Page 257 - Hydrocarbon

244 Well Completions

surface facilities from the variations in tubing head pressure, and the choke size is
selected to create critical flow which maintains a constant downstream pressure.
Initially, a small orifice will be required to control production when the reservoir
pressure is high. As the reservoir pressure drops during the producing lifetime of the
field, the choke size will be adjusted to reduce the pressure drop across the choke,
thus helping to sustain production. The operating pressure of the separators may also
be reduced over the lifetime of the field for the same reason. In fact, the linkage from
the reservoir to the facilities continues down the pipeline – especially for gas fields.
A high separator pressure will put a backpressure on the tubing and hence restrict
production. However it will also make it easier to pump or flow the fluids through
the pipeline. There will be an optimum separator pressure that balances these issues
and this balance will change as the field matures.
The end of field life is often determined by the lowest reservoir pressure which
can still overcome all the pressure drops described and provide production to the
stock tank. As the reservoir pressure approaches this level, the abandonment
conditions may be postponed by reducing some of the pressure drops, either by
changing the choke and separator pressure drops as mentioned, or by introducing
some form of artificial lift mechanism, as discussed in Section 10.8.
In a gas field development, the recovery factor is largely determined by how low
a reservoir pressure can be achieved before finally reaching the abandonment
pressure. As the reservoir pressure declines, it is therefore common to install
compression facilities at the surface to pump the gas from the wellhead through the
surface facilities to the delivery point. This compression may be installed in stages
through the field lifetime. As gas rates decline, it might also be necessary to alter the
tubing size to avoid unstable flow and liquid loading problems – the consequence
of operating with too large a tubing size for the gas rates, that is essentially operating
to the left hand side of the TPR minima.

10.6. Well Completions

The conduit for production or injection between the reservoir and the surface
is the completion. This is commonly split into the ‘lower completion’ or ‘reservoir
completion’ for the section across the reservoir interval and the ‘upper completion’
or ‘tubing completion’ for the section above the reservoir through to the wellhead.
There are a number of options for both the lower and upper completion.
Options for the lower completion are shown in Figure 10.16, whilst upper
completion options are shown in Figure 10.20.
Each of these five main reservoir completion options has its advantages and
disadvantages, but all are in common use in various locations around the world. The
barefoot completion is the simplest and cheapest. The drilled reservoir section is left
as openhole and nothing is installed across the reservoir. Although cheap and simple,
future reservoir access – for logging or for shutting off unwelcome fluids will be
tricky. Care must therefore be taken to ensure that the drill bit does not enter into
a water interval. In addition any weak intervals present might collapse and either