Schlumberger-Sonic Scanner

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Sonic Scanner
Acoustic
scanning
platform

Applications
Adding radius to borehole acoustics
Overcoming earlier acoustic
■ Geophysics
For decades, the oil and gas industry
measurement barriers
has used borehole acoustic measurements
Regardless of the formation type, the
● Improve 3D seismic analysis
throughout the lifecycle of wells to evaluate
Sonic Scanner platform design overcomes
and seismic tie-ins
rock properties in the near-wellbore region.
earlier acoustic measurement barriers to
● Determine shear anisotropy
As the industry continues to develop new
successful formation characterization and
● Input to fluid substitution
methods for producing hydrocarbons
quantification because it
■ Geomechanics
more efficiently, a focus on well integrity
■ uses a wide-frequency range that
has become ever more important.
enables characterizing formations as
● Analyze rock mechanics
Schlumberger has designed a tool using
● homogeneous or inhomogeneous
● Identify stress regimes
the latest acoustic technology for advanced
● isotropic or anisotropic
● Determine pore pressure
acoustic acquisition, including cross-dipole
● Evaluate well placement
and multispaced-monopole measurements.
■ uses long- and short-monopole
and stability
In addition to axial and azimuthal measure-
transmitter-receiver spacing
ments, the tool makes a radial measurement
■ is fully characterized with predictable
■ Reservoir characterization
to probe the formation for near-wellbore
acoustics.
● Identify gas zones
slowness and far-field slowness. Typical
Earlier technologies attempted to operate
● Measure mobility
depths of investigation equal two to three
close to the tool’s low-frequency limit, or
● Identify open fractures
times the borehole diameter.
they depended on previously acquired
The new Sonic Scanner* acoustic scan-
● Maximize selective perfo-
formation information to anticipate forma-
ning platform provides advanced types of
rating for sand control
tion slowness prior to data evaluation.
acoustic measurements, including borehole-
The wide-frequency spectrum used by
● Maximize safety window
compensated monopole with long and short
the Sonic Scanner tool allows data capture
for drawdown pressure
spacings, cross-dipole, and cement bond
at high signal-to-noise ratios and extracts
● Optimize hydraulic fracturing
quality. These measurements are then con-
maximum data from the formation. This
■ Well integrity
verted into useful information about the
design feature also helps ensure that data
drilling environment and the reservoir,
● Evaluate cement bond quality
are acquired regardless of the formation
which assists in making decisions that
slowness. The monopole transmitters have
reduce overall drilling costs, improve
Benefits
recovery, and maximize productivity. The
■ Enhance hydrocarbon recovery
following field examples demonstrate the
Figure 1. The Sonic Scanner tool provides the bene-
fits of axial, azimuthal, and radial information from
■ Make real-time decisions with
greater flexibility in acoustic measurements
both the monopole and the dipole measurements
real-time quality control
offered by the Sonic Scanner tool.
for near-wellbore and far-field slowness information.
■ Improve reserves estimates
Achieving a better understanding
■ Decrease operating time and
of acoustic propagation
reduce job costs by eliminat-
To enable a deeper understanding of
ing multiple logging runs
acoustic behavior in and around the bore-
■ Reduce uncertainty and
hole, the Sonic Scanner tool allows accu-
operating risk
rate radial and axial measurements of the
stress-dependent properties of rocks near
Features
the wellbore. The Sonic Scanner platform
■ Robust measurement of
provides multiple depths of investigation,
compressional and shear
excellent waveform quality, and presenta-
slownesses
tions that reduce the complexity of sonic
logging, without compromising the depth
■ Increased logging speed
of information.
(1,097 m/h [3,600 ft/h])
The more comprehensive understanding
■ Multiple monopole transmitter
obtained by using the Sonic Scanner plat-
and receiver spacing
form helps to improve fracture planning,
■ High-fidelity wideband wave-
sand control, and perforating design.
forms and dispersion curves
■ Large receiver array
■ Predictable acoustics
■ Enhanced behind-casing
measurements with simulta-
neous cement bond log (CBL)
and Variable Density* cement
bond quality measurements
■ Extremely rugged electronic
package

enhanced low-frequency output over the
Obtaining well integrity measurements
The transit time scattering shows ±0.31-in
entire range of sonic frequencies; and
with high accuracy
eccentering in the 7-in, 23-lbm/ft casing.
the dipole transmitters are designed for
The Sonic Scanner tool provides a dis-
The two bond index measurements
high-output power, high-purity acoustic
criminated cement bond log (DCBL) that
show good agreement, even in the zone
waves, wide bandwidth, and low power
can be obtained simultaneously with the
of high eccentralization near the top of
consumption.
behind-casing acoustic measurements.
the interval.
The Sonic Scanner receivers feature a
The two monopole transmitters positioned
longer azimuthal array than other acoustic
at either end of the Sonic Scanner tool
Removing uncertainties about formation
tools; i.e., 13 stations and 8 azimuthal
allow 3-ft and 5-ft cement bond log (CBL)
geometry and structure
receivers at each station. With the two
and cement bond quality measurements
A recurring problem encountered in
near-monopole transmitters straddling
that are independent of fluid and tempera-
reservoir modeling and simulation is the
this array and a third transmitter farther
ture effects and do not require calibration.
lack of available image data having a fine
away, the short- to long-monopole trans-
To demonstrate the DCBL measure-
scale. Until now, the only available alter-
mitter-to-receiver spacing combination
ment accuracy, a logging run made with
natives have been to work with surface
allows the altered zone to be seen and
a Sonic Scanner tool is compared with
seismic data, often too coarse in quality,
provides a radial monopole profile.
measurements from a CBT* Cement
or near-wellbore imaging and its associ-
Bond Tool. The DCBL measurements are
ated limitations. Coupled with the scale
Seeing beyond the altered zone
indicated in blue and the CBT measure-
of seismic measurements, additional
The long-spaced transmitter-to-receiver
ments are in black. A very good match
uncertainties arise regarding geometry
concept in earlier acoustic tools was
is shown between the measurements
and structure, formation property varia-
designed for “seeing” past the altered
of the CBT tool and the azimuthally
tion, and fluid movements.
zone and attempted to provide an unal-
averaged Sonic Scanner platform.
tered slowness measurement.
The range of Sonic Scanner transmitter-
Figure 2. A very good match is shown between azimuthally averaged Sonic Scanner platform and CBT
to-receiver spacings is both short and
curves (1). Curve scattering indicates 0.31-in eccentering (10 % of the internal radius) in the 7-in casing (2).
long enough to see the altered zone and
A good match between bond index measurements is indicated (3).
thus provide a radial monopole profile.
These features improve measurement
Variable
Variable
accuracy of the fluids and the stress-
Density
Density
dependent properties of the rocks near
Gamma
Transit
Variable
Discriminated Discriminated
Bond
Variable
Ray
Time
Density*
Attenuation
Amplitude
Index
Density
the wellbore; and that benefits fracture
XX,700
planning, sand control, and perforating
design, as well as shallow-reading-device
XX,800
3
point selection.
The wide-frequency spectrum from
XX,900
2
the dipole transmitters used in the Sonic
Scanner platform eliminates the need for
XY,000
Depth,
multiple logging passes that were common
ft
with the earlier-generation acoustic tools.
XY,100
New telemetry, optimized with software
XY,200
1
and hardware, enables increased logging
speeds and decreased operating times.
XY,300
XY,400
0 150 275
295 200
600 0 150 0 50 0 1 200
1200
gAPI
dB/ft
mV
CBT
Sonic Scanner
Sonic Scanner
Bond index limit

Figure 3. Excellent resolution obtained from the Sonic Scanner tool compared with the surface seismic image.
XX,000
Interpreted oil/gas contact
Top of reservoir
XX,005
True
Wellbore
vertical
depth,
XX,010
m
XX,015
Bottom of main sand body
Planned well
Drilled well
XX,020
20
600
Horizontal position, m
Figure 4. In this example, the high-gamma ray activity indicates a shaly interval. An isotropic zone (N = 0)
The inset image in Fig. 3 shows the
extends from XY,500 to XY,600 m, and a high-permeability zone exists from XY,005 to XY,100 m.
surface seismic data with normal, rather
poor, resolution. In the Sonic Scanner
image of Fig. 3, the solid green line indi-
Shear Rigidity in
X2–X3 Transversely
cates the interpreted reservoir top, and
Borehole Plane
the dashed blue line is the interpreted
0
GPa
10
bottom of the main sand body. The purple
Borehole Deviation
Compressional DT
Shear Rigidity in
Shear Rigidity in
line shows the wellbore path.
0
deg
90 440
µs/ft
40
X2–X3 Transversely
X2–X3, X1–X2, and
Isotropic Vertical Plane
X1–X3 Borehole Plane
The relative horizontal position along
[email protected]_Aniso_Com
Fast Shear DT
–300
GPa
300 440
µs/ft
40 0
GPa
5 0
GPa
10
the bottom scale is 20 – 600 m from left
Slow Shear DT
Shear Rigidity in
Equivalent Shear
to right, and the vertical scale (deep
Shale
440
µs/ft
40
X1–X2 Transversely
Rigidity in
reading) is in increments of 5 m, show-
Isotropic Vertical Plane
Borehole Plane
Depth
Stoneley DT
Thin Bed
ing clearly more than 15 m of excellent
m

440
µs/ft
40 0
GPa
5 0
GPa
10
resolution compared with the surface
seismic image.
The Sonic Scanner image measurements
XX,800
are used to update the geological model
and as input to the reservoir simulator
for predicting pressure with production.
XY,000
High
Obtaining transversely isotropic
permeability
formation parameters
XY,200
A 3D anisotropy algorithm transforms the
compressional, fast-shear, slow-shear, and
Stoneley slowness Sonic Scanner meas-
urements with respect to the borehole
XY,400
axes to anisotropic moduli referenced to
the earth’s anisotropy axes. These moduli
Isotropic
help to classify formation anisotropy into
XY,600
isotropic, transversely isotropic (TI), or
orthorhombic types. The moduli also
assist in identifying microlayering or
XY,800
thin-bedding-induced TI anisotropy
(N < 0 implies microlayering-induced

intrinsic anisotropy; N > 0 implies bedding-
Figure 5. Mobility measured by the Sonic Scanner tool is shown in Track 4. The red dots indicate mobility
induced anisotropy), relative magnitude
values measured by the MDT* Modular Formation Dynamics Tester, which show good agreement.
of principal stresses, and fluid mobility
in porous rocks.
Figure 4 shows the 3D anisotropy algo-
Shale
rithm’s ability to generate the TI param-
Sand
eters. With reference to a borehole that
Porosity
Quality
DT Compressional
Bound Water
is parallel to the X3 axis, shear modulus
0
%
100
Flag
160
µs/ft
60
Gamma Ray
Signal-
DT Shear
Mobility Error
Oil
or rigidity in the X2-X3 plane and shear
0
gAPI
150 to-Noise 300
µs/ft
150
Caliper
Ratio
DT Stoneley
Stoneley Mobility
Water
rigidity in the X1-X2 plane enable
6
in
16 30 dB 50 300
µs/ft
200 1
mD/cP
10,000
Bulk Density
Depth
DT mud
MDT Mobility
Sonic Scanner Stoneley
Coal
quicklook interpretation of formation
1.95
g/cm3
2.95
ft
240
µs/ft
40 1
mD/cP
10,000
0
µs/ft
16,000
anisotropy, stress, and mobility effects.
Determining formation mobility
Because there is essentially no continuous
logging measurement of mobility available,
X,X00
other methods have to be considered.
One method is to measure formation
mobility, which is the ratio of perme-
ability to viscosity.
Mobility, however, is not always avail-
able when it is needed because porosity
estimates are often preliminary, wireline
cores require an additional run into the
X,X20
well, and whole cores are expensive.
When the borehole is in reasonably
good condition, Stoneley waves can be
used to measure a continuous mobility
profile in sands and carbonates. These
data can serve as an extension of core
permeability over a continuous interval
to save on coring costs, or to get a quick
X,X40
permeability estimate for selecting the
perforating interval.
Minimizing the effects of tool presence
on sensitive Stoneley wave measurements
is extremely important. The design of the
Sonic Scanner tool, coupled with exten-
sive laboratory and field testing, enables
highly accurate prediction of the effects
X,X60
of the tool on acoustic measurements
in all environments.
The example in Fig. 5 demonstrates
how the Sonic Scanner Stoneley waves
can be used to measure a continuous
mobility profile and obtain a quick per-
meability estimate. Other applications of
Stoneley permeability include formation
evaluation, production testing strategy
and programs, and reservoir modeling.
Evaluating the mechanical properties
of formations

Acoustic measurements have typically
been acquired in 1D as a function of
depth, but seldom in 2D simultaneously
as a function of depth and azimuthal
direction. And interpretation has almost
always been based on the assumption
that the formations were homogeneous
and isotropic—a debatable assumption,

at best, because of fracture alignment,
Figure 6. A mechanical earth model can be constructed and compared with independent measurements
dipping beds, unbalanced stresses, and
of rock properties and in situ stresses.
formation damage from drilling.
The Sonic Scanner tool enables a full
Earth Stress Plot
x10
2.5
3D characterization of the formation by
0
adding the radial dimension from the
2

multiple transmitter-receiver spacings,
1.5
2,000
along with wideband frequency measure-
1
ments and acquisition of all acoustic
Effective axial stress, psi
4,000
E - 3.084 x 10 psi
0.5
modes propagating in the borehole. From
Young’s Modulus
True
o = 3000 psi
3
Sample 67-S1
vertical
Depth: 4912.00 ft
0
the expanded set of measurements, dom-
0

0.2
0.4

0.6


0.8
1


1.2

1.4
1.6

depth,
Axial strain, %

ft
6,000
inant formation data can be evaluated
Delta Stability
10
and the appropriate processing tech-
niques can be selected to extract 3D
8,000
5
)
acoustical properties.
0
In a tight-gas reservoir, formation
10,000
Distance (in
6
8 10 12 14 16 18 20 22
evaluation data and wellbore images
-5
Equivalent mud density, ppg
were combined with Sonic Scanner
Pore pressure
σVertical
σmin Sand
σmax Sand
-10
shear wave anisotropy and Stoneley
σmin Shale
σmax Shale
Kick
Pressure Xpress*
-10
-5

0

5
10
Mud loss
DataFRAC* service
σmin Sand-Wbs
service
Distance, in
wave data shown in Fig. 6. Wellbore
σmin Shale-Wbs
σmax Shale-Wbs
σmax Sand-Wbs
FMI log
stability simulation was used to ensure
consistency between the mechanical
earth model and the logging and drilling
data. The mechanical earth model was
Figure 7. Stoneley wave measurements enabled determination that the fractures were natural, not
then applied to optimize subsequent
drilling induced.
drilling operations.
Detecting and evaluating open
Crossline
Washout
Energy
fractured intervals
Gamma Ray
Maximum
0
gAPI
150
Crossline
Energy
Bit Size
Understanding the mechanisms of aniso-
4
in
14 0
100
Caliper 1
tropy can be important when selecting
Minimum
Slowness
Slowness
Dynamic Image
Crossline
4
in
14
Slowness
Frequency
Slowness
Frequency
Horizontal Scale: 1:13.744
Energy
Projection
Analysis
Projection
Analysis
Orientation North
the right hydraulic fracture fluid for a
Caliper 2
Fast-In-Line
Slow-In-Line
0
100
Variable
Variable
80
µs/ft 280 80 µs/ft 280
80
µs/ft 280 80 µs/ft 280 0
120
240
360
4
in
14
Density
Density
Resistive
Conductive
well, especially if there is stress-induced
Stoneley Fractures
Depth
DT Shear Fast DT Shear Fast
DT Shear Slow DT Shear Slow
0
in
0.5
ft
0
µs 6,000 80 µs/ft 280 80 µs/ft 280 0
µs 100 80 µs/ft 280 80 µs/ft 280
FMI Image
anisotropy or intrinsic anisotropy related
to the presence of natural fractures. The
Sonic Scanner tool can be used in evalu-
ating the type of anisotropy, in addition
to differentiating between open natural
fractures and drilling-induced fractures.
XX,050
The fractures shown in the FMI*
Fullbore Formation MicroImager log
in Fig. 7 are near vertical. Upon foot-
by-foot examination, they were origi-
nally interpreted to be drilling induced.
XX,100
Stoneley wave measurements from the
Sonic Scanner tool made it clear that the
fractures were open natural fractures
and not drilling induced.
The additional sonic data undoubtedly
prevented the operator from making an
incorrect interpretation, which would
have led to selection of a high-gel fracture
fluid that would have destroyed the
permeability of the naturally fractured
formation. In this situation, encapsulated
breakers are much less effective, and an
effective treatment can be designed.
In addition to preventing fluid loss,
this information would also be critical
in preventing cement loss during com-
pletion operations.

Sonic Scanner Measurement Specifications
Output
Compressional and shear DT, full waveforms, cement bond quality waveforms
Max. logging speed
1,097 m/h [3,600 ft/h]†
Range of measurement
Standard shear slowness: <4,921 µs/m [1,500 µs/ft]
Vertical resolution
<1.82-m [6-ft] processing resolution for 15.24-cm [6-in] sampling rate‡
Accuracy
DT: <6.56 µs/m [2 µs/ft] or 2% up to 35.6-cm [14-in] hole size
<16.40 µs/m [5 µs/ft] or 5% for >35.6-cm [14-in] hole size
Mud weight or type limits
None
Combinability
Fully combinable with other tools
† Acquisition speed depends on product class and sampling rate.
‡ Vertical resolution of <60.96 cm [<2 ft] is possible.
Sonic Scanner Mechanical Specifications
Max. temperature
177 degC [350 degF]
Max. pressure
138 MPa [20,000 psi]
Borehole size
Min.
12.07 cm [4.75 in]
Max.
55.88 cm [22 in]
Outer diameter
9.21 cm [3.625 in]
Length
12.58 m [41.28 ft]†
6.7 m [22 ft]‡
Weight
383 kg [844 lbm]†
188 kg [413 lbm]‡
Tension
157 kN [35,000 lbf]
Compression
13 kN [3,000 lbf]
† Advanced toolstring, including isolation joint
‡ Basic toolstring, near monopoles only
www.slb.com/oilfield
05-FE-130
© 2005 Schlumberger
November 2005
*Mark of Schlumberger
Produced by Schlumberger Marketing Communications