One of the major challenges in fracturing low permeability/tight/unconventional gas formations is the loss of frac water and well productivity due to fluid entrapment in the matrix or fracture. Field results have indicated that only 15-30% of the frac fluid is recovered at the surface after flow back is initiated. Past studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped due to the high capillary pressure in the matrix. Significant efforts have been made in the past to understand the impact of liquid blocking in hydraulically fractured conventional gas wells. Numerous remediation measures such as huff and puff gas cycling, alcohol or surfactant based chemical treatments have been proposed to reduce fracture face damage. However, when considering hydraulic fractures in unconventional reservoirs horizontal wells, the fluid may also be trapped within the fracture itself and may impact the cleanup as well as productivity. This study shows that under typical gas flow rates in tight / shale gas formations, liquid loading within the fractures is likely to occur. Most of the previous simulation studies consider a 2D reservoir model and ignore gravity, considering the high vertical anisotropy (or extremely low vertical permeability) in these tight reservoirs matrix. However, this study presents the results of 3D simulations of liquid loading in hydraulic fractures in horizontal wells, including gravity and capillary pressure effects. Both CMG IMEX and GEM have been used to study this phenomenon in dry and wet gas cases. The impact of drawdown, fracture and reservoir properties on liquid loading and well productivity is presented. Results show that low drawdown, low matrix permeability or low initial gas rates aggravate the liquid loading problem inside the fracture and thereby impact the cleanup and gas productivity during initial production. A clear understanding of the phenomena could help in selection of optimal production facilities and well profile. / text

Various models featuring horizontal wells with multiple induced fractures have been proposed to characterize flow behavior over time in tight gas and shale gas systems. Currently, there is little consensus regarding the effects of non-ideal fracture geometries and coupled primary-secondary fracture interactions on reservoir performance in these unconventional gas reservoirs. This thesis provides a grid construction tool to generate high-resolution unstructured meshes using Voronoi grids, which provides the flexibility required to accurately represent complex geologic domains and fractures in three dimensions. Using these Voronoi grids, the interaction between propped hydraulic fractures and secondary "stress-release" fractures were evaluated. Additionally, various primary fracture configurations were examined, where the fractures may be non-planar or non-orthogonal. For this study, a numerical model was developed to assess the potential performance of tight gas and shale gas reservoirs. These simulations utilized up to a half-million grid-blocks and consider a period of up to 3,000 years in some cases. The aim is to provide very high-definition reference numerical solutions that will exhibit virtually all flow regimes we can expect in these unconventional gas reservoirs. The simulation results are analyzed to identify production signatures and flow regimes using diagnostic plots, and these interpretations are confirmed using pressure maps where useful. The coupled primary-secondary fracture systems with the largest fracture surface areas are shown to give the highest production in the traditional "linear flow" regime (which occurs for very high conductivity vertical fracture cases). The non-ideal hydraulic fracture geometries are shown to yield progressively lower production as the angularity of these fractures increases. Hence, to design optimum fracture completions, we should endeavor to keep the fractures as orthogonal to the horizontal well as possible. This work expands the current understanding of flow behavior in fractured tight-gas and shale-gas systems and may be used to optimize fracture and completion design, to validate analytical models and to facilitate more accurate reserves estimation.