Page 314 - Well Control for Completions and Interventions

Well Kill, Kick Detection, and Well Shut-In 305

10. If the pressure increase is not consistent with the volume pumped,
i.e., P 2 is less than the anticipated value, the most likely explanation
is that fluid is being lost to the formation as the downhole pressure
increases. Since fluid loss will result in a reduced hydrostatic head,
bleeding off pressure equivalent to the head of fluid pumped will
likely result in an influx. The revised fluid level can be estimated
from the pressure at surface. For example, Table 7.15 predicts a pres-
sure rise from 3728 to 4067 psi during the 5th stage of the kill.
Consider a situation where, after pumping 10 bbls, the pressure had
not risen to the expected 4067 psi but had stabilized at 3920 psi.
Boyles law can be used to estimate the volume of fluid in the tubing,
and therefore the revised hydrostatic head.

3728 3 120
V 2 5 5 114:12 bbls:
3920
The compressed gas volume remaining in the tubing is 114.12 bbls,
not 110 as planned. Even though 10 bbls of fluid were pumped, only
120 2 114.21 5 5.88 bbls remain in the tubing, the rest (4.12 bbls) is lost
to the formation. The head increase is therefore 5.88/0.0149 5 395 ft. 3
(0.572 2 0.08) 5 194 psi, not the 330 psi anticipated. Bleeding off the
planned amount of pressure (330 psi) would result in an influx. If losses
are suspected, then pressure adjustments will need to be made “on the
fly.” More stages will be required, the kill will take significantly longer
and more kill fluid will be needed.

7.7.3 Lubricate and bleed. Constant pressure method
Like the constant volume method, the constant pressure method also
uses four steps at each stage of the kill; pump, wait, calculate, and
bleed. Where the pressure method differs is that each time fluid is
pumped, the wellhead pressure is brought back up to maximum allow-
able pressure. This technique will, in theory, kill the well more quickly
as fewer stagesare required.However,itmustbetreated with caution.
As the operation progresses, the combination of high wellhead pres-
sure and increasing hydrostatic head results in increasingly high BHP.
BHP must not be allowed to go above formation fracture pressure, nor
should pressure be allowed to reach the tubing burst limit. The most
conservative approach when defining a tubing burst limit is to assume
that the casing is evacuated. Differential pressure is based on the
tubing hydrostatic at the packer 1 applied surface pressure against an