The results of parametric studies of two naturally fractured lenticular tight gas reservoirs, Fluvial E-1 and Puludal Zones 3 and 4, of the U.S. Department of Energy Multi-Well Experiment (MWX) site of Northwestern Colorado are presented and discussed. The three-dimensional, two-phase, black oil reservoir simulator that was developed in a previous phase of this research program is also discussed and the capabilities further explored by applying it to several example problems. The simulation studies lead to the conclusion that 1) at early times the reservoir performance does not depend on lenticularity; 2) the initial reservoir performance does not depend on natural fracture concentration, although at later times the performance predictions of systems with lower natural fracture concentrations begin to fall below the ones with higher concentrations; 3) porosity change with time and pressure leads to double performance prediction reversals when comparing gas flow rates and cumulative gas production from naturally fractured and non-naturally fractured tight gas reservoirs; 4) the assumption of zero capillary pressure in the fractures can lead to erroneous predictions in the simulation of naturally fractured tight gas reservoir performance; and 5) the simulator developed in a prior phase of this project is capable of handling a reservoir block that is blanket sand, lenticular, completely fractured, partially fractured or completely unfractured and is amenable to an anisotropic heterogeneous reservoir whether the reservoir is fractured or not.

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