Innovative Modeling to Quantify the Impact of Natural Fractures, Optimize Well Spacing and Increase Productivity in the Marcellus Shale

Abstract

Abstract Individual well performance in the Marcellus Shale of northeastern Pennsylvania varies markedly, even in areas where the lithology, fluid composition, and completion design are consistent. A primary reason for this is the natural fracture system, which influences hydraulic fracture growth, dynamic fluid flow, reservoir pressure and stress behavior. Chief Oil and Gas (Chief) contracted Schlumberger to conduct an integrated study using an innovative modeling approach to quantify the impact of these natural fractures and optimize field development. Working together, the team created an approach that consisted of constructing and coupling three models: a 3D geomechanical model, an unconventional fracture model (UFM), and a 3D dynamic dual-porosity model. The geomechanical model is composed of a discrete fracture network (DFN) containing both regional (J1 and J2 sets) and tectonic fractures. These are interpreted from seismic attributes (anisotropy azimuth, seismic velocity anisotropy) and ant tracking. The UFM model simulates the growth of hydraulic fractures and their interaction with natural fractures in the DFN. Portions of the natural fracture network are assumed to be open tectonic fractures, and their flow properties are adjusted (porosity and permeability) to match well performance. Adjustments are also made to account for production-related perturbations in dynamic stress magnitude and azimuth, which impact later wells. These modifications to the fracture network are critical for history matching the dual-porosity model. The production history match showed that hydraulic fractures and open tectonic natural fractures are key production drivers in the study area, and that the spatial variability of the natural fracture network exerts more influence on well performance than initially thought. The connection between the hydraulic fracture network and portions of the open tectonic natural fracture system enhances parent well access to larger drainage areas. This controls the strongly variable well production observed in the study area. Subsequent stress perturbation resulting from parent well depletion is detrimental to the completion efficiency of the child wells, even even though they have better frac designs with higher proppant loading. The modeling work also shows that the gas-in-place is consistent with volumetric and rate transient analysis (RTA) estimates. The coupling of the three models reasonably approximated changing reservoir conditions and created a nexus of domain expertise including geology, geophysics, geomechanics, stimulation, completions engineering and reservoir engineering. This enabled an understanding of the complex reservoir behavior of the naturally-fractured Marcellus Shale and generation of an optimized fit-for-purpose development plan. Chief was already implementing changes in spacing and increasing the distance between offset PDP (Proved Developed Producing) wells and this study affirmed that revised development plan.