Dynamic simulation results of thermal and hydraulic performance of the Gemini deepwater subsea production system of three wells and two pipelines are presented. This paper shows how transient models such as OLGA are used to predict and alleviate the flow assurance problems associated with deepwater production of a gas condensate subsea system. The paper addresses the importance of flow modeling before and during production. The results of this study can be applied to the design of new deepwater production systems in order to maintain flow assurance, and to safely operate a subsea pipeline/riser system. Comparisons of predictions with the measured production data are presented.


The Gemini subsea development1,2,3,4 was brought on stream in June 1999, sixteen months after project sanction. Suites of dynamic simulation runs were made at various conditions before and after the field went on production. The simulations cover both steady state and transient flows inside the wellbore and the pipeline system. The paper addresses how transient software, like OLGA, can be used effectively to minimize flow problems, to ensure sound operability before and during production, and to aid in problem diagnosis during operations.


The Gemini Field is located in Mississippi Canyon Block 292 (MC 292), approximately 90 miles southeast of New Orleans in a water depth of 3,400 ft. The field was discovered in 1995 with the drilling and subsequent testing of MC 292 Well No. 1. The field is part of the three-block Gemini prospect in the Mississippi Canyon area, MC 247, MC 291, and MC 292. The field and was developed by Texaco as operator with 60% working interest and partner Chevron with remaining 40% working interest.

The Gemini Field is a subsea development tied back to the Viosca Knoll (VK) 900 Platform located 27.5 miles northwest of MC 292. Chevron is operator of VK 900 with 75% working interest and Texaco holds the remaining 25%.

The subsea development1 consists of three production wells tied into a 4-slot cluster manifold, with each well located approximately 50 ft from the manifold. The manifold has two headers connected together via a pigging loop. Rigid pipeline jumpers connect the manifold to dual 12- flowlines that transport the produced fluids 27.5 miles to the host platform. The subsea system is controlled from the host via an electrohydraulic control system through a steel tube umbilical with electrical conduits. Fig. 1 illustrates the field arrangement.

The manifold and well functions are controlled from VK 900 using a multiplexed electro hydraulic control system. The manifold has two headers connected via a pigging loop with an actuated pigging/isolation valve. Each well is connected to both headers via actuated manifold isolation valves, providing flexibility to direct a well into either flowline. Tree-mounted subsea chokes control flow rate from individual wells into the manifold. Each manifold header is connected to a 12-inch flowline via rigid steel pipe jumpers.

Dual 12-inch uninsulated flowlines transport the produced fluids to the host platform.

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