Single Point Gas Lift (SPGL) is preferred in subsea wells due to its certain advantages over conventional completion with unloading valves in meeting the aim for no intervention, pressure barrier requirements etc. Current paper presents a flow assurance study of an SPGL system in a deepwater field in India. The development strategy envisages clustered subsea wells with common flowlines connected to an FPSO about 12 km away.Requirement of gas lift is envisaged from mid-life due to expected depletion in reservoir pressures and increase in water cut. Subsea gas lift in deepwater environment typically requires higher injection pressure to lift from desired injection depth. The gas lift, flowline and riser system is expected to operate over a wide range of conditions in terms of fluid composition, pressure and flow rates. Optimum design and operation of an SPGL system under such conditions is a challenge. Integrated dynamic modelling from down hole to host facility at the pre-FEED stage can provide valuable inputs for system design and operability.The impact of various gas lift parameters like orifice size, setting depth, kick off pressure and operating injection pressure on the system has been studied. The field is having waxy crude with high pour point of 36°C with gelation propensity during long shut downs. The paper also brings out the operability windows during start up, turndown, shutdown, restart etc. and their impact on topside design. Transient modelling has been used to invetigate threats to system integrity due to high velocities of fluid through orifice, low temperature limits due to JT cooling, pressure surges into the production line resulting in large slugs arriving at FPSO. Slugging in riser may lead to process shut downs due to the pressure and rate variations resulting in loss of production. Design and optimization of the SPGL system is also aimed at increasing total production by avoiding process shut downs due to well instability and pipeline slugging.

Subsea flow lines in deep water are typically exposed to high pressure and low temperature conditions which can create problems due to formation of gas hydrate. The gas hydrate formed can plug the flow lines causing not only loss of production, but may also create severe safety and environmental hazard. Moreover, dissociation of these plugs may take weeks or even months. Assessment of the hydrate formation potential during both steady is therefore an essential part of field development studies. The paper presents a case study of a gas field located in KG basin of India which was brought on production in 2018. The objective of the study was to assist the on-site team on issues related to hydrate inhibition during ongoing initial start-up operation and assess the arrival time of rich MEG in the onshore plant in view of turn down flow conditions during commissioning. The study also demonstrates how the transient simulations helped to monitor progress, identify and respond quickly to address the challenges during initial start-up operation of the deepwater gas field in Indian east coast. It emphasizes the need for accurate estimation of rich MEG arrival time and the minimum required gas flow rate from the subsea wells to ensure timely return of rich MEG to the onshore plant in order to avoid disruption in hydrate inhibition in the subsea system.