Becquey-geo4409r14851501

Volume 44 September 1979

GEOPHYSICS

Number 9

Acoustic impedance logs computed from seismic traces M. Becquey*, M. Lavergne*, and C. Willm*

Acoustic impedance, the product of seismic velocity and density, is a basic physical property of rocks.

Seismic traces are converted into pseudoreflection-coefficient time series by appropriate initial processing. then into acoustic impedance by the inversion of the time series. Such pseudologs are rough11 equivalent to logs recorded in wells drilled at every seismic trace location. They yield important information concerning the nature of the rock and variations in lithology

To obtain the best quality pseudologs, careful initial processing is necessary: true-amplitude recovery. appropriate deconvolution. common-depth-point (CDP) stack. wave-shaping, wave-equation migration, and amplitude scaling.

The low frequencies from moveout velocity information are inserted. Both the short-period information computed from reflection amplitudes and the long-period trend computed from reflection moveout are displayed on acoustic impedance logs.

Possible causes of pseudolog distortions are inaccuracies of amplitude recovery and scaling, imperfection of deconvolution and migration. and difficulties of calibrating the pscudolog to an acoustic Iof derived from well logs. Such calibration increases the precision; facies variations observed in well logs cau bc extrapoled to large distances from the wells. leadin, (7 to a more accurate estimation of hydrocarbon resel.ves.

INTRODUCTION

Acoustic impedance, the product of seismic velocity and density, is a basic physical rock property. It can yield important information concerning the nature of the rock and changes in litholopy. The generanon of acoustic impedance and velocity pseudologs has been published previously (Lavcrpne, lY75; Lindseth, IY76). A number of examples of acoustic impedance pseudologs will be shown using a technique close to that described by Lavergne ( 1975).

The seismic traces are first transformed into pseudoreflection-coefficient time series, then converted into acoustic impcdanccs using the recursive algorithm

q+, zr Zi 1 1 -ki (1)

where Z, is the acoustic impedance in the ith layer,

and ki is the pressure amplitude reflection coefficient at the ith interface; the acoustic impedance Z, in the first layer is assumed to be known.

The low-frequency component, absent on seismic traces, is inserted on the acoustic impedance pseudologs using reflection-moveout velocity information and a velocity-density relationship to convert velocity to acoustic impedance. Appropriate processing methods. such as amplitude corrccticrn and decon- solution, are described. Acoustic impedance traces are displayed in variable amplitude 01 in color, and calibration of pseudologs to acoustic logs derived from well logs is performed to increa\c the accuracy of the former.

It will be shown in several field examples how acoustic impedance logs are suitable for detecting lateral lithologic variations, and hoI+ they can be used for detailed investigation of hydrocarbon fields and for exploration of offshore continental margins.

Presented at the 46th Annual International SEG Mcctinp October 26, 1976 in Houston. Manuscript recei\cd by the Editor May 16, 1977; revised manuscript received Februarv 13. 1979. :i; institute Franc& du Petrole, B.P. 3 I I, 92506 Ruejl-Malrnaison Cedex, France. 0016.X033/79/0901~1~8.5$03.00. @ 1979 Society of Exploration Geophysicists. All rights reserved.

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(I) (2) ( 3) (4) (5) (6) SYNTHETIC SYNTHETIC

ACOUSTIC ACOUSTIC IMPEDANCE IMPEDANCE

VELOCITY DENSITY ACOUSTIC SYNTHETIC LOG LOG IMPEDANCE SEISMOGRAM WITH TREND

(m/s) ( g/cd ISO? 20,oo ?500 I,5 2;: q5

I m4$jDc me3 ) , 6000

(71 SEISMIC PULS,E

#++->

- I.

- I.5

P B 5

Y

B s

0.5 -

SEISMIC WELL # I ACOUSTIC IMPEDANCE PSEUDO LOGS h=?

24 H SYNTHETIC WELL#l ACOUSTIC ACOUSTIC IMPEDANCE IMPEDANCE

LOG LOG

LITHOLOGY

L SHALE I SAND

- GAS-BEARING SAND

SEISMIC ACOUSTIC IMPEDANCE PSEUDO LOGS

25

FIG. 2. Gas field no. I-comparison of seismic acoustic inlprdance pseudologs with synthetic acoustic impedance log and lithology obtained from well I logs.

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FIELD EXAMPLES

Two examples, each from a gas field, and one example from a continental margin in an offshore basin are illustrated.

Gas field no. 1 The first example (Figures I to 6) consists of a

3.5km long seismic section from a sand-shale sequence containing a gas reservoir. Logs from well WI were used to calibrate the pseudologs.

Data acquisition.-Seismic records were recorded In shallow water, 8 to !2 m in depth, with: 1200 inch3 aigun array at a depth of 4 m, 33 m between shotpoints, 32 hydrophone-group streamer, 50 m between groups, binary gain recorder with a 4-msec sample interval, and an 8-62 Hz prefilter.

Initial processing.-The initial processing sequence was: demultiplexing and editing, true- amplitude recovery and application of a gain program, muting, deconvolution before stack (DBS), reflection-moveout velocity analysis, 12-62 Hz filtering, moveout correction and 24-fold common- depth-point (CDP) stacking, deconvolution after stack (DAS), wave-equation migration, and amplitude scaling.

The initial processing was conducted such that amplitudes of the processed section would be, insofar as possible, proportional to the reflection coefficients derived from the well logs. All factors affecting amplitude variations that do not contain subsurface information, such as source strength variation and source and detector coupling, were tentatively eliminated by trace-amplitude equaliwtion, together with subsurface dependent factors such as geometrical divergence, absorption, and focusing effects due to reflector curvature (ODoherty and Anstey, 1971; Sheriff, 1973).

Well ! !ogs were used to compute synthetic seis- mograms and synthetic acoustic impedance logs by the method described by Lavergnc and Willm (1977). These are displayed in Figures 1 and 2 for comparison with well logs, pseudologs, and lithology.

True-amplitude recovery was applied to remove the effects of variable gain in field recording. The gain program was derived from the observation of amplitudes of synthetic seismogram (4) of Figure 1. A geometrical divergence correction program (New- man, 1973), consisting of multiplying each trace- amplitude sample by a factor proportional to TV2 where V is the root-mean-square (rms) velocity and 7 is the two-way reflection time was tried first. This led to an essentially constant average absolute value

-0.5

-1.0

.I.5

BLACK = POSITIVE SEISMIC SIGNAL

FIG. 3. Gas field no. I-24-fold CDP stack.

Acoustic Impedance Logs 1499

.0.5

.I .o

4 .5

BLACK = POSITIVE SEISMIC SIGNAL

FIG. 4. Gas field no. l-migrated section.

of the amplitude over 600.msec time intervals, except within the zone of the gas reservoir, where it was 15 percent larger. Experience showed that in the 0.5-I .7-set interval, the divergence correction program was practically equivalent to applying an average amplitude equalization over 600.msec win- dows. The amplitude obtained by this method was in agreement with the synthetic seismogram.

Long-offset traces were muted to eliminate reflections with incidence angles greater than 26 de- grees. DBS then was performed by a predictive operator, 96 msec in length. One operator was computed for each trace from the autocorrelation of the 1240 to 1700 msec trace sector. The main purpose of DBS was to remove the very intense water layer reverbe- rations present on initial records. A 12-62 Hz prefilter also was used to eliminate a very strong low-frequency wave with a predominant frequency of 8 Hz, propagating horizontally at 800 misec.

Reflection-moveout velocity analysis was performed~about every 20 shotpoints to determine moveout corrections and velocity-time curves. The curves obtained are practically the same on both ends of the section. The velocity increases linearly from 1480 m/set at the surface to 2300 m/set at 1400 msec and remains practically constant thereafter.

Trace-amplitude equalization was performed be-

fore stack, adjusting the average amplitude over an interval of O-1800 msec such that the average amplitudes of the traces were comparable, thus com- pensating for amplitude variations due to offset and instrument gain variations.

DAS was performed to obtain an appropriate wavelet shape. Our experience shows that the best shape is a zero-phase wavelet, which introduces minimum distortion of acoustic impedance. DAS performed with a 140.msec operator obtainccl by a least- squares method gave a wavelet 64 msec in length with a 24-msec period, a positive central lobe, and two negative side lobes whose peak amplitudes did not exceed 0.4 times that of the central lobe.

The CDP section then was migrated by the finite- difference wave-equation method which eliminated part of a diffraction hyperbola causctl by faulting.

Amplitudes of the migrated seclion finally were scaled such that the sum of sampled values of the central lobe of each reflection was made equal to the reflection coefficient derived from the acoustic impedance log (log 3 in Figure I).

The CDP section after DAS is shown in Figure 3, and the corresponding migrated section is shown in Figure 4. The high-amplitude event due to gas is clearly visible in the center of the section, its lateral extent is about 3 km, and its two-way time is I.25

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set (3600 ft). Black bands (peaks) correspond roughly to positive reflection coefficients, and white (troughs) correspond to negative reflection coefficients. The negative reflection coefficient at the top of the gas sand gives a large negative central lobe (white) pre- ceded and followed by smaller positive lobes (black). The front black lobe is clearly visible; the back lobe interferes with later reflections, probably with the gas sand bottom reflection or with reflections from interbedded shale layers.

Acoustic impedance computation.-Acoustic impedance was computed from the pseudoreflection- coefficient time series (Figure 4) from equation (I), using an initial impedance value of 3600 at 0.45 set (velocity 1800 misec, density 2.0 g/cm3). Before computing the acoustic impedance, the traces of Fig- ure 4 were resampled from 4 to I msec, for direct comparison with well logs converted to a time scale with amplitudes at I-msec intervals. The seismic pseudologs obtained are displayed in Figure 2 in variable amplitude and in Figure 5 in color. Figure 2 shows the amount of distortion in the seismic pseudologs. which is due to the following:

1) The high and low frequencies are missing due to the limited frequency spectrum of the seismic data; in particular, the low-frequency acoustic impedance trend is absent.

2) The basic wavelet is not a spike, but a wavelet with negative side lobes. This introduces artifacts such as positive lobes prior to large decreases and negative lobes prior to large increases of acoustic impedance; the positive lobe at I .2 set just above the gas sand is probably such an artifact.

3) lnterbed multiples have not been attenuated. This can cause distortions, such as the small changes in wavelet character observed within the reservoir between I .2 and I .3 sec. In Figure 2, 48 acoustic impedance pseudologs are

shown which were computed from 38 migrated traces close to well 1, without inserting the low-frequency trend: thus only relative variations of acoustic impedance are represented. The correlation between the well I acoustic impedance log (log 3 in Figure I) and the seismic pseudologs is fair, and helps to correlate the seismic section to the lithology The acoustic impedance variations are directly lclated to the lithology and hydrocarbon content, as indicated by the two

2.5

-1.5

-2.0

-2.5

BLACK = NEGATIVE SEISMIC SIGNAL

FIG. 7. Gas field no. 2--4%fold CDP stack.

Acoustic Impedance Logs

w w2

1.5,

2.5,

3.0,

BLACK = NEGATIVE SEISMIC SIGNAL

-1.5

-2.0

-2:5

-3.0

FIG. 8. Gas field no. L-migrated section

impedance minima opposite the gas bearing sands (Figure 2). We notice on the right side of Figure 2, close to trace 33, that the gas sand event character changes; the top of the gas sand seems to be shifted 38 msec downward by a fault.

Figure 5 shows the acoustic impedance section computed from the migrated section of Figure 4 using equation (I). Low frequencies were not included; thus, only the relative variation of acoustic impedance is represented in color. White represents the average, green the lowest, and purple the highest impedance. The low-impedance gas sand is represented by the dark green zone in the middle of the section between 1.24 and I .27 set; it is underlain by a high-impedance layer (red) between 1.27 and I .30 sec. The faulting is clearly shown, especially by the low-impedance shale layers (light green) located between .90 and 1.25 sec. The fault throw decreases upward, and the 40-msec throw in the gas sand reduces gradually to zero in the overburden.

Low-frequency information was inserted using reflection-moveout velocity analyses and an approxi- mate velocity-density relation to convert velocities to impedances (Lavergne, 1975). The spectrum obtained from these velocity analyses is estimated to

extend from 0 to 8 Hz. It is impossible to obtain information at frequencies higher than 8 Hz, because interval velocities based on reflection moveout be- come very inaccurate for intervals smaller than approximately I25 msec. On the other hand, there is no information at frequencies lower than I2 Hz on seismic traces, due to the low-cur lilter. There is, therefore, a gap between the low-frcclucncy (O-8 Hz) and the high-frequency (12-64 HY I portions of the spectrum, leading to some distortioll of the acoustic impedance pseudologs. The amount of distortion obtained can be estimated in Figure I by comparing the synthetic acoustic impedance log (6) with the well acoustic impedance log (3). For example, the acoustic impedance trend between I, I5 and I .35 set is not exactly duplicated on the two logs. Higher-frequency seismic data, providing more detailed reflection- moveout velocity analyses, would have given better results.

The velocity-density relation used to convert the velocity to acoustic impedance is given by Gardner et al ( 1974), which is approximately correct for brine- saturated sedimentary rocks, over a wide range of basins, geologic ages, and depths. If velocity V is expressed in ftisec and density D iu g/cm, this re-

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lationship is

D = 0.23 V.25.

If velocity is expressed in misec, equation (3) be- comes

D = 0.3 1 V.25, (4) and the relationship between velocity and acoustic impedance is given by

z = 0 31 Vl.2 (5) where V is velocity in misec and Z is acoustic impedance in (m/set) (g/cm3). This enables velocity to be computed from acoustic impedance, and vice versa, in most sedimentary rocks, except for salt, anhydrite, and hydrocarbon reservoirs.

Fi_pure 6 shows the acoustic impedance section with low-frequency trends included. The acoustic impedance values are represented by a color scale. The impedance increases from 3500 to 5.500 (miscc) (g/cmJ) as indicated by the color which changes downward, generally from light blue to green, yellow. red, purple. violet. and dark blue. The low impedance due to the gas sand is represented by the green- yellow zone in the middle of the section between 1.24 and I .27 set: the gas sand impedance is about 3X00- 4000, and that of the overlying and underlying layers is. respectively. 4600 and 5000 (misec) (g/cm). Well i encountet-ed gas in ihis i~~W-i~llpd2lKCc mm (Figures 5 and 6). Well logs indicated an average impedance of 3800 in the gas sand, 4600 in the overlying. and 5200 (miaec) (g/cm) in the underlying layer.

This first example indicates that acoustic impedance pscudologs are sufficiently accurate to define the position and to detect thickness and structural variations of the gas sand.

Correlation of seismic pseudologs to well logs provides accurate detection of lateral facies variations along the seismic section. The vertical resolution of the method, however, is limited by the resolution of the seismic data. Our experience shows that for a basic wavelet with a 24msec dominant period, it is possible to measure the thickness and acoustic impedance of beds for which the two-way time is no less than 15 msec.

Gas field no. 2

The second example (Figures 7 to I 1) consists of a 7-km long portion of a 25.km long section containing gas reservoir reflections. Well W2 was used to calibrate the seismic pseudologs.

Data acquisition.-Seismic data were recorded in water, 120 m in depth, with: 250 g of explosive at a depth of 12 m, 2.5 m between shotpoints, 38 hydrophone-group streamer at a depth of 13 m, 50 m between groups. I.F.P. (instantaneous floating point) recorder with a 4-msec sample interval, and a 2-62 Hz prefilter.

Initial processing.-The initial processing sequence was similar to that of example no. I, i.e., demultiplexing and editing, true-amplitude recovery and application of a gain progranl. muting, deconvolution before stack (DBS). reflection-moveout velocity analysis, moveout correction and 48.fold CDP stacking, deconvolution after stack (DAS), wave-equation migration, 8-62 HI filtering, and amplitude scaling.

True-amplitude recovery and the application of a gain program were similar to thee for the gas field in example no. I. Initial decon\olution was performed to eliminate the source bubble effect.

Reflection-moveout velocity analysis was performed every 12 shotpoints. Eleven velocity functions irregularly spaced along the profile were applied for moveout corrections with linear interpolation between functions. DAS was performed with a 240-msec predictive operator obtained from the autocorrelation of a 2400-msec time interval centcrcd on 1300 msec r&e&on time The p~dse shape, ohtainedaf~e~ DBS is very close to a zero-phase wavelet with a large positive central lobe and two negative side lobes whose peak amplitudes are 0.4 time\ that of the central lobe; the total length is 80 msec and the dominant period is 36 msec.

Finite-difference wave-equation migration shifted inclined reflections updip to their- proper position, and restituted the amplitude of convex reflections, especially on the anticline between 2.6 and 2.9 set (compare Figures 7 and 8). An X -62 Hz filter was applied to eliminate low-frequency noise. Amplitudes of the migrated section finally were scaled to those of a synthetic seismogram derived from the acoustic impedance log of well W2.

The CDP section after DAS is shown in Figure 7 and the migrated section is shown in Figure 8. Black bands (peaks) correspond to negative reflection coefficients. and white (troughs) to positive reflection coefficients; this is emphasized on the two-color representation in Figure 9, where red corresponds to negative and green to positive reflection coefficients. In agreement with well W2 logs, the inclined red reflection appearing at 2.05-2. IO set is related to the top of gas-bearing sandstones, and the horizontal

Acoustic Impedance Logs

4 8 E c .Z 3

-

Becquey at al

Acoustic impedance Logs 1497

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green reflection at 2.11 msec to the gas-water contact. It is clear here that the zero-phase wavelet provides an accurate determination of the gas-sandstone boundaries.

Acoustic impedance computation.-Acoustic impedance was computed from the pseudoreflection- coefficient time series using equation (I). with an initial impedance value of 5000 (misec) (g/cm:) at I .S sec.

The I-msec sample interval was maintained. Lou- frequency information below 8 Hz was reinserted using reflection-moveout velocity analyses and Gardners velocity-density relation. Eleven low- frequency acoustic impedance time curves irregularly spaced alonf the profile were applied with lineal interpolation between them.

Figure IO shows the acoustic impedance section in color and the migrated section in black. The acoustic impedance values are represented by a color scale: the impedance increases from 4000 to I 1,500. as indicated by the color which changes downward from blue to green, yellow, red. pink. and violet. The low impedance due to the gas-sandstone is visible at about 2.10 set, main11 to the left of well W2. The thickness of the gas-sandstone is shown to decrease from right to left, from 70 msec to about 15 msec.

The presentation on the same display of the m- pratcd section in black and the acoustic impedance in color permits determination of the reservoir boundaries. In Figure 10 black peaks of the migrated section represent roughly positive reflection coefficients. The flat event at 2. I I msec indicating the gas-water contact is shown clearly. It separates the low-impedance zone (yellow-green) due to gas-bearing sandstone from the high-impedance zone (purple) due to water- bearing sandstone. When black peaks represent negative reflection coefficients, as in Figure 8. the top of the gas-bearing zone is shown, separating the gas reservoir from the overlying layer.

The acoustic impedance value is 4800-6000 (misec) (g/cm3) in the gas-bearing sandstone on the left side of the section, 6800 in the overlying layer. and 8000 (misec) (g/cm3) in the water-bearing sandstone. Figure 10 shows that impedance of the gas-bearing sandstone increases from 5800 on the left to 7200 (misec) (g/cm3) on the right side of the section, as indicated by the progressive color change from green to yellow and red. This variation is probably due to a lateral facies variation within the reservoir. The sandstone is argillaceous with low velocity and low density on the left side and changes pro-

gressively to a clean sandstone with higher \elocit\ and higher density toward the right side of the anticline. It should be noted that the progres\l\c increase of acoustic impedance from left to right \sithin the reservoir produces a sign inversion of the reflectIon coefficient at the top of the gas-bearing sandstone: thi\ in\crsion is iisible immediately to the right ot well W2 in Figure 9. The lateral facies LarIation i\ iisualired in Figure I I where the IitholoFic interprc- tation has been superposed on the color-coded acoustic impedance. A rig-~12 line has been drlrv,n tentatively separating a low-acoustic impedance LOW. assumed to bc argillaceous sandstone on the left, from a high-acoustic impedance zone (with reel color in the gas-bearing sandstone and pinh color in the water-bearing sandstone). assumtxl to be clean iandstone on the right. These tno facie\ were known in wjell W2. but their rcrpective distribution awa! from the well was not known. This type of sci\mic interpretation, although tentative and inaccurate. CGves very useful information for c\timatinp possible 2 recoverable reserves.

This example shows that acoustic impedance pseudologs are suitable for determination of lateral facics variations within hydrocarbon reservoirs. The vertical resolution. however. is limited b! the rc- solution of the seismic data. For a basic wavelet with a 36-msec dominant period, it is impossible to measure the thickness and acoustic impedance of beds for which the two-way time is less than 24 mscc or so. It is likely, therefore. that neither the IS-msec two-waq time nor the green-yellow zone limit on the left of the low-impedance zone represents the true thickness and the actual edge of the gas-bearing zone. Hisher- resolution seismic records would give better delimita- tion of reservoir extent.

Offshore continental margins The third example consists of two seismic lines,

J 2 I I and J 212 (Figure 12) recorded IO miles east of Minorca, in the wcstcrn Mediterranean basin. near site 372 of the Glomur Challrr~ger drilling campaign (Scientific Party, 1975). J 21 I is a 14km long east- west section. and J 2 I2 is a I3-km long north-south section.

Data acquisition.-Seismic records were obtained in deep water, 2500 m in depth, with: one 123-20 Flexichoc unit at a depth of I6 111. SO m betweenshotpoints, 24 hydrophone-group streamer, at a depth of 20 m. 100 m between proups. binary gain recorder with a 3-mscc sample interval, and a 12.5-80 Hz pretilter.

1500 Becque

Initial processing.-The initial processing sequence was: demultiplexing and editing. true- amplitude recovery and application of a gain program, muting, reflection-moveout velocity analysis, moveout correction and 24-fold CDP stacking, deconvolution after stack (DAS), wave-equation migration, 12-80 Hz filtering, and amplitude scaling.

The initial processing sequence was similar to that of examples I and 2, except that no DBS was performed due to the absence of water-layer reverberation; the gain program also was different. The gain program applied consisted of multiplying each trace- amplitude sample by a factor T1.aaT~~o), where (Y is the absorption coefficient taken equal to 0.23 Npisec (2 dB/sec), T is the two-way reflection time and To is the two-way water-bottom reflection time The program was designed to compensate both for geometrical divergence and absorption.

Continuous reflection-moveout velocity analysis was performed along both sections, and I7 and I3 velocity-time curves irregularly spaced were applied, respectively, on lines J 21 I and J 212 for moveout corrections, with linear interpolation between them.

DAS was performed with a 200-msec operator obtained by a least-squares method from the recorded Flexichoc wavelet (Lavcrgne, 1975; Cholet et al, 1975). Finite-difference wave-equation migration was applied using known velocity information. The migration moved the dipping reflections to their proper positions and eliminated most of the diffraction hyperbolas associated with the basement.

In the absence of well logs for calibration, amplitudes of the migrated sections were scaled such that the sum of the sampled amplitudes of the water- bottom reflection central lobe was made equal to the water-bottom reflection coefficient. This was estimated close to 0.3 from the amplitude ratio of bottom reflection and water reverberation before stacking.

Velocity computation.-Velocity was computed from the migrated traces using equation (1) and as- suming a constant density. The initial 4-msec sample interval was maintained. The low-frequency trends were inserted using the reflection velocity analyses.

Figure I2 shows migrated sections in black and the velocity in color. The velocity scale increases from 1000 to 6000 misec, corresponding to color changes from light green to green, yellow, red, and blue. On the section the velocity increases downward from 1500 m/set in the water to 6000 m/set in the basement. In the sedimentary zone, it is possible to

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differentiate light green and dark green zones, with velocities of about 1800-2200 m/set. yellow Lanes with velocities of 3200-3800 misec, red zones with velocity of 4500 misec, and blue zones with velocities higher than 5500 misec.

DSDP site 372 was drilled a few miles south of line J 2 I I. The borehole penetrated 884 m of sediments, down to Lower-Burdigalian mudstones and sandstones. A core analysis was made, yielding velocity variations with depth very similar to the seismic velocities; however, velocities measured on cores are systematically IS to I8 percent less than seismic velocities. This is perhaps due to decompaction when core samples are brought to the surface. Using the core velocity analysis, an attempt was made to identify lithology. The light green and dark green zones probably correspond to Plio-Pleistocene and Upper-Miocene marl formations, the green-yellow zones to Lower Miocene mudstones; the orange zone in the central trough of J 2 I2 could be related to Oligocene sandstones, the yellow pillows on J 2 I I to anhydrites, and the high-velocity blue and red layers on the right side of J 21 I to salt.

It is interesting to notice the velocity variations in the Plio-Pleistocene and Miocene formations; they could correspond to lithologic facies variations and/ or compaction. The color display is well adapted to facies representation: variable-amplitude displays are better adapted to bed delimitations.

Correlation of seismic sections to the lithology is difficult here because no well logs are available, but, even in this case, velocity pseudologs can help in the detection of facies variations.

CONCLUSIONS These examples show that seismic pseudologs

representing acotistic impedance or velocity can give useful lithologic information. The pseudologs can be used for detailed investipations of oil and gas fields by indicating the reservoir structure and the limits of hydrocarbon zones. Correlation with well logs im- proves the accuracy and helps identify facies and facies changes at large distances from the wells. Pseudologs also provide an efficient geologic tool for deep-water offshore exploration.

When the low-frequency information is inserted, the pseudolog is more complete than that obtained only from the migrated section, for it contains acoustic impedance variations in both the seismic frequency band and the low-frequency band. Even when the low-frequency trends are not inserted, acoustic impedance pseudologs are more directly


correlated to lithologic variations than are corresponding conventional seismic traces. They contain the same information as the seismic traces, displayed in a manner more directly correlatable to geologic layers.

The accuracy of the acoustic impedance pseudolog depends on the accuracy of amplitude scaling, quality of wave shaping, and the amount of low- and high-frequency information. The proper form of the seismic wavelet is essential. Wavelet shaping depends on the nature of the initial seismic source pulse; if it is short, reproduces on each recording, and is recorded on an auxiliary channel, the effectiveness of wavelet shaping is greatly enhanced.

Future enhancements are directly related to im- provements in field data acquisition. These should include higher-resolution sources, smaller hydrophone-group intervals, and wide-band recording. Data acquisition and processing should provide 3-D migration of reflections, accounting for lateral dips and nonvertical raypaths. In the future, we believe that it will be possible to obtain acoustic impedance logs from seismic traces in structurally complex areas, by the iterative use of seismic sections and models. In reservoir evaluation, this migration should improve the accuracy of detailed maps dis- playing lithologic and petrophysical variations between wells.

ACKNOWLEDGMENTS Our thanks are due E. Maffiolo and B. H&not

of I. F. P., who have been involved in all stages of the data processing.

We are indebted to SociCte Nationale Elf-Aquitaine (Production) who provided some of the seismic data and gave permission to publish these. We are par- ticularly indebted to J. Lacaze of SNEA(P), who took an active part in the interpretation of the acoustic impedance sections.

REFERENCES Cholet, J., Grau, G., and Magneville, P., 1975, Recent

developments in the use of a marine implosion source (Flexichoc): Presented at the 45th Annual International SEG meeting, in Denver.

Gardner, G. H. F., Gardner, L. W., and Gregory, A. R., 1974, Formation velocity and density-the diagnostic basics for stratigraphic traps: Geophysics, v. 39, p. 770-780.

Kunetz, G., 1961, Essai danalyse de traces sismiques: Geophys. Prosp., v. 9, p. 317-341.

- 1963, Quelques exemples danalyse denregistre- ments sismiques: Geophys. Prosp., v. 11, p. 409-422.

Lavergne, M., 1975, Pseudo diagraphies de vitesse en offshore profond: Geophys. Prosp., v. 23, p. 695-711.

Lavergne, M., and Willm, C., 1977, Inverston of seismo- grams and pseudo-velocity logs: Geophys. Prosp., v. 25, p. 232-250.

Lindseth, R. 0.) 1976, Seislog process uses seismic reflection traces: Oil and Gas J., v. 74, no. 43, p. 67-71.

Newman, P., 1973, Divergence effects in a layered earth: Geophysics, v. 38, p. 481-488.

ODoherty, R. F., and Anstey, N. A., 1971, Reflections on amplitudes: Geophys. Prosp., v. 19, p. 430-458.

Scientific party, 1975, Glomar Challenger returns to Mediterranean Sea: Geotimes, August, p. 16-19.

Sheriff. R. E.. 1973. Factors affecting anmlitudes-A re- view of physical principles: Sympo;. , Geophys. Sot. of Houston, October, p. 3-16.

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