The upstream oil and gas process
The oil and gas process is the process equipment that takes the product
from the wellhead manifolds and delivers stabilized marketable products, in
the form of crude oil, condensates or gas. Components of the process also
exist to test products and clean waste products such as produced water.
An example process for
the Statoil Njord floater
is shown on the next
page. This is a
medium-size platform
with one production
train and a production
of 40-45,000 bpd of
actual production after
the separation of water
and gas. The
associated gas and
water are used for
onboard power
generation and gas
reinjection. There is only one separation and gas compression train. The
water is treated and released (it could also have been reinjected). This
process is quite representative of hundreds of similar sized installations, and
only one more complete gas treatment train for gas export is missing to form
a complete gas production facility. Currently, Njord sends the oil via a short
pipeline to a nearby storage floater. On gravity base platforms, floating
production and storage operations (FPSO) and onshore plants, storage a
part of the main installation if the oil is not piped out directly. Photo: Statoil ASA
A large number of connections to chemicals, flares, etc., are also shown.
These systems will be described separately.
Nård main process illustration (next page): Statoil
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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 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.
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 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.
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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.
