Even with the current development of unconventional reservoirs in the United States, where tens of thousands of wells have been drilled and completed, there is not enough understanding of the production and successful completion drivers in unconventional plays.
The Marcellus shale is a naturally fractured formation, and it is vital to account for the natural fractures during a simulation study. A discrete fracture network (DFN) model and a 3D mechanical earth model (3D MEM) were created and used to determine the complexity of the hydraulic fracture geometry. The microseismic data obtained during the hydraulic fracture simulations served to constrain the hydraulic fracture footprint.
The proposed workflow uses unconventional fracture modeling (UFM) to predict the propagation of complex hydraulic fracture networks with pre-existing natural fractures and model the stress shadow effect and the lamination effect considering different proppant placement by type within the fracture. Propped and unpropped fracture half-lengths obtained during history matching provide calibration for the UFM. Based on the calibrated model, an analysis of the current perforation efficiency was performed, which showed that almost half of the perforations do not contribute to the production. Optimization of well spacing and cluster spacing was performed on a two-well pad to account for well interference such as fracture hits, stress shadow, and depletion after 30 years of production. The recommended well spacing and completion design improved production by up to 20% per well compared to the initial development plan.
The complex approach is becoming a new norm for the successful development of unconventional reservoirs because simple analytical models cannot address well interference issues and account for heterogeneity in the rock properties. The presented workflow can be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus to help achieve maximum recovery.