pitfall amplitude interpretation

384 The Leading Edge April 2010

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A high-amplitude anomaly was identified in the Upper Oligocene Daman Formation clastic sequence during

initial interpretation of newly acquired 3D seismic data in the Tapti-Daman sub-basin offshore western India. This anomaly exhibited the depositional signature of a channel and was interpreted as bright spots associated with gas sands, consistent with the occurrence of thin gas pays in the sandstone reservoirs of Daman Formation in the area. Considering thickness and areal extent, thick gas sands were predicted, upon drilling; however, thick water-bearing sands were found. The predrill interpretation was mainly based on windowed amplitudes without validation through character of reflection events and other supporting evidence such as frequency, velocity, and AVO.

To analyze the failure and develop a geologic model con-sistent with well results, the seismic and new well data were re-evaluated. Log motifs show a thick channel filled with 15-m, high-impedance, porous sands embedded in low-impedance shale. Character matching of a synthetic seismogram to the seismic data shows that the highest amplitude is caused by the basal interface (sand-shale) of the channel. Windowed and horizon attributes reconfirm the channel geometry. Imped-ance characteristics of sands with respect to embedding shales vary laterally and vertically in the area; gas sands have higher impedance in some wells and lower impedance in others with respect to encasing shales. Variability in impedance is attrib-uted to variation in depositional environment. Fluvial-to-estuarine channels in the upper delta plain are inferred from analysis of log motifs, seismic characteristics, and attributes. The bright spots were produced by thick, high-impedance po-rous sandstones. The failure of the well to find hydrocarbons was probably due to lack of vertical seal because channel sands are well compartmentalized with faults and positive relief is present. The validation of bright spots was done through AVO modeling. The water-bearing sands in the new well did not show an AVO anomaly, whereas gas-bearing sands in an old well showed a good class 2 AVO anomaly.

IntroductionA local increase in P-wave amplitude (i.e., a bright spot) in association with a mappable trap geometry extent is consid-ered a robust (but not foolproof) direct hydrocarbon indictor (DHI) in Tertiary clastic sequences. DHIs are mostly related to gas rather than oil because gas has a greater impact on the acoustic properties of reservoirs than oil. Water sands have lower acoustic impedance than embedding media and, in the case of gas saturation, the acoustic impedance of a sandstone reservoir decreases further; so the gas-filled portion of the res-ervoir gives rise to a high-amplitude reflection.

Knowledge of the phase and polarity of seismic data is essential before interpreting a high-amplitude reflection as a valid DHI. Amplitude may or may not be associated with

HARILAL and S. K. BISWAL, Oil and Natural Gas Corporation, India

frequency, phase, and polarity changes depending on reser-voir properties, thickness, and data quality. Flat spots (re-flections from fluid contacts), AVO, velocity variation, and shear-wave information may help in positive identification of DHIs (Brown, 2004). 3D visualization, automatic spa-tial tracking, and seismic attribute analyses facilitate precise mapping of anomalous amplitude features. Based on local geological knowledge and the geometry of mapped anoma-lies, anomalous amplitudes may be assigned to some geologi-cal features such as channels or shelf sand ridges.

DHIs are successful in many cases, but they may fail because a given geophysical response is not uniquely asso-ciated with a single geological model either with or with-out hydrocarbon saturation (Houck, 1999). Fizz water and low gas-saturated reservoirs may also give rise to amplitude anomalies not related to commercial hydrocarbon accumula-tions (Han and Batzle, 2002). Inadequate understanding of polarity conventions, tuning effects, high amplitudes related to lithologic contacts, and reflections from geologic contacts resembling flat spots are reasons for pitfalls in relating high amplitudes to DHIs. In addition, there may be complex geo-logical situations where sands have greater impedance than embedding media, contrary to the known or expected ge-ology of the area. In such cases, the sands always generate

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Figure 1. The study area with rms amplitude map over multi 3D surveys and well locations. Amplitude map shows imprints of channels mapped during predrill interpretation. Wells A, B, C, D, E, F, G, I, and J were drilled before 3D interpretation. H indicates the location proposed on the basis of 3D interpretation. TWT contours of reflector M1 are superimposed on the amplitude map.

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April 2010 The Leading Edge 385

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high amplitudes irrespective of saturating fluids (water or gas) and—due to inadequate knowledge of polarity, phase, and impedance—high amplitudes are mistakenly assumed to rep-resent hydrocarbon reservoirs. Dim spots are recognized in a lateral sense but, in the case of narrow channels with high-impedance sands, insignificant dimming of amplitude due to gas saturation may be unnoticed.

The present study is related to a deceptive high-amplitude anomaly associated with Upper Oligocene channel sandstones in India’s offshore Tapti-Daman sub-basin (Figure 1). The anomaly was mapped as part of interpretation of 3D data, newly acquired in 2005. Before 3D, nine wells (A-G, I and J) were drilled, mostly based on structural considerations; a few of these wells encountered multiple thin (1–7 m) sand pays in Daman Formation. High amplitudes associated with low-im-pedance gas sands are known to occur in several wells. Taking the lead from prior knowledge of area, the high amplitudes were assumed to have been generated from oil/gas sands, but were found to be water-bearing upon drilling.

The objective of this paper is to demonstrate the pitfalls in interpreting an anomalous seismic amplitude as a DHI and to assess the rock properties of the channel sandstone which generated the amplitude anomaly.

3D seismic interpretation The channel in Figure 1 was mapped during integrated in-terpretation of newly acquired 3D data and is mainly based on the geometry of the anomalous amplitudes. On vertical sections, stacked high amplitudes were observed between 2000 to 2100 ms (Figure 2); the gross thickness of this high-amplitude zone is about 70 m at an average depth of 2180 m. The top of the high-amplitude zone (yellow reflector) was autotracked and time structure maps, horizon slices, and rms amplitude maps were generated. The rms amplitude map is overlaid on the time structure map in Figure 1. The channel geometry was also validated by other attributes and techniques such as spectral decomposition and seismic facies maps, but investigation of the anomalies as DHIs using ve-locity, AVO, and shear-wave methods was not done. No flat spots and/or polarity reversals were seen on vertical seismic sections.

Because Daman Formation consists mainly of sand and shale in the study area, the amplitude anomaly was assumed to have been generated from a sand-filled channel. In nearby areas, many wells based on DHIs produce gas from Daman. After integrating amplitude, structure, and background infor-mation, well H was drilled to explore the channel. The well penetrated a sand-filled channel as predicted but found no hydrocarbons; however, gas was encountered at lower levels where there was no amplitude anomaly (Figure 3). After this study, multilevel isolated high-amplitude anomalies at lower stratigraphic levels were found to be gas-bearing (Harilal et al., 2008).

To investigate the well failure and develop an accurate geologic model consistent with well results, seismic and new well data were re-evaluated. Logs and an interpreted lithologic column for the new well (H) are shown in Figure 3. The top

contact of the target sand (thickness = 15 m) is gradational and the bottom contact is sharp. The porosity of this sand is good (>20%) and its velocity and impedance are higher than those of its encasing shales.

Well-to-seismic matching and analysisSynthetic seismograms were generated using two types of wavelets: (1) extracted from the seismic and (2) constant 64-Hz Ricker wavelet (Figure 4). The polarity convention for

Figure 3. Log signatures and interpreted lithologic column in well H. The predicted sands are embedded in shales at depths of 2170-2185 m. The sand is water-bearing. Gas was found in lower-level (2300 m) sands.

Figure 2. Portion of seismic section showing stacked high-amplitude zone between 2000 and 2100 ms two-way traveltime.



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these synthetics is that a low-to-high impedance contrast is displayed as a trough (red). The extracted wavelet shows a peak frequency of about 24 Hz with bandwidth of 10–50 Hz. The average interval velocity of the sandy interval is 2800 m/s. At this frequency and velocity, the limit of resolution (tuning thickness) is about 30 m and the top and base of a 15-m thick sand are not resolved, so the synthetic using the extracted wavelet does not have distinct events correspond-ing to the top and base of sand. The top (shale-sand) and base (sand-shale) of the channel fill give rise to a composite trough-over-peak response. The bottom peak has higher am-plitude than the overlying trough, and the log motifs (Fig-ure 3) and synthetic response show this higher amplitude is caused by the sharp contrast between the properties of the channel sands and underlying shales. This may happen if the shales were scoured (incised) and subsequently coarser clas-tics were deposited. In contrast to the synthetic using the ex-tracted wavelet, the 64-Hz synthetic resolves the 15-m thick sand as expected.

Horizon correlation and attribute extractionAn arbitrary profile across the mapped channel and passing through dry wells C and D (Figure 1) is shown in Figure 5. In general, sandstones have higher impedance than shales (Figure 3 and 4) and onsets of sandstone tops are represented by troughs (red) at well C. Onsets of low-impedance shales are represented by peaks (blue). GR, LLD, and impedance logs and geologic markers Daman Top, Daman1, and Da-man2 are overlaid on the seismic section; seismic marker M1 corresponds to Oligocene Top (Daman Top), and seismic markers M2 and M3 correspond to the Daman1 and Da-man2 geologic markers, respectively. The increase in seismic amplitude is seen within the marked yellow ellipse. The com-posite reflection (red event) representing the top of sand is just below the M1 marker and base of sand corresponds to the M2 marker (Figure 5).

Top and base of sand reflections were correlated using a spatial auto-tracking method and horizon slices were gen-erated. Although the top of sand event apparently has high

Figure 6. Horizon slices from (a) top of sand reflector, (b) bottom of sand reflector, and (c) composite.

Figure 4. Synthetic seismogram of well H. Panel 1 uses wavelet extracted from seismic data. Panel 2 uses 64-Hz Ricker wavelet. For display polarity, a positive impedance contrast is a trough. Seismic traces are blue. Reflections are indicated by arrows.

Figure 5. NW-SE line across the channel sand that passes through wells C and D. Location is shown in Figure 1.



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Figure 10. Arbitrary line passing through wells in Figure 9.

Figure 9. Log correlation profile across the study area, flattened at Daman Top (M1). Log motifs and lithologic interpretation indicate two depositional environments.

Figure 8. Log data from wells G, B, A, E, and I. Intervals with sands are shown in yellow and red.

Figure 7. Crossplot of gamma ray and impedance.

amplitude, its horizon slice does not show any recognizable anomaly pattern (Figure 6a). An anomalous high-amplitude channel pattern is seen on a horizon slice of the base of sand event (Figure 6b), consistent with evidence from the synthetic seismograms and log motifs. The composite slice (absolute sum of top and bottom amplitude) also shows the channel pattern (Figure 6c).

Lithology versus impedanceCrossplots between impedance and gamma-ray logs of five wells (G, B, A, E, I) and log tracks consisting of impedance, gamma-ray and resistivity logs within Daman are shown in Figures 7 and 8, respectively, color-coded by resistivity, which can be divided into three zones representing shales (low resis-tivity = blue), water-bearing sands (medium resistivity = yel-low) and gas-bearing sands (high resistivity = red). The rela-tionship between impedance and lithology is: (1) shales have lower impedance; (2) sands have higher impedance; and (3) few water-bearing sands have lower impedance and few gas-bearing sands have higher impedance than encasing shales.

Depositional model of the sandsAcoustic properties of sandstone in Daman are very incon-sistent with respect to depositional age and depth of burial.


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Generally, shallow Tertiary sands have lower impedance than encasing shales in the Tapti-Daman sub-basin, where many bright spots have been mapped and produced gas from low-impedance sands. But in this part of the basin, sands have both higher and lower impedance than encasing shales, ir-respective of saturating fluids. These acoustic properties may be understood by analyzing variations in depositional pro-cess/environments of sands. The depositional processes and environments can be interpeted from log motifs, lithologic interpretation, and seismic character.

The log correlation profile (Figure 9) passing through wells G, B, A, E, J, and I shows sand dominance between Daman Top and Daman1 and shale dominance with occasional lime-stone streaks between Daman1 and Daman2. These differenc-es in lithologic assemblages may be attributed to differences in depositional processes/environments. The M2 reflector (Daman1) is at the base of the channel in well J. The section (Figure 10) along the log profile of Figure 9 shows a high-amplitude reflection above M3. Thin pay zones are known to occur below M3 (Figure 10, red arrows). Reflections be-tween M1 and M3 and below M3 are not conformable, and an unconformity surface (black arrows) is inferred between M2 and M3 (base of bright trough). Shales, minor sands/silts, and occasional limestone streaks below Daman1 (M2) were deposited in the lower delta plain and estuarine environments under the influence of tidal waves. In this environment, many small tidal bars also occur with low-impedance sands gener-ating bright spots and producing gas. Sand dominance and channel signatures between Daman Top and Daman1 may be caused in upper delta plain environments in which the main depositional process is fluvial, and braided and meandering channels are common (see example of channel in Figure 1).

The existence of a channel is further supported by detailed seismic character and log motifs. An arbitrary line passing through wells C, H and D, flattened at M1, shows thickening of bright amplitudes between M1 and M3 at well H (Figure 11). The log motifs of well H, drilled in the middle of the anomaly, suggest a channel by sharp contact at base and a fining-upward pattern (Figure 12). Similar channel sands are

Figure 12. Log profile showing evidence of channel in well H.

Figure 13. 3D map of M1 with +40-ms shift.

Figure 14. Similar seismic and log signatures were noted at wells H and I which were separated by 20 km. One-to-one correlation is not seen, but high-impedance, water-wet sands have a high-amplitude response. Both wells penetrated the same channel (Figure 1).

Figure 15. Crossplot between impedance and gamma ray.

Figure 11. Arbitrary line across the channel, passing through wells C, H, and D and flattened at M1.



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absent in wells C and D. The mapped channel in Figure 1 may be braided or incised valley fill, and is very extensive (length = 35 km, width = 1–2 km, and sand thickness = 15–20 m). It may be that lower strata (lower delta plain) were incised dur-ing transition from the lower delta plain to upper delta plain environment during a normal regression (fall of sea level). In-cised valleys may be filled by fluvial systems of all types, but it is also possible that sands were deposited simply by braided streams in an upper delta plain environment. Whatever the channel type, the upper delta plain channel sands are rela-tively thick and have higher impedance than background and appear as high-amplitude anomalies. These sands have limited lateral continuity and are well compartmentalized by faults. Amplitude, faults, and channel geometry are simultaneously visualized on a 3D map of the M1 surface (Figure 13). This channel is penetrated by only two wells, H and J, both dry and with similar log and seismic signatures (Figure 14).

The pitfallAnomalous high-amplitude reflections within an interpreted channel on the flank of anticline were attributed to gas sands that were found to be water-bearing when drilled. The ampli-tudes, channel sandstones, and structure in and of themselves are not diagnostic of gas because several other factors can cause a similar amplitude response. In this case, asymmetric high-impedance contrasts at top (+2683) and bottom (-3031) (in g/cm3*m/s) generated high amplitudes (Table 1). Plots of gamma ray versus impedance and impedance versus porosity show that water sands have high impedance (Figure 15a) and also high porosity (Figure 15b). Gas sands at deeper levels in well G have higher impedance than shales (Figure 15c). This pay zone cannot be recognized based on stacked seismic am-plitudes alone (Figure 10), and the amplitude anomaly has to be validated by other studies.

AVO modeling at wells G (Figure 16a) and H (Figure 16b) shows significant difference in response. Gas sands in well G show a class II anomaly. There is no AVO anomaly in well H. The model responses suggest that drilling well H might have been avoided on the basis of AVO or similar rock properties analysis.

Figure 16. AVO curve at (a) top of gas sand in well G and (b) top of water sand in well H.

ConclusionsWe used seismic amplitude and depositional signatures to map a large channel in the Upper Oligocene Daman se-quence, interpreting the observed high amplitudes to repre-sent gas-bearing channel sands. Although the sandstones that we drilled were channel deposits, they were water-bearing. We learned that there is a complex relationship between im-pedance and lithology in our study area; the channel sands are porous and have high acoustic impedance, and even some gas sands have higher impedance than encasing shales. Anomalous high seismic amplitudes are caused by the high-impedance contrast between brine sand and shales, and we attribute the variability in acoustic properties to variations in depositional environments/process. AVO modeling has not shown an anomaly at the well, and predrill AVO analysis may have validated the anomaly and avoided the dry hole. Our pitfall is that we based our predrill interpretation on stacked seismic amplitudes alone without having incorporated AVO analysis coupled with good rock properties/lithology calibra-tion into our prospect evaluation and risking.

ReferencesBrown, A, 2004, Interpretation of three-dimensional seismic data:

SEG Investigations in Geophysics, 9.Han, D-H, and M. Batzle, 2002, Fizz water and low-gas saturated res-

ervoirs: The Leading Edge, 21, 395–398.Harilal, S. K. Biswal, and V. Rangachari, 2008, Mapping incised

valley fill systems: Application of sequence stratigraphy and 3-D seismic attribute: 7th International Conference and Exposition on Petroleum Geophysics.

Houck, R., 1999, Estimating uncertainty in interpreting seismic indi-cators: The Leading Edge, 18, 320–325.

Acknowledgments: Our sincere gratitude to the director (E), ONGC, India, for permission for publication of this paper. The au-thors thank S. K. Das, ED-HOI GEOPIC, for his guidance during this study and Don Herron for his critical review and suggestions to improve the manuscript. The views expressed in this paper are exclusively those of the authors and need not necessarily match with official views of ONGC.

Corresponding author: [email protected]

Lithology Density Velocity Impedance Impedance constrast

Water-well (shallower)

shale 2.37 2485 5889.45 2683.35

w-sand 2.35 3648 8572.8 −3031.28

shale 2.26 2452 5541.52

Table 1.


pitfall amplitude interpretation

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thick gas sands

channel sands

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highamplitude anomaly

highamplitude reflection