a few hundred metres, the AVO signatures change
significantly, due to compaction. The oil response
can be quite similar to either a slightly deeper gas
response or a slightly shallower water response. In
general, we go from a class IV to III AVO regime
for hydrocarbons at the shallowest level, to a class II to
III in the middle level, and finally to a class I to II at
the deeper level, following the AVO classification
system of Rutherford and Williams (1989), see
Fig. 18.21. This shows how important it is to honour
burial history and compaction during AVO analysis.
We can now estimate the fluid factor attribute for
the seismic line shown in Fig. 18.22. The fluid factor
can be derived from near- and far-stack amplitudes
using the formula:
ΔF ¼ Near À η Á Far À Near
ð
Þ
ð 18:28Þ
Here, η is not the same as κ in the earlier formulation of the fluid factor, since Far-Near is not exactly
the same as the AVO gradient. However, the two-term
AVO makes a linear relationship between the FarNear and the AVO gradient, and therefore η and κ
can also be easily correlated. Assuming the far stack
to be around 30
and the near stack to be at 0
(normally the far stack will be representative for slightly
lower angles than 30
, whereas near stack will be
1400
2600
2400
2200
2000
1800
1600
Gas
Oil
Brine
Gas
Oil
Brine
Gas
Oil
Brine
Shale
Shale
Depth (m)
2000 4000 6000 8000 1000012000
1.5
2
2.5
Vp/Vs
3
– 0 . 5
0
Fluid Factor
0.5
–0.1
–0.08
–0.06
–0.04
–0.02
0
0.02
0.04
0.06
0.08
0.1
Acoustic Impedance (km/s*kg/m 3 )
Fig. 18.24 Seismic depth trends and expected fluid factor.
Note that both oil and gas sands show large negative fluid factor
values down to about 2,300–2,400 m burial depth, whereas brine
sands show weak or positive fluid factor values for all depth
ranges. Gas sands seem to give negative fluid factor even deeper
than the modelled window, beyond 2,600 m. The gas and oil
zone in the well log data also show a relatively strong fluid
factor anomaly, as expected from the depth trends. (Adapted
from Avseth et al. 2008)
478
P. Avseth
significantly, due to compaction. The oil response
can be quite similar to either a slightly deeper gas
response or a slightly shallower water response. In
general, we go from a class IV to III AVO regime
for hydrocarbons at the shallowest level, to a class II to
III in the middle level, and finally to a class I to II at
the deeper level, following the AVO classification
system of Rutherford and Williams (1989), see
Fig. 18.21. This shows how important it is to honour
burial history and compaction during AVO analysis.
We can now estimate the fluid factor attribute for
the seismic line shown in Fig. 18.22. The fluid factor
can be derived from near- and far-stack amplitudes
using the formula:
ΔF ¼ Near À η Á Far À Near
ð
Þ
ð 18:28Þ
Here, η is not the same as κ in the earlier formulation of the fluid factor, since Far-Near is not exactly
the same as the AVO gradient. However, the two-term
AVO makes a linear relationship between the FarNear and the AVO gradient, and therefore η and κ
can also be easily correlated. Assuming the far stack
to be around 30
and the near stack to be at 0
(normally the far stack will be representative for slightly
lower angles than 30
, whereas near stack will be
1400
2600
2400
2200
2000
1800
1600
Gas
Oil
Brine
Gas
Oil
Brine
Gas
Oil
Brine
Shale
Shale
Depth (m)
2000 4000 6000 8000 1000012000
1.5
2
2.5
Vp/Vs
3
– 0 . 5
0
Fluid Factor
0.5
–0.1
–0.08
–0.06
–0.04
–0.02
0
0.02
0.04
0.06
0.08
0.1
Acoustic Impedance (km/s*kg/m 3 )
Fig. 18.24 Seismic depth trends and expected fluid factor.
Note that both oil and gas sands show large negative fluid factor
values down to about 2,300–2,400 m burial depth, whereas brine
sands show weak or positive fluid factor values for all depth
ranges. Gas sands seem to give negative fluid factor even deeper
than the modelled window, beyond 2,600 m. The gas and oil
zone in the well log data also show a relatively strong fluid
factor anomaly, as expected from the depth trends. (Adapted
from Avseth et al. 2008)
478
P. Avseth