SPE APOGCE conference preview – Operational Considerations During Gas-Condensate Well Start-up

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Abstract

Gas hydrates are ice-like crystals formed by gas and free water molecules under low temperature and high-pressure condition of the subsea environment. 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 and longer subsea tiebacks are often required to transport hydrocarbons from the wellhead to the production facilities.

Common mitigation measures for hydrate formation and plugging in subsea gas-condensate flowlines include the traditional control methods of injecting hydrate 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. As the water cut increases at the late life of the field production, the conventional method of injecting thermodynamic hydrate inhibitor faces technical, economic and operational limitations. Low dosage hydrate inhibitor on the other hand, do not offer permanent solutions to hydrate inhibition.

This paper goes through an overview of some of the key operational factors i.e., existing field data and field practice to be considered during the design phase of gas-condensate subsea tiebacks. For the design of a subsea tieback where field data of the existing facilities are available, this presents an opportunity to refine the hydrate inhibitor dosing rate through benchmarking with historical data. Two case studies that integrate field experience are presented to illustrate the benefits of applying these operational factors in refining the hydrate inhibition injection during subsea tieback gas-condensate field start-up.

The first case study shows how the shutdown and start-up scenarios typically considered for design are too conservative. Aqueous arrival and fluid temperature downstream of choke was benchmarked, which helped narrow down the shutdown and start-up scenarios to be assessed (Figure 1). As the scenarios considered are now less onerous, MEG injection rate during well start-up can be reduced by 33% and this increases economic feasibility of the offshore gas-condensate field development.