2 Oilfield Review

Shear Waves Shine Brightly

Jack CaldwellHouston, Texas, USA

Phil ChristieFolke EngelmarkSteve McHugoHüseyin ÖzdemirGatwick, England

Pål KristiansenOslo, Norway

Mark MacLeodChevron UK Ltd.Aberdeen, Scotland

For help in preparation of this article, thanks to LorraineClark, John Kingston, Scott Leaney and Tony Probert, Geco-Prakla, Gatwick, England and Lars Sonneland, Geco-Prakla, Stavanger, Norway; and to the Alba fieldpartnership for permission to publish.MultiWave Array, Nessie and Seismos are marks ofSchlumberger.1. Jolly RN: “Investigation of Shear Waves,” Geophysics 21,

no. 4 (October 1956): 905-938.

Imagine a tool that sees through fog and mirrors as well

as it does through glass, and in the dark. This sums up

the improvements that converted shear waves bring to

hydrocarbon reservoir imaging and characterization.

Scientists have known for almost a hundredyears that combining the information from com-pressional and shear waves can provide valuableinsight into earth properties. Resource explo-ration methods have concentrated on compres-sional (P) waves alone, but long ago when theonly seismic sources were earthquakes, shear (S)waves were accorded their due respect. Oftenmore energetic than P waves by orders of magni-tude, shear waves were recognized as the powerbehind an earthquake’s devastation.

In the 70 or so years that the hydrocarbonexploration industry has been applying seismicwaves, it might seem that adequate results havebeen achieved with P waves alone. Many reser-voirs have been discovered and delineated ascompressional-wave surveys have evolved fromtwo- to three-dimensional (2D to 3D) and recentlyadded a fourth dimension with 4D time-lapseseismic techniques.

However, there are several instances inwhich compressional waves from a standard sur-vey do not adequately image a reservoir ordescribe its properties. Gas, even in smallamounts, disrupts P-wave transmission andobscures underlying targets from compressionalsurface seismic view (next page, top left). Whenthe gas is shallow, it can cloud the entire subsur-face. Some reservoirs do not present sufficientimpedance contrast to the overburden, and so donot reflect P waves strongly enough to producean interpretable image (next page, top right). Inareas where the overburden itself is a high-impedance material, such as salt or hard volcanicrock, imaging the underlying reservoir is difficultbecause so little P-wave energy returns to sur-face after transmission twice—down then up—through high-impedance rocks. Waves thatreverberate in the water column, or that reflectmultiple times at the sea-earth interface, canalso distort the seismic image. Bad weather orsurface obstructions such as platforms, pipelinesand other infrastructure can make acquisition ofconventional towed marine surveys impossible,leaving gaps in subsurface coverage.

In addition to these imaging shortcomings,compressional waves often fail to resolve manyreservoir property questions. In many cases, P waves do identify the target, but do not clearlydelineate its extent. This is a common problem instratigraphic traps, where reservoirs pinch outand are replaced laterally by other lithology.Compressional waves may detect lateral varia-tions in reservoir properties, but be unable to dis-tinguish between changes in lithology andchanges in fluid content or pressure. Bright spots

Spring 1999 3

and other amplitude anomalies can be seen in P-wave surveys, but they can sometimes point tohard, tight rock instead of hydrocarbon accumula-tions unless additional information is supplied.Compressional waves can also be less sensitiveto aligned fractures or rock textures that imposeazimuthal variations of velocity, or other types ofanisotropy, in the reservoir or the overlying strata.

There are several ways of addressing thesechallenges. Advances in acquisition, processingand interpretation of P-wave data are all con-tributing to better images and reservoir charac-terization, but none is meeting the challenge theway that shear waves can.

Shear ExcitementExploration and production geophysicists havealready experimented with shear waves in bothsurface and borehole seismic contexts. From theearliest attempts, dating back to the 1950s, geo-physicists concluded that using shear waves forseismic exploration was not practical.1 Thoseexperiments relied on generation of direct shearwaves that reflected back as shear waves, andwere restricted to land surveys. Generation ofdirect shear waves requires a special, orientedsource, one that excites predominantly sidewaysshaking, or shear motion, as opposed to compres-sional motion, which is easily excited by readilyavailable volume injection—explosive or implo-sive—sources. Shear-wave recording requiresmultiple, orthogonally oriented receivers to regis-ter each component of the motion. This has giventhe name “multicomponent” to methods involvingboth compressional and shear waves.

Since the early shear experiments, improve-ments in acquisition technology have led to somesuccessful land shear-wave surveys, but notmany such surveys are run. They are time-con-suming to set up, because each geophone mustbe properly oriented and planted firmly in theground. Vibroseis trucks with special shakingplates are used as sources.

At first glance, shear waves might seem lessuseful than compressional waves for explorationand production (E&P) purposes. After all, shearwaves are known to propagate only in solids, so

they can neither be excited by conventionalmarine seismic sources nor travel through water.In addition, shear waves are almost insensitiveto a rock’s fluid content: shear-wave velocity andreflectivity remain virtually unchanged whetherthe formation contains gas, oil or water.

However, the combination of shear and com-pressional waves has the potential to revealmore about the subsurface than either wave typein isolation. With information on a formation’s P- and S-wave velocities, an interpreter canbegin to pinpoint lithology more readily than withonly pure P-wave data. The velocity ratio Vp / Vs

has a known range for many rock types. Fluidcontent of a formation is more reliably inter-preted with the combination of wave types. A lateral change in P-wave reflection amplitude

along an interface is more likely to indicate fluid-content change than lithology change if the cor-responding S-wave reflection amplitudes areconstant. If the S-wave amplitudes also change,the variation is more likely to mean the rock prop-erties are changing.

While generating direct shear waves doesrequire a special source, generating reflectedshear waves does not. Shear waves are reflectedwhenever P waves impinge on a solid interfaceat any angle other than 90°. The resultant shearwaves are called converted waves, and can occuras reflected or transmitted waves (below). Areflection in which a P wave converts to an Swave is called a P-S reflection, to distinguish itfrom the more familiar P to P reflection, which islabeled P-P.

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> A conventional, P-wave reflection seismicimage from the Far East. Subsurface structure is unclear because shallow gas disrupts P-wavepropagation. In a later figure (page 7), shearwaves reveal the structure. Compressional-waveand shear-wave velocities plotted as a functionof gas saturation, show that even the slightestamount of gas causes P-wave velocities todecrease, resulting in troublesome imaging conditions (inset).

Conventional P-Wave Image

> A P-wave reflection image of a prolific NorthSea reservoir. The low impedance contrast atthe reservoir top makes this structure nearlyinvisible to P waves. In a later figure (page 9),this structure will be revealed by the S-waveimage of the reservoir.

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> Upon reflection, P waves converting to S waves.

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> Synthetic seismograms for the oil reservoir top (green), oil-water contact (blue), and reservoir base (red). Traces modeled fordifferent source-receiver offsets (track 1) show the vertical-incidence P-P trace has no amplitude at the top of the reservoir, butlarge amplitude at the oil-water contact. Once stacked (track 2), the P-P reflection does show some amplitude at the reservoirtop, because traces from far offsets contribute amplitude. Stacked traces are all the same, but repeated for clarity and displayedat different common depth point (CDP) numbers. Stacked amplitudes tend to cancel at the reservoir base. Converted-wave P-Straces computed for each offset (track 3) exhibit large amplitude at the reservoir top for all offsets. After stacking, P-S amplitudesremain high at the reservoir top and base (track 4).

4 Oilfield Review

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> Logs from an acoustically invisible oil sand reservoir encased in shales. The increase in compressional velocity (track 1) at the top of the reservoir (green) is offset by a decrease in density (track 2) so that acoustic impedance (track 5), or density timesP-wave velocity, of the oil-filled sandstone is the same as that of the overlying shale. The lack of P-wave, or acoustic, impedancecontrast across the interface induces no P-wave reflection. The large contrast in S-wave velocity (track 3) gives rise to a largeS-wave, or shear, impedance (track 6), so S waves will reflect. Poisson’s ratio (track 4) is a function of Vp /Vs ratio, and is sometimes used to interpret rock and fluid properties. Red represents the bottom of the reservoir sand and blue represents the oil-water contact (OWC).

Spring 1999 5

Forward modeling can predict how P and Swaves will reflect at an interface. Compressionaland shear sonic-log measurements and densitylogs are combined to produce an impedancemodel, which can be ray-traced and convolvedwith a basic seismic pulse to create a syntheticseismogram. An idealized example, with ficti-tious but physically realistic log values, showshow the top of a reservoir can be invisible to aconventional P-wave survey but clearly visible toS waves (previous page, top). In this case, theacoustic, or P-wave, impedance—density timesP-wave velocity—of the oil-filled sandstone isthe same as that of the overlying shale. Thus theacoustic impedance contrast across the inter-face is zero. The shear impedance, or densitytimes S-wave velocity, is sharply higher in thereservoir. The P-wave impedance does jump atthe oil-water contact (OWC) deeper in the reser-voir, where, as expected, the change in fluidshardly affects shear impedance.

Synthetic seismograms show how P-P and P-S reflections will react to such a reservoir (previous page, bottom). The vertical-incidenceP-P trace shows no signal at the top of the reser-voir, but there are reflections off the OWC andthe bottom sand-shale interface. At higherangles of incidence, or source-receiver offsetsgreater than about 1500 ft, the top of the reser-voir does support significant P-P reflections. Butwhen reflections from all offsets are stacked, asoccurs in conventional processing, the P-P reflec-tion from the reservoir top diminishes, while theP-S stack shows a clear reservoir reflection.

Shear Waves at SeaWhile it’s true that shear waves will be reflectedand can image otherwise invisible reservoirs,before that can happen, the reflected energymust be recorded by multicomponent receivers.This is already known to be a challenge on land.Knowing that shear waves cannot propagate inwater, how can this task possibly be accom-plished at sea?

The solution lies in recording the shear waveswhile they are still in the solid earth, at theseafloor. Academic institutions initiated seafloorrecording with ocean-bottom seismometers forearthquake and other analyses decades ago.Recently, the recording of P and S waves at theseafloor has been resurrected by the oil and gasindustry, and two methods of multicomponentrecording have been attempted. The first requiresplacing individual recording devices on theseafloor with a remotely operated vehicle (ROV).This method achieves acceptable results, with

high-quality converted-wave data, but mobiliza-tion and operation of the ROV make these typesof surveys expensive.

The second, more tractable, method makesuse of instrumented cables packed withreceivers, similar to the streamers that are towedin conventional marine surveys, but designed tooperate on the seafloor. Geco-Prakla has devel-oped a new marine acquisition technique thataccomplishes this with a rugged multicompo-nent, instrumented cable called the Nessie 4CMultiWave Array system. The cable is laid on theseafloor by the recording vessel, and anothervessel activates sources (above).

The Nessie 4C cable had its origins in a cableof Russian design that contained hydrophonesand geophones and was dragged on the seafloorby a vessel that simultaneously fired sources.Geco-Prakla engineers devised an innovativeway to place the sensors—each containing onehydrophone and three orthogonally oriented geo-phones—inside the cable, distributing theirweight for optimal coupling to the seafloor(below). Each cable houses hundreds of four-component sensors. The four-component designhas given a new acronym, 4C, to marine multi-component acquisition. With four components to

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> Acquisition with the seabed multicomponent system. The cables are laid on theseafloor by the recording vessel, and another vessel activates sources. The source vessel may traverse the cables at any angle, adding flexibility to survey geometry. aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaP P

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> The four components of the Nessie 4C MultiWave Array system. Each sensor stationwithin the cable comprises one hydrophoneand three orthogonally oriented geophonesto record both pressure and particle velocity.Compressional waves are recorded primarilyon the hydrophone and vertical geophonecomponent (Z), while shear waves arerecorded mostly on the transverse (Y) andradial (X) geophones.

each sensor package, full particle-motion vectorrecording of all P and S wavefronts is achieved,along with the pressure wavefront familiar fromtowed streamers. The system is different fromordinary ocean-bottom cables (OBCs) that have ahydrophone and a vertically oriented geophonestrapped to the outside, which is incapable ofrecording the full particle-motion vector and haspoor coupling quality.

The new cable is positioned on the seaflooreither by letting the cable drape into place fromthe sea surface, or by dragging the cable from onebottom location to the next. Environmental author-ities have expressed concern that a cable posi-tioned in this way may adversely agitate the softsediments of the ocean-bottom habitat. However,video recordings of Nessie 4C MultiWave Arraycable being deployed for some Gulf of Mexico sur-veys show that the cable disrupts the sedimentsless than does the native sea life.

Geco-Prakla has acquired about 50 marinemulticomponent surveys in different seabed envi-ronments and different water depths. Data qual-ity is high in all environments, even in soft,unconsolidated seafloor sediments. The cableshave operated in water depths reaching 800 m[2624 ft]. Even an irregular seafloor does not

cause problems; sensors are grouped, so oneimperfectly coupled geophone does not affectthe overall response of the group.

The two-vessel seafloor multicomponenttechnique allows acquisition of true zero-offsetdata, unlike the towed streamer technique thatacquires data at receivers that are offset fromthe source location. With two vessels, seismiclines can be shot across, in the direction of, or atany desired angle to the cable lines.

The seafloor position of the receivers shieldsthem from rough weather that can delay acquisi-tion. Compared to towed-streamer surveys,seabed sensor surveys encounter less time wait-ing on weather (above).

Protection from the weather also lets theseafloor cable acquire data of greater bandwidththan from streamers towed near the sea surface.Isolation from surface conditions reduces noiseand improves signal acquisition (below).

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> Greater bandwidth recorded with seabed system (right) compared to towed streamers (left). Acquisition of the seabed data took place under severe weather conditions that would have precluded any towed-streamer acquisition. [Data courtesy of Saga Petroleum.]

Spring 1999 7

Seeing Through GasIn 1996 the Nessie 4C seafloor cable system wasused for the first time to acquire 2D surveys inthe North Sea for imaging reservoirs shadowedby overlying gas. Since then, about 30 such sur-veys have been acquired by Geco-Prakla, and thegeographic scope has expanded to include theGulf of Mexico and several areas in the Far East.

The power of the technique becomes evidentby comparing seismic lines shot with conven-tional towed-streamer P-P techniques to thoseacquired with the seabed multicomponent sys-tem. The first example replays the earlier imageof a reservoir in the Far East obscured by gas(above). The towed-streamer results are so per-turbed by the gas that no clear image of eitherlayering or faults can be achieved. The multicom-ponent recordings of converted waves clearlyimage the layering and faults.

As important as the detection and delin-eation of faults is the confirmation that there areno faults. The second example shows two por-tions of a P-P reflection line shot over a fault inthe South China Sea (right). Only one image isover the faulted zone, but gas in the subsurfaceclouds the images so that both sections look dis-rupted enough to contain a fault somewherealthough it is not clear where. The line producedfrom the P-S reflections shows the first part ofthe line to be fault-free, at least on the scale ofthe seismic survey, with the fault revealed andimaged well in the second section.

Conventional P-P Image Seabed P-S Image

< Comparison of P-P and P-S images of a FarEast reservoir. The P-P image (left), repeatedfrom the first figure on page 3, shows littledetail compared to the P-S image (right)achieved with the Nessie 4C cable.

> Two portions of a P-P seabed sensor reflection line (top) shot over one fault in the South China Sea.Both portions are disrupted by gas, so pinpointing the fault location is impossible. The P-S images(bottom) from the same seabed line reveal a fault only on the portion at the right.

Seabed P-P Images

Seabed P-S Images

The Invisible ReservoirEvery operating company probably has an exam-ple of a reservoir that is invisible on traditionalseismic sections. In the case of Chevron, 1984appraisal drilling into a North Sea Cretaceoustarget encountered another, shallower, oil reser-voir that had not been detected on seismic sec-tions. Thus the Alba field was discovered(below). The reservoir is a poorly consolidatedEocene turbidite sand channel about 9 km [5.6miles] long, 1.5 to 3 km [0.9 to 1.8 miles] wideand up to 100 m [330 ft] thick.2 How could such areservoir go unsuspected? Sonic logs wereacquired, examined, and found to hold the rea-son. The compressional sonic logs showedbehavior similar to the synthetic log example pre-sented earlier: no P-wave impedance contrast atthe top of the reservoir, but a sizable contrast atthe oil-water contact. Shear sonic logs showed ahigh contrast in shear-wave impedance at the topof the reservoir.

Revisiting the image of the reservoir derivedfrom 1989 towed-streamer data, some indicationof reflected energy can be imagined, but no clearimage presents itself (below right). A few verticalappraisal wells delineated the general limits ofthe field, but its detailed 3D shape remaineduncertain. New wells encountered intrareservoirshales that could cause significant drilling andproduction problems, but the shales were mostlyinvisible in the seismic images. Developmentplans called for horizontal production wells to bedrilled as close as possible to the reservoir top,but the shape of the top of the reservoir was any-one’s guess. To position the horizontal wells opti-mally, without losing a single foot of pay,required a better seismic image of the reservoir.

8 Oilfield Review

> Conventional towed-streamer P-P reflection image of the Alba reservoir (repeatedfrom the second figure, page 3). Some broken reflections are recorded, but there isno clear image.

> Indications that converted waves can image the Alba reservoir. Modeling usingsonic and density logs and original fluid-saturation information (middle) shows thatP waves (top) will reflect off the oil-water contact, while converted waves (bottom)illuminate the top and base of the reservoir.

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> The Alba field, anoil-filled unconsolidatedEocene sand in the North Sea,discovered while drilling to adeeper target.

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Oil-Water Contact: Initial Saturation

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Spring 1999 9

A feasibility study was conducted to deter-mine if the desired reservoir description could beobtained from a 3D survey with ocean-bottomcables. Three objectives were defined for such asurvey. First, the reservoir should be delineatedusing converted waves (previous page, top).Second, long-offset P waves should contributereflection amplitude variation with offset (AVO)information for distinguishing lithologic contactsfrom fluid contacts. Third, reflected P waves fromthe new 1998 survey should be suitable for com-parison with the 1989-vintage data to mapchanges in the oil-water contact brought on bythe four years of production since January 1994.

Prior to acquiring the 3D seabed survey,Chevron acquired 2D seabed test lines with twocontractors. The P-wave seabed results obtainedwith the Geco-Prakla Nessie 4C MultiWave Arrayseabed system were found to be most compara-ble to the 1989 streamer data.

Chevron commissioned a 67-km2 [26-sq mile]3D multicomponent survey, which was recordedin 14 swaths parallel to the 1989 survey in orderto facilitate time-lapse comparison for fluid-contact monitoring. Acquisition took 8 weeks inrough weather during a period of intense fieldactivity. The seismic acquisition crew workedaround divers, construction, platforms, umbilicalsand pipelines—an environment in which astreamer survey would be extremely difficult(right). The 3D converted-wave processing wassteered by information obtained from the 2D test

line and from initial analysis of the 3D recordeddata.3 A four-month time limit was set on the pro-cessing to ensure that interpretable resultswould be ready in time to guide the next drillingdecisions, and after 31⁄2 months the 3D data setwas ready.

For the first time, the detailed shape of theAlba reservoir was revealed. The converted-wave survey imaged the reservoir with astonish-ing clarity compared to the compressional-wavesurvey (left).4 The new images have enabled amore confident interpretation of the reservoirsand and identification of some of the larger

> Surface activity and infrastructure preventing conventional towed-streamer surveys of the Alba reservoir.

> Sighting the Alba reservoir with converted waves. The top, base, lateral extension andeven compartmentalization of the channel sand are imaged in this seabed line that cutsacross the reservoir axis. These features are not seen in the compressional-wave imagefrom streamer data.

2. Newton SK and Flanagan KP: “The Alba Field: Evolution of the Depositional Model,” in Parker JR (ed): PetroleumGeology of Northwest Europe: Proceedings of the 4thConference, vol. 1. London, England: The GeologicalSociety, 1993.

3. McHugo S, Probert A, Hadley MJ and MacLeod MK:“Processing of 3D Multicomponent Data from the AlbaField,” presented at the 61st European Association ofGeoscientists and Engineers Conference and Exhibition,Helsinki, Finland, June 7-11, 1999.

4. MacLeod MK, Hanson RA, Hadley MJ, Reynolds KJ,Lumley D, McHugo S and Probert A: “The Alba Field OBC Seismic Survey,” presented at the 61st EuropeanAssociation of Geoscientists and Engineers Conferenceand Exhibition, Helsinki, Finland, June 7-11, 1999.

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intrareservoir shales. Interpreters feel there ismore information in the shear-wave data than inthe long-offset compressional AVO dataacquired for lithologic interpretation. The newshear-wave information is improving theChevron team’s understanding of the deposi-tional model and the importance of injected sandfeatures. Interpretation and visualization of theconverted shear-wave cube now play a leadingrole in the understanding of the geometry of theAlba reservoir (left).

The ongoing drilling program in the Alba fielddemands a precise representation of reservoirfluid distribution. Since 1993, the field has pro-duced 130 million barrels [20.6 million m3] of oil.Currently, 15 horizontal wells produce 83,000barrels [13,190 m3] of oil per day. As more wellsare drilled close to existing production and injec-tion wells, understanding water movementbecomes critical. Two recently drilled wells haveencountered unpredicted fluid profiles: one wellfound a water-wet sand above a sand with pri-mary oil saturation; in another, a partially oil-sat-urated sand was found below the originaloil-water contact.

Modeling studies showed that a water satu-ration change of 40% or more at the Alba OWCwould cause a decrease in P-wave reflectionamplitude large enough to be seen in time-lapseseismic surveys (left). The seabottom cablesrecorded excellent P-wave data for this purpose.Comparison with the streamer data acquiredbefore production shows changes in the locationand reflection strength of the oil-water contactdue to oil production and water injection (nextpage, top). The observed fluid-contact changesare compatible with predicted changes seen onsynthetic seismic lines generated for the Albasand with fluid saturations estimated from reser-voir simulations.

10 Oilfield Review

< Modeled response of P-P reflections at theAlba OWC before and after production. Beforeproduction (top), the reservoir sand has a flat OWC, and modeled P waves image that contact. After production (bottom), the modeledP-wave image shows changes in the strengthand location of the OWC. The seismic responseto two different shapes and saturation changes (middle) is modeled.

Streamer P-P Data

P-S Data

> Three-dimensional renderings ofAlba P-P and P-S reflections greaterthan a given amplitude threshold.The cube of P-P reflections showsroughly uniform reflection amplitudethrough the 3D volume, while thecube of P-S reflection data clearlymaps the sand body.

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Spring 1999 11

The Alba case may be unique in that it is thefirst reservoir to have been brought to light sodramatically by P-S converted waves, but similarreservoirs are probably still eluding detection.The conditions that gave rise to the low-impedance-contrast deposits of the Alba field arewidespread in the North Sea, and probably else-where in the world (below left). Feasibility stud-ies will show in advance where multicomponentsurveys could have the same impact in pinpoint-ing reservoir location, shape and fluid content.

The Shear Process Seismic sections generated by converted wavesresemble traditional P-wave sections closelyenough to allow most Oilfield Review readers tofollow the similarities and differences describedin the text and figure captions. One might thinkthat S waves are similar enough to P waves toallow data processing developed for the latter tobe applied to the former. In fact, the first 2D mul-ticomponent seabottom cable surveys were pro-cessed with commercial P-wave algorithms thathad been tricked into thinking the shear arrivalswere compressional waves.

Except for a few key differences, converted-wave processing does follow a scheme similarto that of P-wave surveys. However, those dif-ferences require sufficient attention to detail torender each multicomponent processing job dif-ferent from the last.

The three major differences between pro-cessing converted wave surveys and those usingpurely compressional waves are asymmetricreflection at conversion, difference in geometriesand conditions of source and receiver, and thepartitioning of energy into orthogonally polarizedcomponents. The first, asymmetric reflection,arises because shear waves have slower velocitythan compressional waves. This means that the

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> Time-lapse comparison between 1989 streamer data (top) and 1998 P-Pdata (bottom) acquired with the seabed cable. The observed fluid-contactchanges, including the lack of a clear OWC in the 1998 data, are compatiblewith changes predicted from production simulations.

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angle at which an S wave is reflected is alsosmaller, so S waves are reflected up moresharply, with near-vertical raypaths (above).

Compressional waves, incident upon a planarinterface, reflect at the angle of incidence.Processing takes advantage of this symmetry inseveral ways. Signal-to-noise ratio is increasedby stacking traces from several source-receiveroffsets centered on one common midpoint (CMP)located halfway between source and receiverand directly above the common depth point(CDP). Another advantage of symmetric reflectionis source-receiver reciprocity. That is, to a firstapproximation, a trace recorded for a givensource-receiver pair is the same as one for whichthe source and receiver have exchanged posi-tions. Many conventional processing steps, suchas normal moveout (NMO) and dip moveout(DMO) corrections, as well as the wavefieldextrapolation processes of trace interpolation,redatuming and migration, rely on reciprocity.

Converted-wave traces may also be stacked,but because of asymmetric reflection, the reflec-tion point, called the common conversion point(CCP), is not halfway between source andreceiver. The conversion point is always dis-placed from the source-receiver midpoint in thedirection of the receiver, whatever the sourceposition. To bin, or put traces at their correct CCP,a special converted-wave correction, called theCCP binning correction, is achieved by a space-and time-variant grouping of traces from a givensource-receiver pair. Then an NMO correctionmust be applied to achieve a proper stack oftraces. However, the difference in velocitybetween the incident P wave and the convertedS wave, along with the different angles of inci-dence and reflection, causes the NMO correctionin converted-wave processing to be nonhyper-bolic. A common occurrence in P-wave process-ing is to simultaneously process traces atcommon offsets, whether receivers are located“ahead” or “behind” the current source position,and to apply the same NMO velocity to all traces

from a given offset. This must be modified forconverted waves, again for reasons of asymmet-ric reflection, because the velocities computedfor negative and positive offsets are different.

The second major difference with convertedwaves is that the source and receiver are at dis-parate levels and in dissimilar materials. Thesource is at the sea surface but the receiver isdeeper, at the seafloor. This is called a differencein datum. The datum is the arbitrary referenceplane on which sources and receivers areassumed to lie to minimize near-surface effects.Most processing algorithms such as NMO, DMOand migration assume that the source andreceivers are at the same datum. When thesource and receivers are at different datums, atime shift and time-variant spatial shift are intro-duced. A correction is required to bring thesource and receivers to the same datum plane.Mean sea level is a natural choice of datum, andis often selected for converted-wave surveys. Forshallow-water acquisition, the spatial shift issmall, so the correction is simply a static shift.For deeper water, redatuming techniques requireextrapolation using the seismic wave equation tocorrect the spatial position.

Differences in near-surface conditions at thesource and receiver locations require further cor-rections in processing. The thin layer of soft sed-iments on which the cables lie has an extremelylow shear velocity. Variation in the thickness orvelocity of this layer from one receiver to the nextcan cause abrupt changes in the traveltime of theshear wave coming up through this layer. Theseeffects are commonly corrected for in land pro-cessing and are known as statics. The traveltimedifferences occur over short distances relative tothe seismic wavelength, they can vary signifi-cantly from trace to trace, and have to beresolved before stack. In the North Sea, shear-wave statics of up to 150 msec one-way timehave been observed. Fortunately, because thesource location can be controlled, statics affectonly the receivers—only the shear-wave portionof the travel path and not the compressional.

The third major difference with convertedwaves is that energy is partitioned into orthogo-nally polarized components, and that is why mul-ticomponent sensors are needed to fully recordthe converted wavefield. When a P wave strikesan interface at nonnormal incidence, the particlemotion of the reflected S wave is polarized in theplane containing the raypaths of the incident Pwave and reflected S wave.5 The three receivergeophones are typically oriented such that onecomponent (Z) is aligned vertically, the second (X)is parallel to the cable, and the third (Y) is trans-verse to the cable in the horizontal plane. In 2Dsurveys, if nothing disrupts the S wave as it trav-els to the receiver, its particle motion will berecorded mainly on the X receiver, and to aninconsiderable extent (but one that increaseswith offset) on the Z component. In practice,especially in 3D surveys, S-wave arrivals will berecorded on more than one geophone. Thisoccurs because the receiver components are ori-ented at some angle to the source-receiver lineor because rock properties cause the particlemotion to change along the raypath between theconversion point and the receiver.

When S waves are recorded on more thanone geophone, the recorded data must be math-ematically rotated into the radial and transversecoordinate system aligned with the source andreceiver before processing can proceed. The sig-nals recorded on the radial component are takento represent the converted-wave arrivals. Anyresidual transverse-component signal, called off-axis energy, indicates the presence of velocityanisotropy. Anisotropy, caused by alignment ofsmall-scale features in rock layers, forces waveparticle motion to adhere to the principal align-ments of the rock, such as horizontal layering orvertical fractures.

Velocity anisotropy in the vertical plane,called TIV anisotropy, occurs when velocity varieswith angle from the vertical. Horizontal layeringis a common cause of TIV anisotropy. It has beenobserved in many compressional-wave surveys,but it sometimes can be neglected in traditionaltowed-streamer data processing. These surveysare not greatly affected by velocity anisotropybecause they are generally restricted to P-waveray angles of 30 to 40°, and most of the effect ofanisotropy occurs between 40° and horizontal. Inaddition, since particle motion is close to thedirection of wave propagation, only one directionis involved. TIV anisotropy becomes most notice-able in towed-streamer surveys at long source-receiver offsets if horizontal P-wave velocitiessurpass vertical velocities by more than about10%—a common occurrence. Compressional-

12 Oilfield Review

IncidentP wave

ReflectedS wave

ReflectedP wave

> Near-vertical raypathsof converted-wavereflections. In this configuration, shearwaves arriving at the surface will berecorded on the radial,or X-component, geophone.

Spring 1999 13

wave velocity anisotropy in some shales canreach more than 30%, and that of shear wavescan be of the same order of magnitude.

Seabed multicomponent converted-wave sur-veys are more likely to be affected by TIVanisotropy, because these surveys use raypaths atlarge angles to the vertical. In addition, horizontalparticle motion of the vertically traveling S wavebrings an additional direction into the picture andincreases the sensitivity of the shear wave tovelocity variation with azimuth, or angle, in thehorizontal plane. This is called TIH anisotropy, andcan be caused by vertical fractures.

The influence of TIH anisotropy shows up asshear-wave energy recorded on both the X and Ycomponents, even when the X component isaligned with the source-receiver axis. The effectscan be pervasive, complicating computation ofconversion point location, stacking, correction ofreflection times for dip (dip moveout, or DMO)and migration, which positions reflections attheir correct location in time and space.

In most converted-wave surveys run to date,as with P-wave surveys, anisotropy has beenconsidered a second-order problem and not thegoal of the survey. However, detection and quan-tification of anisotropy can yield important reser-voir characterization information, pointing todominant stress directions, small-scale layering,fracturing or other internal alignments that may affect imaging, drilling or production.6

Multicomponent surface and borehole seismicsurveys on land have already been used to estimate fracture directions by measuringanisotropy. Multicomponent seafloor surveys aresure to follow.

Converted-wave survey processing mustincorporate all these aspects of asymmetricreflection, source-receiver differences and multi-component polarization into the processingchain, and special multicomponent algorithmshave been developed for this purpose. In addi-tion, algorithms have been devised for special-purpose processing, which can include:angle-dependent summation of hydrophone and

vertical geophone signals to produce better P-P data than from hydrophones alone; velocityinversion for lithologic interpretation; andanisotropic prestack depth migration for imagingcomplex structures.

Geco-Prakla engineers have placed con-verted-wave processing steps into the commer-cial Seismos data-processing software. TheSeismos system allows faster, more efficientdata transfer from field to office, leaving lessroom for error between acquisition, processingand interpretation. It also enables concurrentprocessing in which the effort is shared betweenfield, processing center and client office. Dataquality control and preliminary processing allowdelivery of stacked data as soon as acquisition is complete. However, since each survey isacquired in a different environment and has a different objective, final processing requires individual attention.

In Addition to ImagesIn most cases so far, the objective of the multi-component seabed survey has been to produce aseismic image where conventional technologyhas failed. However, converted waves can domore: in addition to supplying images of subsur-face layers, converted waves give informationabout the rocks and fluids within the layers.

Compressional waves have been used ashydrocarbon indicators, but with mixed success.In some regions, bright spots, or reflections ofanomalously high amplitude, have pointed to oiland gas accumulations. Unfortunately, the bright-spot technique is unreliable. High amplitudesassociated with tight zones or hard rock can havethe same appearance as those from oil and gas,leading to some disastrously expensive dry holes.

One way to characterize the cause of a high-amplitude reflection is to examine the behaviorof the reflection amplitudes as the source-

receiver offset changes. Amplitude variation withoffset analysis can be a powerful tool for distin-guishing fluid-content changes from lithologychanges.7 The method requires acquisition ofcompressional-wave data at a variety of offsets,the range of which can be determined by a feasi-bility study during the survey planning stage.Then follows careful processing to achieve highsignal-to-noise level without stacking, to pre-serve true relative amplitudes. The observed AVOsignatures are then compared to modeledresponses to infer pore-fluid type.

Of course, AVO analysis is an indirect methodto obtain shear information from P-P reflectiondata, since the AVO signal is often parameterizedin terms of the Poisson’s ratio contrast betweenthe caprock and the reservoir. At first glance, itmight seem that there should be a direct linkbetween AVO and P-S reflectivity: when P-Simaging works, so should AVO and when AVOworks, so should P-S imaging. However, the linkcan be more subtle and not quite so direct.Because Poisson’s ratio is a function of the Vp / Vs

ratio, the AVO response is to this ratio, while P-Sreflectivity responds to contrasts in shearimpedance. The Alba field is one example of areservoir top displaying greater effect on P-Sreflectivity than on AVO.

Another way to discriminate fluid changesfrom lithologic changes is to take advantage ofthe additional information contained in convertedwaves. An example from the North Sea showshow the comparison between P-wave and S-wave response at a reflector can help identifyfluid content of the formation. Nessie 4CMultiWave Array seabed cables were used toacquire P-P and P-S images over a speculatedtarget formed by dipping beds abutting a poten-tially sealing fault (below). Compressional-wavereflection amplitudes are high as the layersapproach their termination with the fault, but the

P-P Reflection Amplitude P-S Reflection Amplitude

> Compressional-wave (left) and converted-wave (right) images of target dippingbeds. Analysis of amplitude variations can help map fluid content in the dipping layer.

5. Geophysicists sometimes call the reflected wave an SVwave, because for horizontal reflectors, the polarization isin the vertical plane containing the source and receiver.Another kind of reflected shear wave, called the SHwave, with particle motion polarized in the horizontalplane, can exist. The SH reflection is generated by incident SH waves—the kind excited by shear-wave vibrator sources—or by shear-wave splitting caused byanisotropy or other features with a preferred orientation.

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

7. Chiburis E, Franck C, Leaney S, McHugo S and Skidmore C:“Hydrocarbon Detection with AVO,” Oilfield Review 5,no. 1 (January 1993): 42-50.

high amplitudes could have a number of causes.The objective of the multicomponent survey wasto see if converted-wave reflections would com-plement the P-wave data and help map fluid con-tent in the dipping layer.

To the unaided eye, the color displays of P-Pand P-S reflection amplitude look similar (below).Analysis of the recorded amplitudes by reflectiontracking software shows a subtle difference inthe trend of P-P compared to P-S reflection ampli-tudes. At the updip end near the fault on theright, the normalized P and S amplitudes are rel-atively constant and equal. Downdip, somewherebetween traces 1500 and 1600, the amplitudetrends diverge. The P-S amplitude remainsroughly constant, while P-P amplitude increases.

Interpreters associate the divergence ofthese amplitude trends with a change in fluidcontent. A change in the fluid content of a rocklayer will produce a change in P-wave velocity ofthat layer, and a corresponding change in theamplitude of a P-P reflection off the top of thelayer. The same change in fluid content will havenegligible effect on the S-wave velocity of thelayer, so will not appreciably change the P-Sreflection amplitude. The nature of the fluids con-

tained in this North Sea example might be pre-dicted through forward modeling, but cannot beconfirmed until drilled.

All the Way to InversionThe new proficiency in acquiring multicomponentdata offshore is just one of the ways the E&Pindustry is working to extract more informationfrom shear waves. Even more value can bederived from multicomponent surveys whenborehole seismic and log inputs are integrated.At the earliest stages of survey feasibility, bore-hole seismic and log data can help model seismicwave response and plan acquisition. Three-component vertical seismic profiles (VSPs) areroutinely separated into up and down compres-sional- and shear-wave sections. Because thesesurveys record data at a common depth scale,questions of P- and S-event correlation, waveletpolarity and conversion strength are resolved.Compressional and shear velocities can be ana-lyzed and AVO effects may be calibrated. Shearsonic measurements complemented by multi-component VSPs are also used to detect andquantify velocity anisotropy in the vicinity of theborehole. With multicomponent surface seismic

data, this important information might beextended from the borehole to quantifyanisotropy at the reservoir scale.

One means of combining borehole informa-tion with compressional surface seismic datainvolves inverting the seismic reflectivity data toobtain acoustic impedance. Borehole-measuredacoustic impedance is introduced as a constraintto the inversion process. Through calibration ofacoustic impedance with logged porosity values,the resulting acoustic impedance sections maybe interpreted as porosity sections.8

This technique could also be applied to shear-wave surface seismic data. The method has beentested in the Middle East in a pilot survey over a portion of the Unayzah reservoir. The objectiveof the experiment was to demonstrate the feasibility of predicting lithology—specificallydistinguishing sand from shale—using multi-component seismic data. Studies of the availablewell data in the area indicate a good correlationbetween high sand/shale ratio and low Vp / Vs

ratio. After calibration with borehole sonic andgamma ray logs, the Vp / Vs ratios mapped fromsurface seismic data might be used as reservoirquality indicators.

14 Oilfield Review

P-S Image

p

54

3

2

10

1100 1200 1300 1400 1500 1600 1700 1800

P-P Image

P-S

P-P

P-P and P-S Amplitudes

Trace Number

> Displays of P-P (top) and P-S (middle) reflection-amplitude images from dipping layers, flattened on the target horizon.Reflection amplitude plotted versus trace number (bottom) shows relatively equal P and S amplitudes at the updip edge on the right that diverge, probably due to changes in fluid content, downdip to the left.

Spring 1999 15

The land survey consisted of three multi-component 2D surface seismic lines and five multicomponent VSPs, all acquired with com-pressional and shear vibrator sources. A numberof wells along the 2D lines penetrated the targetreservoir, and full suites of logs, including shearsonic logs and shear check shots, provided ade-quate well control. The seismic recordings wereprocessed to produce seismic sections contain-ing P-P and SH-SH reflections, and then invertedfor impedance, where the shear impedance cor-responded to that of the SH modes. Each trace inthe P-impedance section was divided by the cor-responding trace in the S-impedance section;density was cancelled out; and a Vp / Vs trace wasderived. The average Vp / Vs over the reservoirthickness can then be compared with log data indry and producing wells to see where the seis-mic-based Vp / Vs indicates there may be dry orproductive zones elsewhere on the seismic line.Interpreters are evaluating the results and willpresent findings in the near future.9

Shear AdvancesThe arrival in 1996 of multicomponent surfaceseismic technology in the offshore environmenthas, in a few short years, solved many of theproblems for which it was designed. Aspromised, it successfully images subsurface lay-ers previously obscured by shallow gas, some-thing no other surface seismic technique hasaccomplished. It can also acquire seismic data inareas of surface obstructions where streamerscannot be towed. Multicomponent methods canimage low-impedance reservoirs, register time-lapse data for monitoring fluid-contact displace-

ment, resolve changes in saturation and reservoirpressure, indicate fluid content and characterizelithology and other reservoir quality parametersbetter than methods using P waves alone.

The seabed multicomponent technique doeshave some limitations, however. Several servicecompanies operate seabottom multicomponentcable systems, each with different advantagesand disadvantages. Although there is no inherentlimit to the water depth at which the technologycan be applied, cable handling, strength specifi-cations and positioning capabilities drive practi-cal constraints. Surveys have been acquired inwater depths slightly exceeding 2000 m [6560 ft].As water depth increases, handling the longercables can require special winches or capstansfor tension reduction. Deep water also adds diffi-culty to tracking the position of the cable: tem-perature and salinity variations alter soundvelocity in water, affecting pinging systems usedfor pinpointing cable location.

To date, Geco-Prakla surveys have beenacquired with one or two Nessie 4C cablesdeployed on the seabed. In the future, acquisitioncould become more efficient with more cablesactive. The time, equipment and expertise neces-sary to deliver a high-quality seabed cable surveycommand a premium price, and currently off-shore 4C surveys cost from 1.5 to 4 times that ofa towed-streamer survey. As more such surveysare run, acquisition experience will continue togrow and the cost will decline.10

As more types of surveys are acquired andprocessed, expertise in processing will grow.Time-based processing applied today givesresults in time, not depth. Since S waves travelabout half as fast as P waves, reflections on S-wave time sections appear about twice as“deep” as reflections on P-wave sections. Forquality control of converted-wave processing, itis useful to adjust the S-wave section with atime-varying correction to tie and compare majorreflectors to the P section. To further complicatematters, what may appear as a positive event ona P section may show up as a negative event onan S section, and some events on S sections maynot even appear on P sections. For detailed inter-pretation purposes, more careful correlationtechniques may be necessary before reflectorsimaged with S waves can be compared with P-wave images.

Ultimately, converted-wave surveys, like P-wave surveys acquired to image complex struc-tures, may need depth-based processing. Thisyields images on a scale of depth instead of time.Depth-based processing requires construction ofa velocity model of the subsurface, and researchis being done to find efficient ways to do this forS waves. Advances in model-based processingare expected to help. Application of depth-basedprocessing will also be able to accommodateanisotropic velocity models, crucial to the pro-cessing of converted waves. When these pro-cessing methods are ready, there may be furtherapplication of converted-wave surveys, such asclearer imaging below salt.

To support the evolution of multicomponentmethods from their current level to one of morewidespread use requires advancing interpreta-tion techniques to get the most out of the data.The key to new interpretation techniques will beintegration of data from many sources. Oneapproach under development is to use 4C seabeddata to enhance the value of conventional 3Dtowed streamer data. In a case study from theDanish sector of the North Sea, a technique hasbeen tested in which Vp / Vs ratios were com-puted from converted-wave sections. Theseratios were used to calibrate the lithology effecton the 3D-survey AVO response so that any resid-ual AVO effect could be attributed to pore fluids.11

Integration of borehole seismic and log infor-mation will also contribute to improved con-verted-wave interpretation. This integration canprovide valuable input for forward models thatare key to lithology and fluid characterization. Inaddition to velocity and density, two propertiesparticularly important for converted-wave appli-cations are anisotropy and attenuation. Theseproperties are difficult to measure accuratelyfrom surface seismic data alone, but are rela-tively easy to measure with borehole seismicdata. Schlumberger geophysicists are investigat-ing ways to include this information to constructmodels for more accurate simulation.12

As more multicomponent surveys are run,more applications will be found. If there is aproblem that P waves can’t solve, technology isavailable to test the feasibility of solving it withshear waves. Some geophysicists believe theimpact of multicomponent methods will be asgreat as that resulting from the move from 2D to3D seismic surveys in the 1980s. What is certainis that we don’t yet know the limits of what theE&P industry can gain from shear waves. —LS

8. Ariffin T, Solomon G, Ujang S, Bée M, Jenkins S, Corbett C,Dorn G, Withers R, Özdemir H and Pearse C: “SeismicTools for Reservoir Management,” Oilfield Review 7, no. 4 (Winter 1995): 4-17.

9. Macrides CG, Kelamis PG, Marschall R, Potter G andGunaratnam K: “Lithology Estimation of a PermianClastic Reservoir Using Multicomponent Seismic Data,” presented at the 61st European Association ofGeoscientists and Engineers Conference and Exhibition,Helsinki, Finland, June 7-11, 1999.

10. Caldwell J: “Marine Multicomponent Seismic-Acquisition Techniques,” paper OTC 10981, presented atthe Offshore Technology Conference, Houston, Texas,USA, May 3-6, 1999.

11. Sønneland L, Veire HH, Hansen JO, Hutton G, Nickel M,Reymond B, Signer C and Tjøstheim B: “ReservoirCharacterization Using 4C Seismic and Calibrated 3D AVO,” presented at 60th European Association ofGeoscientists and Engineers Conference and Exhibition,Leipzig, Germany, June 8-12, 1998.

12. Leaney S, Cao D and Tcherkashnev S: “CalibratingAnisotropic, Anelastic Models for Converted WaveSimulation,” presented at the 61st European Associationof Geoscientists and Engineers Conference andExhibition, Helsinki, Finland, June 7-11, 1999.