The successful exploitation of tight-gas reservoirs requires fracture networks, sometimes naturally occurring, often hydraulically stimulated. Borehole microseismic data acquired in such environments hold great promise for characterising such fractures or sweet spots. The loci of seismic events delineate active faults and reveal fracture development in response to stimulation. However, a great deal more can be extracted from these microseismic data. For example, inversions of shear-wave splitting data provide a robust means of mapping fracture densities and preferred orientations, useful information for drilling programs. They can also be used to track temporal variations in fracture compliances, which are indicative of fluid flow and enhanced permeability in response to stimulation. Furthermore, the frequency-dependent nature of shear-wave splitting is very sensitive to size of fractures and their fluidfill composition. Here we demonstrate the feasibility of using such analysis of shear-wave splitting measurements on data acquired during hydraulic stimulation of a tight-gas sandstone in the Cotton Valley field in Carthage, West Texas.
It is still common practice to adjust transmissibility multipliers of faults within production simulation models to achieve a history match without establishing whether or not the values are physically reasonable. Analysis of the permeability and threshold pressure of numerous (>2000) fault rocks from cores has provided a detailed understanding of the controls on fault rock properties, which now allows one to establish whether transmissibility multipliers incorporated into simulation models are physically realistic. Fault transmissibility multipliers within many simulation models that we have studied have proven to be far lower than core measurements suggest are reasonable. In effect the faults are being made ‘scapegoats' to compensate for inadequacies in the physical description of the reservoir within the simulation model. The recognition of these discrepancies is, however, valuable and indicates that further characterization is required to understand the flow behavior of the reservoir.
The multiphase flow properties of faults are very rarely taken into account during simulation modeling. Theoretical, anecdotal, as well as the results from history matching of simulation models, suggests that considering the multiphase flow properties of faults could lead to better day-to-day and long term decision making. In other situations, it may not be necessary to consider the capillary pressure characteristics of faults. We therefore recommend that, prior to full field simulation modeling, simple models are constructed in which the capillary pressure and relative permeability characteristics of fault are included using a local grid refinement so that the importance of multiphase flow across the faults can be established.