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Compositional Simulation With Capillary Pressure For Oil Production From Tight Formation
- Publisher: European Association of Geoscientists & Engineers
- Source: Conference Proceedings, ECMOR XVI - 16th European Conference on the Mathematics of Oil Recovery, Sep 2018, Volume 2018, p.1 - 19
Abstract
The influence of porous media on phase behaviour is a topic of interest driven by the shale gas boom because many field observations suggest the saturation pressure in tight shale formation may change dramatically. There has acmally been such a concern for other low permeable tight formation, such as the Lower Cretaceous (LC) formation in the Danish North Sea. for decades. However, there is no consensus on the extent of the influence and also little analysis of the issue in the open literature.
The integration of the capillary pressure effect on phase equilibrium into a reservoir simulator is not entirely trivial. The modifications needed will depend on the implicitness level of the numerical model of the simulator, with an increasing complexity as the level increases. In general, the standard thermodynamic routines should be modified to handle the cases where the liquid pressure becomes negative as a result of the high capillary pressures. The flash and stability analysis routines involving capillary pressure need an efficient implementation to maintain the robustness and speed needed during simulation. For the linear solver, the derivatives of the selected pressure models must be obtained and implemented in a consistent way to avoid differences between the capillary pressure model used for phase equilibrium, and the capillary pressure used for the flow equations. A fully implicit compositional simulator was modified by adding the influence of the capillary pressure into the phase behavior. The customized tool served to investigate a natural depletion scenario of a shale reservoir and a tight reservoir from the LC formation in the Danish North Sea using different capillary pressure models.
In general, low to moderate deviations in the cumulative oil production, pressure profiles, and saturation profiles were observed for the cases with effective pore sizes less than 40 nm. For the producing gas oil ratio considerable deviations were found even for pore sizes close to 100 nm. Moreover, a pore size distribution was compared to the fixed pore size assumption in the capillary pressure model. A variable pore size capillary pressure model shows similar results to those obtained at fixed capillary radius. In the long term, the results are closer to effective pore size calculated at the bubble point given by the maximum value of the pore size distribution.