Characterization and Simulation of Naturally Fractured Tight Gas Sandstone Reservoirs

Abstract

Abstract Significant gas reserves are present in low-permeability sandstones of the Frontier Formation in the 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 sandstone at five locations in the basin. Fracture characterization involved construction of detailed fracture network maps of outcrops that provided information on the fracture orientations, lengths, and spatial distribution. The fracture network maps clearly demonstrate that regional fractures are a unidirectional set of fractures that are perpendicular to bedding and have varying length and spacing. The spatial distribution of regional fractures is controlled by bed thickness, with fewer and longer fractures per unit area as bed thickness increases. The fracture data was combined with matrix permeability data to compute an anisotropic horizontal permeability tensor (magnitude and direction) corresponding to an equivalent reservoir system in the subsurface. This analysis shows that the maximum and minimum horizontal permeability is controlled by fracture intensity and decreases with increasing bed thickness. The relationship between bed thickness and the calculated fluid-flow properties was used in a reservoir simulation to predict gas production from vertical, hydraulically-fractured wells and horizontal wells of different lengths in analogous naturally fractured gas reservoirs. Simulation results show that horizontal wells drilled perpendicular to the maximum permeability direction can maintain a high target production rate 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. Introduction Although fractures are present at some large scale in all reservoirs, it is only when they have sufficient spacing and length that their effect on fluid flow becomes important. Fractures not only enhance the overall porosity and permeability of many reservoirs, they also create significant permeability anisotropy In order to assess the role of fractures on hydrocarbon production and reservoir permeability an isotropy, characterization of naturally fractured reservoirs has focused primarily on the distribution and orientation of fractures and fluid-flow properties of individual representative fractures in a given reservoir volume.1 Characterization of the fracture network can be made from analysis of cores and logs from the subsurface and field studies of surface outcrops. Core and log studies are limited to individual fractures that intersect the wellbore and provide information on fracture orientation and distribution along the wellbore and an estimate of fracture width. These methods do not provide direct information of the spatial distribution and interconnectivity of the fracture network away from the wellbore. P. 437