally
presented in units of revolutions per minute (RPM). The number of
toolface bins and the feed rate of the streaming toolface affect
the resolution of the composite velocity image. For example, the
revolutions per minute (RPM) of a given bin (RPM(x)) can be
calculated from:
RPM(x)=60/(r*n*s)
[0052] where: [0053] r=ToolFace feed rate (Seconds), [0054]
s=Samples in a given Bin, [0055] n=Number of Bin in one
revolution=360/bin span, and [0056] 60=number of seconds in one
minute.
[0057] Calculation of the average RPM for a complete rotation can
be found from:
RPM AVG=60/(r*SUM(bins))
[0058] The table in FIG. 6 shows some examples of different feed
rates and number of bins that can be used for the toolface binning
in the present techniques. Given a number of bin samples counted,
the corresponding RPM of the bin (and hence toolface orientation)
can be determined from the table.
[0059] Returning to FIG. 4, the processor 40 uses the toolface
binning to derive the toolface velocity (RPM) during drilling,
which produces a less complicated and cumbersome model. From the
resulting toolface velocity (RPM) data, the processor 40 recognizes
whether detrimental vibrations from stick/slip and/or whirl are
occurring. To do this, the processor 40 determines any vibration
patterns in the derived toolface velocity (Block 108).
[0060] As discussed previously, both stick/slip and whirl involve
cyclical variations in the RPM of the BHA 10. Although the average
RPM may remain relatively constant and may follow the imparted RPM
by the rig at the surface, the repetitive decreases and increases
in the RPM indicate that potentially detrimental vibrations are
occurring at the BHA 10. In addition, knowledge of the azimuthal
direction of the toolface at which the RPM variations occur
indicates the repeated physical nature of the vibrations as the BHA
10 encounters various parts of the borehole with repeated RPM
variations.
[0061] Accordingly, the processor 40 can first locate an RPM value
or range of values in the data that either exceed an upper RPM
threshold or fall below a lower RPM threshold. For example, a data
value that exceeds an upper RPM threshold may be indicative of the
BHA 10 in a slip condition of a stick/slip vibration as the drill
string 4 releases its accumulated torque. Alternatively, a data
value that falls below a lower RPM threshold may be indicative of
the BHA 10 in a stick condition of the stick/slip vibration as the
drill bit 16 decreases or ceases in rotation. Having one such RPM
value or range beyond the threshold does not necessarily indicate
that detrimental vibrations. Therefore, the processor 40 looks for
a repeat of the exceeded threshold at or within a range of the
toolface orientations during subsequent rotations of the BHA
10.
[0062] Therefore, based on pattern recognition, the processor 40
can determine whether detrimental vibration is occurring (and
potentially what type of vibration). In the discussion that
follows, the processor 40 can determine detrimental vibration by
finding a calculated coefficient of variation that exceeds a
threshold and by finding a pattern in the calculated coefficient of
variation or in the RPM values. Further details and examples of
these are provided in more detail below.
[0063] Before discussing the processing techniques, we first turn
to details of stick-slip and whirl. Stick-slip is a torsional or
rotational type of vibration and is caused by the bit 16
interacting with the formation rock or by the drill string 4
interacting with the borehole wall. As shown in FIG. 7, stick/slip
usually involves torsional vibration of the drill string 4 in which
the BHA 10 alternates between intervals of stopping and sticking to
the borehole and intervals of increase angular velocity (RPMs) of
the BHA 10. During periods of stick/slip, the instantaneous bit
speeds are much faster than the rotational speed observed at the
surface. In fact, the maximum instantaneous RPM at the bit 16 can
be several times the average RPM at the surface.
[0064] By contrast, whirl is a bending or lateral type of
vibration. In forward whirl, the BHA 10 deflects and precesses
around the borehole axis in the same direction as the BHA 10
rotates. In backward whirl, the BHA 10 deflects and precesses
around the borehole axis in an opposition direction to BHA's
rotation. As shown in FIG. 8, whirl can have a multiple-lobed, star
pattern as the drilling assembly 10 encounters the borehole wall,
slowing its RPM, and then rebounds with increased RPM. Whirl
usually involves low spots in the RPM that occur when the bit 16
contacts the borehole wall. Shown here as five lobe whirl, other
forms of bit whirl can involve three lobes or other
characteristic.
[0065] During whirl, the average RPM over time would be what is
expected from the drilling assembly 10 based on what RPM is
imparted at the surface. However, the RPM downhole and the drilling
assembly 10 suffer from intervals of high and low RPM that can
damage components. As long as rotation is applied, whirl may
continue once initiated, and an impediment, such as hard contact or
stop, may be needed to interrupt it.
[0066] Although not shown, it is understood that vibration of a BHA
10 can transition between stick-slip and whirl depending on
interaction between bending and torsion during operation.
Therefore, intermediate or alternative forms of detrimental
vibration can develop during drilling and may involve various
amounts of bending (lateral) and torsional (rotational) vibration,
as well as involving other vibrations, such as axial (longitudinal)
vibrations called "bitbounce." The techniques disclosed herein may
not only be useful for handling stick-slip and whirl, but can be
used to handle other forms of detrimental vibration as well.
[0067] Returning to the technique 100 in FIG. 4, once detrimental
vibration is encountered, the processor 40 proceeds to determine
the severity of the vibrations (Block 110). The level of severity
can depend on the level of the vibration, the time span in which
the vibration occurs, or a combination of both of these
considerations as well as others, such as any cumulative effect or
extent of the drilled borehole in which the vibration occurs.
Accordingly, the details of the detrimental vibrations are compared
to one or more appropriate thresholds.
[0068] For example, as the toolface measurements for the bins are
compiled, the processor 40 can determine the severity of the
vibrations by applying a coefficient of variation to the data to
determine the severity of the whirl or stick/slip. The coefficient
of variation c.sub.v is the standard deviation .sigma. of data
relative to the mean .mu. of the data, which is characterized
as:
c v = .sigma. .mu. . ##EQU00001##
[0069] As is known, the standard deviation .sigma. is a measure of
the variability or dispersion of data and is the square root of the
variance (the measure of the data's variation). As is also known,
the mean .mu. is the arithmetic average of the data values. To make
the calculation, the value of the standard deviation and average
RPM can be first smoothed using an appropriate algorithm or
averaging.
[0070] If the vibrations are sufficiently severe, then the
processor 40 uses the telemetry unit 28 to telemeter raw data,
processed data, alarm conditions, or each of these uphole to the
surface equipment 6 (Block 112). For example, telemetry of an alarm
or warning can be done when severe variations in RPM are occurring
which could indicate stick/slip or whirl.
[0071] Drilling operators receive the data, and the surface
equipment 6 displays the information and can further process the
information. Once the detrimental vibrations are known, the
drilling operators can manually adjust drilling parameters to
counteract the vibration, or the surface equipment 6 can
automatically adjust the parameters (Block 114). Various parameters
could be adjusted to mitigate the vibration. For example, these
parameters can include, but are not limited to, weight on bit,
rotational speed, torque, pump rates, etc.
E. Exemplary Logs
[0072] 1. Normal
[0073] For comparative purposes, FIGS. 9A and 9B illustrate normal
drilling vibration. As shown, for example, toolface RPM plots
300A-B are plotted for a drilling assembly operating normally with
average forms of vibration. Across the horizontal axis in a RAW
section shown only in FIG. 9A, raw velocity (RPM) data is plotted
around the toolface [top (T) or 0.degree., right (R) or 90.degree.,
bottom (B) or 180.degree., left (L) or 270.degree., top (T) or
360.degree. ] in shades (darker being slower RPM and lighter being
greater RPM). Data for each revolution is plotted along the
horizontal axis. Section A plots the average RPM values 302 and the
max/min RPM values 304 calculated for each revolution along the
vertical axis. Section B is smoothed data from the raw data
removing some anomalies. Again, toolface velocity (RPM) is plotted
around the toolface [top (T) or 0.degree., right (R) or 90.degree.,
bottom (B) or 180.degree., left (L) or 270.degree., top (T) or
360.degree. ] in shades (darker being slower RPM and lighter being
greater RPM).
[0074] Section C on the far right shows three traces, including the
mean RPM (RPMSM) 306, the RPM's standard deviation (RPMSTDEV) 307,
and a stick/slip coefficient of variation (RPMSSCV) 308. Values for
the mean RPM 306 and the standard deviation 307 of the smooth data
are plotted vertically for each revolution along the horizontal
axis. Likewise, the coefficient of variation (c.sub.v--i.e., the
ratio of the standard deviation .sigma. to the mean .mu.) 308 is
similarly plotted.
[0075] The processor 40 monitors the value of this coefficient of
variation 308 to determine whether detrimental vibrations are
occurring. To make this determination, the processor 40 can
determine whether the coefficient of variation 308 exceeds one or
more thresholds T.sub.1 and T.sub.2. The thresholds T.sub.1 and
T.sub.2 for spikes in the coefficient of variation, the timing
between spikes, and the period of time over which they occur depend
of the particulars of an implementation, including but not limited
to the average RPM, the type of drill bit, other components of the
BHA, the ROP, etc.
[0076] In one example, a first threshold T.sub.1 can be triggered
when the coefficient of variation 308 reaches 25% (i.e., the ratio
of the standard deviation .sigma. to the mean .mu. for the RPM is
about 0.25). A second threshold T.sub.2 can be triggered when the
coefficient of variation 308 reaches 50% (i.e., the ratio of the
standard deviation .sigma. to the mean .mu. for the RPM is about
0.50. As can be seen in FIGS. 9A and 9B, the toolface RPM in
section B is relatively uniform across the toolface orientations
[top (T) or 0.degree., right (R) or 90.degree., bottom (B) or
180.degree., left (L) or 270.degree., top (T) or 360.degree. ]. In
addition, the coefficient of variation 308 does not exceed the
thresholds T.sub.1 and T.sub.2, as would be expected for normal
vibrations
[0077] 2. Stick/Slip
[0078] By contrast, FIG. 10A shows a toolface RPM plot 300C for a
drilling assembly operating under stick/slip-like vibration. As
shown in Section A, the average RPM 302 remains relatively constant
as expected, with only the min/max RPM 304 indicating possible
vibration issues. Likewise, the mean RPM 306 of the smooth data of
each revolution plotted in section C also remains relatively
constant. However, the coefficient of variation 308 shows
significant spiking when stick/slip occurs. The processor 40 is
sensitive to the level of these spikes, the timing between them,
and how many occur within a period of time so the processor 40 can
determine that these vibrations indicate stick/slip and are
detrimental to the operation.
[0079] As noted above, values for the thresholds T.sub.1 and
T.sub.2 can differ depending on the implementation. In the present
example, if the coefficient of variation 308 exceeds the first
threshold T.sub.1 of 25%, then the processor 40 can issue a warning
of stick/slip to the driller via the telemetry system 28. If the
coefficient of variation 308 exceeds a second threshold T.sub.2 of
50%, then the processor 40 can indicate an alarm condition to the
driller that severe stick/slip is occurring. At this point,
corrective action can be taken either automatically or manually at
the rig before the stick/slip causes damage or develops into
whirl.
[0080] In addition to threshold checking and triggering, various
algorithms can also be used to recognize patterns in both the
toolface RPM values (Section B) as well as the coefficient of
variation 308 (Section C). Because processing capabilities can be
limited in downhole environment, the algorithms are preferably
robust. Briefly, the algorithms to detect the detrimental vibration
can use preset or adaptive threshold levels, time intervals,
counts, flags, etc. to track events and trigger alarm conditions.
In this way, the algorithms can be configured to detect stick/slip
and whirl-like vibration as well as characterizing the vibration's
severity.
[0081] As shown in FIG. 10A, for example, the thresholds T.sub.1
and T.sub.2 are set for the coefficient of variation 308. These
thresholds T.sub.1 and T.sub.2 can be preset according to known
drilling parameters and expected conditions, or they can be
adaptively set as conditions change. When one or both of the
coefficient's thresholds T.sub.1 and T.sub.2 is exceeded (such as
at the first peak shown), then the algorithm flags the event and
awaits a given amount of time (or number of revolutions of the
drilling assembly) for another event (peak) to occur. The waiting
period can be set or variable, depending on the conditions.
[0082] If a second event (peak) occurs due to the coefficient 308
exceeding the threshold T.sub.1 and/or T.sub.2, then that second
event is also flagged, and a time interval (I) is derived between
the events. At this point, if stick/slip is occurring and the RPM
applied to the drilling assembly is remaining consistent, then
another stick/slip vibration event (spike) would be expected to
occur within about the same time interval (I) or around some
tolerance thereof. If this same behavior repeats itself as drilling
continues for a set or variable amount of events, time, or
revolutions, then the processor 40 can set an alarm that
stick/slip-like vibration has developed.
[0083] However, the repetitive events (spikes) can be further
characterized based on the toolface RPM values (Section B). Instead
of just knowing the max/min RPM 304 for each revolution, the
toolface RPM values (Section B) show where the stick and slips
occur relative to the determined toolface (T, R, B, L, T) on the
drilling assembly. When the coefficient of variance 308 passes one
or both of the thresholds T.sub.1 and T.sub.2, then the algorithm
can locate a low RPM window W.sub.2 at a particular toolface
orientation A.sub.2 within the toolface RPM data where sticking
occurs. Likewise, the algorithm can locate a high RPM window
W.sub.1 at another toolface orientation A.sub.1 within the toolface
RPM data where slipping occurs. (The window W.sub.1-2 can be used
for detection purposes of the particular toolface orientation
A.sub.1-2 because the orientation may vary slightly from one
revolution to the next.) The windows W.sub.1-2 may have a set size
or may vary depending on the RPM levels involved or other
factors.
[0084] In any event, if stick/slip is occurring and the applied RPM
is consistent, then the low and high RPMs occurring at the events
(i.e., spikes in the coefficient 308) would be expected to occur
within these windows W.sub.1 and W.sub.2 at roughly the same
toolface orientations A.sub.1 and A.sub.2 as the drilling assembly
continues drilling. Therefore, finding low or high RPM events in
these windows W.sub.1 and W.sub.2 of the toolface orientations
A.sub.1 and A.sub.2 in subsequent revolutions of the drilling
assembly when the coefficient of variance 308 exceeds its set
threshold T.sub.1 and/or T.sub.2 can indicate that stick/slip is
occurring and what its character is. In response, the processor 40
can set the alarm and telemeter data to the driller at the surface
including the alarm and characterizing the stick/slip
condition.
[0085] FIG. 10B shows another toolface RPM plot 300D for a drilling
assembly operating under stick/slip-like vibration. Also, FIG. 10C
shows a toolface RPM log 300E for a drilling assembly operating
under stick/slip-like vibration. In FIG. 10C, the variations in
max/min RPM (Section A) are less pronounced than found in FIGS. 10A
and 10B. Yet, the coefficient of variation 308 plotted in Section C
shows spiking events that exceed one or both thresholds T.sub.1 and
T.sub.2. Again, exceeding these thresholds T.sub.1 and/or T.sub.2
can indicate when stick/slip occurs (i.e., those revolutions with
low RPM and high RPM). When the lower threshold T.sub.1 of 25% is
repeatedly exceeded but the upper threshold T.sub.2 of 50% is not,
then the algorithm may adjust (reduce) the upper threshold T.sub.2
by some amount so spikes can be better identified.
[0086] 3. Whirl-Like Vibration
[0087] FIGS. 11A through 11C show examples of what appears to
involve a whirl-like vibration that has a different character than
the stick/slip-like vibration. For example, FIG. 11A shows a
toolface RPM plot 300F. RAW data is not shown. In this example, the
toolface RPM involves three possible lobes where the drilling
assembly appears to stick. Between these lobes, the drilling
assembly experiences an increased RPM as it releases pent-up
torque. As with the stick/slip techniques, the analysis algorithm
can initially look for the coefficient of variation 308 exceeding
the thresholds T.sub.1 and T.sub.2. In contrast to the stick/slip,
an event of exceeding the threshold T.sub.1 and T.sub.2 is not
followed by an intermediate interval of somewhat normal drilling
vibration as in FIGS. 10A-10C. Rather, the coefficient of variation
308 continues to exceed the thresholds T.sub.1 and T.sub.2 for a
period of time.
[0088] Using the toolface RPM data (Section B), the algorithm
determines the toolface values (indicated at A.sub.1, A.sub.2 and
A.sub.3) where low RPM values (sticks) occur, and the algorithm can
apply suitable windows W.sub.1, W.sub.2 and W.sub.3 to each of
these toolface values A.sub.1, A.sub.2 and A.sub.3. The algorithm
can also count the number of these low RPM values (sticks) and
determine the number of lobes involved. Here, there are three
potential lobes in the whirl based on the three toolface values
A.sub.1, A.sub.2 and A.sub.3. Additional information may be
obtained, for example, from accelerometers to determine whether the
whirl is backward or forward whirl.
[0089] Once features of the whirl are identified in the toolface
RPM data (Section B), the processor 40 can trigger an alarm for
telemetering uphole to the driller. In addition, knowing that the
coefficient's threshold T.sub.1 and T.sub.2 is being exceeded for a
time period and knowing the number of lobes (sticks), the processor
40 can further characterize the vibration and telemeter suitable
information uphole to the driller.
[0090] FIGS. 11B and 11C show additional plots 300G and 300H with
whirl-like vibration. Again, the toolface RPM data (Section B) can
be used to determine the toolface values (indicated at A.sub.1,
A.sub.2 and A.sub.3) where low RPM values (sticks) occur, to
determine the number of lobes involved, and to trigger an alarm for
telemetering uphole to the driller.
[0091] 4. Other Detrimental Vibration
[0092] In addition to stick/slip and whirl-like vibrations, the
processing techniques disclosed herein can be used to detect and
characterize other types of behaviors, such as bit bounce, bit
wobble, bit walking, lateral vibration, and torsional oscillation.
FIGS. 12A through 12C show what is believed to be other forms of
detrimental vibration that are somewhat similar to stick/slip and
whirl that may be encountered during drilling. Using similar
processing techniques as those discussed previously, the processor
40 can detect and characterize these forms of vibrations to warn
and alert the drilling operators.
[0093] In FIG. 12A, for example, the thresholds T.sub.1 and T.sub.2
for the coefficient of variation 308 are continuously exceeded, and
the toolface RPM data (Section B) shows a toolface value (indicated
at A.sub.1) where a low RPM value (stick) occurs, which can be
fitted by a suitable window W.sub.1.
[0094] In FIG. 12B, for example, the lower thresholds T.sub.1 for
the coefficient of variation 308 is almost continuously exceeded,
while the upper threshold T.sub.2 is intermittently exceeded. The
toolface RPM data (Section B) shows a toolface value (indicated at
A) where a low RPM value (stick) occurs, which can be fitted by a
suitable window W. This toolface value (A) is also shown to shift
from the left toolface (L) more toward the top (T) and right
toolface (R). This information may be helpful to drillers.
[0095] In FIG. 12C, for example, the thresholds T.sub.1 and T.sub.2
for the coefficient of variation are almost continuously exceeded,
and the toolface RPM data (Section B) shows toolface values
(indicated at A.sub.1 and A.sub.2) where low RPM values (sticks)
occur, which can be fitted by suitable windows W.sub.1 and
W.sub.2.
[0096] In each of these examples, the processing techniques
disclosed herein can indicate detrimental forms of vibration using
alarms and warnings. Likewise, the processing techniques can
characterize the toolface values, spikes, lobes, intervals, and the
like for the detected vibrations so that drilling operators can
have a better understanding on the types of vibrations encountered
downhole. From this information, operators can alter parameters to
reduce or eliminate the problems and improve the drilling
efficiency.
[0097] As will be appreciated, teachings of the present disclosure
can be implemented in digital electronic circuitry, computer
hardware, computer firmware, computer software, or any combination
thereof. Teachings of the present disclosure can be implemented in
a computer program product tangibly embodied in a machine-readable
storage device for execution by a programmable processor so that
the programmable processor executing program instructions can
perform functions of the present disclosure. The teachings of the
present disclosure can be implemented advantageously in one or more
computer programs that are executable on a programmable system
including at least one programmable processor coupled to receive
data and instructions from, and to transmit data and instructions
to, a data storage system, at least one input device, and at least
one output device. Storage devices suitable for tangibly embodying
computer program instructions and data include all forms of
non-volatile memory, including by way of example semiconductor
memory devices, such as EPROM, EEPROM, and flash memory devices;
magnetic disks such as internal hard disks and removable disks;
magneto-optical disks; and CD-ROM disks. Any of the foregoing can
be supplemented by, or incorporated in, ASICs (application-specific
integrated circuits).
[0098] The foregoing description of preferred and other embodiments
is not intended to limit or restrict the scope or applicability of
the inventive concepts conceived of by the Applicants. In exchange
for disclosing the inventive concepts contained herein, the
Applicants desire all patent rights afforded by the appended
claims. Therefore, it is intended that the appended claims include
all modifications and alterations to the full extent that they come
within the scope of the following claims or the equivalents
thereof.
* * * * *