2 Oilfield Review

Seismic Integration to Reduce Risk

Rune HopeTOTAL ThailandBangkok, Thailand

Dick IresonScott LeaneyGatwick, England, UK

Joerg MeyerDallas, Texas, USA

Wayne TittleSonat ExplorationTyler, Texas

Mark WillisMobil Exploration and ProductionDallas, Texas

Despite the enormous advances in surface seismic acquisition,

processing and interpretation over the past decade, drilling still

involves uncertainty. These financial and economic risks, however,

are being ameliorated by new techniques that are emerging from

the combination of borehole- and surface-acquired seismic data.

From their first use in 1928, surface seismicsurveys have been lauded for their effect onexploration success, reducing risk apprecia-bly.1 During the years since, surveys haveextended from two-dimensional (2D) tothree-dimensional (3D), and have expandedto encompass the development and produc-tion as well as exploratory phases of reservoirlife. Likewise, advances in seismic data pro-cessing utilizing massively parallel computersand integrated reservoir imaging softwarehave improved the reliability of data interpre-tation and thereby of drilling accuracy itself.

Risk, nevertheless, remains a major factorin all phases of oil and gas reservoir exploita-tion, and this is particularly true when mar-ket conditions drive operators to obtainmaximum value from their investment inseismic data.

One sure way to increase the value of sur-face seismic data is to incorporate boreholeseismic measurements. Integration of bore-hole seismic and surface seismic data canoccur at two levels. The most basic is whenborehole seismic velocities are used to con-vert seismic sections from time to depth andwhen images are used to fill gaps where sur-face seismic acquisition fails. The second,and more far-reaching, is to use boreholeseismic measurements to get better surfaceseismic results—to optimize survey plan-ning, guide data processing, and producehigher quality, quantitative, calibratedimages from the surface seismic data.Surface seismic data created in this way pro-vide a more consistent interpretation and amore complete picture, or solution.

Autumn 1998 3

Surface and Borehole Seismic Basics Surface seismic data are acquired with bothsource and receiver essentially on the surfaceof the earth. Sound energy generated by thesource propagates in all directions, but theuseful energy is that which travels down,reflects at layer interfaces, and comes backup to the receiver. The receiver records dataas wiggles with amplitude that varies withtime, and through sophisticated processingthese are turned into an image of the reflec-tors. However, unless the velocities of thelayers are known, the image cannot be con-verted accurately from time to depth. And ifthere are obstructions on the surface that pre-clude source or receiver placement, or if the

subsurface properties are such that reflectionsdon’t travel back up to the receivers, thenthere is no surface seismic image at all.Borehole seismic techniques and data areusually applied to overcome these limitations.

Borehole seismic surveys, also known asvertical seismic profiles (VSPs) are acquiredwith the source on the surface and receiversat known depths in the borehole. Energyfrom the source arrives at the receivers bothdirectly, as the first arrival, and also afterreflection from interfaces below the receiver.The simplest borehole survey is the checkshot, or velocity survey, in which a receiveris stationed at specific intervals—often sepa-rated by hundreds of feet or meters—in the

borehole while the surface source is firednearly vertically above. The receiver recordsthe traveltime from source to depth, at sev-eral depths, and a table is constructed of theseismic velocities between the depth sta-tions. This velocity table can be used to con-vert, albeit crudely, a surface seismic sectionfrom time to depth, or logs from depth totime.

A VSP provides more data than a check shotbecause the distance between geophonerecording depths is far less—every 15 to 30 m[49 to 98 ft]. In addition, VSPs collect notonly first arrivals of the seismic energy but theentire wavetrain, which is processed forupgoing and downgoing events.2

1. Hyne N: Nontechnical Guide to Petroleum Geology,Exploration, Drilling and Production. Tulsa,Oklahoma, USA: PennWell Books (1995): 236.

2. Gadallah M: Reservoir Seismology: Geophysics inNontechnical Language. Tulsa, Oklahoma, USA:PennWell Books (1994): 139-178.

For help in preparation of this article, thanks to Dean Clark, Ian Scott and Mark Wheeler, Geco-Prakla,Gatwick, England, UK; Greg Lerigier, Geco-Prakla,Houston, Texas, USA; Rutger Gras, GeoQuest, Gatwick;Keith Tushingham, GeoQuest, Houston, Texas; Steve Horne, Everhard Muyzert and Carl Spencer,Schlumberger Cambridge Research, Cambridge, England.

ASI (Array Seismic Imager), CSI (Combinable SeismicImager), DSI (Dipole Shear Sonic Imager), FMI (FullboreFormation MicroImager), GeoViz, IESX and SAT (SeismicAcquisition Tool) are marks of Schlumberger.

4 Oilfield Review

Most VSP surveys are two-dimensional andare achieved with a variety of configurations(above). These include zero-offset VSPs,where the source is near the wellheaddirectly above the receivers; offset VSPs, withthe source on the surface some distance fromthe borehole; walkaway VSPs, in which mul-tiple sources are located along a line extend-ing away from the well while an array ofgeophone receivers is fixed in the borehole;walk-above VSPs, where sources are posi-tioned directly over receivers in a deviated orhorizontal well; salt-proximity VSPs, with asource above the salt dome and receivers inthe wellbore in a vertical plane containingthe source; shear-wave VSPs, acquired withshear-wave sources; and seismic-while-drilling (SWD) drill-noise VSPs, where thedrill bit is itself the seismic source andreceivers are on the surface.3 Three-dimen-sional VSPs are essentially walkaway profilesin which multiple lines of sources or spiral-ing lines of sources extend away from thewell and an array of geophone sensors isdeployed in the borehole.

Borehole seismic receiver tools aredesigned for either cased or uncased holes,or both, and have from 1 to 12 receiver lev-els, with varying combinations of geophones

and hydrophones (next page, top left). Thereare, in addition, borehole seismic tools thatcan combine with themselves or other wire-line logging tools for openhole VSP dataacquisition, or be run inside or conveyed ondrillpipe to acquire VSPs in highly deviatedand horizontal wells (next page, bottom).

Because the geophones are situated deepwithin the strata when obtaining a VSP, someof the disadvantages of surface seismicacquisition are avoided. Accurate depths areregistered, and surface noise is reduced,yielding data with less distortion andenhanced frequency content. Furthermore,the use of the full waveform allows betteridentification and treatment of noise that cancontaminate surface seismic records.

The integration of borehole seismic andsurface seismic data is not entirely new.Check-shot services for time-to-depth con-version have existed in the oil field since the1950s, but full-fledged waveform VSPs havebeen tapped only since the 1980s. Through aseries of case studies, this article tracksrecent developments in existing methods,then introduces some new integration tech-niques that are also proving to reducedrilling risk.

Filling Gas GapsPhillips Petroleum Norway has been inte-grating borehole seismic images with surfaceseismic data to revitalize production from itsgiant Ekofisk field in the Norwegian sector ofthe North Sea. It had been highly productive,generating oil and gas from the Danian- andMaastrichtian-age chalk reservoir for morethan 26 years, but production was dropping,and Phillips determined to redevelop thefield by drilling some 50 new wells, addinga sophisticated waterflood system andinstalling new surface facilities.

A major problem in mapping the fieldusing surface seismic data is the presence ofa gas “cloud” above part of the reservoir. Inthis area, a surface seismic-derived image ofthe reservoir is not achievable (next page,top right). This means that wells drilled intothe crest of the structure are riskier as thedetailed fault patterns are not mappeddirectly from the surface seismic data.

3. Christie P, Dodds K, Ireson D, Johnston L, Rutherford J,Schaffner J and Smith N: “Borehole Seismic DataSharpen the Reservoir Image,” Oilfield Review 7, no. 4(Winter 1995): 18-31.

Salt

Drillbit

Receivers

B. Offset VSP C. Walkaway VSP D. Walk-above VSP

E. Salt-proximity VSP F. SWD (drill-bit) VSP G. Multi-offset VSP

Direct waveDowngoing multiple

Geophone position

Reflected primary

Reflected upgoing

multiple

Subsurface

reflector

Time

A. Zero-offset VSP

Source

offset

■■Some types of vertical seismic profiles (VSPs). The most common VSP surveys include: A. Zero-offset VSP, B. Offset VSP, C. WalkawayVSP, D. Walk-above VSP, E. Salt-proximity VSP, F. Drill-bit VSP and G. Multi-offset VSP. Ray paths are shown as black lines.

Autumn 1998 5

■■Magnetically clamped ASI Array SeismicImager tool. This tool has five seismic shuttles linked by a bridle to a signal-conditioning cartridge. Each shuttle sensorcontains three fixed orthogonal geophones.

Tensionsub

Wetconnect

Gammaspectroscopy

Compressionsub

Resistivity

Pressuresampling

Sonic Gammadensity

Neutronporosity

CSItool

■■Efficiency with the CSI Combinable Seismic Imager tool. This tool can combine with other logging tools and physi-cally isolates its sensor module by anchoring it against the formation, achieving optimum acoustic coupling for itsthree gimbaled geophones that is verified by a shaker source within the module.

8787 m

16,8

87 m

2960 ms 3244 ms

■■Ekofisk contoured seismic time surface. This surface shows the area where the top of the Ekofiskreservoir can be interpreted from surface seismicdata, and indicates the seismic time associatedwith the reservoir top. The area in black cannot be imaged with surface seismic alone and needsintegration of 3D VSP data.

6 Oilfield Review

A combination of 2D and, recently, 3DVSP techniques does, however, provideimages of the reservoir in the gas-obscuredarea (above). This is achieved by placingthe VSP receivers below the gas cloud incarefully selected wells. The use of thedirect arrival traveltimes obtained fromnumerous source positions, particularly inthe 3D VSP, allows the existing velocitymodel to be upgraded. When the reflectiondata from the same VSP data set arefocused using this upgraded velocitymodel, a clear image of the reservoiremerges. The 3D VSP image can then becombined with the existing 3D surface seis-mic image to provide a continuous picture.

Thus, in gas-obscured areas where 3D VSPdata have provided images, the reservoirstructure can be mapped with greatlyincreased confidence. This will dramaticallyreduce the uncertainty associated with thepositioning of wells.

Borehole-Guided ProcessingThe second level of borehole-surface seismicintegration is achieved when VSPs provideinformation to produce higher quality sur-face seismic results. In the simplest cases,VSP data, together with synthetic seismo-grams derived from velocity and density logdata, have been used to determine the prop-erties of the wavelet, or basic pulse responsefrom a reflector, contained within themigrated surface seismic data. This knowl-edge allows the surface seismic wavelet tobe “zero-phased,” providing optimal resolu-tion for interpretation.

In order for this process to be successful, thesame sequence of wavelets must exist in bothdata sets. Because they include both down-going and upgoing waves, VSP data can beprocessed in a straightforward manner toremove multiples, or unwanted reverbera-tions, and provide a sequence of waveletsthat relates directly to the local geology.Surface seismic data, on the other hand, relyupon more indirect techniques to removemultiples and produce the correct sequenceof wavelets in both time and space.

A comparison between the desired seismicresponse—provided by the VSP—and thesurface seismic response in the vicinity of thewell, at various stages during processing, can

indicate how well the surface seismic dataare converging to the desired result. The VSPimage is generally at a higher resolution thanthe surface seismic data and is producedwithout the necessity of a comprehensiveediting process that accompanies the genera-tion of synthetic seismograms derived fromacoustic and density logs. Furthermore,because the VSP reacts to dip in the sameway as the surface seismic data, imagesextracted from the VSP data can be compareddirectly with unmigrated surface seismicdata. This permits monitoring of parameterand technique selection from the beginningof the surface seismic processing sequencewithout having to go through a costly andtime-consuming migration process to com-pare the data sets.

In addition, it is very desirable to monitor theeffect of any process on the wavelet phase. Byextracting the embedded wavelets at anystage during the processing, not just aftermigration—the residual wavelet stage, in seis-mic terms—it is possible to see how theattributes of the extracted wavelet are affectedby any processing step and note any signifi-cant variations between wells. These interwellchanges may be spatially mapped by lookingat the variations in statistically derivedattributes occurring in the surface seismic dataand calibrating them to the wells.

1000

m

4500 m

■■Filling the gap. This vertical cut in the 3D surface seismic data volume (left) is made along a line corresponding to a traverse in the 3D VSP data. The image of the structural crest is obscured by gas, which disrupts seismic wave propagation. With only interpolationbetween existing well locations to rely on, confidence in positioning a crestal well to miss possible faults is low. The correspondingtraverse from the 3D VSP image (right) is superimposed on the first figure. It is clear that the hole in the data at and above the reservoirlevel has been very effectively filled, providing increased confidence in planning crestal wells.

1000

m4500 m

Autumn 1998 7

In a North Sea example, the integration ofborehole data and surface seismic data pro-duced a quantitative approach to the selec-tion of a demultiple technique—a methodfor removing seismic reverberations—andparameters, thereby increasing confidencein the conformation of the final surface datato the reflection sequence derived from theborehole data.4

The Mobil North Sea Ltd. Beryl field, UKsector blocks 12 and 13, lies in a structurallycomplex and highly faulted area (above).Interpretation of its target zone was compro-mised by reflections that were masked byfree-surface multiples in a low-reflectivityportion of the survey area. The operatorrequired better quality final 3D volumes toachieve an improved structural interpreta-tion, thus new 3D surface seismic acquisitionand processing were conducted. During thepast 20 years, there had been many checkshots and VSPs shot over the main structure,and these data were used to assure an objec-tive rather than subjective approach todemultiple optimization.

Prior to the acquisition and processing ofthe new 3D data, existing surface and VSPdata were used to optimize the design of the

acquisition, then a set of the VSPs wasselected from a vertical section of the well-bore with sufficient receiver levels in the tar-get zone to cover the field adequately. TheVSPs were dip-corrected for premigrationmatching to the surface data.

The goal is to match surface seismic tracesin a small volume around each well to theVSP traces acquired in that well. To deter-mine the match “location” for each VSP, a 1-km2 [0.39-sq mile] data cube was extractedfrom an existing stacked but unmigrated 3Dsurface data set along the path of each well inthe target zone. Partial spectral coherencematching was carried out to mate the trans-posed and dip-corrected VSP trace with theseismic data in several time windows con-centrated around the target zone, and pre-dictability was assessed for each match, witha predictability surface generated for eachmatch time window, from which the bestmatch locations in space and time weredetermined. After the new 3D survey wascompleted, traces covering the VSP locationswere examined, and the match was recon-firmed (above right). Once that was done, thedata sets were used to optimize the selectionof demultiple technique and parameters.

4. Clark D, Scott I and Willis M: “Using Borehole Datato Optimize Demultiple Parameter Selection—ANorth Sea Example,” paper SP 9.7, presented at the68th Annual International Meeting of the Society ofExploration Geophysicists, New Orleans, Louisiana,USA, September 13-18, 1998.

6.5 58Predictability, %

1 km

1 km

■■Color-coded matching. The quality of theposition match for the VSP trace within thesurface seismic volume is shown by color,with the best match in white (top). Thematch is computed in a 1 by 1 km2

volume in a time window across the reservoir. Inserting the dip-corrected VSPinto this best match position along a 2Dpanel (bottom) from the stacked, newlyacquired surface seismic data confirmsthe quality of the trace match.

2.5 s

3.0 s

950 m

East Shetlandplatform

South Vikinggraben

Crawford spur

Berylfield

N

0 5mi

km0 8

■■The Beryl Field. The green area within the box represents theapproximate extent of the primary field.

8 Oilfield Review

During the demultiple testing stage of theproject, the use of these small test data setsand repeated surface and borehole seismiccomparison made it possible to test numer-ous combinations of techniques and parame-ters and to quantify even the most subtledifferences. In addition, target-oriented statis-tical attributes were derived from the surfaceseismic data set. These measurements wereused to classify the target data’s geophysicalcharacteristics spatially into a number of datatypes. This classification revealed how theresults at a particular well were representativeof the whole data set (below).

A choice of two demultiple techniquesresulted from the optimization process, vari-able tau-p deconvolution and conventionaldeconvolution before stack (dbs).5 The tau-pdeconvolution emerged as the technique ofchoice following application by interpretersto make composite sections for each well. A0.5-km [0.31-mile] stack mini-cube wasextracted from around each well at key stagesin the processing sequence for added qualityassurance. This demonstrated that a straight-forward approach to demultiple algorithmand parameter selection by integrating sur-face and borehole seismic data at a very earlystage provided confidence in the final 3Ddata volume for interpretation and inversion.

Reef SteeringBorehole data can also be used later in theprocessing sequence to enhance surfaceseismic images and reduce drilling risk.Sonat Exploration integrates its 3D surfaceseismic data with VSP data to overcomesome of the limitations and pitfalls of 3Dseismic data while prospecting for very smalldrilling targets—between 20 and 60 acres [9 and 24 hectares]. Borehole and surfaceseismic data integration allows the companyto carry out its final and most critical step,seismic migration, properly. Migration per-formed with the appropriate velocity func-tion positions and focuses a reflection

Pre

dic

tab

ility

, %

4240

30

5956

36

45

204

2028

406072

4 2028 40

6072

120180

240300

360420

120180

240300

360420

Pre

dic

tab

ility

, %

Well A Well B

Match power at Well A

dbs tau-p

Seismic section Match power at Well B

dbs

60

50

40

30

20

10

0

60

50

40

30

20

10

0tau-p

Prediction gap, ms Ope

rato

r len

gth,

ms

Prediction gap, ms Opera

tor l

engt

h, m

s

Surface A Surface B

■■Comparing wells. The difference between data type areas is evident in this comparison of wells A (left) and B (right). The blue lines in the lower middle image are the well locations on a panel between the two wells extracted from the 3D seismic volume. The left andright upper images demonstrate the match surface obtained at each well by varying two parameters—the prediction gap and theoperator length—in a particular demultiple technique. The bottom left and right charts illustrate the optimum parameter selectionmatch for two different demultiple techniques. The upper middle image is a composite of four target-oriented statistical attributesgenerated from the surface seismic data. The two wells are in different data-type areas, which may explain why there is variation inthe success of different demultiple techniques at the two locations.

Autumn 1998 9

element correctly in the subsurface to pro-vide a sharper image for steering the drillinginto the target. Sonat has accomplished thismore than 20 times with extraordinary accu-racy on the East Texas Cotton Valley PinnacleReef trend, one of North America’s mostdynamic onshore plays (right).

The Cotton Valley Pinnacle Reef play is a collection of Jurassic carbonate build-upswith known reserves of up to 80 Bcf [2.265Bm3] natural gas. Most reefs that are drillingtargets in the trend have an elliptical shapeand steep seaside flanks that can fall offsharply. The relatively small lateral footprint—a diameter of 600 to 800 ft [183 to 244 m]—and depths to 18,000 ft [5486 m] compoundthe complexity of accurately fixing the reefanomaly in space. Vertical sections rangefrom 400 to 1300 ft [122 to 396 m].

Located at the transition from Bossier shaleto Cotton Valley limestone in Bossier sands,the trend is characterized by a hostile envi-ronment, with high temperatures at the tar-get depth ranging from 375 to 400°F [190.5to 204.4°C]. There is a pressure gradient of0.8 to 0.9 psi/ft, so bottomhole pressures areabout 18,000 to 20,000 psi [124,105 to137,888 kPa]. In addition, there are sour gasand carbon dioxide contents that affectdrilling and logging tools. With such highrisks, completion costs per well rangebetween $5 million and $7.2 million, butthe rewards are significant; some wells havetested 35 MMcf/D [991 MMm3/d] gas, andsome have sustained their initial productionof 5 to 10 MMcf/D [141,580 to 283,169m3/d] gas for over a year.

Sonat attributes its success in the play tothe advent of affordable 3D seismic acquisi-tion and its technical growth since the areafirst was explored. Before 1995, more than800 wells were drilled in the Cotton ValleyPinnacle Reef trend based on 2D data, butwith poor results most of the time. The playtook off significantly in 1995, when 3D seis-mology became a major tool in onshore

exploration.6 There are still limitations, suchas having to operate with wavelengths on theorder of 400 ft [122 m], but it is possible toobtain between 150- to 250-ft [46- to 76-m]vertical resolution with surface seismic data.It is also a challenge to identify small reefswhose seismic expressions span only sixseismic traces.

Another limitation is to rely solely on sur-face-based measurements for the analysis ofsurface seismic data-processing parameters.A critical step in obtaining a reliable imageof subsurface reflectors is creating the cor-rect velocity model of the subsurface itself.

This can be derived from surface seismicdata to some degree, but only borehole sur-veys can extract seismic velocities of geo-logic formations. It is here that Sonat made abreakthrough by integrating borehole seis-mic and surface seismic data.

The borehole seismic process measures thetrue velocities of the subsurface instead ofattempting to derive them from measure-ments on the surface. In addition, a measure-ment of the seismic wavefield at depth isobtained, and thus a much broader calibra-tion toolkit is available for properly process-ing surface seismic data. The VSP recordings

5. Tau-p is the name given to a coordinate space intowhich seismic data are transformed for processing.Tau has units of time and p has units of inverse veloc-ity. Deconvolution is an inverse filtering process torestore a wavelet to its original form.

6. Shirley K: “3-D Still Sparks Cotton Valley Play,” AAPGExplorer 19, no. 9 (September 1998): 32-35.

Louisiana

Eastern play

Outboard play

Northern play

Southern play

• Dallas• Tyler Kilgore

• Longview

•

Texas

0 km 48

0 mi 30

■■The Cotton Valley Pinnacle Reef play. The orange areas indicate a widespread onshoregas play stretching across eight counties of East Texas. Areas with known reefs areshown in blue.

10 Oilfield Review

usually contain higher frequencies and pro-vide a higher resolution image of subsurfacefeatures (left). Furthermore, a borehole seis-mic survey using the offset VSP configura-tions creates additional and calibratedimages of the subsurface around the welland even ahead of the drill bit. Today, themost significant advances are made when allthe borehole seismic information—velocity,amplitude, phase and polarization—is usedto quality control and improve the surfaceseismic processing.

The borehole survey also provides a pre-ferred recording environment, with lessnoise related to traffic or weather. In theopenhole conditions of the Cotton Valley, thedual CSI Combinable Seismic Imager toolwith 60-ft [18-m] spacers is used for mostsurveys. Flasked SAT Seismic AcquisitionTool instruments are used for the hotterholes. Data are recorded from up to fouroffset locations per trip in the hole, with off-sets ranging from 3000 to 8000 ft [914 to2438 m] away from the wellbore. Surveysrange in size from 3 to 14 offsets with up to10 vibrator trucks per VSP job.

Before the use of borehole seismic tech-niques, the overall success rate for new wellswas about 45% in the reef play. Today, SonatExploration is the only operator in the trendthat runs borehole seismic surveys beforereaching the target depth on all of the wells itdrills, and it has had an unparalleled successrate of 90% in the play, with failures occur-ring when structures looked like reefs but, infact, were not. The breakthrough has comefrom using the borehole survey not only as adiagnostic calibration tool—imaging after thehole is drilled—but from exploiting its pre-dictive features to look ahead and around thedrill bit in near real time as well.

To increase its success rate as well asreduce exploration risk, Sonat employs twoapproaches in the use of borehole seismicinformation.7 First, a zero-offset VSP is runwith the source in the vicinity of the rig, andvelocities and seismic waves are recorded inthe wellbore. This calibrated velocity infor-mation is used as the main input for migrat-ing surface seismic data. A small subvolumeof the 3D data around the wellbore is remi-grated to update the drilling target location.This operation, usually applied to poststackdata, can be conducted within a shortturnaround time to facilitate drilling deci-sions. In one case, by applying this techniqueSonat was able to avoid drilling a nonreefstructure that turned out to be a fault (left).

In this example, artifacts caused by incor-rect migration velocities created a seismicanomaly that looked like a reef. After remi-gration and offset VSP interpretation, the drill

200210220230240250260270

200210220230240250

8800 ft

6600 ft

575

ms

575

ms

■■Reefs or somethingelse? Reef-like structures on surfaceseismic images canturn out to be processing artifacts.What appears to bea reef before integrating VSPinformation (top) isexposed as a fault(red) after applyingthe correct velocitiesmeasured by theVSP (bottom). As aresult of a look-ahead VSP survey,the drill bit could besteered away fromthe fault into thenearby reef to makea successful well onthe first attempt.

Potential well locationSurface seismic line

Reef

Reef

Zone of uncertainty

Drilling rig

Wellbore

Zone of uncertainty reduced

■■Less uncertaintywith a VSP. Surface seismicwaves, with theirlower frequenciesand greater distance betweenreflector andreceiver, can “see”objects only if theyare big enough.Small features,such as reefs, fallin a zone of uncer-tainty (top). VSPshave shorterwavelengths andshorter reflector-receiver distance,and smaller zonesof uncertainty(bottom).

Autumn 1998 11

bit could be steered a couple of hundred feetaway to intersect a reef and make a success-ful well. This example emphasizes that thecritical seismic processing step of migrationhas to perform the task of not only properlypositioning reflections of the subsurface, butalso focusing structure, particularly aroundabrupt changes like faults.

The second reef-finding approach Sonatemploys, developed since June 1996, appliesthe look-around and look-ahead capability ofborehole surveys. In employing it, the drillingoperation is temporarily suspended at a cer-tain depth above the target to map the actualposition of the reef in 3D with a sequence ofoffset VSPs distributed radially around thewellbore. These additional VSP data are thenintegrated with the surface seismic data usingIESX seismic interpretation software andGeoViz 3D interpretation and geovisualiza-tion software. The new interpretation is usedfor a final update of the drilling direction andto steer the subsequent drilling down to thereef target (above).

The technique has been termed RSVP, forreef steering by vertical seismic profiling, areal-time survey while drilling that requiresonly one to two days downtime for the VSPacquisition. Drillers are finding it worth theirwhile to be idle for the additional two days ittakes to complete the processing and inter-pretation while geoscience colleaguesupdate the subsurface model and providenew coordinates for optimum reef intersec-tion. This additional time, however, has beenused to acquire other wireline logs at thisintermediate depth.

Sonat’s experience has shown that the bestproduction resulted from wells that penetratethe reef near the core. The offset VSPs helplocate the center of these features by imagingthe limits of the regional limestone that sur-rounds them (right).

7. Meyer J and Tittle W: “Exploration Risk ReductionUsing Borehole Seismic: East Texas Pinnacle ReefApplications,” paper BH 4.3, presented at the 68thAnnual International Meeting of the Society ofExploration Geophysicists, New Orleans, Louisiana,USA, September 13-18, 1998.

VSPSurface seismic

8700 ft

1.4

s

■■Surface seismic image before and after VSP integration to image a reef. The surface seismic image (left) shows a hint of a reef as a disruption of the regional limestone reflector. With the VSP image inserted, the disruption of the regional reflector is clearer, delineating the extent of the reef (right). The well trajectory is indicated by the vertical line.

Reef fringe

Sidetrack

Newproduction

wellCook 3

VSPinterpretation

Reef core

Surfacelocation

VSParm 1

VSParm 4

VSParm 3

VSParm 2

Cook 2Original hole

Cook 2

•

•

•

0 ft 400

0 m 122

■■Multiple interpretations of the Cook field reef in the Cotton Valley Pinnacle Reef play. The original well, Cook 2, was drilled to a nonpay zone on the fringe of the reef, then side-tracked east into a dry hole. Four VSPs (arms 1, 2, 3 and 4) were shot to illuminate the reefby imaging the extent of the regional limestone reflector that is disrupted by the presenceof the reef. The segments of the limestone reflector imaged by the VSPs are shown as greenlines. The absence of a green line means the presence of a reef, indicated by the dashedpurple circle. Following this interpretation, Well Cook 3 was drilled into the center of thereef and is now producing, at a distance of only 400 feet from the abandoned Cook 2. Theblue elongated feature with a pink core is the new interpretation of the reef shape basedon surface seismic data remigrated with VSP velocities.

Pinnacle reef

Haynesville reflectorShale

Cook #2

Limestone

Salt

1.4

s

8700 ft

12 Oilfield Review

For those unwilling to hold up drilling, athird technique—the reef recovery method—applies when the drilling target has beenmissed. In this remedy, wireline logs are runand a borehole seismic survey is performedto recover the reef location. Typically, an FMIFullbore Formation MicroImager log isacquired to get the drape pattern and the ori-entation of the carbonate buildup, then anoffset VSP survey is shot along this selecteddirection to locate the actual position of the reef and steer the drillstring into the car-bonate buildup.

More Than VelocitiesAs discussed in the Sonat example, velocitiesmeasured directly in borehole seismic sur-veys can be used to fine-tune surface seismicprocessing. But borehole surveys can pro-vide more than just interval velocity. Withthe proper geometry, VSPs can also measureamplitude variation with offset (AVO), atten-uation, and velocity anisotropy, all of whichcan be used to correct surface seismic datafor better results. The next example demon-strates how TOTAL Thailand, a subsidiary of

France’s TOTAL S.A., now plans its strati-graphic targets in the Bongkot field in theGulf of Thailand by analyzing borehole-guided, long-offset AVO effects.

The Bongkot field is situated in the NorthMalay basin, Gulf of Thailand, 800 km [497 miles] south of Bangkok. One of thelargest and most prolific in the region, thefield has been in production since 1993.TOTAL Thailand was the operator of theBongkot Joint Venture until July 1, 1998,when operatorship was handed over to theThai state oil company, Petroleum Authorityof Thailand Exploration and Production PLC(PTTEP), which holds 40% interest. TOTALholds 30%, BG, 20% and Den Norske StatsOlijeselskap (Statoil), the remaining 10%.

Prior to relinquishing operatorship, TOTALundertook a new development phase onBongkot that has increased the gas productionto 550 MMcf/D [16 MM m3/d], liquid pro-duction to 12,000 BOPD [1430 m3/d] andmaintained reinjection of all produced waterto reduce the environmental impact of theoperations. Beyond this stage, another level ofdevelopment is expected to provide further

production increases of an additional 250MMcf/D [7 MM m3/d] gas and 8000 BOPD[954 m3/d] of petroleum liquids.

Bongkot’s hydrocarbons are distributedover a 2000-m [6562-ft] gross pay zone(1000- to 3000-m [3281- to 9843-ft] depth)of Miocene age. Around 70 separate fluvio-deltaic sand reservoirs 1 to 25 m [3 to 82 ft]thick can be encountered in a single faultblock. As a result, the critical factors arereservoir size, orientation and quality.

Until recently, Bongkot developmentdrilling was focused on drilling wells instructurally closed, tilted fault blocks or four-way dip closures, with multiple stacked tar-gets. Field development is maturing,however, with higher risk stratigraphic trapslocated outside closure being drilled. Thesewells target only a few reservoirs and oftenrequire expensive extended-reach wells.

TOTAL had been using a 3D lithologyprobability cube it had generated through apoststack migrated 3D volume inverted foracoustic impedance, combined with otherattributes calibrated to logs. Although thesecubes were very helpful, they neverthelesspredicted sand in some situations wheredrilling encountered organic-rich shales andcoals. Typically, predictions for gas werebetween 70 and 75% successful, acceptablefor the traditional multitarget prospects, butnot for wells drilled to just a few strati-graphic targets.

Almost all seismic attributes that could bederived from poststack data were investi-gated without solving the problem of organicshales and coals, thus it was necessary to goto the prestack domain to move forward.Plans were made to achieve good prestackdata suitable for AVO analysis. AVO hasbeen widely used to identify reservoir sandsbecause it allows recovery of a seismicattribute related to Poisson’s ratio contrasts,which can be related to lithology contrasts.

Four deviated wells were drilled inNovember and December 1996. In two ofthese wells, DSI Dipole Shear Sonic Imagerlogging for both compressional and shearwave velocity was carried out to performsynthetic modeling of the expected AVOresponse. Furthermore, vertical-incidence or

Fault at target depth

Shot points

Receivers

8 km

■■Bongkot VSP surveys. The borehole seismic shot points (red) and receiver locations(blue) in the Bongkot field are diagrammed here. Two walk-above (vertical-incidence)VSPs and 33 multi-offset, walkaway VSPs were acquired.

Autumn 1998 13

walk-above VSPs were acquired in the same two wells, and some 33 multi-offsetVSP walkaway surveys were conducted inthree of the four wells. Because VSP datawere being acquired while subsequent wellswere being drilled, a substantial boreholeseismic data set was acquired at no effectiverigtime cost to TOTAL. In all, two sets ofseven lines were obtained for AVO measure-ment (previous page).

The AVO walkaways were acquired, inpart, to measure AVO effects directly on topof a channel with two different lithologyfills—a sand and an organic-rich shale—toverify the modeling and to get an idea of off-sets needed to expose the AVO effects withgreater clarity. The modeling confirmed thatlithology could be differentiated, demon-strating that the gas sands showed a positiveAVO effect while the organic shale showeddimming with offset (right). For the first time,a method had been found, modeled andborehole-measured that could discriminatetarget Bongkot lithologies that all appear as high amplitudes in stacked surfaceseismic sections.

Modeling and multi-offset VSP measure-ments indicated that AVO could be used todistinguish the organic shale-filled channelsfrom channel gas sands, but only at relativelylarge offsets—larger than those used in con-ventional processing and corresponding toincidence angles well in excess of 30 degrees.The seismic data had been acquired with suf-ficiently long offsets, so TOTAL agreed to aproposal to reprocess the surface seismic datain which maximum use would be made of theborehole data. Over a period of months, a borehole-guided, long-offset processingsequence was developed that enabled reflec-tion amplitude variations out to 60 degrees tobe recovered, dramatically improving theeffectiveness of seismic lithology classification(right). As a consequence, where once about30% of the predicted stratigraphic reservoirtargets in Bongkot were being misidentified,long offset AVO is now being used to planwell trajectories, avoiding false targets and hit-ting gas sands with an increased drilling suc-cess ratio.8

8. Leaney S and Hope R: “Borehole-Guided Long OffsetAVO Processing for Improved Lithology Classifi-cation,” paper AVO 3.2, presented at the 68th AnnualInternational Meeting of the Society of ExplorationGeophysicists, New Orleans, Louisiana, USA,September 13-18, 1998.

33000offset, m

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15 50 75 100 0 1000 2000 3000

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■■Ray-trace AVO synthetic, or modeled, traces. The first track shows Vp/Vs ratio measured from sonic logs, the second track, acoustic impedance. The synthetic traces(center)—a normal-moveout corrected common-midpoint (CMP) gather—show differentamplitude variations with offset for different lithologies. Significant AVO is seen onlybeyond 30 degrees. Superimposed are contours of equal incidence angle. At the rightare three AVO attribute traces of gradient, intercept and product which characterize theAVO behavior. The right-most track is the trace obtained by stacking, or averaging, allsynthetic traces out to 33° (the trace is repeated five times for visibility). Stacking, a stepin conventional processing, obliterates AVO signatures. The horizontal scale on the synthetic traces is offset in meters.

Density Vp/Vs Ac. Imp.

Processed AVO Walkaway Data

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2 21 5 10 250 500 750 10000

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■■VSP AVO measurement. Properly designed multi-offset VSPs can provide actual mea-surement of the angle- or offset-dependent AVO response of an interface. The wavelet ismeasured just above the reservoir so propagation losses that affect AVO can be measured and removed through processing. In this measurement of the processed AVOwalkaway reflections at Bongkot, true relative amplitude data are shown. To correspondwith the offset of the surface seismic CMP, these offsets must be approximately doubled.The organic shale event can be distinguished as dimming with offset, while some deepersand events show noted brightening.

14 Oilfield Review

An important factor in the success of thelong-offset AVO approach was making use ofborehole-derived parameters in the surfaceseismic data processing. Parameters describ-ing frequency-dependent attenuation andanisotropy were measured from the multi-offset VSP data using novel algorithms, andthe derived parameters were then used in thesurface seismic processing sequence.9 Thisallowed long offset reflection amplitude datato be retained, information discarded in con-ventional AVO processing. For example,inverting the multi-offset VSP direct arrivalsfor offset-dependent attenuation allowed thelong-offset surface data to be compensatedto true amplitude (above left). Estimatingeffective anisotropy allowed events on com-mon-midpoint (CMP) gathers to be flattenedat long offsets (left). This step improvedmigration focusing (below left). The impactof borehole-guided, long-offset processingwas that it revealed lithology differences inthe AVO response between 30 and 60degrees incidence angle (next page, top).

TOTAL’s financial risk is reduced apprecia-bly by this integrated approach to AVO.Before selecting a stratigraphic target, seis-mic data are processed to take advantage of the longer offsets. The AVO responses ofall potential bright spot targets within theradius of a well are examined and the tra-jectory is optimized. Money was saved bydeciding to terminate a well above a targetwhere AVO predicted an organic shale andby hitting a large gas reservoir based on itspositive long-offset AVO response. Furtherwork is being done to see if lateral variationswithin the same sand may suggest variationin fluid content.

Overall, TOTAL says the impact of this newtechnology has been impressive. It helps themto decide between two anomalies or channelshapes that look the same. One could result in$1 or 2 million in drilling costs for absolutelynothing; the other may hold the potential of mil-lions of dollars in revenue (next page, bottom).

9. Anisotropy is the variation in a physical propertydepending on the direction in which it is measured.For a discussion of the role of anisotropy in identify-ing stratigraphic traps: Caldwell J, Chowdhury A,van Bemmel P, Engelmark F, Neidell N andSonneland L: “Exploring for Stratigraphic Traps,”Oilfield Review 9, no. 4 (Winter 1997): 48-61.

10. Chapman C, Farmer P, Fryer A, Paul A and SandvinO: “3D Tomographic Inversion and Depth Migrationof VSP Data,” paper ST15.2, presented at the 67thAnnual International Meeting of the Society ofExploration Geophysicists, Dallas, Texas, USA,November 2-7, 1997.

1.0

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■■Offset-dependentamplitude lossesmeasured with a multi-offset VSP(MVSP). The combinedeffects of geometricalspreading andfrequency-dependentattenuation at longoffsets are almost twice that assumed inconventional seismicprocessing (t-squared).The horizontal axis isCMP offset-to-depthratio for a reflector at1.5 s two-way time.

Data minus hyperbolic fitAnisotropic fit minus hyperbolic fit

10 ms

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DataAnisotropic fitHyperbolic fit

Walkaway times

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■■Effective anisotropy measured from multi-offset VSP traveltimes. Conventional processing assumes a hyperbolic fit to moveout times, but the data do not fit this assumption (left). The residuals show a higher order variation that can be fit with an anisotropic model (right).

2700280029003000 2700280029003000

Isotropic Borehole-calibrated anisotropic

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Time, s

Offset, m Offset, m

■■The impact of anisotropy on imaging. Prestack time migration stacked sections use anisotropic model (left) and a borehole-calibrated anisotropic model (right). The organicshale-filled channel event at 1.5 s is better focused using anisotropic migration.

Autumn 1998 15

The FutureThe integration techniques discussed here area small sample of the potential ways thatborehole seismic data can enhance the valueof surface seismic data and reduce drillingrisk. Methods that are still being developedinclude converted wave applications andanisotropic depth imaging. Converted wavesin VSP data—waves that begin as compres-sional or shear waves and convert to theother upon reflection—contain a wealth ofinformation. They are valuable for selectionof surface survey acquisition parameters, for

deterministic processing parameter selection,and in the analysis and interpretation of theprocessed data. It is hoped that convertedwave interpretation can reveal the completefluid and lithology content of the subsur-face—part of the impetus behind new multi-component seafloor sensors for marineseismic acquisition. Converted waves arevital for studying the feasibility of these mul-ticomponent seabed surveys. As this method-ology improves, borehole seismic integrationwill evolve as well. VSPs will be instrumentalin establishing where the mode conversion is

taking place and in discriminating betweensimple compressional-to-shear (P-S) reflec-tions and more complicated P-S-S modes,which can be very significant in amplitude.

Anisotropic depth imaging, likewise, is stillin development. Anisotropic seismic migra-tion can dramatically improve the quality andpositional accuracy of a seismic image.Estimating the model anisotropy parametersrequired for optimum imaging is difficultfrom surface data alone, however, and foranisotropic depth imaging, determining therequired anisotropy parameters is impossiblewithout borehole information. Calibrating ananisotropic 3D velocity model with VSPtraveltimes is therefore essential if depthmigrations are to be on depth. Developmentof anisotropic prestack depth migration, uti-lizing an anisotropic ray tracer, is now indevelopment at the Schlumberger CambridgeResearch Center, Schlumberger KabushkiKaisha (SKK) and Geco-Prakla.10

The examples presented in this article arebut the beginning of a major technologicalmovement anticipated during the next decadein integration of borehole and surface seismicdata. Other advances that will contribute tosuccessful integration are now on the wishlists and in many cases the drawing boards ofgeoscientists: simultaneous surface and bore-hole acquisition, continuous updating viaseabed sensors and drill-bit sources, targetingof “sweet spots” by generating attributes inreal time, immediate drilling of further wellsafter the first success, permanent sensors,passive event monitoring, quantifyinguncertainty, more flexible acquisition geome-tries via seafloor cables, and integration of VSP and surface seismic data with otherborehole information. —DG, LS

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■■Borehole-guided, long-offset AVO processing for three potential drilling targets.Significant amplitude variation is seen only beyond 30 degrees.

■■The benefits of seismic integration. A well was deviated to hit a false organic shale target, adding an estimated $300,000 in cost. The deeper target was missed with thiswell but was drilled based on long-offset AVO and will pay for itself about five times over.

Organic shaleGas sand

Final target missed, but drilled from an adjacent platform paying for the well five times over

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