Deepwater developments such as the one depicted in Fig 1 rely on production flowlines to carry raw, unprocessed reservoir fluid, called full wellstream (FWS) production, from wells to production facilities. As the search for reserves has taken the petroleum industry into deeper water and colder environments, the feasibility of producing FWS may become questionable due to the possibility of hydrates in the flowlines. The lower capital investment of FWS production flowlines is also attractive in shallower water. Even here, the risk of hydrates raises questions of feasibility in shallow, cold water environments.

When hydrates form in production streams, they can pose problems with economic consequences. Field experience indicates that hydrates occasionally obstruct production flowpaths (Ref 1 and 2). In the event of a partial obstruction, hydrate formation is a nuisance, slowing the production stream until the obstruction can be removed. And, in the event of a complete obstruction, full stoppage of production can last for weeks while mobilizing equipment to remove the obstruction. The cost of the mobilization on top of the lost revenue from the interruption in production can have serious economic repercussions.

Figure 2 is a hydrate formation curve for a crude oil reservoir fluid with a gas-oil-ration (GOR) of 1000 SCF/STB (177 SCM/STCM). Note that increasing pressure or decreasing temperature favours hydrate formation. The worst exposure to hydrate formation usually is associated with a prolonged interruption in production, when the pressure rises to shut-in wellhead pressure (SIWHP) and the contents of the flowline cool to seabed temperature. While hydrate formation will be more likely in deep water, even at typical seabed temperatures in the North Sea (40-45°F or 4-7°C), hydrate formation is possible.

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