ABSTRACT

An integrated study using 3-D seismic data, smear gouge ratio (SGR) calculations (estimate of sand to shale ratio of fault gouge), well logs, well performance data, and gas isotope data has created an empirically-based model that predicts production induced fault seal breakdown in the South Marsh Island 66 (SMI 66) gas field. Furthermore, the timing of seal breakdown was identified in several cases.

Because the SMI 66 gas field contains many fault separated depletion drive reservoirs, it represents a unique opportunity to study the effects of production induced pressure differential across faults that initially sealed. Examples of ten juxtaposed permeable reservoirs showed that: 1) Seals associated with intraformational faults broke down in four out of five cases (80%); all four breakdown cases had SGR's of 4.9 or greater, 2) Seals associated with interformational faults broke down in zero out of five cases; all cases involved SGR's of 1.6 or less, 3) Seal behavior was not predictable when SGR's were between 1.6 to 4.9; this was a leak/seal transition zone, 4) If a fault seal broke, it occurred at or before a 35% drop of initial reservoir pressure, 5) All seal breakdowns occurred at or before 1500 psi of pressure differential; all sealing cases had pressure differentials in the 3400 to 5600 psi range.

A better understanding of production induced fault seal behavior has enabled the SMI 66 field management team to optimize the number of wells needed for development, to identify potential drill hazards, and to better understand reservoir drive mechanisms, which has enhanced production forecasting and completion design.