Industry has been relying on the injection of considerable amount of Mono Ethylene Glycol (MEG) for hydrate inhibition in petroleum production systems, especially in offshore gas wells. However current design of MEG injection and regeneration systems is used to be over-sized as it consider the worst operation conditions such as shut-in pressure, ambient seawater temperature, and maximum water production rate. Recently, multiphase simulation tools have been widely used to estimate the temperature and pressure profiles of offshore flowlines for both steady-state and transient operations, which would be useful to better estimate the worst operation conditions of offshore flowlines. Moreover, recent research [1] results on synergistic inhibition suggest that MEG injection rate might be reduced below the required concentration by adding small amount of Kinetic Hydrate Inhibitors (KHI). Here we carried out an experiment to validate the effect of using synergistic inhibition with MEG and KHI on the design of MEG injection and regeneration systems for offshore gas wells. The studied concentration range of MEG is up to 30 wt% and PVCap concentration is between 0.1 and 1.0 wt%. Synthetic natural gas composed of C1 90 mol%, C2 6 mol%, C3 3 mol%, and nC4 1 mol% is used for all experiments. High pressure autoclave system mounted with overhead stirrer is used with constant cooling method. Furthermore, multiphase simulation tool, OLGA, is used to simulate the operation conditions of offshore gas fields. The amount of condensed water and temperature-pressure profiles during extended shut-in period are calculated for 10 km offshore flowlines. The obtained results suggest that the injection rate of MEG can be reduced about 50% by adopting synergistic inhibition and multiphase flow simulation, which would reduce the CAPEX and OPEX for MEG. Moreover the reduced size of MEG regeneration unit would improve weight and space management on platform topside.

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