Pipelines and risers

This facility uses subsea production wells. The typical high pressure (HP) wellhead at the bottom right, with its Christmas tree and choke, is located on the sea bed. A production riser (offshore) or gathering line (onshore) brings the well flow into the manifolds. As the reservoir is produced, wells may fall in pressure and become low pressure (LP) wells.

This line may include several check valves. The choke, master and wing valves are relatively slow. Therefore, in the case of production shutdown, the pressure on the first sectioning valve closed will rise to the maximum wellhead pressure before these valves can close. The pipelines and risers are designed with this in mind. Short pipeline distances are not a problem, but longer distances may cause a multiphase well flow to separate and form severe slugs – plugs of liquid with gas in between – traveling in the pipeline. Severe slugging may upset the separation process and cause overpressure safety shutdowns. Slugging may also occur in the well as described earlier. Slugging can be controlled manually by adjusting the choke, or by automatic slug controls. Additionally, areas of heavy condensate may form in the pipelines. At high pressure, these plugs may freeze at normal sea temperature, e.g., if production is shut down or with long offsets. This can be prevented by injecting ethylene glycol. Glycol injection is not used at Njord.

The Njord floater has topside chokes for subsea wells. The diagram also shows that kill fluid, essentially high specific gravity mud, can be injected into the well before the choke.

Production, test and injection manifolds

Check valves allow each well to be routed into one or more of several manifold lines. There will be at least one for each process train plus additional manifolds for test and balancing purposes. In this diagram, we show three: test, low pressure and high pressure manifolds. The test manifold allows one or more wells to be routed to the test separator. Since there is only one process train, the HP and LP manifolds allow groups of HP and LP wells to be taken to the first and second stage separators respectively. The chokes are set to reduce the wellhead flow and pressure to the desired HP and LP pressures respectively.

The desired setting for each well and which of the wells produce at HP and LP for various production levels are defined by reservoir specialists to ensure optimum production and recovery rate.