Unexpected early waterflood breakthrough in a high matrix porosity, Pennsylvanian age sandstone reservoir, indicated the possible presence of a high directional permeability fracture flow system superimposed on the matrix flow system. A simulation study was initiated to study this problem.
Simulation history matching results showed that the fractures exhibited high directional permeability but low storage capacity relative to the matrix portion of the reservoir. A low fracture intensity index was calculated. This low storage capacity fracture system supports the hypothesis that the fracture system resulted from previous stimulation treatments rather than from an extensive naturally occurring fracture system. The recognition and quantification of this new model led to significant improvements in field production practices, well alignments, ultimate oil recovery and production forecasting.