Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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Logging Systems and Methods with Tilt Compensation
for Sector-Based Acoustic Tools
BACKGROUND
Oil field operations demand a great quantity of information relating to the
parameters and
conditions encountered downhole. Because drillers and operators are forced to
operate remotely
from the underground formations and reservoirs they wish to exploit, their
access to relevant
information is limited. Consequently, there is a demand for tools that provide
new types of
information, more accurate information, or more efficient collection of
information. Examples of
information that may be collected include characteristics of the earth
formations traversed by the
borehole, and data relating to the size and configuration of the borehole
itself. This information
is usually recorded and displayed in the form of a log, i.e. a graph of the
measured parameter as
a function of tool position or depth. The collection of information relating
to conditions down-
hole, which commonly is referred to as "logging", can be performed by several
methods includ-
ing wireline logging and "logging while drilling" (LWD).
In wireline logging, a probe or "sonde" is lowered into the borehole after
some or all of a
well has been drilled. The sonde hangs at the end of a long cable or
"wireline" that provides
mechanical support to the sonde and also provides an electrical connection
between the sonde
and electrical equipment located at the surface of the well. In accordance
with existing logging
techniques, various parameters of the earth's formations are measured and
correlated with the
position of the sonde in the borehole as the sonde is pulled uphole.
In LWD, the drilling assembly includes sensing instruments that measure
various pa-
rameters as the formation is being penetrated, thereby enabling measurements
of the formation
while it is less affected by fluid invasion. While LWD measurements are
desirable, drilling
operations create an environment that is generally hostile to electronic
instrumentation, teleme-
try, and sensor operations.
Acoustic logging tools can be employed in both wireline logging and LWD
environ-
ments. Acoustic well logging is a well-developed art, and details of acoustic
logging tools and
techniques are set forth in A. Kurkjian, et al., "Slowness Estimation from
Sonic Logging Wave-
forms", Geoexploration, Vol. 277, pp. 215-256 (1991); C. F. Morris et al., "A
New Sonic Array
Tool for Full Waveform Logging," SPE-13285, Society of Petroleum Engineers
(1984); A. R.
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Harrison et al., "Acquisition and Analysis of Sonic Waveforms From a Borehole
Monopole and
Dipole Source . . . " SPE 20557, pp. 267-282 (September 1990); and C. V.
Kimball and T. L.
Marzetta, "Semblance Processing of Borehole Acoustic Array Data", Geophysics,
Vol. 49, pp.
274-281 (March 1984).
An acoustic logging tool typically includes an acoustic source (transmitter),
and a set of
receivers that are spaced several inches or feet apart. An acoustic signal is
transmitted by the
acoustic source and received at the receivers which are spaced apart from the
acoustic source.
Measurements are repeated every few inches as the tool passes along the
borehole.
The acoustic signal from source travels through the formation adjacent the
borehole to
the receiver array, and the arrival times and perhaps other characteristics of
the receiver re-
sponses are recorded. Typically, compressional wave (P-wave), shear wave (S-
wave), and
Stoneley wave arrivals and waveforms are detected by the receivers and are
processed. The
processing of the data is often accomplished by an uphole computer system or
may be processed
real time by a processor in the tool itself. Regardless, the information that
is recorded is typically
used to find formation characteristics such as formation slowness (the inverse
of acoustic speed),
from which pore pressure, porosity, and other formation property
determinations can be made. In
some tools, the acoustic signals may even be used to image the formation.
Acoustic logging tools generally perform well. However, as measurement
electronics are
improved and tool resolution improves, anomalous slowness measurements are
being more
commonly observed. Such measurements may unnecessarily confuse interpreters or
lead to
customer dissatisfaction with the logging tools. It has been discovered that
these anomalous
measurements may be the result of tool tilt.
BRIEF DESCRIPTION OF THE DRAWINGS
A better understanding of the various disclosed embodiments can be obtained
when the
following detailed description is considered in conjunction with the following
drawings, in
which:
Fig. 1 shows an illustrative logging while drilling environment;
Fig. 2 shows an illustrative wireline logging environment;
Fig. 3 shows an illustrative acoustic logging tool;
Fig. 4 shows the sectorization of an illustrative acoustic receiver;
Fig. 5 illustrates an off-center and tilted acoustic logging tool;
Figs. 6A and 6B show illustrative waveforms received in opposing sectors of
the tool of
Fig. 5;
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Fig. 7A and 7B are slowness-time semblance graphs illustrating the effects of
tool tilt;
Fig. 8 is a flow diagram of an illustrative acoustic logging method with tilt
compensation;
Fig. 9 is a block diagram of an illustrative computer system suitable for
implementing
aspects of the disclosed methods.
While the invention is susceptible to various modifications and alternative
forms, specific
embodiments thereof are shown by way of example in the drawings and will
herein be described
in detail. lt should be understood, however, that the drawings and detailed
description thereto are
not intended to limit the invention to the particular fonn disclosed, but on
the contrary, the
intention is to cover all modifications, equivalents and alternatives falling
within the spirit and
scope of the present invention as defined by the appended claims.
DETAILED DESCRIPTION
Disclosed herein are various logging systems and methods with tilt
compensation for sec-
tor-based acoustic logging tools. Some method embodiments include: generating
an acoustic
signal that propagates along a borehole in a formation; receiving a signal
from each of a set of
azimuthally-arranged acoustic transducers; processing the signals to
compensate for logging tool
tilt; and determining a property of the formation based at least in part on
the compensated
signals. Some tool embodiments include an internal controller that processes
signals from
different directions to detemiine and correct time offsets that are
attributable to logging tool tilt.
Thereafter, the tilt-compensated signals can be used to measure formation and
borehole parame-
ters which may be associated with position and displayed in the form of
borehole logs and/or
images.
Fig. I shows an illustrative logging while drilling (LWD) environment. A
drilling plat-
form 2 supports a derrick 4 having a traveling block 6 for raising and
lowering a drill string 8. A
kelly 10 supports the drill string 8 as it is lowered through a rotary table
12. A drill bit 14 is
driven by a downhole motor and/or rotation of the drill string 8. As bit 14
rotates, it creates a
borehole 16 that passes through various formations 18. A pump 20 circulates
drilling fluid
through a feed pipe 22 to kelly 10, downhole through the interior of drill
string 8, through
orifices in drill bit 14, back to the surface via the annulus around drill
string 8, and into a reten-
tion pit 24. The drilling fluid transports cuttings from the borehole into the
pit 24 and aids in
maintaining the borehole integrity.
An acoustic LWD too126 is integrated into the bottom-hole assembly near the
bit 14. As
the bit extends the borehole through the formations, logging tool 26 collects
measurements
relating to various formation properties as well as the tool orientation and
various other drilling
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conditions. The logging tool 26 may take the form of a drill collar, i.e., a
thick-walled tubular
that provides weight and rigidity to aid the drilling process. A telemetry sub
28 may be included
to transfer tool measurements to a surface receiver 30 and to receive commands
from the sur-
face. In some embodiments, the telemetry sub 28 does not communicate with the
surface, but
rather stores logging data for later retrieval at the surface when the logging
assembly is recov-
ered.
At various times during the drilling process, the drill string 8 may be
removed from the
borehole as shown in Fig. 2. Once the drill string has been removed, logging
operations can be
conducted using a wireline logging too134, i.e., a sensing instrument sonde
suspended by a cable
42 having conductors for transporting power to the tool and telemetry from the
tool to the
surface. An acoustic logging tool 34 may have pads and/or centralizing springs
to maintain the
tool near the axis of the borehole as the tool is pulled uphole. A logging
facility 44 collects
measurements from the logging tool 34, and includes a computer system 45 for
processing and
storing the measurements gathered by the logging tool.
Fig. 3 shows an enlarged view of an illustrative acoustic logging too126 in a
borehole 16.
The logging tool 26 includes an acoustic source 52, an acoustic isolator 54,
and an array of
acoustic receivers 56. The source 52 may be a monopole, dipole, quadrupole, or
higher-order
multi-pole transmitter. Some tool embodiments may include multiple acoustic
sources or one
acoustic source that is configurable to generate different wave modes. The
acoustic source may
be made up of piezoelectric elements, bender bars, or other transducers
suitable for generating
acoustic waves in downhole conditions. The contemplated operating frequencies
for the acoustic
logging tool are in the range between 0.5kHz and 30kHz, inclusive. The
operating frequency
may be selected on the basis of a tradeoff between attenuation and wavelength
in which the
wavelength is minimized subject to requirements for limited attenuation.
Subject to the attenua-
tion limits on performance, smaller wavelengths may offer improved spatial
resolution of the
tool.
The acoustic isolator 54 serves to attenuate and delay acoustic waves that
propagate
through the body of the tool from the source 52 to the receiver array 56. Any
standard acoustic
isolator may be used. Receiver array 56 includes multiple sectorized receivers
58 spaced apart
along the axis of the tool. Although five receivers 58 are shown in Fig. 3,
the number can vary
from one to sixteen or more.
Each sectorized receiver 58 includes a number of azimuthally spaced sectors.
Referring
momentarily to Fig. 4, a receiver 58 having eight sectors A1-A8 is shown.
However, the number
of sectors can vary and is preferably (but not necessarily) in the range
between 4 and 16, inclu-
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sive. Each sector may include a piezoelectric element that converts acoustic
waves into an
electrical signal that is amplified and converted to a digital signal. The
digital signal from each
sector is individually measured by an internal controller for processing,
storage, and/or transmis-
sion to an uphole computing facility. Though the individual sectors can be
calibrated to match
their responses, such calibrations may vary differently for each sector as a
function of tempera-
ture, pressure, and other environmental factors. Accordingly, in at least some
embodiments, the
individual sectors are machined from a cylindrical (or conical) transducer. In
this fashion, it can
be ensured that each of the receiver sectors will have matching
characteristics.
When the acoustic logging tool is enabled, the internal controller controls
the triggering
and timing of the acoustic source 52, and records and processes the signals
from the receiver
array 56. The internal controller fires the acoustic source 52 periodically,
producing acoustic
pressure waves that propagate through the fluid in borehole 16 and into the
surrounding fonna-
tion. At the borehole boundary, some of the acoustic energy is converted into
shear waves that
propagate along the interface between the borehole fluid and the formation. As
these "interface
waves" propagate past the receiver array 56, they cause pressure variations
that can be detected
by the receiver array elements. The receiver array signals may be processed by
the internal
controller to determine the true formation shear velocity, or the signals may
be communicated to
the uphole computer system for processing. The measurements are associated
with borehole
position (and possibly tool orientation) to generate a log or image of the
acoustical properties of
the borehole. The log or image is stored and ultimately displayed for viewing
by a user.
The processing methods applied to the acoustic tool measurements commonly
assume
that the acoustic logging tool is centered, or at least that the logging tool
axis parallels the
borehole axis. In practice, however, the logging tool can move off-center and
become tilted
relative to the borehole axis as shown in Fig. 5.
In Fig. 5, the acoustic logging tool is offset by 2 inches and tilted at 2.5
relative to the
axis of a 10 inch borehole through a 50 s/ft fonnation. Such tilts, alone or
in conjunction with
off-centering, have been found to cause anomalous slowness measurements. The
tool tilt pro-
duces a gradual shortening of the tool-to-borehole wall offset on one side of
the tool, and a
gradual lengthening of the offset on the opposite side of the tool. As a
consequence, the acoustic
waves 62 propagating along one side of the borehole may appear to be
propagating past the
receiver array at a greater velocity than the acoustic waves 64 propagating
along the opposite
side of the borehole.
Fig. 6A shows a set of amplitude versus time waveforms 62 recorded from (say)
the A3
sectors of each receiver in the receiver array. The receivers are located at
3, 3.5, 4, 4.5, and 5 ft
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from the acoustic source, and various slowness value slopes are shown to aid
interpretation. Fig.
6B shows the set of amplitude versus time waveforms 64 recorded from A7, the
sector opposite
A3 and tilting away from the borehole wall.
In both figures, the time scale is from 68 to 1832 s. Each of the waveforms
is shown
for a corresponding receiver as a function of time since the transmitter
firing. (Note the increased
time delay before the acoustic wave reaches the increasingly distant
receivers.) After recording
the waveforms, the internal controller typically normalizes the waveform so
that they have the
same signal energy.
To identify waves and their slowness values, the internal controller or uphole
processing
system may calculate the time semblance E(t,s) as a function of slowness and
time for the data.
This information in turn may be used to determine various formation
properties, including wave
propagation velocity and dispersion of acoustic waves. The equation for the
time semblance
E(t,s) is:
N Z
E(t, s) = N' N Z (1)
~x; (t -sd;)
;-~ -
In the above equation, N is the number of receiver elements, and hence is also
the num-
ber of recorded waveforms, x;(t) is the waveform recorded by the ith receiver,
d; is the distance
of the ith receiver from the transmitter, and s is the slowness. In Equation
1, the quantity (t-sd;) is
the relative time at the ith receiver for a given slowness s.
Semblance values E(t,s) range between zero and one. Values near one indicate a
high
correlation between the various recorded waveforms at the given time and
slowness, and hence
indicate the presence of a propagating wave having that slowness value. Values
near zero
indicate little correlation between the various waveforms at the given time
and slowness value,
and hence provide no indication of a propagating wave having that slowness
value.
Fig. 7A shows a plot of the time semblance E(t,s) as a function of time and
slowness for
the waveforms of Fig. 6A, and Fig. 7B shows a similar plot for the waveforms
of Fig. 6B. Of
particular interest in measuring formation slowness are the first-arrival
peaks, i.e., the peaks in
the lower left corner, corresponding to the fastest waves. The graph on the
right shows the
maximum semblance value found for a given slowness value.
In Fig. 7A the first arrival peak 72 has a maximum semblance value at 41.7
s/ft, while
in Fig. 7B the first arrival peak has a maximum semblance value at 58 s/fft.
Thus, when com-
pared with the formation slowness of 50 s/ft, the receiver sectors tilting
toward the borehole
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wall measure a reduced slowness (i.e., a faster propagation speed), and the
receiver sectors tilted
away from the borehole wall measure an increased slowness (i.e., a slower
propagation speed).
If, in each receiver, all the sector measurements were combined, the resulting
semblance calcula-
tions would have revealed an unnecessarily broad distribution of propagation
speeds, possibly
having a peak at an incorrect value.
Fig. 8 is a flow diagram of an illustrative acoustic logging method with tilt
compensation.
The acoustic logging tool is inserted in the borehole, and as the drilling
process progresses or as
the wireline sonde is pulled, the logging tool moves along the borehole as
indicated in block 82.
ln block 83, the logging tool's internal controller periodically fires the
acoustic transmitter and
collects sector-specific measurements from each of the receivers in the
receiver array.
As indicated by block 84, the internal controller processes the measurements
to deter-
mine the tool tilt effect, and may further calculate the tool offset and tilt
relative to the borehole
axis. In some embodiments, the internal controller determines tool offset and
tilt by first sum-
ming the sector-specific measurements for each receiver to obtain each
receiver's full radial
response. The internal controller then measures the time semblance as given in
equation (1) to
determine a first arrival window, i.e., a time window in which the transmitted
acoustic signal
first reaches each of the receivers. A suitable window length might be 100 s,
centered on the
time value for the first-arrival peak and shifled for subsequent receivers in
accordance with the
slowness value for the first-arrival peak.
Having identified the time window for each receiver, the intemal controller
analyzes the
sector-specific signals to determine a time offset between the waveforms of
the different signals.
The internal controller may employ a threshold crossing or a peak-detection
technique to meas-
ure a time offset for each sector-specific signal, e.g. relative to the center
or leading edge of the
time window. (As a refinement, the peak detection may be performed on an
envelope of the
sector specific signals, the envelope being determined by rectification and
low-pass filtering.)
Alternatively, the internal controller may select one of the sector-specific
signals as a reference
and perform a semblance or correlation calculation to determine the time
offset of the other
waveforms relative to the reference signal. The time-offset determination is
performed between
the sectors for each of the receivers.
In block 85, the internal controller determines whether a tilt effect
correction is needed.
ln some embodiments, the maximum time offset (or the average time offset
magnitude) is
compared to a threshold, and corrections are deemed unnecessary when the
threshold is not
exceeded. For those corrections deemed necessary, the internal controller
applies individual time
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shifts to the sector-specific signals to correct for tilt and to potentially
correct for tool de-
centralization.
In some embodiments, the measured time offset is simply corrected by a
corresponding
time shift. In other embodiments, a more sophisticated processing technique is
employed to
determine the appropriate time shifts. In some embodiments of the correction
process, the
internal controller determines a tilt effect model that best fits the measured
time-offsets. In some
embodiments, the tilt effect model assumes a time offset that varies
sinusoidally as a function of
azimuth, and has the same size and orientation for each of the receivers so
that, e.g., the time
offset is the same in sector A1 of each receiver. With the size and
orientation of the time-offset
as model parameters, the internal controller determines a least-squares fit to
the measured time
offsets. In other embodiments, the tilt effect model includes an time-offset
dependence due to a
tool-offset parameter to account for de-centralization of the tool relative to
the borehole axis.
The time-offsets determined by the best-fitting model are corrected by
appropriate time shifts to
the measured sector-specific signals, thereby correcting for tilt and
"pushing" the summed
receiver signal to the center of the borehole.
Though the foregoing discussion determines the corrections for the receiver
array as a
whole, the same approaches can be applied independently to each receiver in
the array to achieve
similar results with reduced complexity. If sufficient computing resources are
available to deal
with additional complexity, the method may be refined to track tool movement
from measure-
ment to measurement and to use the movement information to refine estimates of
tool tilt and
position effects.
In block 87, the corrected (if correction was needed) sector-specific signals
are processed
to measure formation slowness, measure acoustic anisotropy, perform acoustic
imaging, evaluate
cement bonding, and/or to determine the borehole shape and size in accordance
with existing
techniques. Formation slowness can be measured using the techniques outlined
in U.S. Patent
7,089,119, entitled "Acoustic Signal Processing Method Using Array Coherency".
Acoustic
anisotropy can be measured using the techniques outlined in U.S. Patent
6,188,961, entitled
"Acoustic Logging Apparatus and Method". Acoustic imaging can be performed by
mapping
attenuation or intensity measurements to borehole wall pixels in a fashion
similar to the tech-
niques outlined in U.S. Patent 6,021,093, entitled "Transducer configuration
having a multiple
viewing position feature". With a short-distance acoustic source, or
straightforward modifica-
tions to account for different travel paths, borehole calipering can be
performed using the
techniques outlined in G.J. Frisch and B. Mandal, "Advanced Ultrasonic
Scanning Tool and
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Evaluation Methods Improve and Standardize Casing lnspection", SPWLA 42"d
Annual Logging
Symposium, June 17-21, 2001.
In block 88, the measurements determined from the processing operations of
block 87 are
associated with tool position measurements. If the logging tool includes a
navigation package,
this associate may be performed by the intemal controller or the downhole
telemetry transmitter.
Alternatively, or in addition, this association may be performed by an uphole
computer system
that collects position information from surface instruments and combines it
with the telemetry
data. The measurements, once associated with position, are stored in the form
of a log or image
and updated as new information becomes available. In block 89, the uphole
system displays the
log and/or images to a user. The user may be a driller, a completions
engineer, or other profes-
sional needing information regarding the well. The process of Fig. 8 repeats
as logging contin-
ues.
lt is noted here that the actions of Fig. 8 are shown in a sequential order
for explanatory
purposes. However, the disclosed method may in practice have multiple
operations occurring
concurrently and in different orders as suited to the needs of the users.
Although the bulk of the
method is described as being performed by an internal controller of the
acoustic logging tool,
this is not a requirement. To the contrary, the processing steps can be
performed in a surface
computing facility once the sector-specific signals have been acquired and
communicated to the
surface by a computer such as that shown in Fig. 9.
Fig. 9 is a block diagram of an illustrative computer system suitable for
determining and
correcting for logging tool tilt and offset. The computer of Fig. 9 includes a
chassis 90, a display
91, and one or more input devices 92, 93. The chassis 90 is coupled to the
display 91 and the
input devices 92, 93 to interact with a user. The display 91 and the input
devices 92, 93 together
operate as a user interface. The display 91 often takes the form of a video
monitor, but may take
many alternative forms such as a printer, a speaker, or other means for
communicating informa-
tion to a user: The input device 92 is shown as a keyboard, but may similarly
take many alterna-
tive forms such as a button, a mouse, a keypad, a dial, a motion sensor, a
camera, a microphone
or other means for receiving information from a user. In some embodiments, the
display 91 and
the input devices 92, 93 are integrated into the chassis 90.
Located in the chassis 90 is a display interface 94, a peripheral interface
95, a bus 96, a
processor 97, a memory 98, an information storage device 99, and a network
interface 100. The
display interface 94 may take the form of a video card or other suitable
interface that accepts
information from the bus 96 and transforms it into a form suitable for display
91. Conversely,
the peripheral interface may accept signals from input devices 92, 93 and
transform them into a
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form suitable for conununication on bus 96. Bus 96 interconnects the various
elements of the
computer and transports their communications.
Processor 97 gathers information from the other system elements, including
input data
from the peripheral interface 95 and program instructions and other data from
the memory 98,
the information storage device 99, or from a remote location via the network
interface 100. (The
network interface 100 enables the processor 97 to communicate with remote
systems via a wired
or wireless network.) The processor 97 carries out the program instructions
and processes the
data accordingly. The program instructions may fucther configure the processor
97 to send data
to other system elements, including information for the user which may be
communicated via the
display interface 94 and the display 91.
The processor 97, and hence the computer as a whole, generally operates in
accordance
with one or more programs stored on an information storage device 99. One or
more of the
information storage devices may store programs and data on removable storage
media such as a
floppy disk or an optical disc. Whether or not the information storage media
is removable, the
processor 97 may copy portions of the programs into the memory 98 for faster
access, and may
switch between programs or canry out additional programs in response to user
actuation of the
input device. The additional programs may be retrieved from information the
storage device 99
or may be retrieved from remote locations via the network interface 100. One
or more of these
programs configures the computer to carry out at least one of the acoustic
logging methods with
tilt effect correction disclosed herein.
Numerous variations and modifications will become apparent to those skilled in
the art
once the above disclosure is fully appreciated. For example, the disclosed
methods can be
adapted for use with monopole, dipole, quadrupole, and higher-order acoustic
transmitters. In
some embodiments, the tool tilt is collected from other instruments (e.g.,
borehole calipers) and
employed to determine the appropriate time shifts for the individual sector
signals. It is intended
that the following claims be interpreted to embrace all such variations and
modifications.
