Retrograde Condensation in Gas Reservoirs from Microporous to Field-Scale Simulation
本文介绍了一种从数字岩石物理尺度到现场尺度模拟气-油相对渗透率的方法。研究结果表明，实验室测试得到的气-油相对渗透率曲线与通过粗化处理得到的结果存在差异。粗化过程能够更准确地代表凝析油的流动性，从而减少气相的损害。本文的研究强调了在气藏开发项目决策中，纳入更现实的输入到数值模拟中以提高决策的重要性。
CMG软件应用情况：
CMG软件在本文中被用于进行多相流的数值模拟。具体来说，使用了CMG包中的GEM（Compositional and Unconventional Simulator）模拟器，以及CMOST（Intelligent Optimization and Analysis Tool）自动化工具进行储层模拟。这些工具使得研究人员能够模拟和分析气藏中流体的流动行为，并进行相对渗透率曲线的调整和优化。
Abstract
Hydrocarbon fields that contain non-associated gas, such as gas condensate, are highly valuable in terms of production. They yield significant amounts of condensate alongside the gas, but their unique behavior presents challenges. These reservoirs experience constant changes in composition and phases during production, which can lead to condensate blockage near wells. This blockage forms condensate bridges that hinder flow and potentially decrease gas production. To address these challenges, engineers rely on numerical simulation as a crucial tool to determine the most effective project management strategy for producing these reservoirs. In particular, relative permeability curves are used in these simulations to represent the physical phenomenon of interest. However, the representativeness of these curves in industry laboratory tests has limitations. To obtain more accurate inputs, simulations at the pore network level are performed. These simulations incorporate models that consider alterations in interfacial tension and flow velocity throughout the reservoir. The validation process involves reproducing a pore network flow simulation as close as possible to a commercial finite difference simulation. A scale-up methodology is then proposed, utilizing an optimization process to ensure fidelity to the original relative permeability curve at a microporous scale. This curve is obtained by simulating the condensation process in the reservoir phenomenologically, using a model that captures the dependence on velocity. To evaluate the effectiveness of the proposed methodology, three relative permeability curves are compared based on field-scale productivities and the evolution of condensate saturation near the wells. The results demonstrate that the methodology accurately captures the influence of condensation on well productivity compared to the relative permeability curve generated from laboratory tests, which assumes greater condensate mobility. This highlights the importance of incorporating more realistic inputs into numerical simulations to improve decision-making in project management strategies for reservoir development.
Keywords: gas condensate reservoirs; reservoir simulation; upscaling; relative permeability curves; microporous scale
作者单位
巴西石油公司
