Converted Wave

GEOPHYSICS, VOL. 68, NO. 1 (JANUARY-FEBRUARY 2003); P. 40–57, 25 FIGS.10.1190/1.1543193

Tutorial

Converted-wave seismic exploration: Applications

Robert R. Stewart∗, James E. Gaiser‡, R. James Brown∗, and Don C. Lawton‡

ABSTRACT

Converted seismic waves (specifically, downgoingP-waves that convert on reflection to upcoming S-waves)are increasingly being used to explore for subsurfacetargets. Rapid advancements in both land and marinemulticomponent acquisition and processing techniqueshave led to numerous applications for P-S surveys.Uses that have arisen include structural imaging (e.g.,“seeing” through gas-bearing sediments, improved faultdefinition, enhanced near-surface resolution), litho-logic estimation (e.g., sand versus shale content, poros-ity), anisotropy analysis (e.g., fracture density and ori-entation), subsurface fluid description, and reservoirmonitoring. Further applications of P-S data and anal-ysis of other more complicated converted modes aredeveloping.

INTRODUCTION

A great richness of wave types propagate in an explorationseismic survey; hopefully, they encounter a similar wealth ofresources. Measurement of the full ground motion (by mul-ticomponent seismic sensors) excited by a seismic source,combined with analysis to unravel the various wave types, isproviding some remarkable new images. The converted-wave(P-S) method uses P energy propagating downward, convert-ing upon reflection to an upcoming S-wave. P-S analysis canprovide improved subsurface images as well as give a measureof S-wave properties relating to rock type and saturation. P-Ssurveys are a relatively inexpensive (compared to S-S mea-surement), broadly applicable, and effective way of obtainingS-wave information. If we do have P-S reflectivity, what can itbe used for? Various authors (e.g., Kristiansen, 2000; Yilmaz,2001) have suggested or shown a number of applications of

Manuscript received by the Editor March 29, 2001; revised manuscript received July 3, 2002.∗University of Calgary, Department of Geology and Geophysics, 2500 University Drive N.W., Calgary, Alberta, T2N 1N4 Canada. E-mail:[email protected]; [email protected]; [email protected].‡WesternGeco, 1625 Broadway, Denver, Colorado 80202. E-mail: [email protected]© 2003 Society of Exploration Geophysicists. All rights reserved.

P-S data that include imaging reflectors within and beneathgas-bearing sediments; detailed shallow imaging and enhancedfault mapping; imaging shale diapirs, mud volcanoes, and tar-gets beneath salt bodies and basalt layers; providing anothersection with potentially different reflectivity, multiples, andtuning; imaging interfaces with low P-wave impedance contrastbut significant S-wave impedance change; using P-S attributesand internal VP/VS analysis for lithology discrimination (e.g.,sand/shale, dolomite/anhydrite); augmenting conventionalamplitude variation with offset (AVO) analysis to determinedensity and velocity; calibrating P-wave bright spots; investi-gating anisotropy for improved processing as well as for reveal-ing fracture density and orientation; and monitoring reservoirchanges (time-lapse or 4D analysis).

The 2000 SEG-EAGE Summer Research Workshop (Mac-Beth et al., 2001) conducted a poll to evaluate its attendees’assessment of the above applications (see http://www.seg.org/meetings/past/srwboise2000/poll.html). Conference partici-pants considered most to be proven or possible. The Septem-ber, 2001 issues of the SEG’s Leading Edge and the CanadianSEG’s Recorder had special sections on multicomponent seis-mic activities and their application. In addition, the SEG andEAGE sponsored an excellent Distinguished Instructor ShortCourse (Thomsen, 2002) that considered a number of theanisotropic aspects of converted waves and how they couldbe applied. Let us look in more detail at a sample of these ap-plications. First, we provide a selection of imaging cases, thenlithology estimates, followed by anisotropy analyses, then fluiddescription examples, and finally examples of reservoir moni-toring surveys.

IMAGING

“Seeing” through gas-charged sediments

P-wave energy is delayed, scattered, and attenuatedwhen passing through a gas-bearing sediment. Typically, gas

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Converted-wave Seismic Exploration 41

saturation will affect compressibility strongly, but rigidity toa lesser degree; thus, the oft-observed P-wave sensitivity andS-wave insensitivity to gas saturation. Whether in the near sur-face or just above the reservoir, gas-charged sediments canseriously degrade P-wave imaging of deeper features.

Some areas in the North Sea have near-surface channelsapparently containing biogenic gas that saturates poorly con-solidated sediments (Figure 1). Although these near-surfacehydrocarbon deposits are not economic, they are of inter-est because of their impact on conventional P-wave images

FIG. 1. Comparison between (a) P-wave and (b) P-S 2D sec-tions over North Sea shallow-gas channels. The P-wave sec-tion exhibits reverberations and high-frequency attenuation,but the P-S section delineates the channel base and interfacesbelow the channel. (Courtesy WesternGeco.)

FIG. 2. P-P and P-S sections from Valhall field, Norway, showing improved imaging across the anticlinal structure(after Rodriguez, 2000). The white ellipses outline the upper region of the chalk reservoir.

and sediment stability. Reflections from interfaces within andbelow the gas-charged channels are poor on the P-wave sec-tion (Figure 1a), exhibiting reverberations and attenuation ofhigh frequencies. In contrast, the P-S section (Figure 1b) de-lineates the channel bases, interfaces below the channels, andeven sediment boundaries within the channels.

Leaky gas reservoirs can create a gas plume or chimneythat makes conventional P-wave imaging and characteriza-tion of the reservoir very difficult. S-waves, being generallyless sensitive to rock saturants, can be used to penetrate gas-saturated sediments. The sub-sea seismic (SUMIC) techniqueused three-component (3C) geophones planted on the oceanbottom (Berg et al., 1994) that recorded data from which high-quality P-S images were constructed. Examples of this imagingthrough a gas chimney (Granli et al., 1995) led to considerableexcitement about marine shooting with ocean-bottom cables(OBC) and sea-bottom seismometers.

Rodriguez (2000) analyzed a four-component (4C) case fromValhall field, Norway (originally conducted by Amoco NorwayOil Co. and the Valhall Licence partners). He used prestackequivalent-offset migration for converted waves (Bancroft,2000) to image through a gas cloud. The results provided amore interpretable image of the chalk reservoir beneath the gascloud, especially near its anticlinal top at about 2.8 s on theP-wave section (Figure 2). Li et al. (2001) also analyzed theValhall data set. They noted more focussed and continuous re-flectors by using prestack versus poststack P-S migrations. Theyconcluded that converted-wave images provided a “better im-age under gas clouds” than P-P methods. Barkved et al. (1999)discussed a subsequent 4C-3D survey that was conducted overValhall field. They too found that the P-S images were consid-erably less degraded than the P-P images below the gas cloud.

Structural imaging

Resolution of steeply dipping features can be improved us-ing converted waves in certain circumstances. Purnell (1992)showed examples from physical-modeling data where high-dip anomalies were more visible on migrated P-S data thanon migrated P-P data. We note that structurally complicatedareas may have high-velocity layers in the near surface thatallow both P and S energy to propagate at significant anglesaway from the vertical. This results in P-P and P-S energy being

42 Stewart et al.

recorded on both vertical and radial channels, which must becarefully processed.

Cary and Couzens (2000) gave examples from Mahoganyfield in the Gulf of Mexico, where P-S images show excellentdefinition of faults associated with salt intrusion (Figure 3).It is not obvious, at this point, why faults should appear tobe better defined on the P-S than the P-P sections. Explana-tions include more prominent P-S scattering from nonweldedor fluid-saturated contacts (Chaisri and Krebes, 2000), largerlateral S-wave changes across the faults, or P-S ray paths fromsteeply dipping features that are more conducive to capturewith given receiver apertures.

Kendall et al. (1998) also processed 4C data from Mahoganyfield using an anisotropic prestack depth migration. They com-pared their results to streamer data shot in the same area, andillustrated improved imaging of targets underlying a salt struc-ture (Figure 4). We note that Herrenschmidt et al. (2001) alsopreferred a depth imaging approach for the Mahogany data.

Jin and Michelena (2000) described a prestack inver-sion technique that uses automatic velocity building, a ray-Born prestack depth migration, and AVO inversion from thecommon-angle migrated gathers. They tested this approach onthe Mahogany 4C data set to image a salt body (Figure 5).The S impedance from the P-S data may have offered some-what higher resolution than the P impedance above the saltbody.

Le Stunff et al. (2000) applied traveltime reflection tomogra-phy to build both P- and S-wave velocity models in depth. Theythen used these velocities to create prestack depth-migrationimages from the East Natuna Basin in Indonesia. They alsoused common-image gathers in depth to check the validity ofthe velocity model. The P-S image showed an anticlinal struc-ture (Figure 6), indicating further promise for converted-waveimaging in complex structural areas.

Near-surface imaging

We often see more highly resolved reflectors in the nearsurface on P-S sections than on colocated P-P sections. This

FIG. 3. (a) Poststack time migration of the vertical geophone component from the Mahogany 4C survey.(b) Poststack time migration of the depth-variant common-conversion-point (CCP) stack of the in-linecomponent data. (From Cary and Couzens, 2000.)

may be the result of a number of factors, including greaterrelative changes in S versus P velocity, a greater impact ofdensity changes on the P-S reflectivity than on P-P reflectiv-ity, or a shorter S wavelength. For example, a 3C seismic linewas acquired over the Steen River impact structure, Alberta,Canada, by Gulf Canada Resources Ltd. (now ConocoPhillipsCanada Ltd.) in partnership with the CREWES Project at theUniversity of Calgary (Mazur et al., 2002). The resultant P-Pand P-S sections are shown in Figure 7, where the P-P dataare stretched by a factor of two (VP/VS= 3) to match the P-Sdata. The sections are spliced together at a central point on theline. In Figure 7a, the P-P data are on the left and P-S data theright. Note the greater detail evident on the P-S sections. InFigure 7b, the display shows the P-S data on the left and theP-P section on the right. The P-P data are generally more con-tinuous beneath the sub-Cretaceous unconformity (at about480 ms).

Berteussen et al. (1999) showed some striking results froma multicomponent survey conducted in the Norwegian Sea,where the nature of gas hydrates was under investigation. Theyobserved a marked increase in the resolution of the P-S sectionover that of the P-P section. They concluded that P-S data mayprovide a significant contribution to the interpretation of areaswhere gas hydrates and associated free gas exist.

LITHOLOGY ESTIMATION

Sand/shale

P-wave imaging has proven particularly adept at makingstructural pictures of the subsurface; that is, providing an im-age of strata interfaces in reflection time. However, beyondthe configuration of interfaces, we would like to know whatkind of rock and fluids are in the section. P-wave images maybe limited or ambiguous in these regards. S-wave measure-ments provide additional constraint on the rock properties(especially on density and rigidity contrasts). Much P-S anal-ysis is targeted at finding an S-wave velocity or determining aVP/VS value (e.g., Li et al., 1999). Both VS and VP/VS can be


good indicators of rock type, especially in combination with VP

(Tatham, 1982).Garotta et al. (1985) showed P-S and P-P data for a Viking

sand channel reservoir in the Winfield oil field, Alberta. Theyfound that amplitude anomalies on the P-S data correlate withthe known boundaries of the reservoir. They also used P-Pand P-S isochron ratios around the area of interest to deter-mine VP/VS and Poisson’s ratios. Since Poisson’s ratio increasesmonotonically with increasingVP/VS, they interpret lowPoisson’s ratios as differentiating sand from the neighboringshales.

A series of seismic experiments in the Blackfoot oil field,Alberta, was conducted to identify sand reservoir facies from

FIG. 4. P-P and P-S migrated sections from Mahogany field,Gulf of Mexico: (a) towed streamer data (courtesy of DiamondGeophysical), (b) w-z (hydrophone and vertical geophone)processed data from a 4C-2D line, and (c) P-S section fromKendall et al., (1998), who note improved imaging of subsaltfeatures on the 4C data.

nonreservoir rocks (Stewart et al., 1996; Dufour et al., 2002).The surveys included broad-band 3C-2D data, 3C-3D data, and2D and 3D vertical seismic profile (VSP) surveys. The fieldwas originally discovered and developed using P-wave ampli-tude anomalies (Figure 8a); however, there are also amplitudeanomalies not associated with sand channels (that is, false pos-itives). P-P isochron maps are also indicative of the channel,but again with some ambiguity.

As in many multicomponent projects, a 2D line over Black-foot field was first acquired and analyzed to assess the meritof the method. The processed 2D P-P and P-S lines tiedreasonably well. Using this tie and time-thickness maps thatincluded the channel reservoir, an interval VP/VS value wascalculated. A good correlation of VP/VS anomalies and knownoil production was observed. With this promise, a 3C-3D sur-vey was conducted. The resultant P-S amplitude seems to givea more definitive (but lower-resolution) image of the sandchannel (Figure 8b). A P-S isochron map that included thechannel is perhaps more compelling (Figure 9a). The VP/VS

maps, calculated from P-P and P-S isochron map ratios, areanother strong indicator of the reservoir sand channel trend(Figure 9b).

A further 3C-3D survey (Goodway and Tessman, 2000) wasconducted over Blackfoot field in 1999 with I/O VectorSeisdigital 3C geophones. This survey produced similar results tothe previous 1995 3C-3D survey (Figure 10). This independentsurvey indicates robust and repeatable results, and is being usedfor time-lapse analysis.

MacLeod et al. (1999a) showed a case (now a classic!) of con-verted waves successfully delineating sand channels encasedin shale at Alba field in the North Sea. A strong contrast inS-wave velocity (from shale to sand) is associated with the topof the reservoir. On the other hand, there is relatively little P-wave velocity change across this lithologic boundary. Thus, thereservoir top generates strong converted waves, but weakerreflected P-waves. The P-wave velocity, however, is sensitiveto changes in fluid at the oil-water contact in the reservoir,while there is only a modest S-wave velocity change at thisfluid boundary.

The impact of the 4C OBC survey on the development ofAlba has been positive (MacLeod et al., 1999b). To date, anumber of successful wells have been drilled based primarily onthe interpretation of the new converted-wave data. There areexcellent ties between lithologies encountered in these wellsand pseudoelastic impedance computed from the converted-wave seismic response. Also, the P-S data have provided newinsights into the complex geometry of the turbidite channel inAlba field, suggesting significant postdepositional deformationof the channel.

Michelena et al. (2001) discussed a 3C-3D survey conductedover the Zuata heavy-oil field in eastern Venezuela. They in-dicated that there is little difference in acoustic impedancebetween the overlying shales and sand reservoir rocks. How-ever, the S-wave velocity varies significantly from shale to sand(Figure 11). They used these rock properties, seismic inversion,and neural-net classification to create sections that are indica-tive of lithology type (Figure 12).

Van Dok and Gaiser (2001) described three 3C surveysover the Morrow formation in the southern United States.The Eva South 3C-3D survey, in the panhandle of Oklahoma,showed anomalous P-S amplitudes that correlated with net pay

44 Stewart et al.

thickness (Figure 13). Van Dok and Gaiser also used an auto-matic event-correlation technique (Gaiser, 1996) on 3D P-Pand P-S volumes from the Cave West survey in southwesternKansas. They found that VP/VS values (contours) from the au-tomatic technique correlated reasonably with sand thicknessvalues from well information (Figure 14). There is also a goodcorrelation of high VP/VS values with a shale zone in the north-west corner of the survey (confirmed by well results). Notethat the VP/VS values provide a slightly different and possi-bly more detailed interpretation of the distributions of shaleand sand than the well data. Further down in the section, theSt. Genevieve formation is encountered. A coherency plot onthe P-P volume (Figure 15a) indicates a complex channel sys-tem. Low VP/VS values from automatic analysis around thishorizon also give indications of channel sands and also a pale-oshoreline in the southwest corner of Figure 15b.

FIG. 5. P-P and P-S migration and inversion results from the Mahogany 4C-2D survey in the Gulf of Mexico (Jinand Michelena, 2000). The P-wave impedance section from the P-wave data (a) and S-wave impedance valuesderived from P-S data (b) show the general outline of an encased salt body.

FIG. 6. (a) P-S image from the East Natuna Basin in Indonesia (Le Stunff et al. 2000). (b) An image gather showsflattened events and thus an appropriate velocity field.

Conglomerate

Nazar and Lawton (1993) used AVO stacks and P-P andP-S sections to analyze the productive regions of Carrot Creekfield, Alberta (Figure 16). The oil-saturated conglomerate inthis region is a challenge to interpret on conventional data, butis quite apparent on P-S sections as a brightening in amplitude.This relative brightening is partially due to differences in tuningbetween P-P and P-S reflections and the relatively high S-wavevelocity of the Cardium conglomerate.

Anhydrite/dolomite

Miller (1996) found significant variations in VP/VS in a car-bonate play at Lousana, Alberta. She estimated interval VP/VS

values from the ratio of P-P and P-S isochrons that include


the region of interest [as described in a companion article byStewart et al. (2002)]. The VP/VS values in the Cretaceous sec-tion (ranging from 2.2 to 2.5) are indicative of a clastic section,whereas those in the Paleozoic (1.5–2.0) are characteristic ofcarbonate rocks. The lowest VP/VS values in the Paleozoic sec-tion are coincident with an oil-bearing reef. She concluded thatthis anomaly was associated with dolomitization as opposed tothe surrounding higher VP/VS values that were coincident withanhydrite.

ANISOTROPY ANALYSIS

Many hydrocarbon reservoirs are fractured. The volume ofoil or gas in place and the reservoir’s ability to produce itare dependent on the fracture state of the reservoir. Deter-mining fracture density and orientation from seismic data hasthus been a subject of considerable effort (e.g., Probert et al.,2000; Crampin, 2001). Ata and Michelena (1995) showed an

FIG.7. Seismic data over the Steen River structure, Alberta, Canada. The sub-Cretaceous unconformity is evidentat about 480 ms on the P-P section and 1000 ms on the P-S section. (a) The left half of the P-P section spliced tothe right half of the P-S section. (b) The left half of the P-S section spliced to the right half of the P-P section. Notethat some events are more clearly defined in the shallow P-S sections. The data were acquired by Gulf CanadaResources Ltd. (now ConocoPhillips Canada Ltd.) and the CREWES Project at the University of Calgary.

example of three 3C seismic lines arranged in a star patternin Venezuela. After processing and analyzing the data, theyfound indications of fracture orientation from their calculatedanisotropy.

Gaiser (2000) showed the results of applying an Alford(1986) anisotropic rotation procedure and layer stripping(where off-diagonal components are minimized) to 1999 datafrom the Teal South, Gulf of Mexico 4C-4D surveys con-ducted by the Energy Research Clearing House (ERCH) ofHouston. A multiazimuth receiver gather (Figure 17) indicatesthe amount and direction of the S-wave azimuthal anisotropy.

Van Dok et al. (1997) and Gaiser (1999) showed analysesof a full 3C-3D seismic survey from Madden field in the WindRiver Basin, Wyoming. This analysis used 4C Alford (1986) ro-tations and layer stripping (Winterstein and Meadows, 1991a)to calculate the fast shear-wave (P-S1) polarization directionand the associated percent anisotropy. Figure 18 is a portionof the data from an east-west line: the radial and transverse

46 Stewart et al.

polarization for east-west propagation. There are equivalentsections for north-south propagation. To compensate for theeffects of depth-varying properties (Winterstein and Mead-ows, 1991b), the reflection at 1.5 s is analyzed first to removeshear-wave splitting effects from the overburden. Although theenergy on the transverse component for this event is weak inplaces, removing overburden effects from the target reflectionsbelow is an important step in unraveling shear-wave birefrin-

FIG. 8. (a) P-P and (b) P-S time slices at the interpreted sand channel level from the Blackfoot 3C-3D survey.The grid lines indicate a section (1 mile × 1 mile or approximately 1.6 km × 1.6 km).

FIG. 9. (a) P-S isochron map between the Mannville and Mississippian horizons (white/yellow indicates a timethickness of 140 ms through purple with a value of 90 ms) and (b) the VP/VS value as determined from theP-P and P-S isochron maps between the interpreted top of the channel and Wabamun horizons. White/yellowrepresent a VP/VS value of 1.5 through purple indicating a value of 2.8.

gence. Figure 19 shows the fast S-wave direction and its asso-ciated percent anisotropy, corresponding to possible fractureorientation and fracture density of the target horizons between2.2 and 3.3 s. Regions of stronger anisotropy (9% or more) cor-relate well with the known east-west trending faults superposedon the maps. As in many situations, resolution is an issue. Thesefracture-property estimates are averages over 1.1 s of data—aninterval clearly larger than the reservoirs of interest. Fracture


detection at finer intervals can be attempted by careful surveydesign to provide optimal fold, offset, and azimuth distribu-tions.

Numerical modeling (Li et al., 1996) suggests that gas-saturated and oriented fractures may have an effect on

FIG. 10. (a) A second 3C-3D survey conducted in 1999 overBlackfoot field, using VectorSeis digital geophones (Good-way and Tessman, 2000) gave a VP/VS anomaly (red indicateslow VP/VS values similar to Figure 9b) that correlates with(b) net sand thickness (where thicker sands are indicated byyellow/red).

FIG. 11. S-wave velocity versus density from well logs in theZuata heavy oil field, Venezuela. The S velocity of the sands isconsiderably higher than that of the shales (Michelena et al.,2001).

anisotropic P-S reflectivity. This is in contrast to the isotropiccase, where fluid saturation appears to have less impact on S-wave velocities. In fact, Guest et al. (1998) interpreted anoma-lies in S-wave splitting over a gas reservoir in Oman as evidenceof an effect of gas on shear waves.

FLUID DESCRIPTION

Thompson et al. (2000) presented early results from a 30-km2D multicomponent line, in 750 m of water, shot over the FlesDome, offshore Norway. There is a flat spot on the P-P dataset that could be an event caused by a fluid contact (Figure 20).However, it could also be generated by a lithologic change.The continuity of dipping strata in the P-S section (lack of aflat spot) supports the possibility that the P-P anomaly is causedby fluids not a lithologic change.

Stewart and Todorov (2000) used the Blackfoot 3C-3D seis-mic data to estimate oil column height. They first constructed aP-P time-thickness (isochron) map for an interval (Mannvilleto Mississippian) containing the reservoir. This map provideda regular and dense data set complementary to the sparseinterval-thickness values picked from the well logs over thesame Mannville-Mississippian interval. The isochron valueswere then co-kriged with the isopach values from well logs.The isochron map was thus converted to a regularly sampledand dense isopach map.

The VP/VS value was next computed using the isochron ra-tios from the P-P and P-S maps over the same depth inter-val. This VP/VS value was, in turn, co-kriged with the gamma-ray index to give an estimate of the shale content by usingsand and shale lines and linear interpolation of values betweenthem. The clastic interval (the isopach map under considera-tion) was assumed to consist only of shale and sand. Thus, thesand estimate was 100 minus the shale percentage. Amplitudeinversions were derived from both P-P and P-S volumes todetermine P- and S-wave velocities, respectively. The P-P andP-S attribute volumes with VP and VS inversion volumes plusporosity logs were then used to predict porosity values over theinterval using a neural net (similar to a procedure described inRussell et al., 2002). The average water saturation (SW) in thereservoir, which is 25%, was used to infer the oil saturation(100 minus the percentage water).

Finally, the oil column height (OCH) for every seismicpoint was estimated using the product of these factors:OCH= interval thickness× percent sand× porosity× oil sat-uration, as shown in Figure 21. By using a 3.0-m cutoff value,they estimated the volume of oil in place at about 1.2× 106 m3.The engineering report using the original 3D seismic and aboutone year of production data estimated a value of 1.36× 106 m3.

RESERVOIR MONITORING

Isaac (1996) showed P-P and P-S sections from a heavy-oilreservoir at Cold Lake, Alberta, undergoing steam flooding(Figure 22). There are variations in the reservoir rock proper-ties associated with temperature and saturation changes. These,in turn, are associated with changes in the seismic character ofboth P-P and P-S sections. Using surveys in 1993 and repeatedin 1994, she found that the variation in VP/VS values correlatedwith the temperature of the reservoir. The VP/VS values stayconstant in areas away from the injection wells (CDPs 20–70

48 Stewart et al.

in Figure 23). However, in the areas steamed in 1994, there isan increase in VP/VS that causes the ratio of the VP/VS valuesfrom the two years to drop (Figure 23c).

Spitz et al. (2000) also discussed results from the 4C-4D TealSouth survey, Gulf of Mexico, consisting of two 4C-3D surveys,one in 1997 and the other in 1999. Their pioneering study showstime-lapse differences in the fast converted wave (P-S1) overthe Teal South field (Figure 24).

FIG. 12. Section from the Zuata heavy-oil field, Venezuela. The S-wave inversions have been converted tosand/shale estimates by a neural-net process. SP and gamma-ray logs are overlain for comparison (Michelenaet al., 2001).

FIG.13. (a) P-S amplitudes at the reservoir level (top Morrow) from the Eva South 3C-3D survey. High amplitudesare in red. (b) Net pay thicknesses from well information (after Miller and Wheeler, 2000). Sand thicknesscontours are in 10-ft (3.3-m) intervals. The maximum thickness is about 35 ft (11 m).

WHAT’S LEFT TO DO

Converted-wave exploration has come a long way in recentyears, but there is still plenty of room for progress. Furtherapplications await surveys and resultant images in new en-vironments. The P-S method will undoubtedly become morewidely practised and useful as costs decrease. The expense ofland multicomponent surveys is decreasing significantly, but


OBC costs are still well above those of towed-streamer meth-ods. Processing and analysis of P-S data have become muchmore effective and sophisticated, especially by incorporatingprestack techniques and anisotropy (Thomsen, 1999). Process-ing P-P and P-S data together to provide consistent imagesin depth (Mikhailov et al., 2001) and improved rock propertyestimates (Margrave et al., 2001) are critical current develop-ments. For example, Spitz (2001) showed a case from the NorthSea where P-P and P-S inversion was used to derive a densityestimate (which compared favorably with a density log in thearea). Further refinements await.

More detailed analysis of existing images may provide uswith greater understanding of the targets under considerationor even new ones. Better interpretation tools are under de-velopment, especially with respect to correlation and depthconversion, but additional advances would be welcomed. Con-tinued education and experience will further unravel what con-verted waves have to show us (Cary, 2001).

Looking farther ahead, we anticipate making use of othermodes that propagate in a seismic survey, such as a wave, other-wise P, that has an S-wave leg through a high-velocity region. Incases where there are high-velocity layers (basalts, carbonates,salts, or even permafrost in the near surface), seismic imagingmay be complicated or compromised. We can make sections

FIG. 14. Map of the automatically determined VP/VS value from the Cave West, Kansas survey (after Van Dokand Gaiser, 2001). Low VP/VS values are in red. The interval of VP/VS analysis includes the Morrow formationand can be interpreted in terms of possible sand distributions. Note the high values in the northwest corner thatare interpreted to indicate high shale content (confirmed by well results). Gross thickness of the sand interval,from well data, is indicated by 10-ft (3.3-m) contour lines.

(Figure 25) from this more complicated conversion as in theGulf of Mexico, where a P-wave converting to an S-wave in-side a salt volume and then back to P-wave has been used tocreate an image.

The possibility of high-quality, fully elastic and anisotropicimages of the subsurface opens many doors to new interpre-tation. Accurately repeating these surveys (4C-4D) to lookfor changes associated with fluid movement is a very excitingprospect (Grechka, 2001; Jack, 2001). Permanent seismic mon-itoring of oil fields, either with active sources or passive listen-ing, using surface and/or borehole measurements will provideconsiderably more guidance for reservoir production.

CONCLUSIONS

The reflection seismic method has used P-waves for manyyears—with great success. The extension of the reflectionmethod to include P-S waves has been effective in yield-ing new cases of improved imaging of resource targets. Par-ticularly well documented cases exist for gas-cloud imaging,sand/shale discrimination, and anisotropy analysis. How-ever, there is more to be done in converted-wave explo-ration seismology, especially in making full use of these newpictures.

50 Stewart et al.

ACKNOWLEDGMENTS

We express our deep appreciation to the sponsors of the Con-sortium for Research in Elastic Wave Exploration Seismology(the CREWES Project) for their commitment to the develop-

FIG. 15. Maps of the St. Genevieve horizon. (a) Coherency plot derived from the P-wave data indicates a channelsystem, with (b) the correspondingVP/VS plot automatically calculated over a 100-ms window around the horizon.The red and yellow colors indicate a low VP/VS value and possible sand accumulations (after Van Dok and Gaiser,2001).

ment of multicomponent seismology. We also express our grat-itude to Neil Jones, Rich Van Dok, and Robert Bloor of West-ernGeco for providing data examples, and to Heloise Lynnfor her insightful interpretations of the 3C Madden survey.Reinaldo Michelena of PDVSA generously provided us with


FIG. 16. Portions of the (a) P-S and (b) P-P sections from Carrot Creek, Alberta. Note the amplitude anomalyon the P-S section at the Cardium conglomerate level (from Nazar and Lawton, 1993).

FIG. 17. Anisotropic rotations on a receiver gather from the Teal South survey. The slow S-wave (P-S2) on theright has been compressed to fit the fast converted wave on the left. The total amount of anisotropy and itsdirection is shown in the middle panel (after Gaiser, 2000).

the Zuata heavy-oil field example. We thank Robert Kendallof Veritas DGC for supplying us with his Mahogany examples,and Diamond Geophysical for the Mahogany streamer data.We are grateful to the Amoco (now BP) group of companiesfor providing us with the Valhall 4-C data set for our analysis.We used Hampson-Russell’s GEOSTAT program (donated tothe University of Calgary) for analysis in the Blackfoot field oil-estimation case. Joanie Whittemore and Carla Osborne (for-merly with CREWES) ably assisted with the production of thismanuscript.

REFERENCES

Alford, R. M., 1986, Shear data in the presence of azimuthal anisotropy:Dilly, Texas: 56th Ann. Internat. Mtg., Soc. Expl. Geophys., Houston,Expanded Abstracts, 476–479.

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FIG. 18. (a) Radial and (b) transverse receiver components foreast-west propagation from a 3D survey at Madden field inWyoming. Equivalent sections for north-south propagation areused with 4C rotations and layer-stripping techniques to esti-mate fracture orientation and intensity as shown in Figure 19(after Gaiser, 1999).

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FIG. 19. Seismic anisotropy calculated by Alford rotation and layer stripping from the data in Figure 18, after removal of thebirefringence effects of the overburden. (a) Fast S-wave (P-S), polarization direction and (b) percent azimuthal anisotropy for thetarget layer between 2.2 and 3.3 s. Regions of stronger anisotropy (9% or more) correlate well with the known east-west trendingfaults superposed on the maps (after Gaiser, 1999).


FIG. 20. Flat spot analysis on P-P and P-S from the Fles prospect, offshore Norway (Thompson et al., 2000). Thetop section shows the P-wave data from the 2-D OBC survey, the middle section the P-S data from the OBCsurvey, and the bottom section a line extracted from a 3D towed streamer volume. There is no obvious flat spoton the P-S data, suggesting that the P-wave anomaly is a fluid contact, not a lithology change.

FIG. 21. OCH estimate for the Blackfoot, Alberta field (Fig-ure 8) as determined geostatistically from interval thickness×percent sand × porosity × oil saturation.

FIG. 22. Comparison of the (a) 1993 and (b) 1994 3C seismiclines from the Cold Lake, Alberta, steam-injection site. Notethe similar data quality and resolution among all lines (fromIsaac, 1996). The area of interest is indicated by the verticalbar. CDP/CCP trace spacing is 8 m.

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FIG.23. VP/VS plots for (a) 1993 lines, (b) 1994 lines, and (c) theratio of those two. Note that the VP/VS value is fairly constantin the unsteamed regions away from the wells (CDP numbers20–70) (from Isaac, 1996). However, the VP/VS values increasein 1994 with steaming. CDP/CCP trace spacing is 8 m. The lineswere 1800 m long.

FIG.24. Fast-converted-wave (P-S1) time slices from the Teal South, Gulf of Mexico, 4C-4D survey at the reservoirlevel. The P-S image from 1997 (a) is subtracted from the 1999 image to give the (b) difference (Spitz et al., 2000).


FIG. 25. Comparison of prestack depth-migrated streamer data using (a) P-wave and (b) S-wave salt-velocitymodels. Migration with an S-wave salt-velocity model images PSSP waves that have converted at the top of thesalt. The position of the S-wave event at the base of the salt is in agreement with the P-wave image. (CourtesyWesternGeco.)

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