Page 262 - Hydrocarbon

Well Dynamic Behaviour 249

the pump and is pumped up the tubing. In the event of an emergency, the pump
can be stopped and tubing flow will stop. The liquid level in the annulus will rise
and the well will kill itself. Pumped wells will be considered further in Section 10.8.
For naturally flowing wells, especially those flowing at moderate or high
pressures, additional barriers to hydrocarbon escape are employed. In the third
example, the tubing is sealed with a packer or other sealing system. Therefore in the
event that the tubing develops a leak (e.g. through corrosion), the casing can
withstand the pressure. Annulus pressure will be detected, the well shut-in and the
tubing replaced. Replacing tubing is a much easier operation than replacing casing.
Such a completion is very common offshore, where the consequences of a leak are
more severe due to the proximity of people to the well.
The final option shown in Figure 10.20 is a dual string. Clearly more complex
than the other options, there are however some useful advantages. This option is
used in low-to-moderate rate wells where there are multiple stacked reservoirs.
Flow from the two intervals is separately produced, controlled and measured and
any problems with incompatible fluids are avoided. These completions can be very
useful if the reservoir intervals are very different in productivity, pressure or fluids.
Rates are however usually lower than the equivalent single bore commingled
producer due to the size limit for two parallel strings inside the casing. In extreme
examples, three strings or even four strings may be run in parallel.

10.7. Completion Technology and Intelligent Wells

In the last section, we considered a range of completion types for both
the reservoir section and the upper completion. Let us now deal with some of the
equipment you may encounter in a completion. In the example in Figure 10.22, the
completion is a horizontal offshore sand control completion with many optional
pieces of equipment. It does however demonstrate the types of equipment in
common use and the often confusing abbreviations used.
Starting from the top of the well, we have the Christmas tree sitting on top of the
wellhead. The tree is designed to control production or injection. It is the primary
means of shutting in the well. Vertical access through the tree is possible for logging or
other interventions. These operations can be performed on a live well (i.e. pressurised
and capable of flowing) through temporary pressure control equipment installed above
the swab valve (SV). Most wells will use a Christmas tree of some form, including
subsea wells. Rod pumped wells however will replace the tree with a single valve and a
stuffing box to allow the rods to move up and down the well whilst the well flows.
The tubing hanger is a solid piece of metal that supports the tubing. It is either
installed inside the wellhead (as shown) or for certain types of tree it can sit inside the
tree. The tubing hanger connects to the tree via seals and to the tubing below via a
screwed thread. The tubing hanger will usually have penetrations for control lines,
downhole gauge lines and chemical injection lines. Below the hanger comes the
tubing. The tubing has to be designed to withstand high pressure (and sometimes
high temperatures). The production fluids are often corrosive and the tubing