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In offshore gas field development, mono-ethylene glycol (MEG) has been a robust choice for hydrate inhibition in subsea production systems and flowlines. Once hydrate blockage forms, considerable efforts and loss of production are inevitable to remediate the hydrate blockage. Therefore, the industry has been relying on the injection of considerable amount of MEG which is used to be over-estimated based on the worst operation condition: shut-in pressure, sea water temperature, and maximum water cut. However, during steady-state operation, the range of operation condition might be different from the worst condition and for shut-in condition; the sufficient cool down time for hydrate formation could be guaranteed with appropriate insulation. More thorough analysis is required using the multiphase flow simulator. Furthermore, recent studies suggest that MEG may have kinetic hydrate inhibition (KHI) performance. An under-inhibited system where an insufficient amount of THI is present might be possible to avoid hydrate blockage issues and to reduce the operating cost for the injection of large amount of MEG. In this work, the evaluation of under-inhibited system is carried out to identify the possibility of hydrate blockage formation using multiphase flow simulation tool, OLGA, and accompanying hydrate kinetics experiments. The temperature and pressure profiles along with the liquid holdup are estimated during the steady-state and transient operation of offshore gas fields. The optimized concentration of MEG is calculated form the simulation results. Then the under-inhibition concept is evaluated from hydrate kinetics experiments to investigate possible reduction of MEG injection rate. The obtained results suggest that at least 30% of MEG injection can be reduced using the kinetic inhibition performance of MEG in under-inhibited system, which in turn increase economic feasibility of offshore gas fields. More advanced strategy to manage hydrate blockage in offshore field developments would be developed based on the optimization of the injection rate in under-inhibited system. IntorductionOffshore flowlines transporting hydrocarbons have to be operated very carefully to avoid the formation of gas hydrates as they are considered the largest concern for flow assurance engineers. For many years industrial practice to prevent hydrate-related risks is the injection of thermodynamic inhibitors (THI), commonly methanol or mono ethylene glycol (MEG), at the wellhead based on the simulated hydrate equilibrium conditions. However as the search for petroleum resources moves into deeper and colder waters further offshore, these conventional techniques are becoming uneconomic due to higher injection rate of inhibitors and accompanying operational issues such as logistics and storage requirement. Hydrate prevention strategies are now moving toward hydrate risk management, which allows hydrates to form, but delay the formation significantly or prevent the complete hydrate blockage. Kinetic hydrate inhibitors (KHIs) are water-soluble po...