Abstract
The Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin, high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed.
A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate, fracture geometry prediction, and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs.
Over a two-year drilling program, data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field.
This integrated process of measurement, analysis, prediction, evaluation, and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas.
