Drilling and hydraulic fracture stimulation efficiency has been the focus for development of unconventional reservoirs, however, predicting and maintaining lateral well performance remain the most challenging part of these reservoirs' lifecycle. The challenges include, but are not limited to, high water production, high decline rates, casing deformation and frac hits. These challenges can be related to the fact that the formation is highly heterogeneous, reflecting variation in depositional facies, mechanical properties, occurrence of natural fractures, and stratigraphic changes within a specific formation. Surface seismic attributes are used to predict this lateral formation variation; however, it can be only used to a limited extent in understanding and predicting lateral position, assuming wells are steered in a layer cake model. The assumption of lateral homogeneity simply ignores crucial structural, tectonic, and depositional changes that occur ubiquitously on a sub seismic scale, a significant oversight that urges the need for more thorough evaluation.
In this paper, we show a novel workflow applied in the Marcellus shale to evaluate lateral geological variations. First, the mechanical properties and minimum horizontal stress are evaluated with data from a slim dipole sonic tool combined with a density log. Next, the geological facies and the natural fractures are identified from oil-based high-resolution borehole image logs. These tools were conveyed through the bit, meeting the typical low-cost and low-risk exposure requirement while maintaining complete well control. Furthermore, the data was used to build a structural model and an entire discrete fracture network (DFN) model based on the image data and constrained by the output of the slim dipole 3D far-field sonic imaging. This enables the operator to investigate the extension of natural fractures up to 40 ft away from the well, a novel approach where modeling of natural fracture length and height is not based only on a statistical or stochastic process fed by assumptions. Instead we consider the continuity of the fractures from the wellbore into the far field.
