Oil and gas field application of hydrate kinetics modeling

In the offshore environments, hydrocarbons are extracted from the reservoir and transported through subsea flowlines in which ambient temperatures can be as low as 0°C. The production systems must be designed to manage potential gas hydrate formation which can lead to pipe blockages. This thesis assessed the applicability of coupling multiphase Oil and Gas Simulator (OLGA) models with a hydrate prediction model (Colorado School of Mines Hydrate Kinetics) as a tool to better understand the risk with hydrate blockages. This tool would be more realistic than the current method of using hydrate dissociation curves, which can tend to be conservative. Real oil field data is used to validate the coupled model results. Two example cases were analyzed in this work, 1) hydrate blockage had formed and 2) conditions present for hydrate risk. In the first case it was found that the sub cooling (the difference between the flowline and hydrate formation temperatures) assumption may have been conservative, and the model did correctly predict the most likely location of the blockage based on vol% of formed hydrate. In the second case the model confirmed that there was little hydrate formed and in reality there were no signs of blockages upon restart of the flowlines. Overall the analyses showed that the coupled model can be a useful tool for hydrate prediction. Modifications were proposed to improve the modelling predictions by incorporating the impact of the sub cooling and its stochastic nature within the model. Another potential improvement could be integrating compositional tracking in the model to constantly generate hydrate curves in each volume section of the models based on the expected fluid content. It is also proposed to further the understanding of water/oil emulsion in the kinetics of hydrate and hydrate plug formation.