42 Oilfield Review

The Many Facets of Multicomponent Seismic Data

Olav BarkvedBPStavanger, Norway

Bob BartmanBehtaz CompaniDevon EnergyHouston, Texas, USA

Jim GaiserRichard Van DokDenver, Colorado, USA

Tony JohnsHouston, Texas

Pål KristiansenOslo, Norway

Tony ProbertGatwick, England

Mark ThompsonStatoilTrondheim, Norway

For help in preparation of this article, thanks to Jack Caldwell, Houston, Texas, USA; Jakob Haldorsen and JoanMead, Ridgefield, Connecticut, USA; and Andreas Laake,Stephen McHugo and Alan Strudley, Gatwick, England.

In areas where conventional seismic techniques are inadequate, multicomponent

methods that use information from both compressional and shear waves are reducing

exploration risk and improving reservoir management.

1. Gaiser JE: “Acquisition and Application of MulticomponentVector Wavefields: Are They Practical?” paper E036, presented at the 66th EAGE Annual Conference and Exhibition, Paris, France, June 7–10, 2004.

2. “Embracing New Technology in Shell Malaysia,” PetroMin 29, no. 5 (July 2003): 24–25.

In the 75 years that the oil and gas industry hasbeen applying seismic technology, compressionalwaves, or P-waves, have dominated their shear-wave counterparts. Countless reservoirs havebeen discovered, characterized and monitored byP-waves as the technology has advanced fromtwo- and three-dimensional (2D and 3D) methods to the time-lapse, or four-dimensional(4D), methods available today.

Powerful though the conventional P-wavetechnique may be, it cannot solve every seismic-imaging or reservoir-description problem. In some situations, shear-wave, or S-wave, information is required in addition to P-waveinformation to adequately image a reservoir ordescribe reservoir properties. With the addi-tional help of S-waves, oil and gas companieshave found new reserves—hundreds of millionsof barrels of oil and tens of billions of cubic feetof gas—that would not have been found with P-waves alone.1 Millions of dollars have beensaved by properly placing wells using shear-wave information.2

Shear-wave information can improve bothseismic imaging and reservoir characterization.Imaging problems occur when shallow gas dras-tically lowers the overburden P-wave velocity,disrupting P-wave transmission and obscuringlarge volumes of the underlying subsurface. Also,high-velocity layers, such as salt or hard volcanic

rocks, can shield deeper targets from properillumination. This occurs because the highimpedance contrast bends seismic raypaths significantly, causing problems with illuminationand imaging of deeper reflectors. Some reservoirs exhibit a low P-wave acoustic-impedance contrast relative to surroundinglayers, generating only low-amplitude reflectionsand effectively hiding from P-waves.

Compressional waves may fail to determineimportant reservoir properties. For example, areservoir limited by gradual pinchouts andlithology changes may be too subtle for detec-tion by P-waves. Even if compressional wavesindicate a lateral or time-lapse change in reser-voir properties, interpretation of conventionalP-wave data may not be able to distinguishchanges in rock properties, such as lithology orformation stress, from changes in fluid com-position or pressure. Enhanced processing and interpretation of specially acquired compressional-wave data, such as amplitude-variation-with-offset (AVO) analysis, may helpdifferentiate lithology changes from fluidchanges, but typically the results are more qualitative than quantitative. Compressionalwaves alone may fail to characterize the presence, density and orientation of fractures inthe reservoir or in the overburden.

Summer 2004 43

Most of these difficult reservoir problems canbe solved or improved by the addition of S-waveinformation. In this article, we review how shearwaves contribute to enhanced understanding ofreservoirs and we describe the acquisition tech-nology that facilitates collection of high-qualityshear-wave information. Examples from theNorth Sea and the Gulf of Mexico demonstratethe successful resolution of imaging and reservoir-characterization problems by combin-ing results from P- and S-waves.

Shear WavesShear waves bring additional knowledge to aseismic study because compressional and shearwaves sample different rock properties.3

Compressional-wave velocity is a function of amedium’s density, shear modulus and bulk mod-ulus. Bulk modulus is sensitive to fluidcompressibility, making P-waves highly sensitiveto a rock’s fluid content. The dual dependenceon fluid compressibility and shear modulusallows P-waves to propagate in both solids and liquids.

Shear-wave velocity is a function of the density and the shear modulus of the medium; ashear wave is almost insensitive to a rock’s fluidcontent. In a given formation, shear-wave veloc-ity and reflectivity remain unchanged whetherthe formation contains gas, oil or water. However, S-waves can travel only in media withnonzero shear modulus, so they can originateand propagate only in solids.

By combining information from both P- andS-waves, seismic interpreters can learn moreabout the subsurface than from just one wavetype. From P and S velocities (Vp and Vs), lithol-ogy can be determined more readily than withP-wave data alone. Knowing both velocities,interpreters can make use of the Vp/Vs ratio topredict rock type. Comparison of P-wave with S-wave behavior at a reflector can distinguishlithology changes from fluid changes: a lateralchange in P-wave reflection amplitude along alayer boundary may indicate either a lithologychange or a fluid change, but if the S-wavereflection amplitude at the same boundary alsochanges, the variation more likely points to alithology change. Consistent S-wave reflectivityat the same reflector indicates a change in fluidtype is more probable.

In compressional waves, particle motion isparallel to the direction of wave propagation(top left). This is different from the shear-wavecase, in which particle motion is perpendicular

44 Oilfield Review

IncidentP-wave

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> Particle motion and propagation of compressional and shear waves. Forcompressional, or P, waves, particle motion is parallel to the direction ofwave propagation. In shear, or S, waves, particle motion is perpendicular to the direction of wave propagation, and is constrained to the plane ofreflection. In this case, S-wave particle motion is in the plane of the page.

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> Detecting converted waves by seabed sensors. At subsurface interfaces, incident P-waves reflectand transmit as P-waves and also are partially converted to S-waves. Upgoing S-waves can be detectedby seabed receivers sensitive to multiple components of motion. The four receiver components consist ofone hydrophone and three orthogonally oriented geophones or accelerometers—X, Y and Z (inset).

Summer 2004 45

to the direction of wave propagation. In conven-tional surface seismic data acquisition, seismicwaves reflect at subsurface reflectors, thenarrive at the surface traveling nearly vertically.This means that P-waves can be recorded by sin-gle-component geophones that detect verticalmotion in the formation. Compressional wavescan also be detected by hydrophones, or pressure sensors, surrounded by water—the typical recording arrangement in towed marineseismic surveys.

Recording S-waves requires geophones thatdetect more than just the vertical component, sostandard P-wave recording systems are inade-quate. Shear waves are transverse waves, whichmeans that the particle motion is perpendicularto the direction of propagation. Therefore, the S-wave field is fully three-dimensional, andthree-component sensors are required to characterize it. The most common form of three-component sensor is a sensor comprisingthree geophones in orthogonal orientation,which allows detection of S-waves from all possible directions. This use of more than onereceiver has given rise to the name “multi-component” surveys.

The S-wave motion recorded on the horizontal components is reconstructed bymathematical rotation into a radial componentof motion in the plane of wave propagation, anda transverse component out of the plane of wave propagation.

The earliest practical attempts at using S-waves in the exploration and productionindustry date back to the 1950s, when geophysi-cists conducted multicomponent experiments onland.4 In those experiments, an oscillating, orshear-wave, source generated direct shear wavesthat reflected at depth and were recorded on thesurface. Since these early attempts, many land-based multicomponent surveys have beentechnically successful, but they are difficult toacquire. Each geophone must be oriented in thesame direction to allow coordinate rotation, andmust be planted firmly in the ground to accurately measure ground motion. Land multicomponent surveys feature three orthogo-nal sensors, requiring three times the number ofrecording channels and three times the data vol-ume of a single-component survey. Processing ofland shear surveys is also problematic becauseinhomogeneity of near-surface layers causeslarge traveltime variations for the S-waves.

As in land seismic surveys, recording S-wavesin a marine seismic survey requires deploymentof multicomponent sensors on the ground, inthis case on the seafloor. The earliest marine-

environment shear waves were recorded in theearly 1970s with ocean-bottom seismometers(OBSs) thrown overboard. Later experimentspressed OBSs into the seafloor by a remotelyoperated vehicle (ROV).

While the analogy with land multicomponentsurveys works well to describe marine multi-component receivers, it cannot be applied tomarine seismic-source technology: it is stillimpractical to deploy a shear-wave source on theseafloor. Fortunately, although typical marineseismic sources used in towed-streamer surveysdo not directly generate S-waves, the P-wavesthey do generate can in turn generate S-waves inthe subsurface. Compressional waves undergopartial conversion to shear waves at subsurfaceinterfaces and can be detected as S-waves byseabed sensors (previous page, bottom).Recorded waves that start as P-waves and con-vert to S-waves usually are called convertedwaves, or PS-waves, but some recent literaturecalls them C-waves, for converted. Their counter-parts, those waves that start and reflect asP-waves, are called PP-waves.

Converted waves reflect at subsurface inter-faces according to Snell’s law, which relates theangles of incidence, reflection and transmissionto the velocities of propagation of P- and S-waves. For P-waves reflecting at an interface,the angle of reflection equals the angle of inci-dence. This symmetry simplifies acquisition andprocessing of P-wave surveys. However, for PS-waves, the S-wave angle of reflection does notequal the P-wave angle of incidence. An S-wave always reflects more vertically than woulda P-wave, because the propagation velocity of anS-wave is less than that of a P-wave. This asym-metry complicates acquisition and processing ofconverted-wave surveys. Compressional-waveprocessing takes advantage of the fact that the P-to-P reflection point is at the midpointbetween source and receiver. Processing forshear waves must take into account the fact thatthe conversion point is closer to the receiver.

Early techniques for recording PS-wavesgrew out of connecting several OBSs with acable for power and communication, and drop-ping the receiver spread into place.5 An ROV wasstill needed to press each OBS, or node, into theseabed. Another variety of marine shear-waverecording system, called a cable system, is basedon well-logging technology and uses multicom-ponent sensors packaged in steel cylindersconnected by high-strength conductive cable. Adifferent type of seabed-cable technologyevolved from two-component systems called bay

cables, which were designed to improve shallow-water P-wave acquisition by recording with onehydrophone and one geophone. A four-component version, developed by WesternGecoand first used commercially in 1996, relies on seismic-streamer technology similar to thestreamers towed in today’s marine seismic sur-veys. The new systems are known as ocean-bottomcables (OBCs).

The newest marine multicomponent acquisi-tion systems developed by WesternGeco deploy aversion of the fluid-filled cable on the seafloor,and have sensors with three geophone-accelerometers (GACs) and one hydrophone.The three orthogonal GACs, called X, Y and Z,measure the full wavefields of arriving waves.The orientations of each GAC are measuredindependently so that the recorded data can berotated mathematically to yield three neworthogonal components of data—one verticaland two horizontal, with one horizontal component aligned in the direction of wavepropagation. The hydrophone, sensitive to fluid-pressure changes, provides an additionalmeasurement of the P-wave motion. Theseacquisition systems are known as marine four-component (4C) technology, which is synonymous with multicomponent technology.The most advanced systems have extendedacquisition-depth capabilities to record surveysin water depths reaching 2,500 m [8,200 ft],addressing the need for better fluid and lithol-ogy determination in new deepwater prospects.

Marine multicomponent surveys require sev-eral steps for acquisition of high-quality data.6

Before each survey, a reconnaissance side-scansonar study examines the seafloor and inspectspotential seabed-cable locations. Next, a seismicrecording vessel with dynamic-positioning capa-bility deploys the cables as it moves alongselected receiver-line positions. During cabledeployment, the vessel acquires position datafrom transponders on the seabed cables to makesure they are in the correct locations.

After the first cable is in place, its end is con-nected to a buoy while the vessel deploys asecond cable, usually parallel to the first. Most3D multicomponent surveys are acquired withtwo to six active cables on the seabed. When all

3. Caldwell J, Christie P, Engelmark F, McHugo S, Özdemir H,Kristiansen P and MacLeod M: “Shear Waves ShineBrightly,” Oilfield Review 11, no. 1 (Spring 1999): 2–15.

4. Jolly RN: “Investigation of Shear Waves,” Geophysics 21,no. 4 (October 1956): 905–938.

5. Caldwell J: “Marine Multicomponent Seismology,” TheLeading Edge 18, no. 11 (November 1999): 1274–1288.

6. Rowson C: “4C Seismic Technology Makes Mark inCaspian Sea,” Offshore 63, no. 5 (May 2003): 50.

cables have been set out, the cable ends areattached to the recording vessel so that datafrom all cables can be recorded. Additionalcable allows the recording vessel to move out ofthe way of the source vessel without moving theseabed detectors.

The source vessel shoots along predeter-mined shot lines, creating a swath of datarecorded by the seabed streamers in this firstlocation. Then, the recording vessel recovers thestreamers and lays them out again to cover thenext swath. Multicomponent surveys can com-prise tens of overlapping swaths so as not toleave any gaps in subsurface coverage.

Several properties of the water layer and theseabed can affect the quality of multicomponentsurveys acquired by seabed sensors. Some fac-tors affect multicomponent data quality morethan towed-streamer data quality, and some factors have less effect on multicomponent data.Currents can influence the ability to deploy both towed and seabed cables accurately. Depth-dependent variations in temperature andsalinity can disrupt the transmission of acousticwaves used to locate seabed sensors, leading toerrors in sensor location. And while the oceanfloor is usually a quieter environment than theocean surface for marine acquisition, the pres-ence of deep currents, unconsolidated sedimentand bathymetric features may affect seabed dataquality and cable stability.

The first acquisition of marine four-compo-nent seismic data for reservoir mapping was in1993 by Statoil in the Tommeliten field.7 This 2Dseismic line was acquired with a node-based sys-tem of connected OBS sensors deployed by ROV.In 1994, Geco-Prakla acquired the rights todevelop this technology, and also introducedfour-component streamer-type cables. By 1996,Amoco was testing various 2D systems at theirValhall and Hod fields.8 Western Geophysicalconcurrently enhanced their two-componentequipment—one hydrophone and one geophone—to handle four-component acquisi-tion, and Petroleum Geo-Services Company(PGS) developed a concept based on a heavy-duty cable on runners.

Western Geophysical and Geco-Prakla werethe first to have 3D capability. In 1997, 3D multicomponent surveys were acquired on theOseberg and Statfjord fields.9 The first fully com-mercial success was on the Valhall field, a surveyacquired for Amoco by Geco-Prakla in 1997 and1998.10 The Alba and Lomond field surveys followed soon after.

Seeing through GasThe combination of P- and S-waves has improveddevelopment drilling in the Lomond field, oper-ated by BP in the UK sector of the North Sea.This gas condensate field, discovered in 1972, hasbeen producing since 1993. The reservoir struc-ture is a fractured dome overlying a salt diapir.The producing interval is a high-quality Fortiessandstone partitioned by a fault. Production fromone side of the fault is good, while wells pene-trating the other side are poor producers.

Delineating the major fault is difficult,because gas above the structural crest—gas thatprobably has migrated up along the numerousfaults that cut through the dome—disturbs P-wave propagation. An image from a conven-tional 3D towed-streamer survey exhibits theimaging problems typical of gas clouds (aboveleft). In gas-charged areas, reflections “sag”because gas reduces P-wave velocities. Lowvelocity through the gas layers increases travel-time, which increases apparent thickness onseismic images displayed with traveltime as thevertical axis. In addition to reflection sagging,gas causes faults at the structural crest to bepoorly imaged and obscures reflections insidethe dome.

Converted waves recorded by a 3D multi-component survey acquired in 1998 helpedcreate a clear picture of the Lomond structure(next page, top). Comparison of the PP imagewith the PS image shows a significantly better

46 Oilfield Review

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> Imaging problem in the Lomond gas cloud. The gas cloud obscures this PP image from a conventional 3D towed-streamer survey. Reflections nearthe crest of the Lomond structure are weakened by transmission through the gas-charged zone. Some reflections “sag” because gas reduces seismic velocities.

Summer 2004 47

result with the PS data. On the PS section, thefault is clearly resolved, making it possible toconfidently locate development wells. A newwell that was drilled with the guidance of thesePS data landed on the correct side of the faultand was a good producer.11

Seabed multicomponent surveys also havebeen successful in imaging through gas in theGulf of Mexico (right). In multicomponent 3Ddata from the West Cameron area, the convertedPS image clearly reveals improved fault and stratigraphic resolution relative to the PP

7. Berg E, Svenning B and Martin J: “SUMIC—A NewStrategic Tool for Exploration and Reservoir Mapping,”paper GO55, presented at the 56th EAEG Meeting andTechnical Exhibition, Vienna, Austria, June 6–10, 1994.

8. Kommedal JH, Barkved OI and Thomsen LA: “Acquisitionof 4 Component OBS Data—A Case Study from ValhallField,” paper BO47, presented at the 59th EAGE Meetingand Technical Exhibition, Geneva, Switzerland, May 26–30, 1997.

9. Rognø H, Kristensen A and Amundsen L: “The Statfjord 3-D, 4-C OBC Survey,” The Leading Edge 18, no. 11 (November 1999): 1301–1305.

10. Brzostowski M, Altan S, Zhu X, Barkved O, Rosland B andThomsen L: “3-D Converted-Wave Processing over theValhall Field,” Expanded Abstracts, 69th SEG AnnualInternational Meeting and Exposition, Houston, Texas,USA (October 31–November 5, 1999): 695–698.

11. Pope DA, Kommedal JH and Hansen JO: “Using 3D 4CSeismic to Drill Beneath the Lomond Gas Cloud,” paperL01, presented at the 62nd EAGE Annual Conference andExhibition, Glasgow, Scotland, May 29–June 2, 2000.

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> Comparison of 3D data from a towed-marine survey and a seabed survey. In the PP image from the towed-marine survey (left), reflections at the crest of theLomond structure are obscured by shallow gas. The PS converted-wave image from the seabed survey (right) clearly resolves the large fault passing throughthe structure at its crest, and fully illuminates the structure with high-amplitude reflections.

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> Areas of the Gulf of Mexico covered by WesternGeco multicomponent surveys.

image (left). Faults, laterally continuous reflec-tions and changes in amplitude that areambiguous on the PP section are unmistakableon the PS section.

In another example, Devon Energy used mul-ticomponent seismic methods to identifyadditional gas reserves in a producing area ofthe Gulf of Mexico, where a large proportion ofgas production comes from shallow reservoirs.Often, the tapped zones are simply the shallow-est of a series of stacked gas sands that could allbe produced by the same surface facilities if thedeeper sands could be discovered. However,deeper gas-bearing zones are difficult to imagebecause the presence of shallow gas seismicallyobscures them (below left).

In 2001, Devon Energy used multicomponentdata acquired by WesternGeco in the WestCameron area offshore Louisiana, USA, toreduce risk in the drilling of four gas wells. Theflat-lying layers of the prospect area createdadditional challenges in interpreting the con-verted-wave images, because there were nostructural features to match from the P-waveimage. Converted-wave images are obtained inPS time: that is, the vertical, or traveltime, axishas units that correspond to the time requiredfor the wave to descend as a P-wave and reflectas an S-wave. Since S-waves are slower than P-waves, PS times are larger than PP times, soPS sections appear stretched relative to PP sec-tions (next page, top).

Interpreting PS sections alongside conven-tional towed-streamer images, which aredisplayed in PP time, requires converting PS time to PP time. Since there is no reliablepetrophysical function that relates shear veloc-ity to compressional velocity at every depth, thisconversion is performed in an interpretive man-ner. Seismic-processing interpreters unstretchthe PS section to find a match with the PP sec-tion, taking into account that the relativestretch varies with depth and that individualevents may have different amplitude and polar-ity on the PP and PS images (next page, bottom).

Interpreting multicomponent data in thisway, Devon Energy was able to correlate eventsin the converted-wave section with P-waveevents at known drilling depths. All four wellsdrilled with the aid of interpreted multicompo-nent sections were successful, and the companydeveloped a number of other prospects withtheir 4C data. In total, nine wells were drilledand seven were successful.

Rocks and Fluids from Multicomponent DataOne excellent example of using multicomponentdata to discriminate lithology is also an excel-

48 Oilfield Review

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West Cameron Area Imaging through Gas

> Conventional, towed-marine PP data and seabed multicomponent PS data from the West Cameronarea, Gulf of Mexico. The converted PS section (right) clearly reveals faults, lateral continuity inreflection character and changes in amplitude that are ambiguous on the PP section (left).

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> Shallow gas obscuring deeper gas reservoirs in the Gulf of Mexico. Thehigh-amplitude reflection near the top of this PP section reveals the shallowgas reservoir already in production. However, the shallow gas also preventsP-waves from imaging deeper reserves.

Summer 2004 49

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>Matching PS images with PP images. In this area with flat-lying reflectors and no gas production, converted-wave reflections recorded in PS time aredifficult to match uniquely with compressional-wave reflections recorded in PP time. A PS image (center) converted to PP traveltime has been inserted into a PP image (left and right), and shows good agreement in all but the shallowest reflections.

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> Relating converted-wave sections in PS traveltime to compressional-wave sections in PP traveltime. Since S-waves are slower than P-waves, PS times(center) are later than PP times (left), so PS sections appear stretched relative to PP sections. Seismic-processing interpreters unstretch the PS section tofind a match with the PP section, taking into account that the relative stretch varies with depth and that events that are strong on a PP image may be weakon the PS image, and vice versa. The final PS image displayed in PP time (right) shows several stacked gas sands with high amplitudes.

lent example of imaging a reservoir with low P-wave impedance contrast. The Alba field in theUK sector of the North Sea consists of high-porosity, unconsolidated turbidite channel sandscontaining intrareservoir shales that contributeto drilling, completion and production problems.Because the P-wave acoustic impedance of the sandstones is similar to that of the shalecaprock, the reservoir top is nearly invisible onPP images. However, it becomes clearly illumi-nated in PS sections.12

From 1993 to 1998, the field produced130 million barrels [20.6 million m3] of oil from15 horizontal wells. In 1998, several new wellswere planned to improve drainage by penetrat-ing pay as close as possible to the top of thereservoir. Illuminating the low impedance-con-trast reservoir was difficult with P-waves, so aseabed survey was designed to map the top ofthe oil-rich sand. Since the new wells might bedrilled near existing producers and injectors, it

was also important to be able to predict fluidsaturation ahead of the bit. The new seabed survey would be compared with an earliertowed-streamer survey to reveal seismicallydetectable saturation changes.

Analysis of the data cube from the seabedsurvey gives a 3D mapping of lithology, whereasthe PP data from the earlier towed-streamer survey present an ambiguous picture (above).These reflection-amplitude maps of the top of

50 Oilfield Review

Alba Field PP Amplitudes Alba Field PS Amplitudes

> Lithology discrimination in the Alba field, operated by ChevronTexaco in the UK sector of the North Sea. Because the reservoir and its surroundingshales have similar acoustic impedances to P-waves, the reservoir does not show up clearly on a map of PP reflection amplitudes (left). Scatteredbrightness (yellow) signifies zones of impedance contrast, indicating potential sand-rich lithology. The reservoir has high acoustic impedance to S-waves, so the reflection-amplitude map for PS-waves (right) clearly shows a sand-rich channel and some sand-rich lobes (green and yellow).

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> Low acoustic-impedance contrast and fault shadowing in the Eugene Island area of the Gulf ofMexico. In the PP section (left), reflections beneath the fault (green) are not clearly imaged, nor is thefault itself resolved. In the PS section (right), converted waves illuminate the volume under the fault(black oval). The blue rectangle highlights an area in the PP image that shows a high-amplitude bright spot, sometimes indicative of hydrocarbon. However, the same area on the PS image is alsohigh-amplitude, suggesting that the reflection could be a high-impedance lithology change. The black rectangle highlights another bright spot in the PP image, but the dim response on thecorresponding PS section suggests that this bright spot could contain hydrocarbons.

12. MacLeod MK, Hanson RA, Bell CR and McHugo S: “TheAlba Field Ocean Bottom Cable Seismic Survey: Impacton Development,” paper SPE 56977, presented at the SPE Offshore Europe Conference, Aberdeen, Scotland,September 7–9, 1999; also in The Leading Edge 18, no. 11(November 1999): 1306–1312.

13. Wilkinson D: “Imaging the Alba Reservoir with PS-Wavesfrom OBC Data and AVO Processing of PZ and PP Data,”presented at the 73rd SEG Annual Meeting and International Exposition, AVO Workshop, Dallas, Texas,USA, October 31, 2003.

Summer 2004 51

the reservoir show high amplitudes when PS waves encounter sand-rich reservoir, and lowamplitudes when the reflector is shale-rich. Thehigh amplitudes map out a sand-rich channeland some sand-rich lobes. Some of the same fea-tures can be seen only vaguely in the PP section.

With the help of the PS data cube, seismicinterpreters were able to distinguish reservoirsand from the encasing shale. Well plannerswere able to locate the new horizontal wells inthis channel just below the reservoir top toreduce water influx. As a result, the Alba assetteam has executed a successful horizontal-wellprogram, placing numerous wells in the richestinterval of the reservoir and adding substantialnew reserves.13 The time-lapse comparison of

seabed and streamer surveys helped identify andavoid regions of high water saturation.

Low impedance-contrast intervals also causeimaging problems in other regions. In theEugene Island area of the Gulf of Mexico, forexample, such intervals can have the addedcomplication of lying in the imaging shadow of a fault (previous page, bottom). Here, the converted-wave section reveals several featuresnot visible in the PP section. The fault itself ispoorly resolved by the P-wave image, and theregion in the fault shadow, indicated by theblack oval, is much better resolved on the PSsection. The PP image shows a high-amplitudebright spot that might be interpreted as a hydro-carbon indicator on the right side of the section.

The corresponding reflection on the PS image,however, is also high-amplitude. This would cau-tion an interpreter about assuming a correlationwith hydrocarbon content, and would suggestthe need for further analysis. In the same sec-tion, the PP image exhibits another brightresponse near the top of the section. The dimresponse on the PS section suggests that thisbright spot is a potential hydrocarbon interval.

Taking advantage of the difference in P- andS-wave response to fluid content, interpreterscan examine subsurface volumes for bypassedpay. An example from the Eugene Island areamulticomponent 3D survey shows how fluid indicators may be obtained by subtracting PSresponses from PP responses (below). First,

PP Section PS Section PP-PS DifferenceEugene Island Amplitude Extractions, Horizon at 3,000 ft

> Using differences in PP and PS responses to map remaining fluids. Reflection amplitudes from the PP (top left) and PS (top center) seismic volumes areextracted across a horizon corresponding to a depth of approximately 3,000 ft [915 m]. High amplitudes (orange) on the map of their difference (top right)show where hydrocarbons may be trapped. Zones with the highest amplitudes (black outlines, bottom right) can be matched with high-amplitude areas onthe PP section (black outlines, bottom left) to show the bright spots that can be trusted as hydrocarbon indicators.

reflection amplitudes from the PP and PSseismic volumes are extracted across a hori-zon corresponding to a depth of approximately3,000 ft [915 m]. Then, a map of their differ-ence highlights potential trappedhydrocarbon where the difference amplitudeis high.

Monitoring Reservoir ChangesMulticomponent surveys can provide impor-tant information about reservoir changescaused by movement of fluid as a result of pro-duction or enhanced-recovery efforts. Onetype of change is reservoir compaction. Com-paction, caused by fluid extraction, can act asthe drive mechanism to maintain production,but it also can cause instability in overlyinglayers. In extreme cases, reservoir compactioncan lead to collapse of overburden and even toseafloor subsidence.

Since shear waves are sensitive to a rock’sshear modulus, they respond to changes inrock stiffness and strength. When stiffnessand strength changes have preferential orientations, shear waves undergo birefringence—as they do in the presence of aligned fractures (see “Characterizing Fractures with S-Waves,” left).

The Valhall multicomponent survey in theNorwegian North Sea was primarily designedto illuminate the crest of the Valhall structure,where gas causes conventional towed-streamer images to be obscured. WesternGecoacquired the 3D multicomponent survey dur-ing the winter of 1997 to 1998.

A few years after the survey was acquired,WesternGeco began to reprocess the data forBP, the operator. The primary objective of thereprocessing effort was to improve the seismicvelocity model of the overburden, with theexpectation that a better overburden-velocitymodel would improve imaging at the level of the reservoir.14

Because shear-wave splitting had beenobserved during earlier data processing, pro-cessing specialists included anisotropy in theseismic-velocity model. The Valhall reservoir isfractured at the crest, so anisotropy wasexpected in the reservoir layers. Also, reportsfrom earlier processing indicated significantanisotropy effects in the overburden. Duringreprocessing, WesternGeco geophysicists foundthat even shear waves converted from the shal-lowest layer showed the effects of shear-wavesplitting, and to an extent not yet seen in otherNorth Sea 3D multicomponent surveys.

Plotting the direction of the fast shearwave and the difference between fast and

52 Oilfield Review

Understanding fracture systems in reservoirsis important for infill-drilling programs, hori-zontal well design and enhanced oil-recoveryprojects. Stresses in the Earth cause mostfractures to be vertical and aligned with eachother. Individual fractures that are smallerthan the seismic wavelength may not bedetected by seismic waves, but seismicwaves—especially shear waves—can senseaverage fracture properties within a large volume to help determine average fractureorientation and density.

Shear waves traveling through or reflectingat such a fractured medium undergo shear-wave birefringence, or splitting. Birefringencecauses a shear wave to split into two waves

with different velocities, one fast and one slow.The fast S-wave particle motion is polarized inthe average direction of fracture strike, and the slow S-wave has particle motion polarizedperpendicular to fracture strike (above). Thedifference in traveltime between the fast S-wave and the slow S-wave is related to fracturedensity. Analyzing land-based multicomponentdata with this method has been used in car-bonate reservoirs to identify zones of highfracture density that have subsequently beenvalidated by drilling and production.1

Characterizing Fractures with S-Waves

Formation

slow axis

Formationfast axis

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> A shear wave splitting into fast and slow waves after reflection at ortransmission through a fractured or anisotropic medium. Fast S-waveparticle motion (blue) is polarized in the average direction of fracture strike,and the slow S-wave (yellow) has particle motion polarized perpendicular tofracture strike. The difference in traveltime between the fast and slow wavesis related to fracture density.

1. Li X-Y and Mueller M: “Case Studies of Multicompo-nent Seismic Data for Fracture Characterization: AustinChalk Examples,” in Pala I and Marfurt KJ (eds): Car-bonate Seismology. Tulsa, Oklahoma, USA: Society ofExploration Geophysicists (1997): 337–372.

Summer 2004 53

slow shear velocities, geophysicists discovered a surprising correlation between the shear-velocity properties of the shallowest layer and

the amount of seafloor subsidence over the crestof the Valhall field (top). The results from theshallowest layer, which extends only a few

hundred meters below the seafloor, show a ringpattern that matches the shape of seafloor subsidence that has occurred since the onset ofoil production.

The actual mechanism causing the shallowshear-wave splitting is not known. Azimuthalanisotropy is usually associated with fracturing,stress or lithology. In this case, the amount ofanisotropy is small at the center of the fieldwhere the subsidence is largest, but theanisotropy is large on the flanks and small againfarther from the center. This strongly points toshear-wave splitting being sensitive to changesin stress or strain. It is believed that this smallamount of seabed subsidence is linked tochanges at the reservoir level—the result offluid production, weakening of the chalk reservoir by water injection, and subsequentcompaction of the reservoir layer.

Detecting reservoir changes with time is thepurpose of 3D time-lapse P-wave surveys, alsoknown as 4D surveys (see “Time Will Tell: NewInsights from Time-Lapse Seismic Data,” page 6).However, in areas where P-waves cannot adequately image the reservoir, geophysicists maybe able to use time-lapse multicomponent data to detect changes that could affect reservoir-development decisions. The first such survey wasrecently performed in the Ekofisk field.

The seafloor overlying the Ekofisk field in theNorth Sea has experienced at least 8 m [26 ft] ofsubsidence, requiring operator ConocoPhillipsto modify platforms and undertake efforts to sta-bilize the effects of future production. Sinceproduction began in 1971, the high-porositychalk formation has produced 1.9 billion bbl[302 million m3] of the 6.7 billion bbl [1.1 billion m3] of oil originally in place. Produc-tion is expected to continue until 2050.Monitoring and mitigating the effects of production are key to achieving long-term project viability.

Monitoring production seismically requirestime-lapse multicomponent technology: approxi-mately one-third of the Ekofisk structure isobscured on existing P-wave images by free gasand overpressured shales in the overburden. Forthe world’s first time-lapse marine multi-component study, an initial multicomponentsurvey performed in September 2002 formed thebaseline. This was compared with the monitorsurvey acquired in December 2003.15 In each sur-vey, a seabed cable was used to acquire datawith a wide range of azimuths (left).

Seafloor subsidence, m

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> Shallow-level shear-wave splitting correlating with subsidence over theValhall field, North Sea. Angled line segments depict the direction of the fastshear wave in the layers just below the seafloor. The length of each linesegment is proportional to the difference between fast and slow shear-wavespeed. Thin lines are receiver lines. Blue shading corresponds to subsidenceof the seafloor over the Valhall Field.

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> Multicomponent survey design and azimuthal binning for the Ekofisk 2003 seabed survey. Red dotsrepresent shotpoints, and blue triangles in a blue box in a line near the center of the survey representreceivers in the seabed streamer. To study azimuthal effects and quantify shear-wave splitting, tracesfrom each receiver location were binned into 10-degree sectors and then stacked. Azimuthal bins areshown for only the first receiver on the left end of the seabed streamer.

14. Olofsson B, Probert T, Kommedal JH and Barkved OI:“Azimuthal Anisotropy from the Valhall 4C 3D Survey,”The Leading Edge 22, no. 12 (December 2003): 1228–1235.

15. Van Dok R, Gaiser J and Probert T: “Time-Lapse ShearWave Splitting Analysis at Ekofisk Field,” paper G046,presented at the 66th EAGE Annual Conference and Exhibition, Paris, France, June 7–10, 2004.

For each survey, converted waves were ana-lyzed to determine the principal directions offast and slow S-waves. At every sensor location,recorded traces were collected, or binned, into10° sectors according to azimuth from the shotlocation, then stacked. This produces a set of 36 traces for each component at every receivedlocation. Principal directions show up as varia-tions in arrival times on the radial component,and low amplitudes on the transverse compo-nent (left). The fast direction corresponds toearlier arrivals on the radial component, and theslow direction corresponds to later arrivals onthe radial component. These principal direc-tions are associated with a polarity reversal onthe transverse component resulting from thedestructive interference of the two S-waves inthese orientations.

Comparison of data from the two multicom-ponent surveys after a year’s worth of productionindicates some small changes in the direction ofthe fast shear wave and in the differencebetween fast and slow shear velocities. The dif-ferences are not consistent across the field, andhave yet to be understood, but are still beingevaluated. The currently observed subsidence isa result of more than 30 years of production, andit is not clear if the effects of one year will beobservable. However, it is likely that a greatersubsidence effect will be seen over a longer production interval.

In another time-lapse multicomponent pro-ject, BP has installed a seabed array—this timepermanently—in the Valhall field offshore Norway to monitor reservoir changes. The deci-sion to install this array and to acquire repeat3D multicomponent seismic surveys at regularintervals was based on the business need to usetime-lapse seismic technology to help determinethe reservoir-drainage strategy, improve wellplanning through the selection of optimal drillingtrajectories and to identify increased reserves asa result of improved reservoir description.

When Valhall production started in 1982, thefield contained 39 million m3 [245 million bbl] ofrecoverable oil reserves. Improvements in reservoir characterization have raised oilreserves by a factor of four, to 167 million m3

[1.05 billion bbl], of which 88 million m3

[554 million bbl], or half, have been produced.BP expects continued growth in Valhall reservesto accompany further improvements availablethrough reservoir monitoring.

The monitoring project will allow repeat multicomponent seismic surveys to image belowthe shallow gas that prevents adequate P-waveimaging. Permanent installation of the seabedsensors will allow time-lapse surveys to acquire

54 Oilfield Review

50 140 230 320 50 140 230 320

Radial Component Transverse Component

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> Azimuth-limited stacked traces from one receiver in the Ekofisk 2003 seabed survey. Each of thetwo panels contains 36 traces, one trace for each 10° bin. On the radial component (left), reflectionsappear to undulate as the bin azimuth turns around 360°. For each undulating reflection, the earlierarrivals correspond to fast shear waves and later arrivals correspond to slow shear waves. The fastshear-wave direction, therefore, is 140°. The principal directions of fast and slow shear waves showup as low amplitudes on the transverse component (right).

Imaging below gas clouds 100

Imaging targets of poor PP reflectivity 86 14

Lithology delineation: clastics 56

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Fluid discrimination

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> Results of a poll of shear-wave specialists at a workshop held by the Society of ExplorationGeophysicists in 2000. Attendees were asked to quantify how well proven they believe multicomponentseismic methods are for addressing 24 different geological or geophysical problems. For solving almostall the proposed problems, multicomponent methods are considered proven or possible.

Summer 2004 55

data from an array of receivers at the same locations, generating repeatable surveys. Theseafloor cables cover a 45-km2 [18-sq mile] areaand are permanently connected to a platform-based recording system.

For implementation of the permanent-moni-toring project on the Valhall field, the ValhallUnit and BP won the Norwegian PetroleumDirectorate’s 2003 Improved Oil Recoveryaward.16 The award acknowledges creativity andthe willingness to take risks in applying methodsthat can improve recovery beyond what can nor-mally be expected. The Norwegian PetroleumDirectorate believes that the time-lapse multi-component method could have potential formany other fields in Norway and elsewhere.

Improving Multicomponent MethodsMarine multicomponent surveys have been avail-able commercially since 1996, and have beenshown to be successful in solving several seismic-imaging and reservoir-characterizationproblems. Some oil and gas companies are con-vinced of the benefits of the multicomponentapproach, while others remain to be persuaded.

To understand the extent to which usershave accepted multicomponent applications,shear-wave specialists examined the question ata workshop held by the Society of ExplorationGeophysicists (SEG) in 2000. A poll of attendeesrevealed how well they believe multicomponentseismic methods can solve any one of 24 possible

geological or geophysical problems (previouspage, bottom).

As the top-ranking application, imagingbelow gas was seen by 100% of attendees as aproven use of multicomponent technology. Imag-ing targets with low P-wave impedance contrastranked second, selected as proven by 86% ofrespondents. A clear majority of specialists per-ceive that these top two applications are proven.The other 22 problems received divided scores,but nearly all are considered possible to solvewith multicomponent technology.

To increase the level of acceptance of multi-component methods, geophysicists are workingto improve all aspects of the technology, fromsignal quality and acquisition efficiency to dataprocessing and interpretation. On the acquisi-tion side, significant advances have been madein newly developed systems. These improve-ments include increasing the water-depthcapabilities of surveys from a few hundredmeters to 2,500 m. Node-based, as opposed tostreamer-based systems, are also able to acquirehigh-quality shear-wave data at these depths.However, node-based systems are operationallyinefficient compared with OBC systems.

New sensor developments include microelec-tromechanical systems (MEMS). MEMS sensorsare based on miniaturized accelerometers,which are produced in a manner like that ofmicrochips. As with geophone accelerometers,these sensors aim to improve the quality of the

recorded seismic signal through improved signal-to-noise ratio and reduced cross-feedbetween the three sensor components.

Other improvements to signal quality areenhancing fidelity and increasing bandwidth inrecording the full wavefield of seabed data.Improving coupling between multicomponentsensor packages and the seafloor also improvesdata quality. These data-quality objectives needto be achieved while also improving operationalefficiency. While recording on the seafloor typi-cally increases survey cost by several timescompared with towed-streamer surveys, thevalue of information can easily outweigh theadditional cost.

The results of processing converted-wavedata have sometimes been disappointing in comparison with P-wave results in the samearea. Processing of multicomponent data has always been challenging because of theasymmetry in the raypaths caused by the velocity difference between P- and S-waves.WesternGeco geophysicists are developingenhanced imaging algorithms tailored to multi-component data. Using Kirchhoff prestack timemigration, in which traveltimes are calculatedaccurately using anisotropic curved rays, WesternGeco processing specialists have beenable to improve resolution of converted-waveimages at any target depth. The first 3D exampleusing this technology is from the Volve field.

The Volve field in the North Sea, operated byStatoil, contains a structurally complex subchalkreservoir. Statoil geophysicists believed that byutilizing the full-azimuth sampling inherent inseafloor survey geometries, a superior image ofthe subsurface could be obtained to aid in reservoir description.

Compressional-wave (PZ) results from thehydrophones and vertical geophones showed significant improvement over images obtainedfrom earlier towed-streamer surveys. Expecta-tions of the PS data were not high, but Statoildecided to test new prestack time-migration pro-cessing techniques on one swath of PS-wavedata. Prestack time migration was expected toproduce better results than conventional PS-wave imaging, which includes common con-version-point (CCP) binning and poststackmigration. Conventional processing of the VolvePS-wave data performed for comparison purposes yields a converted-wave image thatcompares poorly with the PZ image from thesame seabed survey (above).

16. Øyvind M: “IOR Award 2003: The NPD’s Award forImproved Oil Recovery Goes to Valhall,”http://www.npd.no/English/Emner/Ressursforvaltning/Utbygging_og_drift/IORprisen_2003_pm.htm (posted January 13, 2004).

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> Comparison of PP and PS sections in the Volve field, Norwegian North Sea. The PS section (right),processed in a conventional manner, with poststack time migration, is of lower quality than the PP section (left). The PP section comes from the multicomponent survey, and combines hydrophoneand geophone information, called PZ data.

The converted-wave processing tests beganwith isotropic prestack time migration. However,the results were disappointing. The next testincluded anisotropy in the shear-wave velocitymodel for prestack time migration, and yielded amuch better image than the conventionally processed PS data (above).

According to Statoil processing philosophy,prestack depth migration will produce optimalimages from multicomponent data, so, in a thirdtest, prestack depth migration was performed onone swath of data. The prestack depth migrationincluded anisotropy in the shear-wave velocitymodel and yielded a superior image. The newconverted-wave image contains high-resolutionreflections down to and beyond the target level.The good results obtained from the prestackdepth migration encouraged Statoil to have theentire PS volume processed with 3D prestackdepth migration—a new project that is ongoing.

Other reservoirs with complex structures andrapidly varying velocity models stand to benefitfrom the new PS prestack depth-migration tech-nique. Companies that have already acquiredconverted-wave data may profit from having

these surveys reprocessed to improve resolutionand image quality.

Advances in processing techniques will alsomake land multicomponent surveys more feasi-ble. In particular, reservoirs lying below strongreflectors, such as basalt, are difficult to imagebecause high P-wave reflectivity above the reservoir allows little signal to penetrate to thereservoir level. However, basalt causes significant P-to-S conversion, creating opportu-nities for converted-wave surveys. With betterprocessing algorithms, land surveys will gainfrom the same combination of P- and S-wavedata that benefit their marine counterparts.

The examples in this article show how multi-component seismic methods can be used todetect and characterize reservoirs when conven-tional P-wave surveys fail. As with many seismictechniques, their acceptance and widespreadapplication will take time. Past barriers toadopting multicomponent methods—unfamiliar-ity with shear waves, lack of proof of value, PSprocessing methods lagging PP imaging tech-niques, inadequate interpretation workflow—arebeing overcome. Accuracy of seabed measure-ments is increasing, and advances in processinghave led to dramatic data-quality improvements.Improved data quality is stimulating newemphasis on developing interpretation products.

Other new applications of multicomponenttechnology show promise in extracting more information not only from S-waves, butalso from P-waves. Recently, the use of two measurements—the hydrophone and the vertical-component geophone—has been shownto improve P-wave imaging in areas wherewater-bottom multiples, or reverberations withinthe water column, are difficult to remove fromthe desired signal.17 Multicomponent systemsalso aid in the acquisition of P- and S-wave datawith wide azimuthal coverage.18

Enthusiasts of multicomponent technologybelieve it is an emerging breakthrough in theseismic industry that should have an impact onoil and gas exploitation equivalent to that of 3Dseismic technology. Shear waves were once considered just noise in compressional-wave surveys, and had to be filtered out. As has happened often before with seismic technology,what was once noise can become signal. Now, with proper recording, S-waves can be captured and made to deliver the importantinformation they contain about rock and fluid properties. –LS

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17. Amundsen L, Ikelle LT and Berg LE: “MultidimensionalSignature Deconvolution and Free-Surface Multiple Elimination of Marine Multicomponent Ocean-BottomSeismic Data,” Geophysics 66, no. 5 (September–October 2001): 1594–1604.

18. Rognø et al, reference 9.

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> Comparing Volve reservoir close-up images obtained from a PP survey with those from a multicomponent survey processed using two different methods.Careful prestack time imaging with an anisotropic S-wave velocity model (right) clarifies reflection discontinuities in the reservoir section better than thePP image (left) or the PS section with conventional processing (middle).