Completion Operations
Completion Operations tests how a supervisor plans and controls completion work so the well stays overbalanced and every barrier is installed, tested, and verified. Questions focus on fluid density, packer and hanger testing, displacement sequence, and handover of the well.
Core rules
- Maintain two independent barriers. Completion fluid is usually the primary barrier; the packer, tubing hanger, and SSSV provide mechanical barriers.
- Calculate fluid density from the highest expected pore pressure at completion depth, then add a planned overbalance. Do not copy drilling-mud density.
- Test each mechanical barrier from the direction it will see pressure in service. Record test pressure, hold time, and leak acceptance.
- Before setting a packer, circulate out trapped pressure and condition the fluid. Trapped annular pressure can prevent setting or distort a test.
Worked example
A reservoir at 3200 m TVD has a pore-pressure equivalent of 1.18 sg. A 1.22 sg completion fluid gives hydrostatic pressure of 1.22 × 9.81 × 3200 ≈ 38,300 kPa (about 5,550 psi). The overbalance against 1.18 sg is (1.22 − 1.18) × 9.81 × 3200 ≈ 1,250 kPa (about 180 psi). If the planned fluid were 1.15 sg, the well would be about 940 kPa (135 psi) underbalanced, so it is not acceptable without a temporary barrier.
Traps
- Testing the packer only from the annulus when it must hold tubing pressure.
- Forgetting thermal expansion of trapped annulus fluid.
- Treating a test chart with falling pressure as a pass without checking temperature effects.
- Handing over with the SSSV untested or the hanger not pressure-tested.