Speaker
Description
With the sharp decline in conventional geo-energy resources, increasing attention has been paid to tight oil resources. Relative permeability, which characterizes the oil–water two-phase flow behavior, is a vital parameter for the efficient development of tight oil reservoirs. Fluid flow in tight reservoirs exhibits unique phenomena, including near-surface viscosity effects, boundary layers, flow slippage, and dynamic wettability. Existing relative permeability models only partially account for these effects, which reduces their reliability. In this study, a novel relative permeability model is developed with considering these effects, and its reliability is verified through comparison with experimental data. The influences of the unique flow phenomena on relative permeability are then systematically analyzed. The results show that as oil viscosity increases, the oil film thickness also increases, leading to a reduction in oil-phase flow capacity and a relative enhancement of water-phase flow capacity. Furthermore, the water-phase relative permeability without considering near-surface viscosity effects is lower than that with such effects included, and the difference between the two cases becomes more pronounced with increasing oil viscosity. The water-phase relative permeability increases with increasing effective driving pressure, while irreducible water saturation decreases; higher effective driving pressures correspond to a wider two-phase flow region. As the static contact angle increases, water-phase relative permeability increases, whereas oil-phase relative permeability decreases. A reduction in dynamic wettability results in a sharp decrease in water-phase relative permeability and a slight decrease in oil-phase relative permeability. This work provides valuable insights into the development of tight oil reservoirs.
| Country | China |
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