Relative permeabilities are well understood for light oils involving stable displacement. However, conflicting arguments have been presented in the literature regarding relative permeabilities for viscous oils. Most nonthermal viscous oil displacements are unstable. Depending on the magnitude of mobility ratio, displacement is influenced by varying degrees of viscous instability, often referred to as fingering. For viscous oils (>500 cp), even a polymer flood must be designed at partially stable conditions (mobility ratio > 1) to maintain an economical processing rate [% pore volume (PV) injected (PVI) per year]. Typically, viscous fingering is difficult to model in full-field simulation because of the large grid sizes used. To design and optimize a partially stable polymer or waterflood, it is critical to correctly upscale the laboratory-generated relative-permeability curves for reservoir simulation. In recent years, such models have been published in the Society of Petroleum Engineers literature. Unfortunately, most of these models require multiple fitting parameters (at least three). In this work, we present a simplified technique that requires systematic change in only one parameter to generate upscaled relative permeability curve for a given viscosity ratio.

Using fine-grid simulations, we show that the flow at high-viscosity ratio is channelized even in a core perceived to be homogeneous at laboratory scale. This happens because of small-scale heterogeneities that are present in every rock. Upscaling averages these fine variations in heterogeneities, causing the grids to be overswept, thus overpredicting recovery. To compensate for this shortcoming, it is recommended to upscale the relative-permeability curves in the simulation model.

对于涉及稳定排量的轻油，相对渗透率是众所周知的。然而，关于粘性油的相对渗透率的文献已经提出了相互矛盾的论点。大多数非热粘性油驱替都是不稳定的。根据迁移率的大小，位移会受到不同程度的粘性不稳定性（通常称为指弹）的影响。对于粘性油（> 500 cp），甚至必须在部分稳定的条件下（流动比> 1）设计聚合物驱，以保持经济的加工速度[每年注入的％孔体积（PV）（PVI）]。通常，由于所使用的网格较大，因此很难在全场模拟中对粘性指法进行建模。为了设计和优化部分稳定的聚合物或注水，正确放大实验室生成的相对渗透率曲线对于油藏模拟至关重要。近年来，这种模型已经在石油工程师协会的文献中发表。不幸的是，这些模型大多数都需要多个拟合参数（至少三个）。在这项工作中，我们提出了一种简化的技术，该技术仅需要系统地更改一个参数即可生成给定粘度比的放大的相对渗透率曲线。

使用细网格模拟，我们显示出即使在实验室规模被认为是均质的岩心中，高粘度比的流体也会被通道化。发生这种情况是因为每个岩石中都存在小规模的异质性。升级将平均这些异质性的精细变化，从而导致网格被过度扫描，从而过度预测了恢复。为了弥补这一缺点，建议放大仿真模型中的相对渗透率曲线。