Rate of Hydrate Inhibitor in Long Subsea Pipelines
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This thesis is divided into several parts. The first part deals with hydrate theory and where hydrates form in the gas-and oil-dominated systems. A review of how hydrate plugs is formed and a method for removing hydrate plugs safely is also included.Simplified HYSYS models of the upstream part of Ormen Lange and Snøhvit gas fields on the Norwegian Continental Shelf constituted the basis for answering the second part of the task. Data from private conversations, reports, slide presentations, and other documents were used to create the models.Based on the models, calculations were made on the injection rate and storage capacity of mono ethylene glycol (MEG) on Ormen Lange and Snøhvit. The same models and calculation methods were used to determine injection rates for both methanol (MeOH) and MEG on the same fields. All the results combined with literature were then used to compare the inhibitors properties to determine which one was best suited for use on the current fields. During rate calculations several cases were made to determine which factors have the greatest impact on the amount of inhibitor needed.It was found that hydrates are formed on the pipe wall in gas dominated pipelines, while they are formed in the bulk flow in oil-dominated systems. The heat transfer coefficient and the seabed temperature have great influence on the amount of inhibitor needed. MEG-rate and storage capacity on Snøhvit are very large. Ormen Lange needs a larger inhibitor injection rate than Snøhvit. MEG is better suited than MeOH as an inhibitor of long-distance multi-phase tie-backs such as Ormen Lange and Snøhvit.