U.S. patent application number 13/054900 was filed with the patent office on 2011-06-23 for drillstring motion analysis and control.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Paul F. Rodney.
Application Number | 20110153217 13/054900 |
Document ID | / |
Family ID | 42709922 |
Filed Date | 2011-06-23 |
United States Patent
Application |
20110153217 |
Kind Code |
A1 |
Rodney; Paul F. |
June 23, 2011 |
DRILLSTRING MOTION ANALYSIS AND CONTROL
Abstract
Apparatus, systems, and methods may operate to obtain
acceleration data from an operational drillstring, decompose the
acceleration data into one or more empirical modes, monitor the
amplitude of at least one of the empirical modes to detect
indications exceeding a preselected threshold, and modify
drillstring operational parameters comprising at least one of
rotational speed, weight on bit, or mud flow, based on the
indications. Additional apparatus, systems, and methods are
disclosed.
Inventors: |
Rodney; Paul F.; (Spring,
TX) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
42709922 |
Appl. No.: |
13/054900 |
Filed: |
March 5, 2009 |
PCT Filed: |
March 5, 2009 |
PCT NO: |
PCT/US2009/001418 |
371 Date: |
February 16, 2011 |
Current U.S.
Class: |
702/9 |
Current CPC
Class: |
E21B 47/007 20200501;
E21B 47/00 20130101; E21B 44/00 20130101 |
Class at
Publication: |
702/9 |
International
Class: |
E21B 47/16 20060101
E21B047/16 |
Claims
1. An apparatus, comprising: an analysis module to decompose
acceleration data provided by an accelerometer attached to a
drillstring into at least one empirical mode; and a monitoring
module to monitor an amplitude of the at least one empirical mode
to provide indications of the amplitude exceeding a preselected
threshold.
2. The apparatus of claim 1, further comprising: a receiver to
receive the preselected threshold from a surface source, the
receiver to couple to the monitoring module.
3. The apparatus of claim 1, further comprising: a downhole tool to
at least partially house at least one of the analysis module or the
monitoring module.
4. The apparatus of claim 1, further comprising: a processor to
derive the amplitude of the at least one empirical mode.
5. The apparatus of claim 4, wherein the processor is at least
partially housed by a downhole tool.
6. The apparatus of claim 1, comprising: a processor to maintain a
running average of the amplitude.
7. The apparatus of claim 1, comprising: a transmitter to transmit
at least one of the amplitude, a running average of the amplitude,
a number of the indications per unit time, a mean separation time
between the indications, or an average of an instantaneous
frequency during a time period when the amplitude exceeds the
preselected threshold.
8. The apparatus of claim 1, comprising: a transmitter to transmit
an alert message to the surface, the alert message based on the
amplitude.
9. A system, comprising: a drillstring; an accelerometer attached
to the drillstring; an analysis module to decompose acceleration
data provided by the accelerometer into at least one empirical mode
upon rotation of the drillstring; and a monitoring module to
monitor an amplitude of the at least one empirical mode to provide
indications of the amplitude exceeding a preselected threshold.
10. The system of claim 9, comprising: a display to present
rotational activity of a bit coupled to the drillstring, based on
the amplitude and the indications, in graphic form.
11. The system of claim 9, comprising: a downhole tool, wherein at
least one of the analysis module or the monitoring module are
attached to the downhole tool.
12. The system of claim 9, further including: a control system to
modify drillstring operational parameters comprising at least one
of rotational speed, weight on bit, or mud flow based on the
indications.
13. A method, comprising: obtaining acceleration data from an
operational drillstring; decomposing the acceleration data into at
least one empirical mode; monitoring an amplitude of the at least
one of the empirical mode to detect indications exceeding a
preselected threshold; and modifying drillstring operational
parameters comprising at least one of rotational speed, weight on
bit, or mud flow based on the indications.
14. The method of claim 13, further comprising: calibrating a
drillstring dynamics modeling program used to select a rotary speed
of the drillstring, based on the indications.
15. The method of claim 13, further comprising: determining an
average time between the indications.
16. The method of claim 13, wherein the modifying comprises:
reducing the rotational speed until a number of the indications per
unit time falls below a selected frequency.
17. The method of claim 13, wherein the modifying comprises:
increasing the rotational speed until a number of the indications
per unit time falls below a selected frequency.
18. The method of claim 13, wherein the obtaining comprises:
obtaining the acceleration data from a single accelerometer
attached to the drillstring.
19. The method of claim 13, wherein the at least one empirical mode
comprises: a mode having a dominant frequency of about 0.2 Hz to
about 500 Hz.
20. The method of claim 13, further comprising: publishing a report
comprising one of stick/slip, bit bounce, whirling, or lateral
vibration based on the indications.
21. The method of claim 13, comprising: displaying rotational
activity of a borehole bit attached to the drillstring based on the
amplitude and the indications.
22. The method of claim 13, comprising: steering the borehole bit
along a path based on feedback associated with the indications.
23. An article including a computer-accessible medium having
instructions stored thereon, wherein the instructions, when
accessed by a computer, result in the computer performing:
obtaining acceleration data from an operational drillstring;
decomposing the acceleration data into at least one empirical mode;
monitoring an amplitude of the at least one empirical mode to
detect indications exceeding a preselected threshold; and modifying
drillstring operational parameters comprising at least one of
rotational speed, weight on bit, or mud flow based on the
indications.
24. The article of claim 23, wherein the instructions, when
accessed, result in the computer performing: determining the
preselected threshold based on a running average of the
amplitude.
25. The article of claim 23, wherein the instructions, when
accessed, result in the computer performing: receiving the
preselected threshold from a surface location.
Description
BACKGROUND INFORMATION
[0001] A number of undesirable conditions can develop while
drilling a borehole. For example, standing vibration waves can be
generated along the drillstring, leading to a condition known as
stick/slip. In this condition, the drillstring stops rotating for a
period of time, and then spins free. The resulting instantaneous
rotation frequency can be high enough to loosen the coupling
between drillstring elements. Another condition is known as whirl,
in which the bit, or a portion of the drillstring, rotates around
the circumference of the borehole (instead of substantially
centered within the borehole). This can quickly become a chaotic
phenomenon in which the drillstring seems to randomly bounce back
and forth, slapping against the sides of the borehole. These
conditions, and others, can result in reduced drilling efficiency,
and may even cause the drillstring to become stuck in the
borehole.
BRIEF DESCRIPTION OF THE DRAWINGS
[0002] FIG. 1 illustrates accelerometer signal modal decomposition
according to various embodiments of the invention.
[0003] FIG. 2 illustrates apparatus that operates to decompose
accelerometer signals according to various embodiments of the
invention.
[0004] FIG. 3 illustrates systems according to various embodiments
of the invention.
[0005] FIG. 4 is a flow chart illustrating several methods
according to various embodiments of the invention.
[0006] FIG. 5 is a block diagram of an article according to various
embodiments of the invention.
DETAILED DESCRIPTION
[0007] Time series measurements made using accelerometers and other
motion-sensitive sensors can be used to diagnose undesirable
vibration phenomena that occur as part of drilling operations.
Because of inter-related effects, a reliable diagnosis can be
difficult to make when several phenomena exist simultaneously.
However, if enough motion-sensitive sensors are used, along with
instrumentation for real-time standoff measurements, the various
modes of drillstring motion can be isolated by combining the sensor
outputs. Unfortunately, due to constraints on funding and computer
resources, this type of operation is not practical.
[0008] As an alternative, a mechanism is disclosed herein that
permits identifying various modes of vibrational motion presented
by a bottom hole assembly (BHA) using a single measurement vehicle
(e.g., a single accelerometer). By deriving modal decomposition
information from surface or downhole (or both) acceleration
sensors, and identifying/correlating the behavior of the modes with
specific downhole phemonena, operational drilling parameters can be
modified to reduce or eliminate undesirable vibration that has been
identified.
[0009] In some embodiments, the entire analysis may be carried out
downhole and used to stabilize a downhole drilling motor, a rotary
steerable device, an adjustable blade stabilizer, a controllable
shock sub, and other components having functions that affect
drillstring operational parameters. The operations disclosed can be
carried out in a higher-dimension space to incorporate a plurality
of measurements.
[0010] The phenomenon of stick/slip will be used to illustrate the
teaching of this disclosure. It should be noted, however, that the
various embodiments are not to be so limited. Any vibrational
phenomenon that can be identified via substantially repetitive
behavior when analyzed using empirical mode decomposition is
included.
[0011] FIG. 1 illustrates accelerometer signal modal decomposition
according to various embodiments of the invention. In this case, a
sequence of signal data is shown in graph 100, as acquired from a
single downhole accelerometer attached to a drillstring while the
drillstring was operating in a stick/slip mode. The hesitation of
the drillstring is clearly visible in graph 100 at time intervals
centered around 0.7 seconds, 3 seconds and 5.1 seconds. Because of
the shortness of the time interval, the temporal and spectral
resolution for a conventional spectrogram (e.g., using Fourier
analysis) would be relatively poor.
[0012] The empirical mode decomposition of signals is well known to
those of ordinary skill in the art. For example,
computer-implemented empirical mode decomposition as applied to
luminance in digital camera images is described in detail in U.S.
Pat. No. 6,311,130, incorporated herein by reference in its
entirety. The empirical "modes" into which accelerometer signal
data are decomposed herein are equivalent to the Intrinsic Mode
Functions (IMF's) described in U.S. Pat. No. 6,311,130, and are
indicative of intrinsic oscillatory modes in the physical
phenomenon to be studied (e.g., drillstring vibration).
[0013] When the original signal shown in graph 100 is decomposed
into empirical modes, the results can be seen in graphs 102
(mode-1), 104 (mode-2), 106 (mode-3), 108 (mode-4), 110 (mode-5),
and 112 (mode-6). The residue, without bias, is shown in graph
114.
[0014] Modes 1 and 2 (i.e., graphs 102, 104) represent high
frequency events that are likely not related to stick/slip. Mode 3
(i.e., graph 106) represents a process that starts at about 1
second, dies down at about 2.5 seconds, and restarts at about 3
seconds. As with the base waveform (shown in graph 100), the
process appears to be substantially repeatable, although this is
not always the case. Mode 4 (i.e., graph 106) represents a more or
less continuous mode upon which the stick/slip has been
superimposed. The base waveform signal that results from continuous
drilling represented in graph 100 can be represented by the sum of
modes 4, 5, 6 and the residual (i.e., graphs 108, 110, 112, and
114).
[0015] The breakdown of a signal into empirical modes has the
advantage that, at least ideally, and typically as a good
approximation, the modes represent what are called analytic
signals, which can be represented by a time-domain amplitude
function and a time-domain phase function, where the phase
increases monotonically with time. That is, a mode (e.g., any one
of modes mode-1 through mode-6) can be expressed in the form:
M(t)=Re[A(t)*e.sup.i*.THETA.(t))],
where Re designates the real part of the enclosed function, A(t) is
the amplitude of the mode M(t) as a function of time, i= {square
root over (-1)} and .THETA.(t) is the phase of the mode as a
function of time. Ideally, A(t) is a positive definite function and
.THETA.(t) undergoes no reversals over time. This form of
expression makes it possible to define the instantaneous frequency
(the Hilbert frequency) as the time derivative of the phase:
.omega. ( t ) = .THETA. ( t ) t . ##EQU00001##
[0016] As shown in graph 106, the amplitude 130 of one or more of
the modes (in this case, mode-3) can be monitored continuously for
excursions above a pre-set threshold 120. For example, a downhole
or surface computer can keep track of the average of the amplitude
130 over some selected period of time and compare the values of the
current amplitude 130 with this average (which may be a running
average, such as an exponential average, among others). The
threshold can be at some fixed value, or a fixed amount above the
average, or expressed as a band substantially centered on the
average. Alternatively, a pre-defined threshold amplitude, such as
threshold 120, can be transmitted from the surface to the downhole
tool using any available measurement while drilling (MWD) downlink
communications channel.
[0017] When an anomalously high amplitude is detected, such as
where the threshold is exceeded by the amplitude 130 of mode-3 at
points 122, 124, 126, and 128, the amplitude and the mode number
can be relayed to surface equipment, perhaps along with information
about the number of high amplitude events, the mean separation in
time between such events, the instantaneous frequency during the
time period when the amplitude exceeded the threshold 120, an
average of the instantaneous frequency during the time period when
the amplitude exceeded the threshold 120, etc. This information is
sufficient for the driller to identify that the angular rate at
which the rotary table turns needs to be changed and for the
driller to determine how it needs to be changed. The calculated
amplitude can also be compared with that obtained using various
drillstring dynamics modeling programs, thus providing a
calibration point for the drillstring dynamics program that has
been selected for use, while the program itself is used to select a
different rotary speed.
[0018] It is noted that in this case mode-1 and mode-2 (i.e.,
graphs 102, 104) contain information about the shock spectrum of
the downhole instrumentation that has been modally decoupled from
the stick/slip motion. If other modes of motion had been present,
it is expected that they would also be separated out by the modal
analysis. It can also be noted that the modal decomposition
analysis can be accomplished without recourse to Fourier
techniques, and that, in comparison, Fourier techniques often
provide a less complete picture of the phenomenon, because they
cannot provide the frequency resolution in short time intervals
that is usually possible with modal decomposition apparatus and
methods.
[0019] FIG. 2 illustrates apparatus 200 that operates to decompose
accelerometer signals according to various embodiments of the
invention. Here it can be seen that the signals from one or more
accelerometers 284 can be acquired using a data acquisition system
260, which feeds the signals, perhaps after amplification and
filtering, into an analysis module 262. The analysis module 262, in
turn, may be used to decompose the accelerometer signals into
empirical modes.
[0020] The signal characteristics of the raw accelerometer signals
and/or the derived empirical modes (e.g., amplitude, polarity,
phase, etc.) may be monitored by a monitoring module 264 to
determine whether the current empirical mode signal values exceed
some selected threshold, perhaps established as an absolute
threshold, or as a relative threshold (e.g., a threshold riding at
some distance, absolute or relative, above and/or below a running
mean of the acquired amplitude). For example, a change of more than
.+-.10% or .+-.20% from a running mean of the empirical mode signal
amplitude values.
[0021] The accelerometer signals, the mode amplitude values, the
mode instantaneous frequency values, and indications of the
threshold being exceeded can all be transmitted from downhole to
the surface 204 for further processing. It should also be noted
that any of the components shown below the surface 204, as part of
the apparatus 200 may be located at the surface 204. Similarly,
components shown as part of a logging station 292 and located at
the surface 204 may be located downhole, perhaps attached to a BHA,
which may serve to reduce the use of high data rate telemetry
techniques on a particular project. Thus, many embodiments may be
realized.
[0022] For example, an apparatus 200 may comprise an analysis
module 262 to decompose acceleration data provided by an
accelerometer 284 attached to a drillstring into at least one
empirical mode. In some cases, only one empirical mode will be
evident, with the residue comprising random noise. The apparatus
200 may also comprise a monitoring module 264 to monitor the
amplitude of one or more empirical modes, and to provide
indications of the amplitude exceeding a preselected threshold.
[0023] Thus, the apparatus 200 can be used to measure acceleration
of the drillstring, or some component attached to the drillstring,
decompose the data into empirical modes, and monitor the behavior
of modal data. The apparatus 200 can be located on the surface 204,
downhole, or various components of the apparatus 200 may be divided
between the two locations.
[0024] In some embodiments, a receiver 266 can be used to receive
various parameters from the surface 204, such as the threshold used
by the monitoring module 264. Thus, the apparatus 200 may comprise
a receiver 266 to receive a preselected threshold from a surface
source (e.g., the logging station 292), where the receiver 266 can
be coupled to the monitoring module 264 (e.g., via the analysis
module, as shown in FIG. 2).
[0025] The analysis module 262, the monitoring module 264, or both,
may be housed in a downhole tool 224. Thus, the apparatus 200 may
comprise a downhole tool 224 to at least partially house at least
one of the analysis module 262 or the monitoring module 264.
[0026] A processor 254 can be used to further process modal data,
perhaps to determine the amplitude of empirical modes as a function
of time, and/or to maintain a running average of the amplitudes.
Thus, the apparatus 200 may comprise a processor 254 to derive the
amplitude of one or more empirical modes and/or to display a
variety of information about modal behavior on the display 296. The
processor 254 can be at least partially housed by the downhole tool
224 as well.
[0027] As noted previously, a transmitter 268 can be used to send
many different types of information to the surface 204. For
example, the apparatus 200 may comprise a transmitter 268 to
transmit one or more amplitudes, running averages of amplitudes,
the number of indications of one or more amplitudes exceeding one
or more corresponding thresholds per unit time, or the mean
separation time between the indications. In some embodiments, the
transmitter 268 can be used to transmit an alert message to the
surface 204, with a display of the alert message content based on
the amplitude. In this way, anomalous amplitude events might be
used to initiate an alarm, perhaps used to stop drilling
operations.
[0028] FIG. 3 illustrates systems 300 according to various
embodiments of the invention. The system 300 may comprise more than
one of the apparatus 200. Thus, the apparatus 200, as described
above and shown in FIG. 2, may form portions of a down hole tool
224 as part of a downhole drilling operation.
[0029] Turning now to FIG. 3, it can be seen how a system 300 may
also form a portion of a drilling rig 302 located at the surface
204 of a well 306. The drilling rig 302, comprising a drilling
platform 386 may be equipped with a derrick 388 that supports a
drill string 308 lowered through a rotary table 310 into a wellbore
or borehole 312.
[0030] Thus, the drill string 308 may operate to penetrate a rotary
table 310 for drilling the borehole 312 through subsurface
formations 314. The drill string 308 may include a Kelly 316, drill
pipe 318, and a BHA 320, perhaps located at the lower portion of
the drill pipe 318. The drill string 308 may include wired and
unwired drill pipe, as well as wired and unwired coiled tubing,
including segmented drilling pipe, casing, and coiled tubing.
[0031] The BHA 320 may include drill collars 322, a down hole tool
224, and a drill bit 326. The drill bit 326 may operate to create a
borehole 312 by penetrating the surface 204 and subsurface
formations 314. The down hole tool 224 may comprise any of a number
of different types of tools including MWD tools, logging while
drilling (LWD) tools, and others.
[0032] During drilling operations, the drill string 308 (perhaps
including the Kelly 316, the drill pipe 318, and the BHA 320) may
be rotated by the rotary table 310. In addition to, or
alternatively, the bottom hole assembly 320 may also be rotated by
a top drive or a motor (e.g., a mud motor) that is located down
hole. The drill collars 322 may be used to add weight to the drill
bit 326. The drill collars 322 also may stiffen the BHA 320 to
allow the bottom hole assembly 320 to transfer the added weight to
the drill bit 326, and in turn, assist the drill bit 326 in
penetrating the surface 204 and subsurface formations 314.
[0033] During drilling operations, a mud pump 332 may pump drilling
fluid (sometimes known by those of ordinary skill in the art as
"drilling mud" or simply "mud") from a mud pit 334 through a hose
336 into the drill pipe 318 and down to the drill bit 326. The
drilling fluid can flow out from the drill bit 326 and be returned
to the surface 204 through an annular area 340 between the drill
pipe 318 and the sides of the borehole 312. The drilling fluid may
then be returned to the mud pit 334, where such fluid is filtered.
In some embodiments, the drilling fluid can be used to cool the
drill bit 326, as well as to provide lubrication for the drill bit
326 during drilling operations. Additionally, the drilling fluid
may be used to remove subsurface formation 314 cuttings created by
operating the drill bit 326.
[0034] Thus, referring now to FIGS. 1-3, it may be seen that in
some embodiments, the system 300 may include a drill collar 322, a
drill string 308, and/or a down hole tool 224 to which one or more
apparatus 200 are attached. The down hole tool 224 may comprise an
LWD tool, or an MWD tool. The drill string 308 may be mechanically
coupled to the down hole tool 224. Thus, additional embodiments may
be realized.
[0035] For example, a system 300 may comprise a drillstring 308,
one or more accelerometers 284 attached to the drillstring 308, and
one or more apparatus 200, as described previously. In some
embodiments, the system 300 comprises a display 296 to present
rotational activity of the bit 326 coupled to the drillstring 308,
perhaps based on the amplitude of one or more of the empirical
modes, and the indications of the one or more modes exceeding some
selected threshold. In this way, the drillstring 308 and/or bit 326
activity can be displayed to the rig operator, perhaps in graphic
form.
[0036] Depending on the specific implementation, various components
of the system 300 may be attached to the downhole tool 224. Thus,
the system 300 may comprise a downhole tool 224, wherein at least
one of the analysis module or the monitoring module (see elements
262, 264, respectively in FIG. 2) are attached to the downhole tool
224.
[0037] A control system 398 can be used to modify drilling
operations based on the data obtained by monitoring the empirical
modes. Thus, a system 300 may comprise a control system 398 to
modify drillstring operational parameters comprising one or more of
the rotational speed, weight on bit, or mud flow based on the
indications (of exceeding a selected threshold). One or more
displays 296 may be included in the system 300 as part of a
processor 254 in a logging station 292 to display any type of
acquired data, including the raw acquired accelerometer data,
empirical mode data (amplitude and/or phase), threshold data,
etc.
[0038] The apparatus 200, downhole tool 224, processor 254, data
acquisition system 260, analysis module 262, monitoring module 264,
receiver 266, transmitter 268, accelerometers 284, logging facility
292, system 300, drilling rig 302, drill string 308, rotary table
310, Kelly 316, drill pipe 318, bottom hole assembly 320, drill
collars 322, drill bit 326, mud pump 332, drilling platform 386,
derrick 388, and control system 398 may all be characterized as
"modules" herein. Such modules may include hardware circuitry, one
or more processors and/or memory circuits, software program modules
and objects, and firmware, and combinations thereof, as desired by
the architect of the apparatus 200 and system 300, and as
appropriate for particular implementations of various embodiments.
For example, in some embodiments, such modules may be included in
an apparatus and/or system operation simulation package, such as a
software electrical signal simulation package, a power usage and
distribution simulation package, a power/heat dissipation
simulation package, and/or a combination of software and hardware
used to simulate the operation of various potential
embodiments.
[0039] It should also be understood that the apparatus and systems
of various embodiments can be used in applications other than for
borehole drilling and logging operations, and thus, various
embodiments are not to be so limited. The illustrations and
descriptions of apparatus 200 and systems 300 are intended to
provide a general understanding of the structure of various
embodiments, and they are not intended to serve as a complete
description of all the elements and features of apparatus and
systems that might make use of the structures described herein.
[0040] Applications that may include the novel apparatus and
systems of various embodiments comprise process measurement
instruments, personal computers, workstations, and vehicles, among
others. Some embodiments include a number of methods.
[0041] For example, FIG. 4 is a method flow diagram 411 according
to various embodiments of the invention. Thus, a method 411 may
begin at block 421 with obtaining acceleration data from an
operational drillstring. For example, as noted above, acceleration
data may be obtained from a single accelerometer. Thus, the
activity at block 421 may include obtaining the acceleration data
from a single accelerometer attached to the drillstring.
[0042] The method 411 may continue on to block 425 with decomposing
the acceleration data into one or more empirical modes. In many
embodiments, the empirical modes comprise one or more modes having
a dominant frequency of about 0.2 Hz to about 500 Hz.
[0043] The method 411 may include monitoring the amplitude of the
one or more empirical modes at block 429, perhaps to detect
indications exceeding a preselected threshold (as determined at
block 437). Thus, if a threshold has not been previously selected,
or if the threshold is to be changed, the method 411 may include
determining the preselected threshold at block 433 based on a
running average of the amplitude of one or more modes, to detect
excursions beyond normal operation. In some embodiments, the
activity at block 433 includes receiving the preselected threshold
(downhole) from a surface location.
[0044] If the indications do not exceed the threshold, as
determined at block 437, then the method 411 may return to block
421 to obtain additional accelerometer data. However, if the
indications are determined to exceed the selected threshold, as
determined at block 437, then the method 411 may continue on to
block 441 with determining an average time between the indications.
This is because the average time between indications that exceed
the selected threshold can help determine what type of activity is
occurring with the drill string and/or bit (e.g., stick/slip or
whirl).
[0045] Depending on the number, amplitude, and frequency of the
indications received, the rig operator can be informed of the
vibrational modes that might be in existence along the drill
string, or at the drill bit. Alternatively, or in addition, the
activity can be stored in a log for later use. Thus, the method 411
may go on to include, at block 445, publishing a report comprising
one of stick/slip, bit bounce, whirling, or lateral vibration based
on the indications. The method 411 may go on to block 449 to
include modifying drillstring operational parameters comprising at
least one of rotational speed, weight on bit, or mud flow, based on
the indications.
[0046] In this way, the method 411 may include acquiring
acceleration data, decomposing the data into one or more empirical
modes, monitoring the amplitude of at least one of the modes, and
modifying drillstring operations responsive to the amplitude
behavior. For example, the activity at block 449 may include
reducing the rotational speed until the number of the indications
per unit time falls below a selected frequency. In cases of
whirling, for example, it may be the best practice to reduce the
rotational speed. The activity at block 449 may additionally, or
alternatively include increasing the rotational speed until a
number of the indications per unit time falls below a selected
frequency. For example, in some cases of resonant behavior, such as
stick/slip, it may be beneficial to increase the rotational speed
beyond the resonant condition.
[0047] Dynamic phenomena, such as stick/slip, whirl, bit bounce,
and lateral vibration, can be identified using the apparatus and
systems described herein, or as part of the disclosed methods.
After individual phenomena have been identified, various
embodiments can sometimes operate to correct them, or at least, to
reduce their intensity, perhaps by varying the rotational bit
speed, weight on bit, and/or mud flow.
[0048] For example, stick/slip can be identified by the sudden
appearance of a mode that has non-zero amplitude at approximately
zero frequency for a period of time that is a significant fraction
of what, in the short-term history of the drillstring, was the
average period revolution.
[0049] Those of ordinary skill in the art are aware that at least
two types of whirl exist: bit whirl and collar whirl. Conceptually,
they are the same, but practically, they may have a different
impact on the overall drillstring operation, since the bit and
collars are typically located at different points of the
drillstring.
[0050] The onset of whirl may follow the appearance of a mode with
an instantaneous frequency close to (or equal to) a harmonic of the
rotational frequency, perhaps as determined by the historical
output of one or more rotationally sensitive transducers. As whirl
worsens, there is typically a doubling or tripling of the frequency
of the first mode that has appeared. Several such modes may be
present simultaneously. When the most destructive level of whirl
has been reached, the progression of harmonic modes breaks down
completely--these modes suddenly disappear and are replaced by
random impulse noise.
[0051] Due to whirl's nature (the bit or the drill collars rolling
around the inside of the borehole wall), it is possible to have
negative frequencies (i.e., rotating clockwise or
counter-clockwise). Unlike the negative frequencies that may arise
as an output of a Fourier Transform analysis, these negative
frequencies indicated by a modal analysis are physically
significant.
[0052] If only one sensor is used, the negative frequencies will
appear as positive frequencies in a modal decomposition. However,
when two or more sensors are used (e.g., two orthogonal
accelerometers), experimental results as a function of time
indicate that a correlation of the outputs of these sensors can be
used to determine the direction (i.e., sign) of the modal
frequencies.
[0053] When an experiment is designed so that only one mode is
present, the modal decompositions of the two signals are, in
essence, the signals themselves. The direction of rotation can be
determined by calculating an angle defined as the four quadrant
arctangent of the x- and y-signals provided by the orthogonal
sensors, where the x-signal is provided by one sensor, and the
y-signal is provided by the other. If the x- and y-signals are of
different magnitudes, they can be rescaled to be of the same
magnitude. The direction of rotation is then determined by the
change between samples of the rotation angle. Since the arctangent
is a discontinuous function, there are some samples where the
direction of rotation can not be determined. One of ordinary skill
in the art will realize that there are yet other ways of
ascertaining the direction of rotation from the two sensor outputs,
or from modes of the two sensor outputs.
[0054] There is another type of whirl phenomena that is known as
"synchronous whirl." In this type of whirl, the drillstring is
generally in contact with the borehole wall. This may by
accompanied by slipping, but normally occurs in a direction
opposite to that of the drillstring rotation. Under such
conditions, it may be useful to use a different type of sensor to
identify the modes. In particular, one or more bending moment
sensors can be used to produce signals indicative of the bending
stress along the drillstring. Fourier analysis or modal analysis
can be used to establish the presence of regular frequencies in the
bending stress signals. Two or higher dimensional analyses similar
to those discussed above can also be carried out with the bending
moments.
[0055] A subspecies of synchronous whirl is one in which the same
side of the drill collars or of the bit continually faces or rubs
against the borehole wall. In this case, a significant level of
bending will be present at the same time that all modes have
diminished to a value of approximately zero.
[0056] Bit bounce includes a significant random component. However,
some portions of the bit motion along the drillstring axis can
still exhibit modal behavior. A first example is when roller cone
bits are used: as the formation is broken up by the bit, a regular
pattern develops in the bottom of the borehole. This pattern,
created by the motion of the bit, also contributes to drillstring
motion of the bit. The pattern typically continues to deepen until
the depth contrast of the pattern is equal to (or somewhat less
than) the relief across the face of the bit, at which time the bit
operates to destroy the pattern. While the pattern grows,
drillstring bit vibration increases. When pattern destruction
occurs, drillstring axis bit vibration decreases. This is described
in SPE 14330-MS Field Measurements of Downhole Drillstring
Vibrations, Wolf, S. F., Zacksenhouse, M., Arian, A., 1985.
[0057] Bit bearing failure will modify the vibrations along the
drillstring axis near the bit since a dragging cone scrapes the
formation, instead of crushing it. When this happens, a change in
the bit bounce vibration mode will be evident. In addition,
stalling may be evident, as indicated by sensors responding to
vibrations orthogonal to the drillstring axis or by
rotation-sensitive sensors. This might seem to be similar to
stick/slip, but because stick/slip is a standing wave phenomenon,
the associated frequencies usually fall within a well-defined,
reasonably predictable range. Hence, the signature of a dragging
bit would be a sudden change in the normal mode of drillstring-axis
vibration coupled with a broad-band modal behavior with frequencies
that fall outside of the frequencies expected for stick/slip.
[0058] The predicted approximation of drillstring vibrational
behavior provided by a drillstring dynamics modeling program
according to the torque load, formation type, weight on bit,
borehole shape, surface rotational speed, and other factors can be
adjusted to match the measured vibrational behavior represented by
the indications. Thus, in some embodiments, the method 411 includes
calibrating a drillstring dynamics modeling program used to select
a rotary speed of the drillstring, based on the indications
(perhaps as used to identify the various phenomena), at block
453.
[0059] The activity of the bit and/or drillstring may be
graphically displayed, depending on the monitored mode activity.
Thus, the method 411 may include displaying rotational activity of
the borehole bit attached to the drillstring based on the amplitude
of one or more monitored modes, and the indications (of exceeding a
selected threshold).
[0060] Bit steering operations may also be adjusted according to
the monitored mode indications. Thus, the method 411 may include
steering the borehole bit along a path based on feedback associated
with the indications, at block 461. For example, it may turn out
that steering in a particular direction to enter a softer formation
type operates to lessen vibrations indicating stick/slip
conditions.
[0061] Of course, this assumes that due consideration is given to
normal drilling operations, so that feedback to "correct" the
operation is not provided when observed events correlate to desired
formation penetration activities. For example, it may be useful to
cross a bed boundary at an angle that is not-orthogonal to the
boundary, such as when drilling through an anisotropic
formation--perhaps purposely drilling along an axis where the
rock/bit interaction causes a deflection of the drill bit from the
desired direction. In these circumstances, a mode of vibration
orthogonal to the drillstring, and a mode along the drillstring can
develop that together reflect the instantaneous velocity of the
bit, which changes continuously and somewhat repetitively during
each rotation of the bit until the bit has cleared the boundary.
Thus, in this case, the feedback associated with various
indications may be modified.
[0062] It should be noted that the methods described herein do not
have to be executed in the order described. Moreover, various
activities described with respect to the methods identified herein
can be executed in iterative, serial, or parallel fashion.
Information, including parameters, commands, operands, and other
data, can be sent and received, and perhaps stored using a variety
of tangible media, such as a memory. Any of the activities in these
methods may be performed, in part, by a digital electronic system
(e.g., a digital computer), an analog electronic system (e.g., an
analog control system), or some combination of the two.
[0063] Upon reading and comprehending the content of this
disclosure, one of ordinary skill in the art will understand the
manner in which a software program can be launched from a
computer-readable medium in a computer-based system to execute the
functions defined in the software program. One of ordinary skill in
the art will further understand that various programming languages
may be employed to create one or more software programs designed to
implement and perform the methods disclosed herein. The programs
may be structured in an object-orientated format using an
object-oriented language such as Java or C++. Alternatively, the
programs can be structured in a procedure-orientated format using a
procedural language, such as assembly, FORTRAN or C. The software
components may communicate using any of a number of mechanisms well
known to those skilled in the art, such as application program
interfaces or interprocess communication techniques, including
remote procedure calls. The teachings of various embodiments are
not limited to any particular programming language or environment.
Thus, other embodiments may be realized.
[0064] For example, FIG. 5 is a block diagram of an article 585
according to various embodiments of the invention. The article 585
comprises an article of manufacture, such as a computer, a memory
system, a magnetic or optical disk, some other storage device,
and/or any type of electronic device or system. For example, the
article 585 may include one or more processors 587 coupled to a
computer-accessible medium 589 such as a memory (e.g., fixed and
removable storage media, including tangible memory having
electrical, optical, or electromagnetic conductors) having
associated information 591 (e.g., computer program instructions),
which when executed by a computer, causes the computer (e.g., the
processor(s) 587) to perform a method including such actions as
obtaining acceleration data from an operational drillstring,
decomposing the acceleration data into at least one empirical mode,
monitoring the amplitude of the at least one empirical mode to
detect indications exceeding a preselected threshold, and modifying
drillstring operational parameters comprising at least one of
rotational speed, weight on bit, or mud flow based on the
indications. The data may be acquired using a single accelerometer.
Additional actions may include, for example, determining the
preselected threshold based on a running average of the amplitude,
or receiving the preselected threshold from a surface location.
Indeed, any of the activities described with respect to the various
methods above may be implemented in this manner.
[0065] Implementing the apparatus, systems, and methods of various
embodiments may provide the ability to detect abnormal drilling
conditions, diagnose them, and provide a controller with the
appropriate parameters to correct the situation--all from data
acquired using a single accelerometer. Improved drilling
efficiency, and lower drilling costs, may result.
[0066] The accompanying drawings that form a part hereof, show by
way of illustration, and not of limitation, specific embodiments in
which the subject matter may be practiced. The embodiments
illustrated are described in sufficient detail to enable those
skilled in the art to practice the teachings disclosed herein.
Other embodiments may be utilized and derived therefrom, such that
structural and logical substitutions and changes may be made
without departing from the scope of this disclosure. This Detailed
Description, therefore, is not to be taken in a limiting sense, and
the scope of various embodiments is defined only by the appended
claims, along with the full range of equivalents to which such
claims are entitled.
[0067] Such embodiments of the inventive subject matter may be
referred to herein, individually and/or collectively, by the term
"invention" merely for convenience and without intending to
voluntarily limit the scope of this application to any single
invention or inventive concept if more than one is in fact
disclosed. Thus, although specific embodiments have been
illustrated and described herein, it should be appreciated that any
arrangement calculated to achieve the same purpose may be
substituted for the specific embodiments shown. This disclosure is
intended to cover any and all adaptations or variations of various
embodiments. Combinations of the above embodiments, and other
embodiments not specifically described herein, will be apparent to
those of skill in the art upon reviewing the above description.
[0068] The Abstract of the Disclosure is provided to comply with 37
C.F.R. .sctn.1.72(b), requiring an abstract that will allow the
reader to quickly ascertain the nature of the technical disclosure.
It is submitted with the understanding that it will not be used to
interpret or limit the scope or meaning of the claims. In addition,
in the foregoing Detailed Description, it can be seen that various
features are grouped together in a single embodiment for the
purpose of streamlining the disclosure. This method of disclosure
is not to be interpreted as reflecting an intention that the
claimed embodiments require more features than are expressly
recited in each claim. Rather, as the following claims reflect,
inventive subject matter lies in less than all features of a single
disclosed embodiment. Thus the following claims are hereby
incorporated into the Detailed Description, with each claim
standing on its own as a separate embodiment.
* * * * *