This study identifies challenges for under-inhibition strategies for offshore flowlines transporting gas-dominant fluids with low flow rates to determine the optimal concentration of hydrate inhibitor. The offshore gas fields considered in this study contains four wellheads, two manifolds, and one flexible riser. The distance between the offshore platform and the manifold is about 20 km with the maximum water depth of 250 m. The commercial multiphase flow simulation tool, OLGA, is used to simulate the operation conditions of the gas fields. The liquid holdup, temperature-pressure profiles, and the accumulated amounts of MEG (Mono-ethylene Glycol) with the distance along the pipeline are calculated during the steady state operation. The obtained results present that at least 44 wt% of MEG is required to completely avoid the hydrate formation when the shut-in condition of the flowline is assumed to be 3 °C and 90 bar. The production rate of base case is about 200 MMscfd and it may decrease to 40 MMscfd in the end of the design life. The accumulated amounts of MEG in the flowline is increased, mainly due to the increase in the accumulated liquid holdup in the pipeline when the production rate is decreased. The injected MEG aqueous solution from each wellhead which has relatively higher density than gas and condensates is stayed in the low spot of the pipeline due to the slower liquid velocity. This system is evaluated to identify the possibility of hydrate blockage formation. An experiment using high pressure autoclave is performed to validate the effect of under-inhibition system with MEG and the kinetic performance of MEG. The optimal concentration of THI (Thermodynamic Hydrate Inhibitor) considering the accumulated amounts in the flowline is calculated from the simulation and experimental results.

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