18

iciveay tooires

togsf a].

lesoiral-

thps.ic

eir ofro-er-ndng

ole

has helped to correlate time-based surfaceseismic surveys with depth-based logs.Check shots check the seismic travel timefrom a surface shot to receivers at selecteddepth intervals. Subtraction of times, com-bined with the depth differences, yields ver-tical interval velocities and thus relates welldepths to surface seismic times.

In vertical seismic profiles (VSPs), thespacing between downhole geophone levelsis considerably closer than for check-shotsurveys. VSPs use high-quality full wave-forms that include reflection informationrather than just the time of first arrivals —orfirst breaks—to create an image of reflectionsnear the wellbore.1 Building on this tech-nique, 2D reflection images have beenobtained by offset and walkaway surveyswith sources and receivers in a variety ofconfigurations that address most reservoirproblems (see ”The VSP Family,” page 22).

Seismic surveys in the bor easure of the seismic response of the

surrounding reservoir. Alth e to image local features, they may

also be tied with well data xtensive surface seismic data.

Advances in borehole geo f existing data to create a sharper

image of the reservoir.

For help in preparation of this article, thanAhmed and Antoine Track, Schlumberger uct Centre, Clamart, France; Philip ArmstrPrakla, Gatwick, England; Bruce Cassell, WTesting, Dubai, UAE; Alex Cisneros, GeoQTexas, USA; Ian Gollifer, GeoQuest, AberdJakob Haldorsen and Doug Miller, SchlumResearch, Ridgefield, Connecticut, USA; Band Colin Sayers, Schlumberger CambridgCambridge, England; Mike Jones, WirelineCalgary, Alberta, Canada; Scott Leaney, Wing, Jakarta, Indonesia; William Underhill,Hannover, Germany; and John Walsh, Wiing, Houston, Texas.

In this article, ASI (Array Seismic Imagerbinable Seismic Imager), DSI (Dipole Sheaand Formation MicroScanner are marks of

Borehole Seismic Data Sharpen the Reservoir Image

A

SA

Phil ChristieCambridge, England

Kevin DoddsAberdeen, Scotland

Nigel SmithStavanger, Norway

It’s a matter of resolution. Surface seismsurveys deliver one of the few quantitatmeasurements of reservoir properties awfrom wells, making the technique centralstructural mapping of the entire reservvolume. However, surface seismic wavcannot resolve features smaller than 3040 ft [9 to 12 m]. On the other hand, loand cores resolve features on the scale ofew feet down to about 6 inches [15 cmReconciling these two measurement scato get the optimal picture of the reservvolume is a problem that has long chlenged the industry.

Borehole geophysics has a foot in bothe logging and surface seismic camFrom the vantage of the wellbore, seismdata often have higher resolution than thsurface seismic counterparts. Depthseach borehole receiver are also known, pviding a better tie to the formation propties provided by petrophysical, core aother in-situ measurements and relatithem to the 3D seismic volume.

The idea of locating a receiver downh

ehole deliver a high-resolution quantitative m

ough these measurements may be used alon

—logs and cores—and then related to more e

physics are helping realize the full potential o

ks to ShabbirRiboud Prod-ong, Geco-

ireline &uest, Houston,een, Scotland;berger-Dollrian Hornbye Research, & Testing,ireline & Test- Geco-Prakla,reline & Test-

), CSI (Com-r Sonic Imager)Schlumberger.

Johnny RutherfordAmerada HessHouston, Texas, US

Jack SchaffnerSt. Louis, Missouri, U

Dick IresonGatwick, England

Lucian (Sonny) JohnstonCaracas, Venezuela

Oilfield Review

and a seismic source at surface is not new.For more than half a century, the check shot

19Winter 1995

Yet despite these and other developments,borehole geophysics has for many yearsfailed to gain the status in reservoir charac-terization that some industry specialiststhink it deserves. Now, thanks to improvedquality and increased confidence in thematch between borehole and surface seis-mic data, borehole geophysics seems to bemoving into an increasingly valued position.

Before examining how borehole seismicdata are being used to successfully integrateother data, this article will illustrate how thescope of VSP is broadening through thedevelopment of horizontal, 3D and through-tubing techniques.

Broadening the Scope of VSP ApplicationsIn the deviated and horizontal wells of theNorth Sea, the most common type of bore-hole seismic survey is the vertical-incidenceVSP. These are often called walk-above sur-veys because, as the geophone is movedalong the deviated section of borehole, thesource is kept vertically above it, “walkingabove” the well. In VSP terms, a horizontalwell is an extreme version of a deviatedwell. Like other VSPs, deviated well surveysmay be used for locating the well in the 3Dsurface seismic volume and assessing thequality of surface seismic surveys. Also, thetechnique may be employed for measuringlateral velocity variations and for imagingfaults and structures below the wellbore.

The following example of a walk-aboveVSP was carried out in late 1994, in a NorthSea well with a 1.2-kilometer [0.75-mile]horizontal section. There were two mainobjectives. The first was to measure a sus-pected lateral velocity anomaly that mayhave been creating artifacts in the surface

1. Babour K, Joli F, Landgren K and Piazza J-L: “Elementsof Borehole Seismics Illustrated with Three Case Stud-ies,” The Technical Review 35, no. 2 (April 1987): 6-17.Belaud D, Christie P, de Montmollin V, Dodds K, JamesA, Kamata M and Schaffner J: “Detecting Seismic Wavesin the Borehole,” The Technical Review 36, no. 3(July 1988): 18-29.

• median filtering techniques to estimateand subtract the energy scattered by faults

• enhancement of the desired upgoing signal

• equalization of the reflected wavefieldamplitudes from the horizontal and thebuild up sections.The final image showed three important

features: the two faults marked A and B,which appear where suspected in thereflected image, and the dip of the stratabelow the well (next page, left). FormationMicroScanner data acquired during open-hole logging were compared with the VSP,confirming the fault locations—seen aschevrons in the VSP—and the apparent dips.

In this case study, VSP processing wasperformed before Formation MicroScannerdata were ready to interpret, and the VSPhelped the interpretation by outlining the

seismic data (above). The second was toobtain a high-resolution seismic imagebelow the deviated portion of the well. Anadditional objective was to obtain a seismicimage in the horizontal part of the well.2

Data were collected in the vertical anddeviated portions of the cased well usingthe conventional wireline-conveyed ASIArray Seismic Imager tool. In the horizontalsection, a two-element CSI CombinableSeismic Imager geophone array was run ondrillpipe in combination with a cementbond log. By decoupling the sensor modulefrom the body of the CSI tool, the geo-phones are isolated from noise and distor-tions created by the drillpipe.

20 Oilfield Review

As with any survey, the desired seismicimage is produced using the reflected, orupgoing, wavefield. So the first processingtask was to separate downgoing waveformsfrom upgoing. For walk-above surveys inhorizontal wells, this is far from straightfor-ward, since unlike vertical and deviatedwells, there is no apparent time differenceacross the array between the downgoingand the reflected upgoing waves. It is there-fore impossible to use conventional tech-niques to distinguish between reflectionsand downgoing waves (above, right ). Toimprove the image a number of specialtechniques were used, including:• multichannel filtering to attenuate noise

and sharpen the desired signal3• downgoing wavefield subtraction

using a long filter length to estimate the downgoing wavefield

nWalk-above VSP in a North Sea horizontal well to assesslateral velocity variations and local structure. The first-arriving seismic signals are tracked with a red line, whichalso delineates the borehole trajectory in two-way time.

nThe shortcomings of conventional processing for VSPs inhorizontal wells. In conventional methods of VSP process-ing, the lack of apparent velocity difference betweendowngoing and upgoing wavefields leaves little or noreflected upgoing energy after wavefield separation.Boosting the gain in the horizontal section is of little value.There is poor continuity of reflected events, and the fault-scattered energy further complicates the image.

Two-

way

tim

e10

0 m

sec

Level number2401

Two-

way

tim

e10

0 m

sec

Level number2401

2. Ediriweera K, Smith N and Prudden M: “BoreholeSeismic Surveys in Horizontal Wells—A Case Studyfrom the North Sea,” paper B018, presented at the57th EAEG Meeting and Technical Exhibition, Glasgow, Scotland, May 29-June 2, 1995.

3. Haldorsen J, Miller D and Walsh J: “MultichannelWiener Deconvolution of Vertical Seismic Profiles,”Geophysics 59 (October 1994): 1500-1511.

the same signal polarity for a downgoingwave, they show different polarities for theupgoing wave. By taking the differencebetween signals received at the two types ofsensors—for a signal consisting of a directpulse followed by a reflected pulse—thedirect wave is canceled and the reflectionenhanced (above, right).

Complications arise from differences in thecoupling and impulse responses betweengeophones and hydrophones. However, thisapproach has recently been applied in thefield, enabling the extraction of reflectedwavefields in a horizontal well and the imag-ing of reflectors below the receivers.

major features. The two data sets were theninterpreted and refined together, providing amore complete description of near-wellgeology than was otherwise available. Theresults met the main objectives of the surveyand delivered an image below the horizon-tal section.

An alternative strategy for acquiring andprocessing horizontal VSP data exploits thedifferent responses of geophones andhydrophones to differentiate downgoingenergy from upgoing energy in horizontalwells. Geophones are clamped to the for-mation, and sense its motion. In contrast,hydrophones are suspended in the boreholefluid and are sensitive to fluid pressurechanges as a seismic wave passes in anydirection. When the two sensor types show

21Winter 1995

nHorizontal VSP data after improved processing. Thereprocessed data show three important features: twofaults marked A and B which appear as anticipated inthe reflected image, together with evidence of dipping.The apparent formation dips seem to be parallel to theborehole until very near total depth. This turned out to beentirely consistent with the Formation MicroScanner com-puted dips.

Two-

way

tim

e10

0 m

sec

Level number2401

BA

=-

Direct,downgoing wavelet

Reflected,upgoing wavelet

Geophone Hydrophone

nSeparating downgoing and upgoingwaves in horizontal VSPs using geophoneand hydrophone seismic signals. A wavearriving from above pushes the sensor inthe geophone down, recording a positivemotion (trace swing to the right). The samewave, having reflected below the geo-phone without changing polarity, pushesthe sensor upwards as it arrives frombelow (swing to the left). The resulting seismic trace consists of a positive down-going then a negative upgoing pulse. A hydrophone, by comparison, produces a seismic trace with two wavelets of thesame polarity. Therefore, the reflectedevent as seen by a geophone is of oppositepolarity to that seen by the hydrophone.Subtraction of one seismogram fromanother, after appropriate scaling, elimi-nates the downgoing wavelet, leaving the reflected signal.

22 Oilfield Review

The members of the family of borehole seismic

measurements differ in the number and location

of sources and geophones used and how they

are deployed.1

The simplest of all services—in common prac-

tice by 1940—is the check shot, sometimes

called a velocity survey.2 Check shots measure

direct travel times from source to receiver, with

no reflections along the way. This provides a

measure of seismic velocity near the well and

relates seismic time to well depth. The check-

shot service deploys a stationary seismic

source, while a single downhole geophone is

moved to locations in the well indicated by the

well logs, measuring the travel times to specific

reflectors. The first arrivals—or first

breaks—recorded on the seismic traces are

picked to deliver the time-to-depth information.

This geophone and source configuration is

similar for the next member of the family, the

zero-offset VSP. The zero-offset VSP has its ori-

gins in the 1950s.3 The source is located directly

above the receivers (above, right). However, to

obtain an image of subsurface reflectors, a

higher density of receiver positions is used than

in a check-shot survey and trace recordings

extend beyond the first breaks to include later-

time reflections.

Next in the family comes the offset VSP, in

which a single surface source is positioned at a

substantial distance—termed offset—from the

well (next page, top). This shifts the reflection

points away from the well and extends the

subsurface coverage, helping to detect faults,

for example.

The check shot and the two VSP techniques

described above are multireceiver, single-source

techniques. The walkaway VSP departs from

this. In its simplest form, a receiver array of five

to seven geophones collects data from multiple

surface source locations along a line that

extends from the well. Each line typically has

hundreds of source positions. Reflections from

each horizon below the geophone offer an

umbrella-shaped coverage of the formation

The VSP Family

Reflected upgoing multipleReflected primary

Source

Reflector

Downgoing multiple

Direct wave

Geophone positionTime

Subsurface reflector

Zero-offset VSP

alongside and beneath the well. These data may

then be processed to create an image that usually

has higher resolution than that from surface seis-

mic surveys. The acquisition of 3D VSP involves

multiline walkaway profiles.

Somewhere between single-source and walka-

way VSP is the VSP in deviated and horizontal

wells—often called a walk-above VSP. In this

technique a source may be positioned directly

over the receiver to map a deeper reflector and to

map a deviated well onto a seismic section.

Three special members of the VSP family are

salt-proximity surveys, shear-wave VSPs and

drill-noise VSPs. Salt-proximity surveys, which

originated in the 1930s, are recorded in wells

adjacent to salt domes with the source placed

immediately above the salt dome.4 Travel-time

information and the polarization of first arrivals

are measured by the downhole geophone at vari-

ous locations in the well.

Knowing the location of the receivers and the

source, the velocity of the salt, the velocity of the

sediment layers and the distance to the top of the

salt dome, a travel-time inversion may be per-

formed to determine the locations of points where

rays exit the salt dome. This allows a profile of

the salt dome to be constructed, which may be

used to determine the lateral distance from the

well to the salt, and also to identify possible over-

hangs and potential traps along the salt flank.

As the name suggests, shear-wave VSPs are

VSPs recorded with shear-wave sources, usually

shear-wave vibrators (next page, middle). These

may be used in a manner similar to P-wave VSPs

to create a high-resolution image of reflectors.

However, another application is to measure a

phenomenon known as shear-wave splitting. This

is associated with anisotropy due to stress or ver-

tically aligned fracture systems. Shear waves

travel faster when their particle motion is polar-

ized in the plane of fractures than when it is per-

pendicular to the fracture plane. Shear-wave VSPs

have been used to determine the expected orien-

tation of induced fractures, the orientation of nat-

ural fractures and stress directions, and a qualita-

tive indication of fracture density.5

The drill bit seismic technique, sometimes

called drill-noise VSP or seismic-while-drilling,

reverses the geometry of the source and receiver

(next page, top). The drill bit itself is the seismic

source, and receivers are placed on the surface.6

Clever processing can image the reservoir or a

drilling hazard, such as overpressure, as the well

is being drilled.

23Winter 1995

Ordinary VSPs can give an indication of such

features below the current total depth of the well,

by flagging zones of anomalous acoustic

impedance. But VSP data can be converted to

depth only as far down as the lowest borehole

receiver level. After that, results are in time, and

so not very useful to drillers.

The drill bit seismic technique can complement

the time-based acoustic impedance profile

derived from VSPs by providing a means to mea-

sure the time-depth information below the bottom

VSP receiver level as the drilling progresses.

Thus, the depth index of the acoustic impedance

prediction can be continuously updated at the

wellsite, showing clearly when a suspected

drilling hazard is about to be hit (left).

1. For a review: Oristaglio M: “A Guide to Current Uses of Vertical Seismic Profiles,” Geophysics 50 (December 1985):2473-2479.

2. Heiland CA: Geophysical Exploration. New York, NewYork, USA: Prentice-Hall, 1940.

3. Jolly RN: “Deep-Hole Geophone Study in GarvinCounty, Oklahoma,” Geophysics 18 (July 1953): 662-670.

4. McCollum B and LaRue WW: “Utilization of ExistingWells in Seismograph Work,” AAPG Bulletin 15(December 1931): 1409-1417.Gardner LW: “Seismograph Determination of Salt DomeBoundary Using Well Detector Deep on Salt DomeFlank,” Geophysics 14 (January 1949): 29-38.

5. Sun Z and Jones M: “Shear Anisotropy Analysis fromDirect and Converted Wave VSP Data Using VariousAlgorithms,” paper BG4.5, presented at the 64th SEGAnnual International Meeting and Exposition, Los Angeles, California, USA, October 23-28, 1994.Winterstein DF and Meadows MA: “Shear-Wave Polar-izations and Subsurface Stress Directions at Lost HillsField,” Geophysics 56 (September 1991): 1331-1348.

6. Meehan R, Miller D, Haldorsen J, Kamata M and Under-hill B: “Rekindling Interest in Seismic While Drilling,”Oilfield Review 5, no. 1 (January 1993): 4-13.

■■Prediction to depthof a drilling hazard,continuously updatedwith drill bit seismicwellsite processing.Acoustic impedance intwo-way time from aVSP acquired at a shal-lower drilling depth(top) shows a drillinghazard in the form of a decrease in acousticimpedance at 2.19 sec(blue line). This is con-verted to depth usingtime-depth pairsderived from drill bitseismic processing(bottom). The earlyprediction of the depthto the drilling hazard at2673 m (gold line) isupdated to a new,deeper prediction, 2684 m (red line).

Shear-Wave VSP

Fractured layer

Two shear-wavepolarizations

2200

Dep

th, m

2100

2000

2300

2400

2500

2600

2700

2800

6000

7000

8000

Aco

ustic

impe

danc

e,m

/sec

x g

/cm

3

Two-way time, sec

1.8 2.0 2.2 2.4

Old hazard depth = 2673 m

New hazard depth = 2684 m

Offset VSP Walkaway VSP Walk-above VSP Salt-Proximity VSP

Salt

Drill-Noise VSP

Receivers

Drillbit

North

South

To V20(E)

End of Survey

fromV17(W)

A 591762 N591576 N

591949 N

24 Oilfield Review

seismic survey. The image was then to beused to produce an accurate structural mapto aid the planning of horizontal develop-ment wells in the Brent slump—a crestalzone of complex faulting and collapsewhich contains a significant portion of thefield’s remaining oil reserves.7

The survey was executed from a well witha trajectory that allowed positioning the geo-phones to give three-dimensional illumina-tion of the slump zone. The receivers con-sisted of five shuttles with fixed triaxialsensors, clamped 2000 ft [606 m] above thetarget during the entire survey. Once in thewell but prior to shooting, the couplingbetween each of the shuttles and the forma-tion was evaluated using internal shakers toensure distortion-free data.

The seismic source consisted of a clusterof three 150-in.3 [2460-cm3] sleeve guns. Tosupply sufficient gas for 41 lines of 200shots per line, four 5100 cubic meter nitro-gen-filled tube skids were used. Simultane-ously with the downhole data acquisition,each shot location on the surface wasrecorded using two differential GPS naviga-tion systems.8

To make the survey cost-effective, it wasvital to minimize time spent acquiring data—every extra minute per sail line meant anadditional 41 minutes of rig time. For exam-ple, to reduce the time the vessel took tomaneuver between lines, a strategy wasdevised to wrap each line efficiently into thenext (far left ). In the end, the data wereacquired within the planned survey time oftwo and a half days, including a conven-tional VSP.

The 3D processing involves an extensionof methods already developed for 2D walk-aways—data preparation and navigationcheck, triaxial projection, wavefield separa-tion, deconvolution and migration (see “3DVSP Processing,” page 26).

In this case, the processing consisted ofseparate preparation and processing of all 41lines up to the deconvolution stage. Then all41 reflected energy profiles were accessed bythe 3D VSP migration algorithms to place thereflections correctly in space.

The successful processing of these surveysrequired an experienced geophysicist withstrong interpretative skills to make the cor-rect decisions at each stage of the process-ing—for example, to ensure that all possiblequestions related to the influence of dataquality had been resolved. These skillsensured that the image was interpreted interms of reservoir structure without process-ing artifacts.

The migration process requires the compu-tation of raypaths from each source and every

3D VSPsVSP imaging surveys, such as walkaways,have been used for a number of years toimage structural complexity away from theborehole.4 These walkaway profiles areessentially two-dimensional, confined to thevertical plane containing the surface sourceand the borehole.

Because of the proximity of the receiversto the target, like all VSPs, these 2D imagesusually have the advantage of being ofhigher resolution than their surface seismiccounterparts. But, by definition, 2D walka-ways don’t describe the full volume of thereservoir. Fortunately, the acquisition princi-ple may be extended to cover three dimen-sions by repeated profiling in parallellines—in effect, by collecting a series of 2Dwalkaway surveys similar to marine 3D seis-mic data acquisition (below).

The progression from 2D to 3D in VSPsurveys is similar to the progression in thesurface seismic technique, and offers equiv-alent benefits. Thus, 3D VSPs allow high-resolution imaging to augment surface 3Dsurveys and make it possible to obtain

images beneath surface obstacles, such asplatforms, and near-surface obstructions,such as shallow gas zones. In addition,because the acquisition conditions and pro-cessing steps of VSP surveys are accuratelyreproducible, 3D VSP opens up the possibil-ity of time-lapse, or 4D, seismic surveying.5

However, progressing from 2D to 3D sub-stantially increases the need for planningand logistics control. Similarly, the process-ing requirements are almost an order ofmagnitude greater.

The first 3D VSP survey was run in 1987in the Adriatic Sea Brenda field, operated byAGIP.6 Since then, there have been two 3DVSP surveys in the Norwegian Ekofisk fieldfor Phillips Norway—where a large gasplume over the center of the structure pre-vents imaging using conventional 3D surfaceseismic techniques. Other Norwegian sur-veys probe the Eldfisk and Oseberg fields.

In the UK North Sea, a 41-line, 3D walk-away VSP survey has been carried out inShell Expro’s Brent field. In this case, theaim was to acquire a survey with improvedresolution compared with the 3D surface

nMarine 3D VSP acquisition.Sail lines are planned tominimize turning, and satel-lite navigating systems trackthe shot points.

4. Christie PAF and Dangerfield JA: “Borehole SeismicProfiles in the Ekofisk Field,” Geophysics 52, no. 10(1987): 1328-1345.

5. Johnstad SE and Ahmed H: “Reservoir MonitoringUsing the Vertical Seismic Profiling (VSP) Technique, ACase Study in the Oseberg Field,” presented at the 54thEAEG Annual Meeting and Technical Exhibition, Paris,France, June 1-5, 1992.

6. Belaud et al, reference 1.

7. Van Der Pal RC, Bacon M and Pronk DW: “EnhancingSeismic Resolution in the Brent Field by a 3D VSP,”paper B017, presented at the 57th EAEG Meeting andTechnical Exhibition, Glasgow, Scotland, May 29-June 2, 1995.

8. GPS is Global Positioning System.A description of the GPS technique may be found at:http://www.utexas.edu/depts/grg/gcraft/notes/gps/gps.html

9. Johnston LK: “Borehole Seismic Applications Using a Slim Well Seismic Receiver in a Production Environ-ment,” presented at the 1st Latin American Geophysi-cal Conference and Exposition of the LAGU, Rio deJaneiro, Brazil, August 20-24, 1995.

25Winter 1995

receiver to every reflection point in thesubsurface. The rays are traced through avelocity model of the subsurface that canvary in complexity between flat layers (a 1Dlayercake) to complex structures in 2D or 3D.

For simple structures, a layercake velocitymodel, which reduces computation time, issufficient. However, using this model inmore complex subsurface may lead to erro-neous positioning of reflections and theincorrect focusing of real events. Morecomplex velocity models increase the num-ber of ray-trace computations required, butare better able to position reflected eventsand focus the wave energy.

The Brent structure varies in the dipdirection but changes very little alongstrike. Consequently, the velocity model ismore complex than a plain 2D model butnot as complex as a full 3D model; thestructure varies in one horizontal directionand is extruded into the other horizontaldimension to form a so-called “2.5D”model. In this, the volume may be thoughtof as filled with an infinite number of 2Dsections. This allowed computational effi-ciency due to symmetry and ensured aclose match with the actual Brent structure.

Shell concluded that the Brent 3D VSPimproved vertical resolution and signifi-cantly improved horizontal resolution—resolving features on the order of 100 to 150ft [30 to 45 m] as opposed to the original3D surface seismic resolution of 200 to 300ft [60 to 90 m]. The interpretation of theslump features has confirmed conclusionsreached independently, demonstrating thetechnique’s potential and reducing the riskof a proposed new 3D surface survey.

Through-Tubing VSPsThe third application broadening the scopeof borehole geophysics is the VSP throughtubing. Thanks to hardware developments,cost-effective VSPs can be run in maturefields that promise significant economicbenefits.

Traditionally, borehole seismic surveys areacquired in exploration wells when they aredrilled. However, in older fields, boreholeseismic information is often needed to aidthe reservoir engineer in areas where nonew wells are planned, or to plan a newwell. Now a slim seismic receiver may bedeployed by a simple masted logging truckto acquire borehole seismic data throughproduction tubing and inside casing duringworkover or while the well is still on pro-duction. This reduces acquisition costs and

makes surveys in multiple wells possibleduring the same mobilization.

In this way, a full range of borehole sur-veys may be carried out and the data maybe used to tie log and production informa-tion to new 3D surface seismic surveysbeing run in older producing fields.

The slim seismic tool has a 111/16-in. out-side diameter and may carry one single-axisgeophone group or three orthogonallymounted accelerometers. The mechanicallyactuated anchor has a maximum opening of7 in. [17 cm]. The tool is adapted for opera-tion with a monocable wireline andthrough-wellhead pressure fittings. Thisallows for operations in producing wellswith surface pressure. As with any system, arange of seismic information may beobtained in vertical or deviated wells, fromcheck shots to walkaway VSP images.

For example, an offset VSP survey wasacquired through tubing and through casingin an abandoned well in an inland shallow-water field in south Louisiana, USA, using amarine vibroseis unit as a source to acquirehigh-resolution data.

9 The offset VSP surveywas designed to confirm the location of alow-angle fault—indicated by logs—whichcould not be seen on the surface seismicimages. The fault’s orientation was neededto reduce the risk of an infill developmentwell and was easily spotted using the offsetVSP image (above).

Using Borehole Geophysics to Integrate DataAt the heart of developments to improvedata integration is the recognition of thecomplementary nature of some measure-ments. Perhaps the best example of this isthe relationship between sonic logs andseismic data. In these two measurements,the physical interaction with the reservoir isthe same, but at a different scale of resolu-tion. The sonic tool measures formationcompressional slowness, which is depen-dent on many factors, including the forma-tion porosity and lithology. Compressionalslowness combined with density providesthe one-dimensional acoustic impedance ofthe formation, the same property that under-lies seismic reflections.

But seismic waves are sensitive only torelative changes in acoustic impedance,unlike sonic slowness measurements, whichsample absolute values. Therefore, acousticimpedances from logs provide sufficientinformation to model most, but not all fea-tures of the seismic response. The totaltravel time measured by sonic logs is arequired contribution to the bulk responseof the low-frequency surface seismic sur-veys. Then, synthetic seismograms may beconstructed and the response of the forma-tion simulated by altering parameters suchas porosity, fluid type and lithology. The syn-thetics can be used to interpret real data.

Although the scope of VSPs is expanding,the wealth of information relating to lithol-ogy, fluid contacts and the seismicresponses that they produce is not alwaysused to its fullest extent. This is particularlytrue when it comes to evaluating andimproving the information content of sur-face seismic data. Now, existing technolo-gies are being used in new ways to provideadditional direct quantitative measurementsof the seismic response of the reservoir adja-cent to wells.

The next two examples clearly indicatehow the integration of all available data mayimprove understanding of the reservoir. Thefirst example looks at how structural andstratigraphic interpretations may beimproved. The second shows how reflectionamplitude variation with offset (AVO) fromVSPs may be used to calibrate surface seismic AVO.

nThrough-tubing, through-casing VSP.The offset VSP survey was designed toconfirm the location of a low-angle fault(yellow) that could not be seen on the sur-face seismic images. It was easilylocated from the offset VSP image.

250

mse

cTi

me

Distance, ft 01650

3D VSP Processing

Data Preprocessing—This includes loading and

verification of the navigation or geographical sur-

vey data for each shot location and the display of

the data for each receiver level and for each of

three components for quality control purposes.

Triaxial Projection—To acquire data rapidly, a

tool with multiple triaxial geophone “shuttles” is

deployed in the well. However, each shuttle can

have a different, unknown orientation in the

borehole, and this orientation may change if the

tool is moved and clamped at a new level. Thus,

waves arriving from one direction, say a reflec-

tor, may have a different appearance on each

receiver. Triaxial projection converts the data

from the recording geometry to the geometry of

the arriving waves, to make the data suitable

for processing.

Morgan’s BluffIn the Morgan’s Bluff field of Orange County,Texas, USA, the operator IP Petroleumneeded to map the shale edge of its Hack-berry reservoir to design a secondary recovery program.

Substantial existing 2D surface seismicdata did not adequately image the reservoir.Therefore, vertical incidence and offset VSPswere shot within a production well. Theseresults were combined with logs and geo-logic information to map the edge of theshale. Further, the surface seismic lines werereinterpreted, resulting in an extensiveremapping of the Hackberry sand.10

The aim was to drill a sidetrack from theshut-in producing Well 8 toward the adja-cent Well 10, depending on the exact reser-voir boundary, to be determined using theVSP—the Hackberry sand was originallymapped on the strike line that runs throughboth of these wells.

First, the feasibility of this plan was testedand detailed survey models were con-structed using structure maps, log data fromthe two wells and velocity data from a thirdwell. Borehole seismic data shot in 1986 inthe central part of the field were used toconstruct the general velocity model. InWell 8, sonic logs were available to about8000 ft [2440 m], and only nuclear andresistivity logs from there to total depth. Apseudosonic log was constructed from theselogs and compared to the velocities from

26 Oilfield Review

Wavefield Separation—The energy arriving at

the geophone consists of energy arriving from

above overprinting the energy reflected from the

target formations below. Wavefield separation

discriminates between this “downgoing” and

“upgoing” energy in the received wavefield. This

is achieved by velocity filters, which enhance the

coherency of events aligned with a given appar-

ent velocity relative to the receiver geometry.

The same technique may be used to separate

compressional from shear waves, since they

travel at different velocities. A popular method

for wavefield separation is called parametric

wavefield decomposition.1

Deconvolution—In addition to reflections, the

earth creates unwanted additional seismic events

called multiples, and it attenuates higher fre-

quencies more than lower frequencies, producing

signals with both desirable and undesirable infor-

mation. The process of deconvolution, of which

there are a number of varieties, attempts to undo

the excess work of the earth so that only signals

related to reservoir features remain. Through

deconvolution, the recorded downgoing wavefield

is converted into an idealized downgoing wave-

field. The filter that accomplishes this is then

applied to the upgoing wavefield to produce sig-

nals that would have been recorded if the experi-

ment had been perfect. Special deconvolution

methods have been developed for walkaway data.2

3D VSP migration—The migration technique used

for 3D VSPs allows the repositioning of events and

focusing of energy to their appropriate positions in

space. Possible raypaths and travel times are com-

puted by tracing rays through a velocity model of

the subsurface.3 Then all source-receiver pairs in

the seismic data volume are checked for energy

that could satisfy such path and time constraints.

In contrast to the migration of 3D surface seismic

data, the VSP migration algorithm includes spe-

■■Synthetic offset VSP generatedfrom a model including the abrupttermination of Hackberry sand.This, and another model based ongradual termination of the Hack-berry (not shown) indicate that anamplitude decrease in the Hack-berry can be detected, as distancefrom the well increases.

Well #10 Well #8

1.0

1.5

2.0

Above 0.1060.079 to 0.1060.053 to 0.0790.026 to 0.053

-0.001 to 0.026-0.027 to -0.001-0.054 to -0.027-0.081 to -0.054 -0.107 to -0.081Below -0.107Undefined area

Tim

e, s

ec

2000 0

Hackberrysand

Distance, ft

Amplitude

■■ Original (top) versus revised interpreta-tion. The reinterpretation (bottom) basedon results from the borehole seismic sur-veys suggested that during the Hackberrydeposition, a small slump fault occurredto the southwest of the present field. Thiswas scoured out and filled with shale,serving as a trap.

the VSP survey. A synthetic offset VSP wasthen generated using the same wavefieldseparation, deconvolution and migrationprocessing to be used with the real data.

Two scenarios were forward modeled: agradual shaling out and an abrupt, orfaulted, sand termination (previous page).From this it was agreed that in either casethe shale boundary should be interpretableto within 100 ft using the offset VSP sec-tions, and the go-ahead for the survey wasgiven. Additionally, a second offset VSP tothe west of Well 8 was designed to confirmthe interpretation. A VSP was also to be car-ried out in Well 8 to build an updatedvelocity model for migration.

The three downhole surveys were acquiredwith sources located 4000 ft [1212 m] to thewest-southwest, 4300 ft [1300 m] to thesouthwest and 400 ft [121 m] to the east-southeast. An eight-level downhole receiversystem was deployed to record 110 levels at50-ft [15-m] spacing from 8500 to 3000 ft[2575 m to 909 m]. Across each interval, thetop and bottom shuttles were overlapped tocheck for any source amplitude, signature orphase changes during the survey.

Following a standard processing sequenceusing a flat-layer velocity model and somesmall velocity changes to match the modelto the observed transit times, each of the off-set VSPs was migrated. Logs from Well 8were correlated with the offset VSPs.

Formerly, the dominant reflection at 2.2 to2.25 sec on the surface seismic line had

27Winter 1995

10. Schaffner J, Reisinger M and Rutherford JW: “OffsetVertical Seismic Profiles Define Shale Boundaries inMorgan’s Bluff Field,” The Leading Edge 13, no. 1(November 1994): 1095-1100.

11. This new dependance on shear velocity arisesbecause some compressional energy is converted toshear energy at the boundary.

12. For an overview of the AVO technique: Chiburis E, Franck C, Leaney S, McHugo S and Skidmore C: “Hydrocarbon Detection with AVO,”Oilfield Review 5, no. 1 (January 1993): 42-50.Leaney WS: “Anisotropy and AVO from Walk-aways,” paper BG4.4, presented at the 64th SEGAnnual International Meeting and Exposition, LosAngeles, California, USA, October 23-28, 1994.

cific provision for the different source and down-

hole receiver geometry.

The migration applied to 3D VSPs is a full 3D

migration, meaning it considers the positions of

reflectors in the imaged volume, rather than in a

series of 2D slices. The migration algorithm is

based on the seismic wave equation, and applied

prestack, to preserve true reflection amplitudes.

The velocity model used for migration may be

completely 3D with structural complexity and

velocity heterogeneities.

1. Leaney, main text reference 19.

2. Haldorsen et al, main text reference 3.

3. For an explanation of this migration technique:

Van Der Poel NJ and Cassell BR: “Borehole Seismic Surveys for Fault Delineation in the Dutch North Sea,” Geophysics 54 (September 1989): 1091-1100.

Miller D, Oristaglio M and Beylkin G: “A New Slant onSeismic Imaging: Migration and Integral Geometry,” Geophysics 52, (July 1987): 943-964.

been thought to be the Hackberry sand.Now it has been interpreted as a calcareousstreak that runs throughout the field. It isseen on the logs at 8310 to 8360 ft. Thereflection package from the Hackberry sandactually begins at 2.31 sec and ends at 2.36sec. While this was a subtle reflection in thesurface seismic data, it clearly shows up onthe offset VSPs and was confirmed by thetime-based logs from Well 8. The sandsshale out abruptly around 500 ft [151 m] tothe southwest.

This interpretation was then combinedwith existing offset and seismic data to yielda new interpretation of the shale boundary.The termination of the Hackberry sand,along with images of reflections from olderstrata some 150 msec below, generated anupdated seismic interpretation (left). Basedon this survey—at a cost of about $50,000—the IP Petroleum engineers decided not tosidetrack Well 8, saving about $500,000.

The remapping of the Hackberry sandusing the seismic tie developed above sug-gested that a secondary high might exist inthe field in a zone that had previously beenmapped as a water leg. When a well target-ing this zone was drilled, 40 ft [12 m] of oilwas discovered on top of the water, addingnew reserves to the field.

AVO in VSPsWhen a wavefront hits a boundary at verti-cal incidence, the amount of compressionalenergy reflected and transmitted is depen-dent only on the contrast of acousticimpedance—density times compressionalvelocity—of the rocks at that boundary. Butwhen the incident angle is not 0°, theamount of compressional energy reflectedor transmitted depends on the angle of inci-dence, or source offset, and contrasts indensities and shear and compressionalvelocities.11 In such cases, the reflectionAVO can be measured and analyzed toyield information about lithology and porefluid through their effects on density andcompressional and shear velocities.12

Carrying out a walkaway VSP with thereceivers straddling such a boundary allowsdirect measurement of the variation in

Tim

e, s

ec

1600 ft

Well 10 Well 8

1600 ft

Well 10 Well 8

0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

Tim

e, s

ec

0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

measurements made on cores. But beingscale-dependent, anisotropy may be differ-ent at the seismic wavelength scale. There-fore, it is better to measure the elasticanisotropy at the seismic scale.

In 1994, at Schlumberger CambridgeResearch in Cambridge, England, DougMiller proposed a method to do this usingthe arrival times from a walkaway survey toprovide a measure of compressional veloc-ity anisotropy in a shale, and from this tocharacterize the elastic properties of thatshale, governing compressional and verti-cally polarized shear waves.15

Shale consists of finely-layered clayplatelets and exhibits an anisotropy called

nData collection strategy. To evaluate the AVO responses contained within surfaceseismic data, the shooting direction of the walkaway was designed to be the same asthe sail line direction of the 3D surface seismic acquisition. The position of the five-level,three-component downhole geophone array was designed both to provide reflectioninformation from the reservoir and to provide a measure of the TI anisotropy in theshales overlying the reservoir sands, at the same location.

nHorizontal andvertical slow-nesses observedin a walkawayVSP. Anisotropicvelocities, indi-cated by the non-circular curve fitto the data points,can be measuredin situ at the seis-mic scale bywalkaways.

amplitude with offset that arises from lithol-ogy and fluid properties above and belowthe reflector.13 The results can be analyzedfor fluid and lithology identification in awide zone around the well. Formation prop-erties inferred from VSPs can be integratedwith those interpreted from well logs andmeasured directly from cores. In this waythe VSP can also provide independent cali-bration of the same amplitude variation seenacross a surface seismic reflection pointgather—a gather is the collection of tracesthat reflect at the same point, but at differentangles, or offsets.

Calibrating the surface seismic AVO datawith the VSP AVO response brings addedvalue by:• establishing viability of using AVO to

map a reservoir• reducing the risk involved with the added

cost of AVO studies• improving the reliability of AVO

interpretations• quantitatively assessing the effects of

processing on the AVO response.To establish whether AVO is applicable

as an interpretation tool for a particularreservoir, the expected AVO response isusually modeled. This requires knowledgeof the model parameters, including shearvelocity. Dipole shear sonic logging toolsare used to measure shear velocities evenwhere this velocity is slower than the bore-hole fluid velocity.

However, use of density and velocity logdata to model anticipated AVO anomalieshas not always succeeded in fully explain-ing the AVO response observed on surfaceseismic gathers. The reasons for this aremany and include reflectivity mismatchesbetween surface seismic and log data, wavepropagation effects through fine layers, tun-ing effects (constructive and destructiveinterference at seismic wavelengths), geo-metric effects, processing-related issues andintrinsic anisotropy.14

Borehole seismic data can quantify theseeffects. VSPs provide an independent mea-sure of the seismic AVO response and theability to include necessary effects in theforward modeling to satisfactorily explainthe origins of the surface seismic AVOresponse. Anisotropy is one such effect—one that can both mimic and mask AVOresponses, giving false hope for or conceal-ing the presence of hydrocarbons.

Information about anisotropic velocitiesfor forward modeling often comes from

28 Oilfield Review

Sail line ofexisting 3D

Walkaway source pointsVertical incidence source points

Calibration Walkaway in a Producing FieldVe

rtic

al s

low

ness

, sec

/km

Horizontal slowness, sec/km

0.4

0.3

0.2

0.1

0-0.3 -0.2 -0.1 0 0.1 0.2 0.3

transverse isotropy (TI). The acoustic proper-ties vary depending on whether wavespropagate with particle motions parallel orperpendicular to the platelet layers—oftenthought of as horizontally or vertically,because the clays usually lie flat.16

Miller proposed that the vertical slow-ness—the inverse of velocity—of a shalemay be measured across an array of geo-phones for each shot point offset along awalkaway profile. And the horizontal slow-ness can be measured at a single receiverlocation for adjacent shots in the same pro-file, providing the subsurface layers are

nComparing walkaway, walk-above and synthetic data. Thedeconvolved upgoing wavefield of the walkaway is displayedwith two other types of traces spliced in at the zero-offset location.The walk-above trace (left of center) is from the same receiver levelas the central receiver in the walkaway VSP. The walk-abovetrace has been repeated four times for visibility.

A synthetic seismogram (right of center) is derived from densityand calibrated sonic logs corrected to the vertical. For this display,the zero-offset walkaway trace has been shifted to two-way timeand the source wavelet in the synthetic has been chosen to matchthe walkaway source wavelet.

The walk-above VSP data have been processed through a tradi-tional processing sequence. The near-perfect match betweenthese data and the zero-offset walkaway trace gives confidence inthe processed walkaway results, particularly at relatively shortoffsets. The match with the synthetic is complicated by the factthat the well is in a plane that is almost perpendicular to thewalkaway line. Nevertheless, for the top and base reservoir sandinterfaces (black peak at 2.105 sec, white trough at 2.190 sec), the agreement is excellent.

Upgoing Walkaway with Walk-above VSP & Synthetic

Offset, m

Two-

way

trav

el ti

me,

sec

Left Walkaway Right Walkaway

Walk-above VSP Synthetic

1804 1804

2.4

2.3

2.2

2.1

2.0

29Winter 1995

13. Coulomb CA, Stewart RR and Jones MJ: “Elastic WaveAVO Using Borehole Seismic Data,” paper SL3.2,presented at the 62nd SEG Annual InternationalMeeting and Exposition, New Orleans, Louisiana,USA, October 25-29, 1992.

14. See Chiburis et al, reference 12.15. Miller D, Leaney WS and Borland WH: “An In Situ

Estimation of Anisotropic Elastic Moduli for a Subma-rine Shale,” Journal of Geophysical Research 99, no.B11 (November 10, 1994): 21,659-21,665.

16. For an overview of elastic anisotropy:Armstrong P, Ireson D, Chmela B, Dodds K, EsmersoyC, Miller D, Hornby B, Sayers C, Schoenberg M andLynn H: “The Promise of Elastic Anisotropy,” OilfieldReview 6, no. 4 (October 1994): 36-47.

essentially flat. A crossplot of these mea-surements for each shot position defines thecompressional anisotropic response of theshale. A curve fitted to these data pointsprovides a solution to the equations thatdeliver shear anisotropy through a completedescription of the elastic properties of theshale (previous page, top).

The constraint of flat layers has now beengeneralized to dipping layers by work atSchlumberger Cambridge Research.

These research efforts have been put topractical use in the BP-operated Forties fieldin the UK sector of the North Sea. The ulti-mate aim is to enable AVO attributes to bemapped with confidence from 3D surfaceseismic data. To achieve this, a detailed eval-uation of shear velocity anisotropy in the for-mations overlying the Forties sand has beenundertaken to build a velocity model. Thedata used included acoustic measurementsfrom preserved shale and sand cores, a fullsuite of logs—including standard density andDSI Dipole Shear Sonic Imager logs—inaddition to walkaway, rig source and verti-cal-incidence VSP data.17

To evaluate the AVO responses exhibitedby the surface seismic data at the target, theshooting direction of the walkaway wasdesigned to be in the same as that of the saillines of the 3D surface seismic acquisition(previous page, middle).

To sample a wide range of incidenceangles at a common reflection point for AVOevaluation of the reservoir, the geophonearray must be close to the reservoir. Typi-cally, this will be in the caprock just abovethe reservoir, facilitating the measurement ofanisotropy in the caprock at the same time.

In the Forties case, an ASI tool consistingof five magnetically clamped, three-compo-nent receivers, spaced at 15-m [49-ft] mea-sured depth intervals, was positioned so thatthe upper three receivers were in a tuff layerabove the shale that contains the two deep-est receivers.18 The interface at the base ofthe shale represents the top of the reservoirsand, which contains an oil column of only7 m [23 ft] in this well. The source used forthe walkaway acquisition was a small clus-tered sleeve gun array.

The walkaway processing for AVO analy-sis involved three steps: the standard stepsfor data orientation through triaxial projec-tion, parametric wavefield decompositionfor wavefield separation and wavelet stabi-lization through deconvolution.19

With the complete data set, several com-parisons could be made. The walk-abovesurvey assessed the vertical-incidence seis-

mic response near the well, for comparisonwith the vertical-incidence synthetic seis-mogram generated from density and cali-brated compressional-velocity logs (above).The walk-above data and synthetic tracesboth match the nearest offsets of the walka-way data. The walkaway data show varia-tion of reflection amplitudes as a function ofoffset, and can be compared with the sur-

face seismic AVO, when the data becomeavailable.

The next phase of the project was tomodel the walkaway VSP using density andcompressional (P)- and shear (S)-wave soniclogs, but also allowing nonnormal inci-dence angles. The predicted AVO responsewas computed using an algorithm devel-oped at Schlumberger Cambridge Research

17. This combination allowed sonic measurements to becompared with core data, and anisotropy parame-ters from VSPs to be compared with core anisotropy.In both cases good agreement was found.Armstrong PN, Chmela W and Leaney WS: “AVOCalibration Using Borehole Data,” First Break 13,no. 8 (August 1995): 319-328.

18. Tuff is lithified volcanic ash.19. Esmersoy C: “Inversion of P and SV Waves from

Multicomponent Offset Vertical Seismic Profiles,”Geophysics 55 (1990): 39-50.Leaney WS: “Parametric Wavefield Decompositionand Applications,” paper SE2.40, presented at the60th SEG Annual International Meeting and Exposi-tion, San Francisco, California, USA, September 23-27, 1990.

nIsotropic and TImodels. In the firstmodel, the shaleoverlying the reser-voir sand is assumedto be isotropic (left).For the second model,key anisotropy factorscalculated from thewalkaway travel-timesurface were used tomake the shale trans-versely isotropic (TI)(right). Differences inAVO behavior are vis-ible in the reflectionat 1.07 sec, zero-offsettime. The TI modelshows an earlierincrease in amplitudethan the isotropicmodel.

nAVO calibration.Measured walkawayAVO response at thecaprock/oil-sandinterface is shown asa red line (top), andthe response at thebase of the sand as apurple line (bottom).The equivalent mod-eled response utiliz-ing an isotropiccaprock shale isshown in orange,and provides a poorfit to the measuredresponse at longeroffsets. Includingtransverse isotropy(TI) in the caprockshale (green) gives abetter match withthe observed data.However, the shalebelow the base of thesand can be ade-quately modeled asisotropic. The sand ismodeled as isotropicin all cases.

that accounts for fine layers, tuning effectsand shale anisotropy.

Initially, two models were generated, oneassuming the shale overlying the reservoirsand was isotropic and another in which TIanisotropy was introduced (right). Differ-ences in amplitude response between thetwo models were immediately observed,particularly at far offsets for the interfacebetween the shale and the reservoir sand at1.07 sec normal incidence time.

The predicted response assuming ananisotropic shale was validated by theamplitude measured in the calibration walk-away (below, right).20 This implies that theeffect of the anisotropic velocity in the shalemust be taken into account before attribut-ing the AVO response in the surface seismicdata to effects of fluids in the reservoir.

It is clear from this study that the combi-nation of AVO measurement from VSP andlog-based, anisotropic forward modelingprovides a powerful methodology for cali-brating AVO responses observed on surfaceseismic data near wells in low dip struc-tures. Where AVO analysis is used as thebasis for hydrocarbon indication in fieldswith existing wells, the method helps iden-tify the origin of observed AVO effects,determining whether large-scale AVO analy-sis and reprocessing effort are worthwhile interms of achieving the desired objectives.The greater understanding of observed AVOeffects should minimize the risk of missinggenuine hydrocarbon-related AVO anoma-lies or of misinterpreting anomalies causedby other factors, such as anisotropy.

The same combination of data can beused to evaluate and calibrate the seismicresponse to other properties such as porosityvia amplitude inversion (see “Seismic Toolsfor Reservoir Management,” page 4).

An intriguing prospect is the integration ofthe information described above to improvethe quality of surface seismic data. Geco-Prakla uses borehole seismic data in theSurvey Evaluation and Design process tooptimize acquisition and processing param-eters for new 3D surveys and to providequantitative quality control during theacquisition and processing phases.21

30Oilfield Review

20. See Leaney, reference 12.21. Ashton CP, Bacon B, Mann A, Moldoveanu N,

Déplanté C, Ireson D, Sinclair T and Redekop G:“3D Seismic Survey Design,” Oilfield Review 6, no. 2 (April 1994): 19-32.

Walkaway VSP Models

Tim

e, s

ec

20 400 800 1200 1600 20 400 800 1200 16001.0

1.1

1.2

1.3

1.4

1.5

Isotropic shale TI shale

Offset, m Offset, m

Top sand (measured from walkaway VSP)

Model top sand overlain by isotropic shale

Model top sand overlain by transverselyisotropic (TI) shale

Base sand (measured from walkaway VSP)

Model base sand (isotropic)

4 11 18 26 33 41 48 56100 300 500 700 900 1100 1300 1500

Angle, degree/offset, m

Base sand interface

AVO Calibration

Top sandinterface

10

8

6

4

2

0

-2

-4

-6

-8

-10

Am

plitu

de

31Winter 1995

In order to use borehole data to improveand quantify the information content of sur-face seismic data, it is necessary to under-stand the relationship between the differentmeasurements. The potential role of bore-hole seismic data in this respect may beillustrated using the Forties data setdescribed above (right).

In this example, the same Vp and Vs logsobtained from DSI measurements have beenused to produce a synthetic seismogram tobe compared with the measured zero-offsetresponse from the walkaway, then with tracesfrom the 3D survey. The synthetic must be“corrected” for geometric effects due to thelateral offset from source to receiver and thenstacked using the same number of traces andoffset range as used in the surface seismicprocessing. Similarly, the walkaway VSP dataset is corrected and stacked.

The stacked walkaway matches the sur-face seismic data better than the log-basedsynthetic. The first thing this indicates isthat the walkaway more closely resemblesthe physical experiment of the seismic sur-vey. But second, and more important, thesurface seismic traces, although processedto deliver an estimate of the vertical-inci-dence response, do not match a normalincidence model.

The borehole seismic measurement con-nects the log-generated synthetic and thesurface seismic data. The addition of such ameasurement provides a mechanism foridentifying and reducing the uncertaintyassociated with the log and surface seismicmeasurements through evaluation and cali-bration using the borehole seismic data as acontrol. Upscaling the log information tothe seismic scale—not always a trivialstep—is facilitated through the comparisonof the synthetic seismogram with the bore-hole seismic. Last but not least, the indepen-dent measure of the seismic response in theborehole can be used to quantitatively eval-uate the processing of the surface seismicdata at the well location to assure an opti-mum result.

Looking to the FutureWe have seen a distinct evolution in thecomplexity of information provided by bore-hole geophysics. First, direct travel-timecheck shots simply related time to depth.Then, VSP reflection information improvedstructural imaging. Now, AVO and anisotropyare probing the fine-scale properties of theformation within that structure.

But it doesn’t stop there. Borehole seismicsurveys bridge the gap between the log andseismic measurements, merging data atscales as fine as borehole resistivity imageswith reservoir-scale pictures of seismic reflec-tions. Moreover, VSPs span the life of thereservoir, from VSPs while drilling to surveysthrough production tubing. It is clear thatwhile wellbore geophysics is already deliver-ing valuable information, the techniquepromises a great deal more in the future.

—CF, LS

nAssessing the quality of surface seismic surveys using boreholegeophysical data in addition to log-derived synthetics. Data fromDSI measurements have been used to produce a synthetic zero-off-set seismogram (track 2) and a stacked synthetic offset seismogram(track 3). These traces do not compare well with the migrated 3Dsurface seismic data from the vicinity of the well (track 5). The zero-offset traces from the walkaway survey (track 1) show a better, butless than desirable correlation with the surface seismic data thando the stacked walkaway data (track 4). This example reinforcesthe fact that stacked surface seismic data may not provide accu-rate estimates of properties that can be derived from logs unlessborehole seismic information is incorporated.

Tim

e, m

sec

Migrated 3Dsurface seismic

section

Walkawayzero-offset

trace

Syntheticzero-offset

trace

Stackedsynthetic

Stackedwalkaway

2200

2100

2300

2400

2500