Oil and gas production handbook - Process Control and ...

4.1 Manifolds and Gathering
4.1.1 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 bottom. 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 case of production shutdown, pressure before the first
closed sectioning valve 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 is not a problem, but longer distances may cause 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 also
cause overpressure safety shutdowns. Slugging might also occur in the well as
described earlier. Slugging may be controlled manually by adjusting the choke, or
with automatic slug controls. Further, areas of heavy condensate might 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 may be prevented by injecting
ethylene glycol. Glocol injection is not used on 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.
4.1.2 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 the 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 wells produce at HP and LP for various
production levels are defined by reservoir specialists to ensure the optimum
production and recovery rate.
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