Sonic Scanner
Acoustic
scanning
platform
Applications
Adding radius to borehole acoustics
■
For decades, the oil and gas industry
has used borehole acoustic measurements
throughout the lifecycle of wells to evaluate
rock properties in the near-wellbore region.
As the industry continues to develop new
methods for producing hydrocarbons
more efficiently, a focus on well integrity
has become ever more important.
Schlumberger has designed a tool using
the latest acoustic technology for advanced
acoustic acquisition, including cross-dipole
and multispaced-monopole measurements.
In addition to axial and azimuthal measurements, the tool makes a radial measurement
to probe the formation for near-wellbore
slowness and far-field slowness. Typical
depths of investigation equal two to three
times the borehole diameter.
The new Sonic Scanner* acoustic scanning platform provides advanced types of
acoustic measurements, including boreholecompensated monopole with long and short
spacings, cross-dipole, and cement bond
quality. These measurements are then converted into useful information about the
drilling environment and the reservoir,
which assists in making decisions that
reduce overall drilling costs, improve
recovery, and maximize productivity. The
following field examples demonstrate the
greater flexibility in acoustic measurements
offered by the Sonic Scanner tool.
■
■
■
Geophysics
●
Improve 3D seismic analysis
and seismic tie-ins
●
Determine shear anisotropy
●
Input to fluid substitution
Geomechanics
●
Analyze rock mechanics
●
Identify stress regimes
●
Determine pore pressure
●
Evaluate well placement
and stability
Reservoir characterization
●
Identify gas zones
●
Measure mobility
●
Identify open fractures
●
Maximize selective perforating for sand control
●
Maximize safety window
for drawdown pressure
●
Optimize hydraulic fracturing
Well integrity
●
Evaluate cement bond quality
Benefits
■
Enhance hydrocarbon recovery
■
Make real-time decisions with
real-time quality control
■
Improve reserves estimates
■
Decrease operating time and
reduce job costs by eliminating multiple logging runs
■
Reduce uncertainty and
operating risk
Features
■
Robust measurement of
compressional and shear
slownesses
■
Increased logging speed
(1,097 m/h [3,600 ft/h])
■
Multiple monopole transmitter
and receiver spacing
■
High-fidelity wideband waveforms and dispersion curves
■
Large receiver array
■
Predictable acoustics
■
Enhanced behind-casing
measurements with simultaneous cement bond log (CBL)
and Variable Density* cement
bond quality measurements
■
Extremely rugged electronic
package
Achieving a better understanding
of acoustic propagation
To enable a deeper understanding of
acoustic behavior in and around the borehole, the Sonic Scanner tool allows accurate radial and axial measurements of the
stress-dependent properties of rocks near
the wellbore. The Sonic Scanner platform
provides multiple depths of investigation,
excellent waveform quality, and presentations that reduce the complexity of sonic
logging, without compromising the depth
of information.
The more comprehensive understanding
obtained by using the Sonic Scanner platform helps to improve fracture planning,
sand control, and perforating design.
Overcoming earlier acoustic
measurement barriers
Regardless of the formation type, the
Sonic Scanner platform design overcomes
earlier acoustic measurement barriers to
successful formation characterization and
quantification because it
■ uses a wide-frequency range that
enables characterizing formations as
●
homogeneous or inhomogeneous
●
isotropic or anisotropic
■
uses long- and short-monopole
transmitter-receiver spacing
■
is fully characterized with predictable
acoustics.
Earlier technologies attempted to operate
close to the tool’s low-frequency limit, or
they depended on previously acquired
formation information to anticipate formation slowness prior to data evaluation.
The wide-frequency spectrum used by
the Sonic Scanner tool allows data capture
at high signal-to-noise ratios and extracts
maximum data from the formation. This
design feature also helps ensure that data
are acquired regardless of the formation
slowness. The monopole transmitters have
Figure 1. The Sonic Scanner tool provides the benefits of axial, azimuthal, and radial information from
both the monopole and the dipole measurements
for near-wellbore and far-field slowness information.
enhanced low-frequency output over the
entire range of sonic frequencies; and
the dipole transmitters are designed for
high-output power, high-purity acoustic
waves, wide bandwidth, and low power
consumption.
The Sonic Scanner receivers feature a
longer azimuthal array than other acoustic
tools; i.e., 13 stations and 8 azimuthal
receivers at each station. With the two
near-monopole transmitters straddling
this array and a third transmitter farther
away, the short- to long-monopole transmitter-to-receiver spacing combination
allows the altered zone to be seen and
provides a radial monopole profile.
Seeing beyond the altered zone
The long-spaced transmitter-to-receiver
concept in earlier acoustic tools was
designed for “seeing” past the altered
zone and attempted to provide an unaltered slowness measurement.
The range of Sonic Scanner transmitterto-receiver spacings is both short and
long enough to see the altered zone and
thus provide a radial monopole profile.
These features improve measurement
accuracy of the fluids and the stressdependent properties of the rocks near
the wellbore; and that benefits fracture
planning, sand control, and perforating
design, as well as shallow-reading-device
point selection.
The wide-frequency spectrum from
the dipole transmitters used in the Sonic
Scanner platform eliminates the need for
multiple logging passes that were common
with the earlier-generation acoustic tools.
New telemetry, optimized with software
and hardware, enables increased logging
speeds and decreased operating times.
Obtaining well integrity measurements
with high accuracy
The transit time scattering shows ±0.31-in
eccentering in the 7-in, 23-lbm/ft casing.
The two bond index measurements
show good agreement, even in the zone
of high eccentralization near the top of
the interval.
The Sonic Scanner tool provides a discriminated cement bond log (DCBL) that
can be obtained simultaneously with the
behind-casing acoustic measurements.
The two monopole transmitters positioned
at either end of the Sonic Scanner tool
allow 3-ft and 5-ft cement bond log (CBL)
and cement bond quality measurements
that are independent of fluid and temperature effects and do not require calibration.
To demonstrate the DCBL measurement accuracy, a logging run made with
a Sonic Scanner tool is compared with
measurements from a CBT* Cement
Bond Tool. The DCBL measurements are
indicated in blue and the CBT measurements are in black. A very good match
is shown between the measurements
of the CBT tool and the azimuthally
averaged Sonic Scanner platform.
Removing uncertainties about formation
geometry and structure
A recurring problem encountered in
reservoir modeling and simulation is the
lack of available image data having a fine
scale. Until now, the only available alternatives have been to work with surface
seismic data, often too coarse in quality,
or near-wellbore imaging and its associated limitations. Coupled with the scale
of seismic measurements, additional
uncertainties arise regarding geometry
and structure, formation property variation, and fluid movements.
Figure 2. A very good match is shown between azimuthally averaged Sonic Scanner platform and CBT
curves (1). Curve scattering indicates 0.31-in eccentering (10 % of the internal radius) in the 7-in casing (2).
A good match between bond index measurements is indicated (3).
Gamma
Ray
XX,700
Transit
Time
Variable
Density*
Variable
Variable
Density
Density
Discriminated Discriminated
Attenuation
Amplitude
Variable
Density
3
XX,800
2
XX,900
Depth,
ft
Bond
Index
XY,000
XY,100
1
XY,200
XY,300
XY,400
0
150 275
gAPI
295 200
600 0
150 0
dB/ft
50 0
mV
CBT
Sonic Scanner
Sonic Scanner
Bond index limit
1 200
1200
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
vertical
depth,
m
Wellbore
XX,010
XX,015
Planned well
Bottom of main sand body
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)
extends from XY,500 to XY,600 m, and a high-permeability zone exists from XY,005 to XY,100 m.
Shear Rigidity in
X2–X3 Transversely
Borehole Plane
0
Borehole Deviation
Compressional DT
0
deg
90 440
µs/ft
N_TIV@3D_Aniso_Com
Fast Shear DT
–300
GPa
Shale
Depth
m
Thin Bed
300 440
µs/ft
Slow Shear DT
440
µs/ft
Stoneley DT
440
µs/ft
40 0
40 0
XY,000
High
permeability
XY,200
XY,400
XY,800
5 0
Shear Rigidity in
X1–X2 Transversely
40
Isotropic Vertical Plane
XX,800
XY,600
GPa
Isotropic
GPa
GPa
10
Shear Rigidity in
X2–X3, X1–X2, and
X1–X3 Borehole Plane
Shear Rigidity in
X2–X3 Transversely
40
Isotropic Vertical Plane
GPa
10
Equivalent Shear
Rigidity in
Borehole Plane
5 0
GPa
10
The inset image in Fig. 3 shows the
surface seismic data with normal, rather
poor, resolution. In the Sonic Scanner
image of Fig. 3, the solid green line indicates the interpreted reservoir top, and
the dashed blue line is the interpreted
bottom of the main sand body. The purple
line shows the wellbore path.
The relative horizontal position along
the bottom scale is 20– 600 m from left
to right, and the vertical scale (deep
reading) is in increments of 5 m, showing clearly more than 15 m of excellent
resolution compared with the surface
seismic image.
The Sonic Scanner image measurements
are used to update the geological model
and as input to the reservoir simulator
for predicting pressure with production.
Obtaining transversely isotropic
formation parameters
A 3D anisotropy algorithm transforms the
compressional, fast-shear, slow-shear, and
Stoneley slowness Sonic Scanner measurements with respect to the borehole
axes to anisotropic moduli referenced to
the earth’s anisotropy axes. These moduli
help to classify formation anisotropy into
isotropic, transversely isotropic (TI), or
orthorhombic types. The moduli also
assist in identifying microlayering or
thin-bedding-induced TI anisotropy
(N < 0 implies microlayering-induced
intrinsic anisotropy; N > 0 implies beddinginduced anisotropy), relative magnitude
of principal stresses, and fluid mobility
in porous rocks.
Figure 4 shows the 3D anisotropy algorithm’s ability to generate the TI parameters. With reference to a borehole that
is parallel to the X3 axis, shear modulus
or rigidity in the X2-X3 plane and shear
rigidity in the X1-X2 plane enable
quicklook interpretation of formation
anisotropy, stress, and mobility effects.
Figure 5. Mobility measured by the Sonic Scanner tool is shown in Track 4. The red dots indicate mobility
values measured by the MDT* Modular Formation Dynamics Tester, which show good agreement.
Shale
Sand
0
0
6
1.95
Porosity
%
Gamma Ray
gAPI
Caliper
in
Bulk Density
g/cm3
Quality
100 Flag
160
Signal150 to-Noise 300
Ratio
16 30 dB 50 300
Depth
ft
240
2.95
Determining formation mobility
Because there is essentially no continuous
logging measurement of mobility available,
other methods have to be considered.
One method is to measure formation
mobility, which is the ratio of permeability to viscosity.
Mobility, however, is not always available when it is needed because porosity
estimates are often preliminary, wireline
cores require an additional run into the
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
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 extensive laboratory and field testing, enables
highly accurate prediction of the effects
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 permeability 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,
X,X00
X,X20
X,X40
X,X60
DT Compressional
µs/ft
DT Shear
µs/ft
DT Stoneley
µs/ft
DT mud
µs/ft
Bound Water
60
150
200 1
40 1
Mobility Error
Stoneley Mobility
mD/cP
10,000
MDT Mobility
mD/cP
10,000
Oil
Water
Coal
Sonic Scanner Stoneley
0
µs/ft
16,000
Detecting and evaluating open
fractured intervals
Understanding the mechanisms of anisotropy can be important when selecting
the right hydraulic fracture fluid for a
well, especially if there is stress-induced
anisotropy or intrinsic anisotropy related
to the presence of natural fractures. The
Sonic Scanner tool can be used in evaluating the type of anisotropy, in addition
to differentiating between open natural
fractures and drilling-induced fractures.
The fractures shown in the FMI*
Fullbore Formation MicroImager log
in Fig. 7 are near vertical. Upon footby-foot examination, they were originally interpreted to be drilling induced.
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 completion operations.
Figure 6. A mechanical earth model can be constructed and compared with independent measurements
of rock properties and in situ stresses.
Earth Stress Plot
0
2.5 x10
Effective axial stress, psi
2
2,000
True
vertical
depth,
ft
4,000
1.5
1
E - 3.084 x 10 psi
0.5
0
Young’s Modulus
o3 = 3000 psi
Sample 67-S1
Depth: 4912.00 ft
0
0.2
0.4
0.6
6,000
8,000
0.8
1
Axial strain, %
1.2
1.4
1.6
Delta Stability
10
5
Distance (in)
at best, because of fracture alignment,
dipping beds, unbalanced stresses, and
formation damage from drilling.
The Sonic Scanner tool enables a full
3D characterization of the formation by
adding the radial dimension from the
multiple transmitter-receiver spacings,
along with wideband frequency measurements and acquisition of all acoustic
modes propagating in the borehole. From
the expanded set of measurements, dominant formation data can be evaluated
and the appropriate processing techniques can be selected to extract 3D
acoustical properties.
In a tight-gas reservoir, formation
evaluation data and wellbore images
were combined with Sonic Scanner
shear wave anisotropy and Stoneley
wave data shown in Fig. 6. Wellbore
stability simulation was used to ensure
consistency between the mechanical
earth model and the logging and drilling
data. The mechanical earth model was
then applied to optimize subsequent
drilling operations.
10,000
6
8
10
12
14
16
18
20
22
Equivalent mud density, ppg
Pore pressure
σmin Shale
Mud loss
σmin Shale-Wbs
σVertical
σmax Shale
DataFRAC* service
σmax Shale-Wbs
σmin Sand
Kick
σmin Sand-Wbs
σmax Sand
Pressure Xpress*
service
σmax Sand-Wbs
0
-5
-10
-10
-5
0
Distance, in
5
10
FMI log
Figure 7. Stoneley wave measurements enabled determination that the fractures were natural, not
drilling induced.
Washout
0
4
4
4
0
Crossline
Energy
Gamma Ray
Maximum
gAPI
150 Crossline
Energy
Bit Size
100
in
14 0
Caliper 1
Dynamic Image
Slowness
Slowness
Minimum
Crossline
Slowness
Slowness
Horizontal Scale: 1:13.744
Frequency
Frequency
in
14
Energy
Projection
Projection
Analysis
Analysis
Orientation North
Fast-In-Line
Slow-In-Line
Caliper 2
120
240
360
Variable
Variable
in
14 0
100
80 µs/ft 280 80 µs/ft 280
80 µs/ft 280 80 µs/ft 280 0
Resistive
Conductive
Density
Density
Stoneley Fractures
Depth
DT Shear Fast DT Shear Fast
DT Shear Slow DT Shear Slow
ft
in
0.5
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
XX,050
XX,100
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.
Max.
12.07 cm [4.75 in]
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
‡ Basic
toolstring, including isolation joint
toolstring, near monopoles only
www.slb.com/oilfield
05-FE-130
© 2005 Schlumberger
November 2005
*Mark of Schlumberger
Produced by Schlumberger Marketing Communications