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Well Kill, Kick Detection, and Well Shut-In 257
Reverse circulation: Kill chart.
2500
Tubing head pressure
Casing pressure
2000
Pressure (psi) 1500
1000
500
0
0 218 426 644
Figure 7.2 Plot of casing and tubing pressure (Example 1).
Table 7.4 Reverse circulation kill data
Top reservoir depth 10,500 ft.
Current reservoir pressure 5570 psi
Original reservoir pressure 6750 psi
Plug depth 10,350 ft.
Packer depth 10,330 ft.
Sliding sleeve or sliding side door (SSD) depth 10,300 ft.
1
5/2 in. tubing ID 4.670 in.
5
9/8 in. casing ID 8.535 in.
SITP 1900 psi
SICP 0 psi (before sleeve open)
Packer fluid gradient 0.67 psi/ft. (12.88 ppg)
Oil gradient 0.35 psi/ft. (6.73 ppg)
Planned overbalance 200 psi
original reservoir pressure. In all other respects, the well is identical to the
previous example (Table 7.4).
Since the tubing head pressure, oil density values, and reservoir pres-
sure are identical to those used in the first example, it follows that the kill
fluid requirement (0.5564 psi/ft.) is also the same. Tubing and annulus
volumes are also unchanged. However, having a heavier fluid present in