In the oil and gas production industry, it is well known that formation of hydrate blockages can cause substantial economic impact in terms of deferred production and the costs of remediation. Considering these financial implications and to avoid any potential safety concerns during a hydrate remediation, most often operating companies design and operate fields on a hydrate management philosophy of complete avoidance of hydrate formation. In the last few years, however, a shift in the hydrate management philosophy is being observed as discussed in the publications of Creek et al., 2011 and Kinnari et al., 2015, to cite a few. Due to the developments shifting towards more extreme environments, hydrate management philosophy is shifting from complete avoidance to risk management.

This paper discusses the evolution of hydrate management philosophy of a dry tree facility in the Gulf of Mexico. During steady state production, the fluids flow at temperatures outside the hydrate envelope. The hydrate management strategy following a shutdown is to displace (bullhead) the riser tubing with dead oil within the cooldown time (time required for the fluids to enter hydrate forming conditions after a shutdown). However, due to the dry tree configuration, low liquid rates and insulation performance, the cooldown time is short for these high water cut wells. Using gas lift to boost production further decreases the predicted cooldown time to less than an hour making it operationally difficult to complete hydrate safe out measures within the design cooldown time. A few tests conducted in the field to identify a realistic time available after shutdown, along with a few historical instances during which the hydrate safe out measures could not be completed within the cooldown time, have indicated that there exists a range of water cut (WC) and GOR (Gas to oil ratio) within which the system was restarted without a hydrate blockage. This paper describes how a combination of industry standard predictive tools coupled with field observations is shaping the hydrate management philosophy of this field, by operating within conditions that can form hydrates but do not lead to blockage. The paper also describes two hydrate blockage instances that occurred when the operating conditions were outside the identified hydrate blockage limit reinforcing that the WC and GOR of the fluids have a strong influence on the hydrate blockage risk.

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