Fractured reservoirs have drawn more and more attention in the exploration and production business during the past decades. Oil and gas producers are now extensively worked on tight sand, carbonate, and shale reservoirs, all of which are impacted by the intensity and other properties of the fracture systems. When dealing with these reservoirs, two lines of advanced analyses need to be performed: fracture characterization and modeling.
This study explores the possibility of deriving quantitative fracture properties based on whole core description. The results show that in a given core slab, regardless of whether it is continuous or discontinuous, by making certain assumptions, it is possible to derive 0-D, 1-D, 2-D, and 3-D fracture intensities, estimate fracture porosity, and assess fracture openness and connectivity. The results can then calibrated with other geological and geophysical (G&G) data such as FMI and seismic interpretation (texture analysis, ant-tracking, and so on), and reservoir engineering analysis such as production ranking and well testing, possibly providing useful information for reservoir simulation and field development, as the permeability of fractures is closely related to fracture intensities and aperture. The methodology was applied to several producing fields in the Rocky Mountain area and it was concluded that adequate fracture assessment yielded consistent results between static and dynamic reservoir analyses. Although whole core is available only from certain intervals and certain locations of the fields, when integrated with regional structure, lithology, depositional facies, bed thickness, bed dip, and other data, the fracture parameters derived from cores generally provide a reliable assessment of the fractured reservoirs under evaluation.
This study provides a new workflow for quantitative fractured reservoir description, and application of such a data set to improve fractured reservoir simulation.