Gas hydrates are ice-like crystals formed by gas and water molecules under low temperature and high-pressure conditions. Avoiding the formation of hydrate plugs is one of the critical tasks that continuously challenges oil and gas operators, especially as oil and gas operations move into deepwater reserves. Common mitigation measures for hydrate formation and plugging include the traditional control methods of injecting thermodynamic inhibitor that assure the operational conditions are outside the hydrate risk region. However, inhibitor injection rates are typically designed based on the worst operating conditions (i.e., maximum pressure and minimum temperature) with significant safety margin. During transient operation such as well start-up, the risk of hydrate formation is higher compared to normal operation and requires significant volume of hydrate inhibitor. This paper presents two case studies that integrate field experience into design to optimize design scenarios for hydrate prevention during gas-condensate well start-up. The first case study shows how the shutdown and start-up scenarios typically considered for design are benchmarked with historical data to avoid unrealistic over-conservatism when creating design scenarios for well start-up. By benchmarking with historical data, the MEG injection rate is able to be reduced by 30%, which in turn increases economic feasibility of the offshore gas-condensate field development. In the second case study, the hydrate inhibitor rate was reduced by 50% by adopting current field practice into design and using state-of-the-art hydrate kinetic modelling to determine the likelihood of hydrate formation and the transportability of hydrates in flowlines. Combining field experience into design reduces constraint to the hydrate inhibitor distribution system, optimizes usage of topside facilities and aids in the development of hydrate management strategy for the field as a whole.