Improving coarse-scale simulation models with a dual-porosity dual-permeability upscaling technique and a near-well approach

Abstract

In the management of an oil field, the creation of a highly detailed fine-scale model to properly represent the key reservoir heterogeneities is important. This model better represents the main reservoir features but remains a significant challenge for dynamic reservoir simulations with impractically high computational costs, even for single numerical simulation runs. Therefore, the scaling up of a highly detailed model is a crucial step in reservoir engineering studies to enable field-scale simulation runs within a time-frame compatible with the needs of the industry. Upscaling must be carefully performed because it can introduce significant errors and bias to the numerical models due to truncation errors and the smoothing of sub-grid heterogeneities.This work focuses on improving the representation of small-scale heterogeneities in coarse models. It expands the dual-porosity and dual-permeability upscaling technique proposed (Rios et al., 2020) to be applied to 3D highly heterogeneous systems. Specific near-well treatment is considered to improve the overall flow distribution in the wells; with this procedure, the coarse model better represents the production and injection profiles throughout the wells. Therefore, the final coarse-scale model can represent the main reservoir heterogeneities and possible preferential pathways, while improving the definition of the wells’ productivity and injectivity indices.The proposed upscaling technique is applied to different reservoir simulation models with immiscible water flooding in 3D evaluations. Our approach was validated by two case studies: SPE-10 and a field-case heterogeneous reservoir with karst structures. The focus is to demonstrate that the division of the porous media into primary and secondary systems improves capillary and gravity representation of coarse models in 3D applications, while the near-well upscaling makes the flow distribution in the wells in agreement with the fine-scale solution. The resulting coarse-scale dual-permeability models are much faster than the reference fine models (between 0.025% and 1.5% of the fine-scale simulation time), more accurate than the traditional flow-based upscaling results, and can better reproduce the fine-scale responses in different upscale ratios (from 25 up to 1 700).