IOGP Well Control Incident Lesson Sharing
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Migration Below Completion Barrier Unloads Riser During Subsequent Circulation

A subsea water injector had been suspended after installing the lower completion with completion brine in the hole. Two retrievable test packers and storm valves were used for isolation while the horizontal tree (HXT) was installed. After resuming operations and retrieving the upper retrievable test packer, the rig unseated the lower retrievable test packer. Initial high loss rates over 200 BPH were observed, slowing down to 40 BPH after 2.5 hrs. The well was circulated down the drill pipe and up the riser. At 102 bbls from bottoms up, a 5 bbl gain in the pits was observed. the pumps were shutdown and the annular closed. Fluid started coming through the rotary table and the diverter was closed. Before the diverter could close completely, 87.5 bbls of 8.8 ppg brine and 2 barrels of crude oil unloaded from the riser to the drill floor. The shut-in well had zero pressure on the drill pipe and casing. Clean up operations included removal of 485 bbls of crude/brine mix from the riser. Nobody was hurt and there were no environmental impacts as a result of this incident.

What Went Wrong?:

Total depth of the water injector is 4242m MD/ 2661m TVD at ~ 70 degrees in the target sand with 3 oil bearing sands and reservoir pressure 6.5-7.4 ppg EMW.

Lower completion screens were run, and the well circulated to 8.8 ppg brine (~575 psi OB).

An attempt to set a retrievable bridge plug for the lower isolation near the completion packer was unsuccessful.

The lower retrievable test packer with storm valve was set at 2505m (57 deg) with 287m of tail pipe (1085m above the gravel pack packer). The retrievable test packer was set at this depth to allow running the required amount of tail pipe to achieve 30klbs weight below (tail pipe) and prevent the retrievable test packer from unseating.

Loss rate prior to setting retrievable test packer was ~8 BPH.

Due to high loss rates of 200 BPH upon unseating the retrievable test packer, it was not recognized that hydrocarbons had migrated into the wellbore below it and were rising up the annulus while circulating out. Hydrocarbon migration had been anticipated, but it was incorrectly assumed that the losses were effectively sweeping the hydrocarbons in the formation. The high-angle of the hole likely allowed gas to migrate up the high-side of the well during this event.

Corrective Actions and Recommendations:

When barriers are set above exposed permeable formation, it should be assumed that reservoir fluids swap with the fluid below the barrier, and necessary precautions should be taken when removing the barrier to properly sweep any trapped gas thru the choke or bullheaded to avoid risk of unloading the riser.

The lowermost barrier should be set as close as practical to the downhole source of the pressure being isolated to minimize the potential volume of hydrocarbons and associated pressure that could build up in the well.

Before removing the lower most barrier a risk assessment / discussion should be held to ensure personnel are aware of the potential exposures and prepared to respond. Items to address should include

  1. Ability to monitor the well through the drill pipe prior to unseating that barrier.
  2. Key exposure times during the first bottoms-up circulation and benefits of circulating through the choke.
  3. Planned responses if losses (or other circumstances) prevent normal circulating. Options such as bullheading at an appropriate pump rate (annulus fluid velocity) to flush the hydrocarbons back into the formation should be considered.


safety alert number: 298
IOGP Well Control Incident Lesson Sharing


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