Acoustic scanning platform

Sonic Scanner

Adding radius to borehole acoustics For decades, the oil and gas industry has used borehole acoustic measurementsthroughout the lifecycle of wells to evaluaterock properties in the near-wellbore region.As the industry continues to develop newmethods for producing hydrocarbons more efficiently, a focus on well integrityhas become ever more important.

Schlumberger has designed a tool usingthe latest acoustic technology for advancedacoustic acquisition, including cross-dipoleand multispaced-monopole measurements.In addition to axial and azimuthal measure-ments, the tool makes a radial measurementto probe the formation for near-wellboreslowness and far-field slowness. Typicaldepths of investigation equal two to threetimes the borehole diameter.

The new Sonic Scanner* acoustic scan-ning platform provides advanced types ofacoustic measurements, including borehole-compensated monopole with long and shortspacings, cross-dipole, and cement bondquality. These measurements are then con-verted into useful information about thedrilling environment and the reservoir,which assists in making decisions thatreduce overall drilling costs, improverecovery, and maximize productivity. Thefollowing field examples demonstrate thegreater flexibility in acoustic measurementsoffered by the Sonic Scanner tool.

Achieving a better understanding of acoustic propagationTo enable a deeper understanding ofacoustic behavior in and around the bore-hole, the Sonic Scanner tool allows accu-rate radial and axial measurements of thestress-dependent properties of rocks nearthe wellbore. The Sonic Scanner platformprovides multiple depths of investigation,excellent waveform quality, and presenta-tions that reduce the complexity of soniclogging, without compromising the depthof information.

The more comprehensive understandingobtained by using the Sonic Scanner plat-form helps to improve fracture planning,sand control, and perforating design.

Overcoming earlier acoustic measurement barriersRegardless of the formation type, theSonic Scanner platform design overcomesearlier acoustic measurement barriers tosuccessful formation characterization andquantification 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 predictableacoustics.

Earlier technologies attempted to operateclose to the tool’s low-frequency limit, orthey depended on previously acquired formation information to anticipate forma-tion slowness prior to data evaluation.

The wide-frequency spectrum used bythe Sonic Scanner tool allows data captureat high signal-to-noise ratios and extractsmaximum data from the formation. Thisdesign feature also helps ensure that dataare acquired regardless of the formationslowness. The monopole transmitters have

Figure 1. The Sonic Scanner tool provides the bene-fits of axial, azimuthal, and radial information fromboth the monopole and the dipole measurements for near-wellbore and far-field slowness information.

Applications ■ Geophysics

● Improve 3D seismic analysisand 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 perfo-

rating 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 withreal-time quality control

■ Improve reserves estimates

■ Decrease operating time andreduce job costs by eliminat-ing multiple logging runs

■ Reduce uncertainty and operating risk

Features■ Robust measurement of

compressional and shearslownesses

■ Increased logging speed(1,097 m/h [3,600 ft/h])

■ Multiple monopole transmitterand receiver spacing

■ High-fidelity wideband wave-forms and dispersion curves

■ Large receiver array

■ Predictable acoustics

■ Enhanced behind-casingmeasurements with simulta-neous cement bond log (CBL)and Variable Density* cementbond quality measurements

■ Extremely rugged electronicpackage

enhanced low-frequency output over theentire range of sonic frequencies; andthe dipole transmitters are designed forhigh-output power, high-purity acousticwaves, wide bandwidth, and low powerconsumption.

The Sonic Scanner receivers feature alonger azimuthal array than other acoustictools; i.e., 13 stations and 8 azimuthalreceivers at each station. With the twonear-monopole transmitters straddlingthis array and a third transmitter fartheraway, the short- to long-monopole trans-mitter-to-receiver spacing combinationallows the altered zone to be seen andprovides a radial monopole profile.

Seeing beyond the altered zoneThe long-spaced transmitter-to-receiverconcept in earlier acoustic tools wasdesigned for “seeing” past the alteredzone and attempted to provide an unal-tered slowness measurement.

The range of Sonic Scanner transmitter-to-receiver spacings is both short andlong enough to see the altered zone andthus provide a radial monopole profile.These features improve measurementaccuracy of the fluids and the stress-dependent properties of the rocks nearthe wellbore; and that benefits fractureplanning, sand control, and perforatingdesign, as well as shallow-reading-devicepoint selection.

The wide-frequency spectrum from the dipole transmitters used in the SonicScanner platform eliminates the need formultiple logging passes that were commonwith the earlier-generation acoustic tools.New telemetry, optimized with softwareand hardware, enables increased loggingspeeds and decreased operating times.

Obtaining well integrity measurements with high accuracyThe Sonic Scanner tool provides a dis-criminated cement bond log (DCBL) thatcan be obtained simultaneously with thebehind-casing acoustic measurements.The two monopole transmitters positionedat either end of the Sonic Scanner toolallow 3-ft and 5-ft cement bond log (CBL)and cement bond quality measurementsthat are independent of fluid and tempera-ture effects and do not require calibration.

To demonstrate the DCBL measure-ment accuracy, a logging run made with a Sonic Scanner tool is compared withmeasurements from a CBT* CementBond Tool. The DCBL measurements areindicated in blue and the CBT measure-ments are in black. A very good matchis shown between the measurements of the CBT tool and the azimuthallyaveraged Sonic Scanner platform.

The transit time scattering shows ±0.31-ineccentering in the 7-in, 23-lbm/ft casing.The two bond index measurementsshow good agreement, even in the zoneof high eccentralization near the top ofthe interval.

Removing uncertainties about formationgeometry and structure A recurring problem encountered inreservoir modeling and simulation is thelack of available image data having a finescale. Until now, the only available alter-natives have been to work with surfaceseismic data, often too coarse in quality,or near-wellbore imaging and its associ-ated limitations. Coupled with the scaleof seismic measurements, additionaluncertainties arise regarding geometryand structure, formation property varia-tion, and fluid movements.

GammaRay

Depth,ft

gAPI0 150 0 150 0 1 200 1200275 295 200 600 0 50

dB/ft mV

XX,700

XX,800

XX,900

XY,000

XY,100

XY,200

XY,300

XY,400

VariableDensity

VariableDensity

DiscriminatedAttenuation

VariableDensity

DiscriminatedAmplitude

VariableDensity*

BondIndex

TransitTime

Sonic Scanner

Bond index limit

CBT

Sonic Scanner

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).

1

2

3

The inset image in Fig. 3 shows thesurface seismic data with normal, ratherpoor, resolution. In the Sonic Scannerimage of Fig. 3, the solid green line indi-cates the interpreted reservoir top, andthe dashed blue line is the interpretedbottom of the main sand body. The purpleline shows the wellbore path.

The relative horizontal position alongthe bottom scale is 20–600 m from left to right, and the vertical scale (deepreading) is in increments of 5 m, show-ing clearly more than 15 m of excellentresolution compared with the surfaceseismic image.

The Sonic Scanner image measurementsare used to update the geological modeland as input to the reservoir simulatorfor predicting pressure with production.

Obtaining transversely isotropic formation parameters A 3D anisotropy algorithm transforms thecompressional, fast-shear, slow-shear, andStoneley slowness Sonic Scanner meas-urements with respect to the boreholeaxes to anisotropic moduli referenced tothe earth’s anisotropy axes. These modulihelp to classify formation anisotropy intoisotropic, transversely isotropic (TI), ororthorhombic types. The moduli alsoassist in identifying microlayering orthin-bedding-induced TI anisotropy (N < 0 implies microlayering-induced

Trueverticaldepth,

m

XX,000

XX,005

XX,010

XX,015

XX,02020 600

Horizontal position, m

Figure 3. Excellent resolution obtained from the Sonic Scanner tool compared with the surface seismic image.

Thin BedDepthm

XX,800

XY,000

XY,200

XY,400

XY,600

XY,800

Shale

N_TIV@3D_Aniso_Com

GPa–300 300

Borehole Deviationdeg0 90

Fast Shear DTµs/ft440 40

Compressional DT

µs/ft440 40

Stoneley DTµs/ft440 40

Slow Shear DTµs/ft440 40

GPa0 10

GPa0 10

GPa0 10

GPa

GPa0 5

0 5

Shear Rigidity inX2–X3 Transversely

Isotropic Vertical Plane

Shear Rigidity inX1–X2 Transversely

Isotropic Vertical Plane

Shear Rigidity inX2–X3, X1–X2, and

X1–X3 Borehole Plane

Shear Rigidity inX2–X3 Transversely

Borehole Plane

Equivalent ShearRigidity in

Borehole Plane

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.

Top of reservoir

Bottom of main sand body

Wellbore

Interpreted oil/gas contact

Isotropic

High permeability

Drilled well

Planned well

intrinsic anisotropy; N > 0 implies bedding-induced anisotropy), relative magnitudeof principal stresses, and fluid mobility in porous rocks.

Figure 4 shows the 3D anisotropy algo-rithm’s ability to generate the TI param-eters. With reference to a borehole thatis parallel to the X3 axis, shear modulusor rigidity in the X2-X3 plane and shearrigidity in the X1-X2 plane enablequicklook interpretation of formationanisotropy, stress, and mobility effects.

Determining formation mobilityBecause there is essentially no continuouslogging measurement of mobility available,other methods have to be considered.One method is to measure formationmobility, which is the ratio of perme-ability to viscosity.

Mobility, however, is not always avail-able when it is needed because porosityestimates are often preliminary, wirelinecores require an additional run into thewell, and whole cores are expensive.

When the borehole is in reasonablygood condition, Stoneley waves can beused to measure a continuous mobilityprofile in sands and carbonates. Thesedata can serve as an extension of corepermeability over a continuous intervalto save on coring costs, or to get a quickpermeability estimate for selecting theperforating interval.

Minimizing the effects of tool presenceon sensitive Stoneley wave measurementsis extremely important. The design of theSonic Scanner tool, coupled with exten-sive laboratory and field testing, enableshighly accurate prediction of the effectsof the tool on acoustic measurements in all environments.

The example in Fig. 5 demonstrateshow the Sonic Scanner Stoneley wavescan be used to measure a continuousmobility profile and obtain a quick per-meability estimate. Other applications ofStoneley permeability include formationevaluation, production testing strategyand programs, and reservoir modeling.

Evaluating the mechanical properties of formationsAcoustic measurements have typicallybeen acquired in 1D as a function ofdepth, but seldom in 2D simultaneouslyas a function of depth and azimuthaldirection. And interpretation has almostalways been based on the assumptionthat the formations were homogeneousand isotropic—a debatable assumption,

0 100

240 40

300 200

160 60Porosity

gAPI

%

in

g/cm3

Gamma Ray

QualityFlag

X,X20

X,X40

X,X60

Caliper

Signal-to-Noise

Ratio

DepthBulk Density

0 150

30 dB 50

ft

6 16

1.95 2.95

DT Compressionalµs/ft

µs/ft

µs/ft

µs/ft

DT Shear

DT Stoneley

DT mud0 16,000µs/ft

Sonic Scanner Stoneley1 10,000

1 10,000

Sand

Coal

Water

Bound Water

Oil

mD/cP

mD/cP

Stoneley Mobility

Mobility Error

MDT Mobility

Shale

300 150

X,X00

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.

at best, because of fracture alignment,dipping beds, unbalanced stresses, andformation damage from drilling.

The Sonic Scanner tool enables a full3D characterization of the formation byadding the radial dimension from themultiple transmitter-receiver spacings,along with wideband frequency measure-ments and acquisition of all acousticmodes propagating in the borehole. Fromthe expanded set of measurements, dom-inant formation data can be evaluatedand the appropriate processing tech-niques can be selected to extract 3Dacoustical properties.

In a tight-gas reservoir, formation evaluation data and wellbore imageswere combined with Sonic Scannershear wave anisotropy and Stoneleywave data shown in Fig. 6. Wellbore stability simulation was used to ensureconsistency between the mechanicalearth model and the logging and drillingdata. The mechanical earth model wasthen applied to optimize subsequentdrilling operations.

Detecting and evaluating open fractured intervals Understanding the mechanisms of aniso-tropy can be important when selectingthe right hydraulic fracture fluid for awell, especially if there is stress-inducedanisotropy or intrinsic anisotropy relatedto the presence of natural fractures. TheSonic Scanner tool can be used in evalu-ating the type of anisotropy, in additionto differentiating between open naturalfractures and drilling-induced fractures.

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.Stoneley wave measurements from theSonic Scanner tool made it clear that thefractures were open natural fractures and not drilling induced.

The additional sonic data undoubtedlyprevented the operator from making anincorrect interpretation, which wouldhave led to selection of a high-gel fracturefluid that would have destroyed the permeability of the naturally fracturedformation. In this situation, encapsulatedbreakers are much less effective, and aneffective treatment can be designed.

In addition to preventing fluid loss, this information would also be critical in preventing cement loss during com-pletion operations.

Washout CrosslineEnergy

MaximumCrossline

Energy

MinimumCrossline

Energy

Gamma Ray

Bit Size

Caliper 1

Depth

XX,050

XX,100

ft

Caliper 2

Stoneley Fractures

0 gAPI 150

4 in 14

4 in 14

0 100

0 100Fast-In-Line

VariableDensity

Slow-In-LineVariableDensity

0 µs 6,000 0 µs 100 DT Shear Fast DT Shear Fast DT Shear Slow DT Shear Slow 80 µs/ft 280

SlownessProjection

SlownessFrequencyAnalysis

SlownessProjection

SlownessFrequencyAnalysis

80 µs/ft 280

80 µs/ft 280

80 µs/ft 280

80 µs/ft 280

80 µs/ft 280

80 µs/ft 280

Resistive Conductive

FMI Image

Dynamic ImageHorizontal Scale: 1:13.744

Orientation North

80 µs/ft 280 0 120 240 3604 in 14

0 in 0.5

Figure 7. Stoneley wave measurements enabled determination that the fractures were natural, not drilling induced.

Young’s Modulus

Earth Stress Plo

FMI log

t

Pore pressureσmax Shale

σmax Sand

σmax Sand-Wbs

σmin Sand

σmin Sand-Wbsσmax Shale-Wbs

σVertical

σmin Shale-Wbs

σmin ShaleMud loss DataFRAC* service

Kick Pressure Xpress*service

Delta Stability

Effe

ctiv

e ax

ial s

tress

, psi

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6Axial strain, %

6 8 10 12 14 16 18 20 22

Equivalent mud density, ppg

-10 -5 0 5 10

Distance, in

Dist

ance

(in)

x10

o3 = 3000 psiSample 67-S1Depth: 4912.00 ft

2.5

2

1.5

1

0.5

0

0

2,000

4,000True

verticaldepth,

ft 6,000

8,000

10,000

10

5

0

-5

-10

E - 3.084 x 10 psi

Figure 6. A mechanical earth model can be constructed and compared with independent measurements of rock properties and in situ stresses.

05-FE-130 © 2005 Schlumberger

November 2005 *Mark of Schlumberger

Produced by Schlumberger Marketing Communications

www.slb.com/oilfield

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 sizeMin.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 toolstring, including isolation joint‡ Basic toolstring, near monopoles only