During the extraction of deep terrestrial and deep-sea natural gas reservoirs, changes in temperature and pressure in the production well can lead to the formation of natural gas hydrates in the wellbore, blocking the flow channel and posing significant challenges to gas well production and management. To address this, we have established a mathematical model to describe the flow characteristics of hydrate multiphase flow systems in vertical pipelines. We employ Computational Fluid Dynamics simulations coupled with a Population Balance Model to predict the formation and breakage of hydrate particles, taking into account mechanisms such as particle collision, aggregation, and breakage. We have analyzed the impact of gas flow rate, slurry flow rate, and hydrate volume fraction on hydrate particle size in the pipeline. The results indicate that hydrate particles tend to aggregate at the bottom of the pipeline. The larger the hydrate slurry flow rate, the faster the hydrate particle size increases. As the gas phase flow rate increases, the increase in particle size slows down. High gas phase flow rates help form turbulence to suppress particle aggregation, velocity fluctuations contribute to particle aggregation growth, and stable velocities facilitate particle decomposition. The increase in hydrate volume fraction significantly increases the diameter of hydrates in the center of the pipeline. The research results can provide suggestions for wellbore blockage caused by hydrate particle aggregation on the wall and a decline in gas well production during actual natural gas well production.
Read full abstract