Page 303 - Well Control for Completions and Interventions

296 Well Control for Completions and Interventions

the well, gas in the wellbore is compressed, causing an increase in tubing
pressure. The volume of fluid that can be pumped at each stage is limited
by the combination of pressure increase due to gas compression and the
increasing hydrostatic head. If the tubing has not been plugged, formation
fracture pressure normally defines the upper limit; a safety margin should
be included. Where the tubing is plugged (mechanical barrier), the maxi-
mum pressure limit will be the mechanical limit of the plug, the produc-
tion tubing, the tree or surface pumping equipment; whichever is lowest.

7.7.1.1 Constant volume method. Calculations and procedure
1. Calculate the gas gradient in the tubing.
BHP 2 SITP
Gas gradient ðpsi=ft:Þ 5 (7.9)
reservoir depth TVD

2. Calculate pipe capacity and volume.
3. Calculate the kill weight requirement.
In a plugged well: kill weight is calculated to the plug. Assumes a col-
umn of reservoir fluid from the plug to the reservoir.
No plug: kill weight is calculated to the top of the reservoir.
4. Calculate the maximum volume that can be pumped without exceed-
ing the maximum allowable surface pressure using Boyle’s law. If no
plug is installed, formation fracture pressure is likely to determine the
maximum pressure that can be applied at surface.

P 1 V 1
V 2 5
P 2
where
V 2 is the maximum volume that should be pumped (to reach max-
imum surface pressure).
P 1 is closed in pressure.
V 1 is the tubing volume (to the plug or reservoir).
P 2 is the maximum allowable surface pressure.
5. Pump fluid until the wellhead pressure reaches the maximum allow-
able pressure (or the calculated amount has been pumped).
6. Record the volume of fluid pumped.
7. Allow time for fluid to drop down the well.
8. Bleed dry gas from choke to reduce casing pressure to the previous
recorded wellhead pressure plus the calculated hydrostatic pressure
increase. Allow the well to stabilize.