Characterization and fluid flow simulation of naturally fractured Frontier sandstone, Green River Basin, Wyoming

Abstract

Significant gas reserves are present in low-permeability sandstones of the Frontier Formation in the greater Green River Basin, Wyoming. Successful exploitation of these reservoirs requires an understanding of the characteristics and fluid-flow response of the regional natural fracture system that controls reservoir productivity. Fracture characteristics were obtained from outcrop studies of Frontier sandstones at locations in the basin. The fracture data were combined with matrix permeability data to compute an anisotropic horizontal permeability tensor (magnitude and direction) corresponding to an equivalent reservoir system in the subsurface using a computational model developed by Oda (1985). This analysis shows that the maximum and minimum horizontal permeability and flow capacity are controlled by fracture intensity and decrease with increasing bed thickness. However, storage capacity is controlled by matrix porosity and increases linearly with increasing bed thickness. The relationship between bed thickness and the calculated fluid-flow properties was used in a reservoir simulation study of vertical, hydraulically-fractured and horizontal wells and horizontal wells of different lengths in analogous naturally fractured gas reservoirs. The simulation results show that flow capacity dominates early time production, while storage capacity dominates pressure support over time for vertical wells. For horizontal wells drilled perpendicular to the maximum permeability direction a high target production rate can be maintained over a longer time and have higher cumulative production than vertical wells. Longer horizontal wells are required for the same cumulative production with decreasing bed thickness.