After determining the hydrate and gas saturations based only on surface seismic information, we use wells logs from the area of the Blake Outer Ridge to validate our technique and the obtained hydrate estimates.
We show in the left panel of Figure 12 two smoothed well velocities from wells 994 and 995 Matsumoto et al. (1996). The middle and the right panels contain the original porosities obtained from cores (dotted lines), the baseline porosities determined with our rock-physics models and assuming 100% brine saturation of the sediments (solid line), and the polynomial regression representing the normal brine porosity (dashed line). It is obvious that for well 1, the real porosity and inferred normal brine porosity are in good agreement. This good fit of the porosities suggests that the sediment mineralogy assumed in our modeling appears to be a good approximation of the real mineralogy at this spot. Well 2 displays a slight discrepancy between the porosities, thus implying deviation of the model and in-situ conditions.
Subsequently, we determine the hydrate saturations both from the residual between the baseline porosity and the real porosity, and from the residual between the baseline porosity and the fitted normal porosity. The results are shown in Figure 13.
The saturation estimates for well 1 are in close agreement as expected. Hydrate model 1 results in a maximum saturation of about 30 %, model 2 of about 22 % and model 3 of less than 1%. Well 2 shows a larger discrepancy between the estimates obtained from the real in-situ porosities and those obtained from our technique. The real porosities (dashed line) result in about 10 % higher saturation values. The overall saturation levels are, however, consistent with those obtained from surface seismic. Consequently, we can conclude that our technique of estimating hydrate and gas saturation from surface seismic yields reasonable results in the region of the Blake Outer Ridge.