Fault Block B

Pressures in FBB are similar to those in FBA, but GORs are more than an order-of-magnitude less. Whereas downdip gas halps were seen to grow around the A-11 and A-6 wells by 1992 time, but were gone by 1994 time in FBA, there was no production at all from downdip in FBB over then entire time-lapse of our 4 3D seismic surveys, and updip wells were producing a very low GOR's the whole time. Yet, the brightness downdip continued to increase with each new survey. Only with reservoir simulation will we be able to estimate the gas content in the formation downdip. Poor connectivity with the updip reservoir is obvious, though. The difference between 1985 and 1994 surveys shows that the major increases in amplitude occurred along two bands that, interestingly, are perpendicular to the major depositional fairway in the EI 330 field.



Drainage Acreage

The case updip is more traditional -- drainage produces dimming. Here, two wells, the A-12 and B-4 were producing between 1992 aand 1994. About 650,000 bbl of oil was produced, and about 320 acres were dimmed. Reservoir thickness was 50', porosity 30%, and with an oil saturation drop of 30%, 420 bbl/ac-ft would have to have been produced -- again, a very reasonable production rate for pleistocene GOM sands.



LF SEISRES Loop

In order to understand what is happening downdip, we need to determine if enough gas exists in situ to account for the brightening. It is common opinion in the oil inutry that about 5% gas exsolution is required to produce brightening. reservoir simulton is needed, not only for gas solution, but also to predict downdip pressures. Measurements were only made far updip.

We have computed a synthetic seismic cube from inversion of the observed seismic amplitudes. We can account for only some of the brightness downdip--certainly not to the extent observed in the 1994 dataset. This loop from observed to inverted to forward modeled to differences between model and observed we call SEISRES, seismic reservoir simulation.




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