40 Oilfield Review

One of the greatest challenges in optimizingdevelopment of a reservoir is placing wellscorrectly. Getting them in the right place,whether vertical or horizontal, not onlydecreases cost but improves recovery. Today,service companies are focusing their efforton developing new technology to help planfield development, optimize well locationand improve drilling safety. Solutions to theproblem require integrating many types ofdata. At the forefront are measurements thattake advantage of evolving technology insonic logging.

During the last decade important advanceshave been made in sonic logging.1 Usingdipole sources that can excite flexuralwaves—shear-like vibrations of the bore-hole—these tools are capable of measuringsonic compressional and shear-wave slow-ness data in hard and soft formations.2 Shear-wave anisotropy measurements are sensitiveto stress and fracture density and directions.3

This is vital information for those who wantto optimize production by drilling a bore-hole aimed at encountering as many frac-tures as possible.

Sonic logging is becoming a routine way toplan well placement strategies—leading toimprovements in reservoir production.Mechanical rock properties from sonic mea-surements can help predict formationstrength and potential sanding problems. Inboth vertical and horizontal wells, this infor-mation allows prediction of the best direc-tion to perforate for maximum production.Stress magnitude derived from sonic logginghelps forecast maximum sand-free draw-down pressures.

Logging-while-drilling (LWD) sonic toolshave been improving, too. Since the firstLWD sonic tool designed to provide com-pressional-slowness measurements whiledrilling was reported in 1994, many success-ful real-time and memory logs have beenrecorded in hard and soft rocks.4 These real-time LWD sonic measurements bring freshinformation, obtained soon after the drill bitpenetrates the formation. This information isvital to the driller, helping to avoid costly mis-takes such as drilling into overpressuredzones without proper mud-weight adjust-ments. In addition, experience is showingthat the formations around the wellborechange when exposed to drilling fluids. LWDsonic logs from freshly drilled boreholescompared with wireline measurements—usually taken days after the drilling hasexposed the formation—show remarkabledifferences. Both bring important, but differ-ent, information about wellbore properties.

New Directions in Sonic Logging

For help in preparation of this article, thanks to Michael Kane and Christopher Kimball, Schlumberger-Doll Research, Ridgefield, Connecticut, USA; PhilippeLaurent and Julian Singer, Schlumberger Wireline &Testing, Caracas, Venezuela; Frank Morris and RobertYoung, Schlumberger Wireline & Testing, Sugar Land,Texas, USA.CDR (Compensated Dual Resistivity), CMR (Com-binable Magnetic Resonance), DSI (Dipole Shear Sonic Imager), ELAN (Elemental Log Analysis), EPT(Electromagnetic Propagation Tool), FMI (FullboreFormation MicroImager), GeoFrame, ISONIC (IDEALsonic-while-drilling), LSS (Long-Spaced Sonic Tool),PowerPak, PowerPulse and UBI (Ultrasonic BoreholeImager) are marks of Schlumberger.

Alain BrieTakeshi EndoDavid HoyleFuchinobe, Japan

Daniel CodazziCengiz EsmersoyKai Hsu Sugar Land, Texas, USA

Stan DenooEnglewood, Colorado, USA

Reaching the reservoir, and doing so safely, is made easier by recent

advances in shear-wave logs. Anisotropy measurements spotlight

more efficient ways to drill and stimulate formations and real-time

sonic-while-drilling alerts drillers to overpressured zones. These and

other developments are helping solve tough production problems.

Michael C. MuellerAmoco Exploration and ProductionHouston, Texas

Tom PlonaRam Shenoy Bikash SinhaRidgefield, Connecticut, USA

1. Esmersoy C, Koster K, Williams M, Boyd A and KaneM: “Dipole Shear Anisotropy Logging,” ExpandedAbstracts, 64th SEG Annual International Meeting andExposition, Los Angeles, California, USA, October 23-28, 1994, paper SL3.7.“Shear Wave Logging with Dipoles,” Oilfield Review2, no. 4 (October 1990): 9-12.

2. In the language of sonic logging, slowness—thereciprocal of velocity—is most commonly used. It isidentical to the interval transit time, which is a basicmeasurement made by sonic logging tools.

3. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C, Miller D, Hornby B, Sayers C,Schoenberg M, Leaney S and Lynn H: "The Promise of Elastic Anisotropy,” Oilfield Review 6, no. 4(October 1994): 36-47.

4. Aron J, Chang SK, Dworak R, Hsu K, Lau T, Masson J-P, Mayes J, McDaniel G, Randall C, Kostek S andPlona T: “Sonic Compressional Measurements WhileDrilling,” Transactions of the SPWLA 35th AnnualLogging Symposium, Tulsa, Oklahoma, USA, June 19-23, 1994, paper SS.

Spring 1998 41

CAUTION

Fractures

Minimumstress

Maximumstress

Perforations

Overp

ressure

With the introduction of dipole sonic logs,the petrophysical community has the ability torecord high-quality shear and compressionalslownesses in a variety of formations, and forthe first time in slow formations. These mea-surements are helping to solve some of themysteries in formation interpretation.

In this article we look at how sonic shear-wave anisotropy measurements are used tofind fractures and their orientation, under-stand stress directions in formations andpredict the best directions for perforating or drilling stable vertical and horizontalwellbores that yield optimum flow rates. Wediscuss how real-time sonic LWD measure-ments are being used, first as a means toavoid costly drilling mistakes, and then as aneffective way of determining unaltered for-mation properties and pay zones in hard andsoft formations. Both formation types presentspecial problems for LWD measurements.Finally, we will see how petrophysicists areinterpreting sonic logs in gas-saturated shalysands—one of the most difficult environ-ments for sonic logging.

42 Oilfield Review

Using Shear-Wave Anisotropy to Improve ProductionTo produce hydrocarbons efficiently, reser-voir engineers need to know tectonic andwellbore stresses and their direction. Theseproperties first affect wellbore stability(breakouts), and then the ability to hydrofrac-ture the well. Permeability impairment andsanding problems can be influenced bystress. The presence of a borehole will influ-ence the state of stress of the rock and theformation strength around the borehole (left).

Sonic measurements, such as those fromthe UBI Ultrasonic Borehole Imager tool forbreakout measurements and the DSI DipoleShear Sonic Imager tool for shear-waveanisotropy, provide a foundation for under-standing formation geomechanics. Stressdirections can be determined by measuringthe locations of wellbore breakouts (below).Shear-wave anisotropy is a more robustmethod for determining stress directionsbecause the measurement is in the rock anddoes not rely on formation wall failure—washout—which may not always be presentin the well (see “Dipole Shear-WaveAnisotropy Analysis,” page 44).

Natural and induced fracture orientationsare also important considerations for reser-voir management. Since hydraulic fracturesopen in a plane perpendicular to the mini-mum stress, determining stress direction iscrucial. Consider the case of reservoirdrainage from a hydraulically fractured well

in a low-permeability formation. Since thedrainage pattern is elliptical, optimumreservoir drainage depends on the correctplacement of multiple wells (next page, topleft).5 Stress direction is especially importantwhen fracturing from horizontal wells inwhich control of the fracture orientationwith respect to the wellbore is important(next page, top right). Since shear-waveanisotropy measurements are sensitive tofracture orientation, they provide usefuldirections for drilling a horizontal sectionaimed at encountering as many naturalfractures as possible.

Even in soft unconsolidated formations,where sonic measurements are difficult,shear-wave anisotropy measurements are rec-ommended reservoir engineering practicesfor planning fracture treatments.6 Whileenhancing productivity through fracture stim-ulation is the primary goal, fracturing is alsoused as a means of implementing effectivesand control in unconsolidated formations. Ithas been shown that unprotected(unpropped) perforations are a major causeof sand production.7 Once stress direction isdetermined, 180° phased oriented perfora-tions can be used to optimize the fracturetreatment, as well as minimize the number ofunpropped perforations that cause sandingproblems (next page, bottom). In addition,the use of 180° phased perforations alignednormal to the minimum stress direction helpsminimize wellbore tortuosity after fracturing.

Bor

ehol

e ra

dii

Borehole radii

Smin

Smax

Drillingfractures

Damage

Breakouts

-5

-3

-1

1

3

5

1 3 5-3 -1

■■Mechanical state of rock and failuremechanisms. The annulus around thewellbore may be damaged by drillingand tectonic stresses on the openhole.Damage in the form of breakouts orwashouts usually first appears in thedirection of minimum stress (Smin), anddrilling-induced fractures occur with theirstrike direction along the direction ofmaximum stress (Smax).

4

2

2

0

0Borehole radius, in.

Images versus depth

-2

-2-4

4

-4

Breakout

Breakout

Depth X66.7m

Hole deviation 37.7 degrees

Breakout 138.0 degrees N111/2 degrees top0.8 in.

X066

X067

X068

Top N

■■Breakouts from the UBI tool. The UBI Ultrasonic Borehole Imager tool uses a pulse-echoreflection measurement that provides high-resolution images (left) of borehole size andshape. The radius plot (right) shows breakouts (red arrows). Breakouts, caused by theborehole being in compression failure, have been observed worldwide to cause ovaliza-tion of the borehole with the oval’s long axis parallel to the minimum stress.

5. Fletcher PA, Montgomery CT, Ramo GG, Miller MEand Rich DA: “Using Fracturing as a Technique forControlling Formation Failure,” paper SPE 27899, presented at the 64th SPE Annual Western RegionalMeeting, Long Beach, California, USA, March 23-25, 1994.

6. Upchurch ER, Montgomery CT, Berman BH and Rael EL: “A Systematic Approach to DevelopingEngineering Data for Fracturing Poorly ConsolidatedFormations,” paper SPE 38588, presented at the 1997 SPE Annual Technical Conference and Exhibition,San Antonio, Texas, USA, October 5-8, 1997.

7. Fletcher et al, reference 5.(continued on page 46)

Smin

Smin

Spring 1998 43

Fracture

Effectiveperforations

Smin

Ineffectiveperforations

Unstableperforations

Stableperforations

Smax

■■Oriented perforations for sand control. In sand control, the 180° phased perforations ensurethat all the perforations connect to the fracture and are propped. This procedure eliminates theunconnected perforations that produce sand during drawdown. The use of 180° phased perfo-rations, oriented perpendicular to the minimum stress (Smin), is helpful in fracturing becausethese perforations minimize breakout that causes borehole tortuosity.

Good Areal Sweep Poor Areal Sweep

Good Drainage Incomplete Drainage

Injectorwells

Producerwells

Smin

SminSmin

Smin

■■Fracture azimuth and geometry determination. Incomplete reservoirdrainage can occur if fracture orientation is ignored when well spac-ing and placement are designed (top). An understanding of fractureorientation can be useful in determining optimum well location forwaterflooding, and enhanced oil recovery (EOR) applications (bottom).[Adapted from Lacey LL and Smith MB: “Fracture Azimuth and Geom-etry Determination,” in Recent Advances in Hydraulic Fracturing, SPEMonograph No. 12. Henry L. Doherty Monograph Series. Richardson,Texas, USA: Society of Petroleum Engineers (1989): 341-354.]

■■Fracturing horizontal wells. Wells drilled along the line ofminimum horizontal stress will fracture in planes perpen-dicular to the wellbore. Wells drilled in the direction nor-mal to the minimum stress (Smin) will fracture along thewellbore. Fracture placement can influence the draw-down along extended horizontal sections. Knowing stressdirections and magnitude from formation mechanicalproperties helps orient perforations to contain fractures inthe desired directions.

44 Oilfield Review

For sonic measurements, it is well recognized that

sedimentary rocks generally exhibit some degree

of anisotropy.1 Anisotropy may arise from intrinsic

structural effects, such as aligned fractures and

layering of thin zones, or from unequal stresses

within the formation. These effects lead to differ-

ences in formation elastic properties, and if they

are on a smaller scale than the sonic wave-

lengths, then sonic wave propagation can be used

to detect and quantify the anisotropy.

Sonic waves travel fastest when the direction of

particle motion—polarization—is aligned with the

material’s stiffest direction. Shear-wave particle

motion is in a plane perpendicular to the wave

propagation direction. If the formation is

anisotropic in this plane, meaning that there is

one direction that is stiffer than another, then the

shear-wave polarization aligned in the stiff direc-

tion will travel faster than one aligned in the

other, more compliant direction. As a result, the

shear wave splits into two components, one polar-

ized along the formation’s stiff (or fast) direction,

and the other polarized along the formation’s com-

pliant (or slow) direction.2

For example, in the case of vertically-aligned

dense microcracks or fractures, a shear wave that

is polarized parallel to the fracture strike will prop-

agate faster than a shear wave polarized perpen-

dicular to it (above right). In general, a shear (or

flexural) wave, generated by a dipole source, will

split into two orthogonal components polarized

along the X- and Y-directions in the formation. As

they propagate along the borehole, the fast wave

will be polarized along the direction parallel to the

fracture strike and a slow wave in the direction

perpendicular to it.

With two orthogonal dipole transmitters and

multiple receiver pairs aligned in orthogonal

directions, the DSI Dipole Shear Sonic Imager tool

can measure the components of shear slowness in

any direction in a plane perpendicular to the bore-

hole axis (next page). The measurement involves

recording the waveforms on receivers pointing in

directions parallel and normal to each transmitter

along the tool x- and y-axes.3

Four sets of waveforms are recorded at each

depth and receiver level. These measurements

are labeled xx, xy, yx and yy. The first direction

refers to the transmitter and the second direction

to the receiver. The direction and speed of the fast

and slow split shear waveforms traveling in the

formation can be easily determined by mathemati-

cally rotating the measured waveforms through an

azimuthal angle so that they line up with the two

orthogonal formation X- and Y-directions.

This is done by minimizing the cross-receiver

energies, xy and yx. The rotated direction of the

fastest shear wave becomes the fast-shear tool

azimuth; and the tool orientation, measured by a

magnetometer, is used to determine the fast shear

azimuth relative to true north. This rotation, called

the Alford method, uses the fact that the

anisotropy model expects the amplitude of the

cross-receiver measurements to vanish when the

measured axes x and y align with the anisotropy

axes X and Y.4

In addition to the fast and slow shear-wave

velocities—determined by a slowness-time-

coherence (STC) processing on the rotated wave-

forms—three measurements of anisotropy are

computed.5 These are energy anisotropy, slow-

ness anisotropy and time anisotropy.

Dipole Shear-Wave Anisotropy Analysis

Slow shear

Formationslow axis

Fractures

Fast shear

Formationfast axis

Y

X

Z

■■Shear-wave splitting. Shear waves travel in ananisotropic formation withdifferent speeds along thedirections of the formationanisotropy. In this example,anisotropy is caused by thevertical fractures (or micro-cracks) with a strike directionalong the formation Y-axis,and the fastest shear wave—with the longer wavelength component—will be polarized along thefracture strike direction as itpropagates along the bore-hole (Z-axis). When shear-wave splitting is the result ofstress anisotropy, the Y-axiscorresponds to the directionof maximum stress, and theX-axis corresponds to thedirection of minimum stress.

Spring 1998 45

Slowness anisotropy is the difference between

the fast and slow slownesses calculated by

STC on the rotated waveforms. It yields a quanti-

tative measure of slowness anisotropy, and has

the best vertical resolution at about 3 ft [1 m]—

the size of the receiver array. It can be compared

directly with seismic or core measurements of

slowness anisotropy.

Traveltime anisotropy is the arrival-time differ-

ence between the fast- and slow-shear waves at

the receivers. It is obtained from a cross-correla-

tion between fast and slow shear-wave arrivals at

each receiver spacing. Time lags computed at

each receiver are referenced to the largest offset

receiver and averaged across the receiver array.

This is divided by the average of the fast and slow

arrival times to compute a percentage difference.

The traveltime anisotropy indicator is robust and

quantitative, and has the vertical resolution of the

average transmitter-receiver spacing, 13 ft [4 m].

Slowness and traveltime anisotropy indicators are

identical in formations with homogeneous beds

thicker than 13 ft.

Energy anisotropy is the energy in the cross-

component waveforms as a percentage of energy

in all four components. In an isotropic formation,

energy anisotropy reads zero. In an anisotropic

formation, the reading depends on the degree of

anisotropy. Two curves are computed from the

waveforms: minimum and maximum cross-energy.

The minimum cross-energy is the energy in the

cross-components when the tool measurement

axis lines up with the formation anisotropy axis.

Minimum cross-energy reads zero in an ideal for-

mation whether anisotropic or not. This curve is a

good relative measure of whether the assumed

model for anisotropy inversion fits the real forma-

tion. The maximum cross-energy is a measure of

the amount or strength of anisotropy. Unlike the

two previous anisotropy measurements (slowness

and time), energy anisotropy is a measure of both

slowness and amplitude differences of the fast-

and slow-shear waves. Large differences between

the maximum and minimum values, especially

when the minimum energy is low, indicate zones of

significant anisotropy. Energy anisotropy, though

qualitative, is little affected by processing, and is

the principal measure of anisotropy.

X

x Yy

θ

Dipoletransmitterpair

Boreholeflexural wave(exaggerated)

Tx

Receiverarray

R1yR1x

Receiver-1 pair

R2yR2x Receiver-2 pair

R3yR3x

R4yR4x

R5yR5x

Receiver-3 pair

Receiver-4 pair

Receiver-5 pair

R6yR6x

R8y

R7yR7x

R8x

Receiver-6 pair

Receiver-7 pair

Receiver-8 pair

Tool axisTool orientation relative to formation

Formation fastshear wave axis

Undisturbedborehole

Ty

■■Flexural waves induced bydipole transmitters. During log-ging, flexural waves are inducedby dipole transmitters firedsequentially in two perpendiculardirections, first along the tool x-and then the tool y-axes. In thisexample, the fastest componentof the induced shear wave ispolarized along the formation Y-axis direction, which is alignedalong the fracture strike or maxi-mum stress direction. The slow-est component of the shear waveis polarized along the formationX-axis. Projections of these twoshear-wave components arereceived by each of the dipolesonic tool x- and y-receiver pairs.The inline signals xx and yy arethe x-receiver and y-receiverwaveforms received when the x-and y- transmitters are fired.Cross-signal components xy andyx are the y- and x-receiverwaveforms received as the x- andy-transmitters are fired. TheAlford rotation angle, θ, is deter-mined by minimizing the cross-signal components. This wouldhappen automatically if the toolaxes were rotated through anangle, θ, and aligned with the twoorthogonal directions in theanisotropic formation.

1. Armstrong et al, reference 3, main text.2. For compressional waves, the particle motion is the same

direction as the wave propagation.3. Esmersoy et al, reference 10, main text.4. Alford RM: "Shear Data in the Presence of Azimuthal

Anisotropy: Dilley, Texas," Expanded Abstracts, 56th SEGAnnual International Meeting and Exposition, Houston,Texas, USA, November 2-6, 1986, paper S9.6.

5. Kimball and Marzetta, reference 8, main text.

46 Oilfield Review

8. Kimball CV and Marzetta TL: “SemblanceProcessing of Borehole Acoustic Array Data,”Geophysics 40 (March 1984): 274-281.

9. Sinha B and Kostek S: “Stress-Induced AzimuthalAnisotropy in Borehole Flexural Waves,” Geophysics61 (November-December 1996): 1899-1907.

10. Esmersoy C, Kane M, Boyd A and Denoo S:“Fracture and Stress Evaluation Using Dipole-ShearAnisotropy Logs,” Transactions of the SPWLA 36th Annual Logging Symposium, Paris, France, June 26-29, 1995, paper J.

0 20

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% Shear waveforms

Processing window

1000 5000Slowness anisotropy

Slow-wave slowness

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Fast-wave slowness250 50

Fast shear wave azimuth-90 0 +90

deg

5 20in.

0 150API

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Gamma ray0 100

%

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µs

12,800

■■Anisotropy evaluation. The difference between the minimum and maximumcross-component shear energy, shown in the depth track, is an indicator ofanisotropy. The tool orientation (blue), track 2, is used to determine the absolutefast-shear azimuthal direction (red), with its uncertainty (gray shading), track 3.The interval between 12,750 and 12,870 ft [3886 and 3923 m] contains severalanisotropic zones. The average of the fast component of the shear-wave direc-tion, shown in the azimuthal projection (inset, right), is between 20° and 30°. Acoustic time anisotropy (black with shaded gray) is shown in track 4. Thismeasurement is more sensitive to acoustic properties deep within the formationthan surface effects such as drilling-induced fractures. Both fast (blue dashed)and slow (red) components of the shear slowness are computed by STC process-ing and are shown in track 4. For visual quality control, the fast (red) and slow(blue) waveforms from the largest spacing receiver are shown in track 5. Thelight yellow band shows the shear-wave processing window, which shouldinclude the first few cycles of the shear arrival. Both moveout and energy differ-ences between the fast and slow shear waves are easily visualized and can beverified on the display. Both waves would be identical in an isotropic formation.

Aiming for Minimum StressSonic velocity anisotropy was used bySeneca Oil Company in the USA to deter-mine the most productive position and direc-tion for a horizontal well. A pilot hole forhorizontal drilling was drilled through amoderate-porosity—10 to 15 p.u.—shalysand interval. The operator’s objective was todetermine natural fracture orientation andunderstand tectonic stress direction (left andbelow). DSI logs were recorded for Stoneley,monopole P- and S-wave and both crossedreceivers (BCR) dipole modes. The BCR modewas processed for anisotropy. Three differentcomputations of shear-wave anisotropy arepresented, dealing with the time and energyof the dipole shear waveform.

First, shear-wave energy anisotropy—theminimum and maximum cross-componentenergy difference—is the most obvious indi-cation of anisotropy. Large energy differ-ences, when the minimum stays low,indicate significant shear-wave splitting andsignal zones of interest. The interval from12,750 to 12,870 ft contains several zoneswith significant anisotropy.

Spring 1998 47

Second, large shear-wave traveltimeanisotropy indications—based on arrivaltime of the fast and slow waves—correlatewell with the energy-anisotropy indicationsthroughout the interval.

The third anisotropy measurement, slow-ness anisotropy, is derived from the com-puted shear-wave, fast- and slow-componentslownesses—using slowness-time-coherence(STC) processing to obtain slowness.8 Thisdeep-reading measurement suggests that theanisotropic properties are from within thereservoir and not from surface effects such asshallow drilling-induced fractures.9

The fast shear-azimuth direction for thisinterval is between 20° and 30° with respectto north. This azimuth, aligned with the max-imum horizontal stress direction, is thedirection of the current tectonic stress fieldand is the orientation of any drilling-inducedfractures. This is also the direction that wouldproduce the least stable horizontal borehole,and be least likely to intersect open fractures.

The oriented four-arm caliper summationdata over this zone give a qualitative overallview of the borehole profile (above left).Hole breakout is found in two opposingquadrants, which straddle the axis of maxi-mum horizontal stress. Perpendicular to thebreakout direction, the maximum horizontalstress direction is found to be 25°, whichagrees with the direction found by the fastshear-wave azimuth.

The operator sidetracked the horizontal legof this well at right angles to the maximumhorizontal stress, along the direction inter-secting the largest number of natural frac-tures—for maximum production.

In another application, shear-wave aniso-tropy was used by Louisiana Land & Explor-ation Company in southwest Wyoming, USAto find fractures in a cased well drilled in atight gas-bearing sandstone. Openhole logswere not run because of poor wellbore con-ditions.10 However, shear-wave anisotropy

logging was used to find the fractured inter-vals behind casing (above). The fracturedzones are easily identified from the DSI dif-ferential-energy curves shown in the depthtrack. Here the maximum in the energy dif-ference between the fast and slow shearwaves quickly identifies three zones in which large shear-wave velocity aniso-tropy exists—because of the fractures. Thesezones were perforated, and subsequent pro-duction logs show good gas entry from eachzone. This well subsequently produced 4.5 MMcf/D of gas from these perforations.

-8-8

-6

-6

-4

-4

-2

-2

0

0

2

2

4

4

6

6

8

8

in.

SmaxBreakout

in.

■■Four-arm caliper projections as qualitativeindicators of stress direction. The zone con-taining significant anisotropy seen by theDSI tool also shows hole breakouts—shownby enlarged hole size measured by the four-arm caliper—in this vertical borehole. Thebreakouts occur in the direction of mini-mum horizontal stress. Perpendicular to thebreakout direction is the principal tectonicstress direction of 25°. Bit size is shown bythe green circle, and the borehole walls arecompressed inward slightly along the max-imum stress direction. The data inside thebit size represent the calipers opening up as they come off bottom.

Depth, ft Gamma ray Fast shear-wave azmuth

Fractures

7700

7600

Shear waveforms

Fractures

Fractures

Offlineenergy

API

0

0 150 0° 180°Fast shear-wave slowness Processing window

0 µs/ft µs50 1000 6000

1.0

Energyanisotropy

■■Shear-wave splitting in cased hole. The DSI tool differential-energy measurements,shown in the depth track, identify the zones with high shear-wave anisotropy caused byfractures. The difference in the two shear-wave amplitude components (track 5) increasesin the fractured zones.

48 Oilfield Review

Measuring Stress with AnisotropyOne major challenge is to distinguishbetween stress-induced and other sources ofshear anisotropy, such as fractures. Currently,this distinction is difficult to make from sonicmeasurements alone, and remains a topic ofongoing research. Recently, it has beenfound that borehole stress concentrationscause a crossover in the two flexural disper-sion curves (right).11 This crossover is causedby stress-induced radial gradients in theacoustic-wave velocities that are different inthe two principal stress directions.

Other sources of intrinsic anisotropy—caused by finely layered dipping beds,aligned fractures or microstructure found inclays—exhibit neither radial velocity gradi-ents nor flexural dispersion crossover.Consequently, a crossover in the flexuraldispersion curves can be used as an indica-tor of stress-induced anisotropy. In the pres-ence of stress-induced anisotropy, thefast-shear direction coincides with the max-imum stress direction, and the magnitude ofthe shear anisotropy is proportional to thestress magnitude.12

Finding Faults with AnisotropyIn fracture systems, faults are major eventsthat impact not only fracture distribution, butalso the rock stresses. Significant rock defor-mation, fracturing and variations of the stressfields are found near faults (below right).

An example of fault-induced fractures isseen in an Egyptian oil-producing welldrilled in granite basement rock.13 Traditionalsonic techniques, such as Stoneley waveattenuation and reflection were combinedwith anisotropy using shear-wave splitting toevaluate fractures near a fault in this hardrock formation. These techniques react in dif-ferent ways to the presence of fractures in theformations, and their combined analysisreveals the complex picture of this forma-tion. The direction of the fast shear wave pro-vides information on fracture orientation, butthe shear-wave azimuthal measurements dif-fer somewhat from that of traditionalStoneley fracture analysis; in particularshear-wave anisotropy investigates a volumeof formation up to several borehole diame-ters farther from the borehole and can sensefractures missed by other techniques.14

Combining measurements provides addi-tional information about reservoir character-istics, and is especially helpful in locatingthe fault.

0 10 20 30 40 50 60

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1.2

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1.6

1.8

Frequency, kHz

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ocity

, km

/s

0 10 20 30 40 50 60

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Frequency, kHz

Vel

ocity

, km

/s

Fast shear wave

Unstressed

Stressed5 MPa

Slow shear wave

Polarized parallel to stress

Polarizedperpendicularto stress

■■Dipole dispersion crossover. Laboratory experimental (circles) and theoretical (solidcurves) flexural dispersion curves in Berea sandstone. The plots show the shear-waveanisotropy velocities measured without stress (top), and with 5 MPa [725 psi] uniaxialstress (bottom). The effects of stress on shear-wave anisotropy depend on signal fre-quency and stress magnitude. As stress increases, the shear-wave component polarizedparallel to the stress direction becomes the fastest component at low frequencies. Thereverse is true at high frequencies.

���������������������������������

Compressionalstresses

Extensionalstresses

Prefaulting extensionalfractures

Fault

■■Faults as a major disruption in stress and fracture orientation. A fault can cause a dragzone in which rock deformation is large. Bending of the beds next to the fault causesextensional stresses with fractures on one side of the bed, and compressional stresseswith conjugate shear fractures on the other side (inset). Measured stress directions willchange rapidly when a well crosses the fault.

Spring 1998 49

The trick is to identify and locate the frac-ture system associated with the fault zone.Many wells in the same field did not inter-cept the fault zone and as a result neverreached commercial production levels.

DSI logging, using monopole P-, S-wave,Stoneley and BCR modes, was combinedwith conventional openhole porosity loggingand FMI Fullbore Formation MicroImagermeasurements to locate productive fracturesand their orientations. The FMI fracture ori-entation data (not shown) agree with theresults from the fast shear-wave azimuth inthe upper zones of the well and suggest amajor tectonic stress in the area oriented in aNW (320°) direction (above).

The shear-wave anisotropy analysis showsthe fast shear azimuth changing graduallyfrom 320° to 340° below X325 ft. There issubstantial shear-wave splitting at X300 ftindicated by the energy, slowness and timedifferences. However, there are no indica-tions of major fractures at this depth from thetraditional Stoneley analysis (not shown). TheFMI images confirm the anisotropy indica-tions, showing primarily closed fractureswith their strike oriented at 315°.

Major fracture events were recordedbetween X380 and X460 ft with Stoneleyfracture analysis, and Stoneley permeabilityindicators were strong down to X490 ft.Porosity is 15 p.u. from X350 to X460 ft andsignificantly less above and below this zone.Shear-wave splitting shows an abrupt rota-tion of the fast shear azimuth from 315°above X400 ft to 20° below and then back to0° in the lowest part of this interval. It isworth observing that at X400 ft, where theazimuth change is taking place, there is nosignificant evidence of anisotropy. However,shear-wave anisotropy is present above andbelow this depth.

All evidence indicates that the well crossedthe fault at X400 ft. The events detected asfractures in the Stoneley analysis are likely tobe fractures caused by the fault or the faultitself. Faults are common in granite, andthough faults were identified in a higher sec-tion of this well using a vertical seismic pro-file, VSP measurements were not available inthis interval. However, in shear-waveanisotropy logging, the fault signature isclear—the fast shear azimuth starts changingslowly 70 ft [21 m] above the fault, thenquickly changes by nearly 65° across thefault and returns to an intermediate value100 ft [30 m] below the fault until it finallyreturns to the regional trend.

Faults typically have large effects on theproducibility and stability of a reservoir andmust be accounted for when completing awell. The fault seen in this example exhibitshigh permeability and is expected to have agood production potential. The fast shear-wave anisotropy indicates the presence offractures or stress, and the directional varia-tion of the fast shear azimuth can be used todetect faults and their associated high-permeability, fractured zones.

11. Winkler KW, Sinha BK and Plona TJ: “Effects ofBorehole Stress Concentrations on DipoleAnisotropy Measurements,” Geophysics 63, no. 1(January-February 1998): 11-17.

12. Sinha BK, Papanastasiou P and Plona TJ: “Influence of Triaxial Stresses on Borehole Stoneleyand Flexural Dispersions,” Expanded Abstracts,67th SEG Annual International Meeting andExposition, Dallas, Texas, USA, November 2-7,1997, paper BH2.2.

13. Endo T, Ito H, Brie A, Badri M and El Sheikh M:“Fracture and Permeability Evaluation in a Fault Zonefrom Sonic Waveform Data,” Transactions of theSPWLA 38th Annual Logging Symposium, Houston,Texas, USA, June 15-18, 1997, paper R.

14. Sinha and Kostek, reference 9.

Energyanisotropy

X300

Depth, ft

X400

X500

100

Fast shear azimuth 0°

Fault signature

Shear waveforms

Anisotropy

Slowness, %

Time, %

Shear slowness

µs/ft

Gamma rayAPI

Caliper

in.

Tool azimuthdeg 0° 360° 270° +90° 450 50 1000 µs 7000

0

100 00 300

6 16

Caliper

Maximumenergy

Minimumenergy

Gammaray

Toolazimuth

Slowshear

Slownessanisotropy

Processing window

Fastshear

Error bar

TimeanisotropyFa

ult

■■Fault found with anisotropy evaluation. Fast shear azimuth (track 3) shows major rota-tion of the fast shear azimuth from 315° to 20° across a relatively short depth interval cen-tered at X400 ft, the fault location. Anisotropy indicators (track 4) are large below thefault, indicating small cracks in the rocks, probably caused by high stress in this region.Waveforms and the processing time window used to determine shear-slowness velocitiesare shown in track 5.

50 Oilfield Review

Early Warning While DrillingReal-time LWD sonic data in formationswhere pressures are either unknown orknown to vary rapidly can be critical.Knowledge of expected overpressured forma-tions provides the ability to efficiently andsafely drill wells with correct mud weights.15

For example, after there were kicks attributedto overpressured formations in two offsetwells nearby, real-time LWD overpressuredetection capability was tried in an explora-tory well drilled offshore Angola, West Africa.The 133⁄8-in. casing was set down to X905 ftand drilled out using a 121⁄4-in. bit with thesonic-while-drilling tool in the bottomholeassembly (BHA).

A long single-bit run was conducted over a7-day period that covered a depth fromX1000 to X8300 ft (below). The wellbore wasdeviated 20° in this interval. The BHA con-sisted of a PowerPak mud motor, CDRCompensated Dual Resistivity tool,PowerPulse MWD telemetry system—for real-time transmission—and an ISONIC sonic-

while-drilling tool. The ISONIC tool, placedabove the PowerPulse system, was approxi-mately 104 ft [32 m] away from the bit. At theaverage rate of drilling, the LWD measure-ments were made fewer than four hours afterthe formation was first cut. Wireline sonic log-ging was run after the 7-day drilling run wascompleted, and then only after circulating thewell for several hours.

The gamma ray log indicated that the entireinterval is primarily shale, with sand-shalesequences dominating the bottom 2000 ft[610 m] of the formation. A trend of decreas-ing slowness with increasing depth isobserved in the upper interval from X1000 toX4800 ft. This trend is normal and caused bythe overburden stress, which compresses therock and decreases the porosity with depth.As long as slowness readings follow thistrend, formation porosities are maintaining anormal compaction with depth. If overpres-sured formations are encountered, the slow-ness data points will diverge from theexpected trend toward abnormally high val-ues (above right).

This is what happens at about X4800 ft. Thereal-time LWD slowness diverges from thecompaction trend, indicating the approach ofpotential overpressured formations. Similarly,the CDR resistivity log shows a departurefrom its normal trend of increasing resistivitywith depth toward lower than normal resis-tivity values, because of increasing porosityin the overpressured formations and resultinghigher saline-water content in shale. Thisinterval, showing logging values divergingfrom their usual trends, extends down toabout X4850 ft. For the two wells previouslyshowing kicks, the tops of overpressured for-mations were found at X5000 ft—200 ft [60 m] below the first sign of overpressureencountered in this well. The LWD real-timesonic logs provided warning that the drillerwas entering an overpressured formation—hours ahead of expectations.

Another example shows the use of real-time LWD sonic logging in soft formationsto locate a gas-sand pay zone. This verticalwell was drilled by an operator in the Gulfof Mexico. The ISONIC tool was mountedin a BHA 77 ft [23 m] behind the bit, andat the average rate of penetration, the for-mation was logged less than an hour afterthe bit cut through it. The slowness projec-tions on the LWD memory semblance

Depth, ft

X2000

X3000

X4000

X5000

X6000

Gamma rayAttenuation resistivity

Phase shift resistivityAPI0 150

Wireline slowness

µs/ft150 50

ISONIC slowness

µs/ft150 50

ohm-m0.2 20

ohm-m0.2 20

Wireline slowness

ISONIC slownessµs/ft150 50

µs/ft150 50

X7000

X8000

B

A

Compactiontrend

■■Detecting overpressure while drilling. The log display shows a gamma ray, CDR phaseand attenuation resistivity and the LWD and wireline sonic slowness log comparisons in along 7000-ft [2134-m] bit run. The gamma ray log (track 1) indicates that the entire inter-val is primarily shale. The wireline and LWD slowness logs are shown in tracks 3 and 4,respectively, and are shown overlaid in track 5. Real-time LWD sonic readings detectedan overpressured zone 5 hours ahead of expectations, Zone A. There is a consistent differ-ence of up to 10 µs/ft [33 µs/m] between the ISONIC reading and wireline slownesses inZone B attributed to formation alteration near the borehole.

Increasing slowness

Incr

easi

ng d

epth

Enteringoverpressured

zone

Normalpressure

zone

Normalcompaction

trend

■■Real-time overpressure alert. Formationcompaction, resulting from increasingoverburden weight, causes porosity andthus acoustic slowness to decrease withdepth. High deviation from the naturaltrend is a sign of an overpressured zone.Real-time LWD acoustic slowness measure-ment can warn a driller of entry into anoverpressured zone, early enough to allowmud-weight adjustments—avoiding costlydamage to the borehole.

Spring 1998 51

analysis—an indicator of data quality—verify the accuracy of the real-time com-pressional-slowness log (above). It is clearthat high semblance coherence for thecompressional arrival was obtainedthroughout the entire interval. There aregood correlations between the sonic com-pressional and resistivity curves, especiallybelow X400 ft, where both are respondingto changes in porosity.

In the sand bed, Zone B, the neutron anddensity curves show a large crossover—aclassic gas signature. This is supported by thehigh-resistivity readings. The compressionalslowness also reads extremely high in thiszone—much higher than would be expected

from a normal porosity variation—indicatinggas. The gas sand appears to have a thinshale stringer in the middle, which is alsovisible on the porosity and resistivity logs. Itis interesting to note that the wireline soniclog shows less response to gas in this zone,particularly in the upper section of the gassand above the shale stringer. This is thoughtto be due to borehole filtrate invasion gradu-ally depleting—over a few days—the vol-ume of gas in the annular zone surroundingthe borehole, thus decreasing the gas signa-ture seen by the wireline tools. Details suchas these, seen in many LWD and wireline logcomparisons, help show the value of earlyreal-time answers.

Changing FormationIn the previous offshore Angola example,real-time sonic LWD data helped the opera-tor safely drill the well. However, subsequentcomparison of the LWD logs with their wire-line counterparts sparked the curiosity andinterest of log interpretation experts.Although LWD and wireline logs agree inmany wells, experience has shown thatsometimes there are zones, especially inshales, where the slowness measurementscan differ. In the upper interval, Zone B, ofthe offshore Angola well, the LWD slownesslog reads consistently lower than the wire-line log by 5 to 10 µs/ft [16 to 33 µs/m].Everywhere else, the agreement between theLWD and wireline sonic logs is excellent.The agreement in most of the well indicatesthat the differences are not caused by the dif-ferent processing methods—STC processingwas used for LWD; and for wireline, a first-motion-detection scheme (FMD), which istriggered by waveform amplitudes exceedinga selected threshold.

Other explanations were sought. Sonicmeasurements are known to be affected byborehole washouts. These borehole irregu-larities can cause the measured slownessvalues to oscillate around the true formationslowness values. Although the LWD log wasnot borehole-compensated and the wirelinewas, the systematic difference between thetwo observed measurements was probablynot caused by washouts.

First, the borehole should be in excellentcondition during drilling, thus making theneed for borehole compensation minimal.This is particularly true since this boreholewas drilled with oil-base mud, which mini-mizes washout problems. Second, the con-sistently faster trend of the LWD slownessvalues conflicts with the expected effect ofwashouts, which make the uncompensatedslowness values fluctuate around the com-pensated wireline measurements. Becausethe faster trend of the LWD sonic is persis-tent, the absence of borehole compensationis probably not the cause of the discrepancy.

15. Hsu K, Minerbo G, Hashem M, Bean C and PlumbR: “Sonic-While-Drilling Tool Detects OverpressuredFormations,” Oil & Gas Journal 95, no. 31 (August 4,1997): 59-63, 66-67.

Deep inductionDensity porosity

Neutron porosityp.u. 0

p.u.60 0

60Medium induction

ohm-m

Gassand

Wireline

LWD

20

ohm-m0.2 20

0.2ISONIC slowness

LSS slownessµs/ft 80

µs/ft180 80

180STC projection

ISONIC slownessµs/ft30 210

Depth, ft

X500

X300

X100A

B

■■Real-time gas detection in slow formations. The LWD sonic compressional slowness (red)shows a large increase (track 4) in Zone B, a gas-sand pay zone. Comparisons with wire-line sonic (blue) are generally good, except for a systematic difference in Zone A betweenXX50 and X180 ft. This is attributed to stress relaxation in the shales caused by the drillingprocess. In the gas-sand pay zone—confirmed by the classic neutron-density gas crossover(track 2)—the wireline sonic log, track 4, is beginning to show signs of invasion (Zone B)because its gas signature is not as strong as that of the real-time LWD sonic log.

52 Oilfield Review

It is clear that detailed features of the twoslowness logs in the upper shaly zone arecorrelated (above left). However, the consis-tent difference between the two measure-ments in this interval and the STC projectionderived from the ISONIC recorded wave-forms in track 3 provides clues to what washappening. Specifically, the STC projectionshows that there is a second coherent arrivalbecoming apparent about 10 to 20 µs/ft [33to 66 µs/m] slower than the first arrival. Thissecond arrival is too fast to be the shear insuch a slow formation.

A slow-formation phenomenon known asan altered zone provides a possible explana-tion for the second arrival. An altered zone iscreated by the drilling process which maydamage the borehole wall and cause theelastic modulus in an annular zone aroundthe borehole to change. This is particularlytrue in soft formations. Water take-up in cer-tain shales and shaly sands or stress reliefnear the borehole can also change the elas-tic modulus of the annular rock, generallyreducing it. The altered zone traps wave-

fronts in the same way that a borehole does.The extraneous second arrival in this exam-ple—known as a bicompressional wave—corresponds to a compressional wavetrapped in the altered zone (above right). InNorth American test wells, many early wire-line digital sonic field tests recorded bicom-pressional waveform arrivals.

The time delay between the LWD sonicmeasurements and the wireline sonic mea-surements in the altered zone is about 6 to 7days. The presence of a well-developedaltered zone can cause the wireline tool toread slowness values somewhere betweenthe altered and unaltered formation-slow-ness values, depending on the type of tooland spacing used. In this well LWD sonicmeasured the formation—only hours afterrock was drilled—before any significantalteration had occurred.

With all the evidence collected, the opera-tor concluded that the slowness differenceseen while drilling and at wireline time waslikely caused by changed formation proper-ties over time—a time-lapse effect. Confidentin the accuracy of the sonic-while-drillingresults and realizing the potential for real-

time overpressure detection, the operatorcontinued using the ISONIC tool in its high-profile wells in a neighboring block, latermaking a major discovery there.

In cases like this when a systematic differ-ence is observed between LWD and wirelinelogs taken some time after drilling was com-pleted, it usually happens in shaly zones.Experience shows that the two logs generallyagree in hard rock and clean sands. Theslowness difference can be expected toincrease with time, due to shale swelling. Inthese cases, the LWD slowness wouldalways be less than the wireline slowness.

In some wells the opposite occurs. A welldrilled in a plastic shale can lead to boreholedeformation due to compaction from highvertical stress. In such cases, the high meanstresses produce a decrease in porosity and astiffening of the bulk-frame modulus.16 Theoverall effect of this consolidation phe-nomenon can decrease the shale’s slownesswith time, in an annular zone a foot or moreaway from the borehole.17 The distance intothe formation will depend on formation per-meability, magnitude of the pressure differ-ence, rock properties and the time since thewell was drilled. In such cases, the LWD slow-ness can be larger than the wireline slowness.

This phenomenon may have occurred in theprevious Gulf of Mexico shaly-sand example.In this well, the wireline LSS Long-SpacedSonic Tool slowness shows overall goodagreement with the real-time sonic slowness.However, close examination shows that in theupper shale interval, Zone A, the LWD slow-ness tends to read 3 to 5 µs/ft systematicallylarger than the wireline slowness—again indi-cating shale consolidation near the borehole,caused by the drilling process.

Waveform VDLµs500 3500

X2,000

X1,800

X1,600

X1,400

X1,200

X1,000

Wireline slowness

Phantomarrival

WirelineLWD

ISONIC slowness ISONIC slownessDepth, ftµs/ft180 80

µs/ft180 80

STC projection

µs/ft50 200

■■Time-lapse logging using sonic while drilling. Formation alteration is taking place inthe 6 to 7 days between the running of the LWD sonic and the wireline measurement.Details in both slowness logs seen in track 2 correlate closely, but there is a systematicshift to larger slowness in the wireline log. The reason for the shift can be seen in theslowness-time-coherence (STC) projections from the ISONIC tool, track 3, where a sec-ond slower coherent arrival is emerging. This phantom arrival, too fast to be a sheararrival in these slow formations, is likely to be caused by shale alteration.

Altered shalecompressionalarrival

Virgin formationcompressionalarrival

Altered shale

Borehole Soniclogging

tool Undamagedformation

■■Bicompressionalarrival. Water take-up in certain shalesor stress relief nearthe borehole canchange the elasticmoduli of the annu-lar rock. The alteredzone traps wave-fronts in the sameway as the boreholedoes. The extrane-ous second arrival isshown leading to asecond compres-sional wavetrapped in thealtered zone.

Spring 1998 53

Since the LWD measurement has thepotential of determining unaltered formationslowness, it has significant implications fortwo seismic applications, specifically, thetime-depth relationship and the syntheticseismogram. Seismic waves, with their longwavelength, see the bulk unaltered forma-tion and are insensitive to small features suchas the borehole region. However, wirelinesonic logs are frequently affected by forma-tion alteration, and under those conditionsthey do not provide the most appropriatevelocities for comparison with seismic data.

Hard Rock LWDAlthough hard rock formations are consid-ered routine for wireline sonic logging—because the formation signals are fast andseparate from the borehole mud signal—they present a major challenge for LWDmeasurements. Experience indicates that thelevel of drilling-induced noise is high in hardformations, and under these conditions,downhole waveform processing requiresspecial care.

In such wells, waveform stacking is indis-pensable. The stacked waveforms in theISONIC slowness tool are filtered with a nar-row band-pass filter, tuned to frequencies atwhich drilling noise is minimal and drill col-lar arrivals—noise—are highly attenuated.

The stacked and filtered waveforms are thenarchived in memory, while the downhole toolmicroprocessor and digital signal processordetermine the slowness of the coherentarrivals in the waveforms using STC process-ing and selecting the arrival that correspondsto the compressional slowness—known aslabeling. Once the compressional slowness isextracted downhole, it is transmitted to sur-face via the mud telemetry system. TheISONIC slowness log is generated at surfacein real time as the tool passes the formation.

An example in a highly deviated North Seawell shows the current capability of LWDreal-time sonic logging in hard rock(above).18 In this well, the ISONIC loggingtool was attached 114 ft [40 m] behind thedrill bit, which put its measurements morethan 4 hours after drilling. The recordedwaveform variable density log (VDL) showsthe good compressional signal, followed bya strong shear and even stronger Stoneleyarrivals. Some residual drilling noise is visi-ble in the harder sections of the formation.

The compressional slowness from the LWDmatches the wireline results throughout thiswell. Many fast carbonate stringers correlatebetween both sonic logs and the gamma ray,all dipping in value as the clean hardstringers are passed by the logging tools. Inthe lower limestone zone at X1300 m, aWyllie time-averaged porosity of about7 p.u. is computed for this limestone bed.19

These results enable the operator to deter-mine formation rock properties for planninga hydraulic fracturing program.

Petrophysics: Sonic Logs in Gas SandsAfter the structure of the reservoir isknown—traps are located, faults are mappedand fractures and their orientations identi-fied—pay zones must be quantified (see"Localized Maps of the Subsurface,” page56). Hydrocarbon identification, and deter-mination of porosity and saturation areimportant petrophysical applications forsonic logging. The Biot-Gassmann theory iswidely used today to relate wet rock to dryrock frame properties for sonic applica-tions.20 With the introduction of dipole soniclogs, and the ability to record high-qualityshear and compressional slownesses for thefirst time in slow formations, trends can beidentified in sands and shales and matchedwith semi-empirical correlations based onBiot-Gassmann theory. These trends can beused as a quality-control check on sonic logsand for quicklook lithology interpretation.

However, the effects of partial saturationpose special problems. Gas and liquid mix-tures in soft formations make the interpreta-tion more complicated, as these can affectthe sonic slowness significantly, in particularthe compressional slowness. The compres-sional-to-shear velocity ratio, Vp/Vs, hasbeen used in unconsolidated sands to quali-tatively detect gas.

The fluid distribution in the pore system at the microscopic level and the acousticfrequency have a strong influence on the strength of the gas effect on acoustic

16. This situation would occur if the drilling fluid pres-sure was less than the pore pressure. Also, becauseof the high ionic strength of the water phase in somedrilling mud (200 to 300 kppm calcium chloride),the mud can pull water out of the formation, partic-ularly the shales. This can lead to embrittlement ofthe formation, and possible fracturing.

17. Hsu K, Hashem M, Bean CL, Plumb R and MinerboG: “Interpretation and Analysis of Sonic WhileDrilling Data in Overpressured Formations,”Transactions of the SPWLA 38th Annual LoggingSymposium, Houston, Texas, USA, June 15-18,1997, paper FF.

18. Aron J, Chang SK, Codazzi D, Dworak R, Hsu K,Lau T, Minerbo G and Yogeswaren E: “Real-TimeSonic While Drilling in Hard and Soft Rocks,”Transactions of the SPWLA 38th Annual LoggingSymposium, Houston, Texas, USA, June 15-18,1997, paper HH.

19. The empirical time-averaged Wyllie model is asonic-porosity interpretation mixing law that worksin many low-porosity applications. It is a linear vol-umetric mix of the formation and fluid slownesses. Itdoes not account for the fact that real rocks are nothomogeneous, nor microscopically continuous, orisotropic and not ideally elastic.

20. The first significant model of sonic properties in fluid-filled porous rock was developed byGassmann. See Gassmann F: “Elastic WavesThrough a Packing of Spheres,” Geophysics 16, no. 18 (1951): 673-685. Then Biot developed amore complete model by allowing relative motionbetween the fluid and rock matrix. See Biot M:“Theory of Propagation of Elastic Waves in Fluid-Saturated Porous Solids,” Journal of the AcousticalSociety of America 28 (1956): 179-191. The Biotequations converge to those of Gassmann at lowfrequencies. For a general review of sonic propertiesin fluid-filled porous media, see Ellis D: WellLogging for Earth Scientists. New York, New York,USA: Elsevier, 1987.

LWD comp. slownessISONIC

waveform VDLGamma ray

Limestone bed

A

API

Wireline comp.slowness

µs/ft 50200

µs/ft 50 400 3400µs200

µs/ft 502000 150LWD shear slowness

Depth,m

XX900

X1100

X1000

Compressionalslowness

Shearslowness

X1200

X1300

Drilling noiseCompressional wavesShear wavesStoneley waves ■■LWD Sonic in fast

formations. The ISONICtool recorded waveforms plotted in the VDL displayin track 3 show a compres-sional arrival near 1150 µs, a strong shear near1700 µs and a strongerStoneley arrival near 2500µs. Compressional (red)and shear (green) slownessvalues are displayed intrack 2. The LWD compres-sional slowness matchesthe wireline results (blue)throughout this interval.The formation slownessand the amplitude of thecompressional arrival correlate, especially justbelow X850 m, where the formation slownessdrops from 95 to 80 µs/ft[312 to 262 µs/m] and theamplitude of the compres-sional arrival increases by about a factor of two. In the faster—harder—portions of this interval,Zone A, increases indrilling noise are visible onthe early part of the VDLwaveforms, just before the compressional arrival.

54 Oilfield Review

slowness. Although the Biot-Gassmannmodel together with Wood’s mixing lawhave been successfully used at seismic fre-quencies for geophysical interpretation, theygive deceptive results in partially gas-satu-rated formations at sonic frequencies.21 TheBiot-Gassmann model itself is not the prob-lem. The effect of gas on elastic-wave slow-ness has been observed by a number ofauthors, and the problem lies in determiningthe effective modulus of the pore-fluid mix-ture (above).22

To evaluate gas volume from sonic logs inshaly sands, a new mixing law for comput-ing the average sonic properties of gas-satu-rated fluids has been proposed recently.23

The new mixing law differs from Wood’smixing law in that it relates the effective fluidbulk modulus to the liquid and gas modulithrough a power law function of the liquidsaturation (left). The interpretation proceedsstraightforwardly from here. The apparentpore-fluid bulk modulus can still be com-puted from the Biot-Gassmann model, whichrelates it to the formation velocity ratio mea-sured by the sonic logging tool; and theporosity can be derived from neutron anddensity logging. To derive the gas saturation,the apparent fluid modulus is compared withthe one computed by the new mixing lawbased on the liquid saturation in the invadedzone. The crossplot of the velocity ratio ver-sus compressional slowness illustrates howgas-bearing formations are differentiatedfrom liquid-filled formations (above).

The Biot-Gassmann model along withopenhole density, porosity and lithologicalinterpretations are used to derive theexpected dry formation properties, whichenable computing fully liquid-saturated for-mation moduli and slowness values. Theseresults can serve as an effective quicklook gas

indicator on the log plots by comparing themwith the measured slowness values. The drycompressional and shear slowness curves arewhat the logging values would be if the for-mation was completely filled with dry gas.Similarly the wet slowness curves are whatthe logs would read if the formation wascompletely filled with liquid—oil or water.The quicklook gas saturation is computedfrom the difference between the derived wetslowness and observed slowness.

These dry formation parameters also findapplication as inputs to rock mechanics com-putations. These properties are independentof the pore fluid in the rock, and thereforeprovide a more reliable basis for rock-strength estimation than the moduli com-puted directly from the measured slowness.Finally, the dry formation properties can beused to estimate the acoustic response for anypore fluid mixture as an input to amplitude-versus-offset (AVO) modeling—known asfluid substitution.24 Wood’s mixing law,which has a more dramatic effect from gassaturation, should be used at seismic fre-

0204060

80100 Gas saturation, %

2.5

2.0

101102

103104

105106

Frequency, Hz

Sonic

Seismic

Vp,

km

/s

■■Relationship of compressional velocity to frequency and gas saturation. Seismicfrequencies lie near the front of this plot,which shows an abrupt change in velocitywith only a few percent increase in gassaturation. Sonic logging measurementsare in the center of the graph, and show a more gradual increase in velocity as gassaturation increases.

0 100

e = 1

K f (

Flui

d bu

lk m

odul

us)

Sxo (Invaded zone liquid saturation), %

23

510

Kf = (Kliquid - Kgas) Sexo + Kgas

Kliquid

Kgas

■■Pore-fluid mixing laws. The observedpore-fluid bulk modulus Kf changes fromKliquid to Kgas in a nonlinear manner asliquid is replaced by gas in the formation.Field data suggest an average mixing-lawcoefficient, e, of between 2 and 5. Thecurves are scaled according to liquid satu-ration in the invaded zone, Sxo, because thesonic properties of oil and water are similar,and sonic measurements are mostly sensi-tive to fluid present in the invaded zone. For high values of the mixing coefficient(e ≈ 40), the mixing law behaviorapproaches that of Wood’s mixing law.

North SeashalesMalaysiashaly sandsNorth Seawater sand

Compressional slowness, µs/ft

2.00

401.50

3.00

2.50

100 180

V p / V

s

3.50

Gas

Sha

les

90

80

70

6050

40

Invaded zone

fluid saturation

30

20

10

Porosity, p.u.

Unconsolidatedsediments

DolomiteLimestoneWet sandsShalesDry or gas sandstonesAnhydriteSaltQuartz

■■Sonic crossplot. Wet formations, such as theWet Sand trend (bluecurve), show an increasein their Vp/Vs velocityratio due to decreasingshear velocity, caused by fluid-rock coupling.Shales (green curve)show even greater effect.The new mixing law forcomputing the effectivefluid-bulk modulus ofgas-saturated formationssuccessfully explains the observed trends inlogging data.

Spring 1998 55

quencies because seismic compressionalvelocities are more sensitive to gas saturation.In practice, when gas is present, the dryacoustic parameters provide a suitableapproximation to the seismic response.

An example in a well drilled through a shalysand formation with oil-base mud shows thecapability of sonic logging to quantitatively dif-ferentiate between liquid and gas (right). Thelogged compressional and shear slownessesfall between the expected dry-gas and wet-liquid limits. Porosities are high, averaging 33 p.u., in the interval shown, and the com-pressional slowness shows a large gas separa-tion, often as much as 35 µs/ft [115 µs/m],which is characteristic of these soft forma-tions. Hard formations show less separation.The gas effect seen on the shear slowness issmall. This is expected because the shearmodulus is independent of pore fluid in theBiot-Gassmann model, and the effect onshear slowness is coming from density alone.

Over most of the interval shown, gas isclearly seen in the sonic interpretationexcept in the 5-m [16-ft] zone at X100 m,where both compressional and shear slow-nesses agree with the expected wet values.The traditional ELAN Elemental Log Analysisopenhole interpretation, using resistivity andEPT Electromagnetic Propagation Tool data,indicates hydrocarbons in this zone. This isthe only place where there is marked dis-agreement between the sonic logging- andthe resistivity-based interpretation. However,this zone consists of fine-grained silt, and theresistivity interpretation using Archie’s equa-tion did not take into account the effects ofhigh irreducible water saturation associatedwith silt in this zone, which leads to an incor-rect saturation result.

Sonic compressional-slowness logs aremostly sensitive to the fluid present in theinvaded zone. Compressional waves followrefraction laws, and when the invaded zoneis faster than the deep formation—as in a gaszone—then only the invaded zone is seen.The slower, gas-filled, virgin zone lying deepin the formation is not measured because the

compressional wave in this slower formationis refracted away from the wellbore. Theimportant conclusion is that fluid analysisobtained from the sonic logs representsinvaded-zone saturation.

These sonic interpretation techniques areimplemented in the PetroSonic module of theGeoFrame interpretation program. They canbe used to evaluate hydrocarbon saturationfrom sonic slowness, remove pore-fluideffects and analyze frame properties for rockmechanics evaluation, and replace the porefluid present at logging time (invaded zone)with another fluid combination, either to repro-duce the original reservoir conditions, or to sim-ulate other situations for AVO modeling.

Sonic measurements make important con-tributions to our knowledge of a field dur-ing every phase of reservoir life—drilling,completion, formation evaluation, stimula-tion, even fluid characterization and moni-toring. Sonic waves don’t solve everyproblem, but when combined with othermeasurements—neutron-density for gasidentification, FMI measurements for frac-tures or CMR Combinable MagneticResonance Tool readings for permeability—they strengthen our understanding of thesubsurface and ultimately help find andproduce hydrocarbons more efficiently.

—RCH

21. Wood’s law is frequently used in many geophysicsapplications to compute the effective fluid compli-ance—inverse bulk modulus—from a linear volu-metric mix of the gas and liquid compliances.

22. Murphy W, Reischer A and Hsu K: “ModulusDecomposition of Compressional and ShearVelocities in Sand Bodies,” Geophysics 58, no. 2(February 1993): 227-239.

23. Brie A, Pampuri F, Marsala AF and Meazza O:“Shear Sonic Interpretation in Gas-Bearing Sands,”paper SPE 30595, presented at the 70th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 22-25, 1995.

24. Chiburis E, Frank C, Leaney S, McHugo S andSkidmore C: “Hydrocarbon Detection with AVO,”Oilfield Review 5, no. 1 (January 1993): 42-50.

X100

XX50

Depth,m

Slowness, µs/ft 50350

5020 100%0 00 Dry Modulus, GPa

SonicVolume

ELANVolumes

p.u.

Wet

WetDry

Dry

Log Log

Compressionalslowness

Moduli

Quartz

Gas

Clay

Feldspar

Totalporosity

GKdry

Liquid

Gas

Shearslowness

Water

■■Gas evaluation in shaly sands. The compressional and shear slowness logs are shownin track 2, and compared with the dry and wet slowness predicted by the Biot-Gassmann model for fully gas- and water-saturated formations. The difference betweenthe expected wet and observed compressional and shear slownesses are used to deter-mine gas volume, shown in track 3. Dry bulk and shear moduli of the rock shown intrack 2 can be used in rock mechanics applications. The ELAN interpretation, track 4,shows fluid and formation volumes.