Well Completion Considerations
Casing
It is common to fracture-treat a well down casing and run tubing
into the well after the treatment. But even if it is necessary to
perform the treatment through tubing, the annulus is often "live".
Therefore the casing has to tolerate the maximum pressure occurring
during the treatment. When designing a casing string or checking
existing casing, we have to consider the worst scenario, including
possible screenout. Such safety considerations determine the
maximum allowable surface treating pressure.
Zonal isolation is of primary importance in modern fracturing.
To place the fracture in the target layer, the well must be
cemented and the primary cement must provide a satisfactory seal
around the production casing or liner. Occasionally, flaws in the
primary cement job have to be corrected by "squeezing" additional
cement behind the casing.
Tubing
The diameter of the wells tubing string is a critical factor in
fracturing operations as well as in production. The production
tubing should be specially designed to handle the fluid injection
if such a treatment is being considered in the well completion. Too
small a tubing diameter results in excessive friction loss, which
increases horsepower requirements or restricts injection rate.
Either of these conditions could increase the treatments total
fluid volume requirements or could possibly even lead to a
screenout. The minimum recommended tubing size for a frac job is 2
7/8 in. EUE (2 3/8 in. EUE for very shallow wells), while 3 1/2 in.
OD tubing is a fairly standard size for a frac string.
Normally, a tubing grade of N-80 or above is required for
fracturing. Pressure is sometimes held on the annulus above a
packer to provide a tubing-burst safety factor. Other factors to
consider when using a packer on a fracturing treatment, especially
on deeper wells, are
the effects of fluid temperature acting on the tubing
the ballooning effect caused by the high internal pressure,
causing shortening of the tubing
the lengthening of the tubing caused by the frictional drag of
the fluid velocity as it is pumped through the tubulars
The ballooning and frictional lengthening effects are canceled
as soon as the pumping is stopped, but the temperature effects
continue until the wellbore temperature returns to normal. The
calculations should determine the proper hook weight to minimize
forces acting on the packer and tubing. Alternative equipment, such
as slip joints, can also be used to compensate for this movement.
The above considerations are particularly important on deep and hot
wells, where the effective tubing movement may be quite large,
sometimes in excess of 20 feet.
Perforations
Both overbalanced and underbalanced perforation techniques are
available. Perforation diameter, density and phasing may
significantly affect treating pressures and even production rates.
One important concern is shear degradation of the fracturing fluid
through perforations.
Multiple sets of perforations can be treated simultaneously by
diverting techniques. One diverting technique, known as
limited-entry, implies a limited number of perforations and uses a
high injection rate. The perforation friction causes a pressure
increase inside the well and helps to utilize available
perforations in all the individual target zones. Ball sealers and
packers are also used for treatment diversion.
Wellhead
The fracturing pressure will probably be the highest pressure to
which the wellhead is ever subjected. The wellhead equipment must
have a pressure rating adequate to accommodate the anticipated
fracturing pressure plus a significant margin for error. It may be
necessary to install a special wellhead just for the frac job and
change it later, or use special high-pressure wellhead isolation
tools (available for rental in most areas) that can be run through
the master valve to allow the use of standard wellheads. The latter
is generally the most economical alternative.
