New Dual Porosity Thermal Simulator for Steam Injection in Naturally Fractured Reservoirs
A distinguishing characteristic of naturally fractured reservoirs is that fractures have high permeability with very small pore volume while the matrix blocks between fractures have low permeability with large pore volume. Because of the extreme differences in properties between the two media, fluids tend to channel through fractures to production wells, leaving much oil behind in relatively low-permeability matrix blocks, typically resulting in very low oil recoveries. One method proposed to increase recovery from naturally fractured reservoirs is steam injection. Heat transfer, imbibition, gas generation, and other mechanisms have the potential to expel fluids from matrix blocks at sufficient rates and in sufficient quantities to be feasible. The objective of this study is to develop an accurate 3D three-phase dual porosity thermal simulator to study steam injection processes in naturally fractured reservoirs. A new dual porosity thermal simulator, UTDUTHM, has been developed for modeling steamflooding in naturally fractured reservoirs. An implicit algorithm is used to solve the equations for the combined fracture/matrix system. The new simulator can model reservoirs with vertical fractures, horizontal fractures and their combination by appropriate subgridding of matrix blocks. The new simulator can also handle gas generation in the matrix, a capability not found in other simulators. A new set of correlating equations for saturated steam/water properties has also been developed for inclusion in the simulator. These correlations are better than those previously reported in terms of accuracy, continuity, range of applicability, and simplicity. The new simulator is verified by test runs against a commercial simulator, STARS, and a research simulator, UTDUAL. Excellent agreement is achieved. The procedure for implementing a dual porosity model was also implemented into UTCHEM, a chemical flooding simulator developed at The University of Texas at Austin. This implementation shows that the method can easily extend an existing single porosity simulator to a dual porosity simulator with very few changes to the existing code.