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Fracturing fluid may jeopardize the production of hydraulically fractured tight gas formations. Because capillary forces act stronger in low-permeability formations, the invaded fracturing fluid is harder to remove. The increase of water saturation around the fractured well affects the mobility of the gas phase, particularly in tight formations where the gas relative permeability declines strongly when water saturation increases. This damage might greatly reduce the gas production in a very long cleanup period. This paper presents numerical simulation techniques to account for formation damage with both a near-well model and a full-field model for fractured wells in tight formations. For the full-field model, the skin determined from an inversion is suitable for long-term production simulations, and a sector model can be used to update the well skin through a coupled modeling so that the full-field model can be used correctly over the whole life of the project. [ABSTRACT FROM AUTHOR]

Reservoir simulators remain essential tools for improved reservoir management in order to optimize hydraulic fracturing design in unconventional low permeability reservoirs. However, the commonly-used simulator requires too much computational efforts for the description of local phenomena in the vicinity of the hydraulic fractures, and is practically infeasible for field applications, due to large number of gridblocks involved in a full-field simulation with many multi-fractured complex wells. Therefore, coarse grid simulations have been widely used, but the techniques for the coarse grid simulation of fractured wells need to be improved. In this paper, we present efficient numerical methods to handle both long-term well performance and transient behavior simulations for hydraulic fractured wells in unconventional reservoirs with a coarse grid. To simulate correctly the long-term behavior, transmissibilities around the fracture and the connection factor between a fractured block and the fracture are computed, based on a (pseudo)-steady-state near-fracture solution. This approach provides not only an accurate long-term well production calculation, but also a correct pressure distribution in the near-fracture region. In unconventional reservoirs, the transient effects cannot be ignored, due to the very low reservoir permeability and near-well/near-fracture physical processes such as fracturing fluid induced formation damage. In order to handle the transient effect, the coupled modeling technique is used, and its efficiency is demonstrated with a tight-gas reservoir. [ABSTRACT FROM AUTHOR]

Connected porosity and dry gas permeability at 5 MPa hydrostatic stress have been measured for thirteen tight gas sandstone samples originating from a Rotliegend sandstone reservoir in Germany. The samples have then been preserved into hermetic chambers at fixed relative humidity (RH) values, until mass (and water saturation level) stabilisation. This allows a first characterisation of pore size distribution showing that most of the pore network is constituted with pores with entrance radii greater than 50 nm. The relative gas permeability was then measured for different water saturation and hydrostatic stress (up to 60 MPa). The analysis of the results has allowed us to identify the limiting conditions (water saturation and hydrostatic stress) for the apparition of a hydraulic cut-off, also called the “permeability jail”. Dry gas permeability at low confining pressure (5 MPa) has appeared to be a good indicator of the sensitivity of a sample to both hydraulic stress and liquid saturation. This gives an efficient tool to predict the global behaviour of the gas reservoir despite its heterogeneity with a single gas permeability measure. [ABSTRACT FROM AUTHOR]