The BP King West oil well, located in 5400 feet of water in the Gulf of Mexico, is a 2.3 mile tie back to a 17 mile dual active heated King flowline. This heated flowline, receives throughput from two other BP King oil wells, and produces to the Marlin tension leg platform located in 3200 feet of water.

Recent reservoir studies predicted a higher water cut than originally anticipated during project sanctioning. Thus, a project was executed to evaluate if the existing hydrate management strategy, which relies on the crude’s non-plugging tendencies (contains natural surfactants that act as anti agglomerant), is still adequate or any modifications in operating procedures or facilities were required.

Transient simulations were performed to evaluate if hydrates can be prevented by modifying the operating procedures prior to extended shutdowns and during cold restarts. Experimental work was conducted to confirm the non-plugging hydrate characteristics of King West crude and to determine maximum water cut above which the characteristic no longer holds.

Transient simulations showed that water flow back by gravity and gas injection could not displace all the water from the King West flowline; thus should not be used as preventive measures. The experimental work confirmed non-plugging hydrate characteristics up to 25% water cut. Since the recent subsurface simulations predict maximum water cut just slightly above 25%, King West hydrate management can still rely on the non-plugging hydrate characteristics of its crude.

You can access this article if you purchase or spend a download.