The development of unconventional shale gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18 to 24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical-flow simulation model to simulate these production conditions.
This model mimics the impact of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural fracture permeability as well as reduction in hydraulic fracture conductivity due to proppant crushing, deformation, embedment, and fracture-face creep. Matrix permeability evolutions, considering the conflicting effects of non-Darcy flow, and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic fracture planar geometries are then obtained using a finite element method (FEM) scheme.
A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial gas cumulative production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher and higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic fracture conductivity. The results conclude that ignoring impacts of any of the above phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale gas reservoirs can yield substantially higher ultimate recovery.
The model is fully versatile and allows modeling and characterization of all profoundly different (on a petrophysical level) shale gas formations as well as proppant materials utilized for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic fracture design, for fine-tuning production history matching, and, especially, as a predictive tool for pressure drawdown management.