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Shallow kick while running casing leads to complex well control
Rig was running 7” 26# casing at ~1,980’ MD (04:45 hrs) when a 5 bbl pit gain was noted. By the time the casing fill up tool was laid out, the safety valve stabbed and the annular preventer closed on the 7” casing, the pit gain had increased to 30 bbls.
The annular capacity of the 7” x 9 5/8” was only 55 bbls. The initial shut in casing pressure (SICP) continued to increase to above the maximum allowable surface pressure (MASP) of 275 psi. There was no drill pipe pressure due to the floats in the casing string.
Due to rig site concerns that exceeding MASP could result in a casing shoe failure and potential broaching around the surface casing, at 05:00 hrs the casing pressure (CP) was bled down to 110 psi (~13 bbls additional influx). This volume was bled due to a miscommunication between the rig and town, who had only wanted to bleed of 100 psi to see if and how high the pressure would stabilize. At 05:10 the pressure had increased back to 280 psi. At this point all non-essential personnel were removed from the rig.
At 06:10 the CP was 465 psi. The casing pressure continued to increase to 544 psi at 08:16. A plan was developed in conjunction with the Well Control Team and the rig started pumping mud at 0.5 barrels per minute (bpm) in an attempt to obtain drill pipe pressure.
After pumping 7 bbls the drill pipe pressure increased to 34 psi. At this point the driller’s method was employed to circulate out the gas bubble. After pumping 43 bbls, matching the calculated volume of influx in addition to the volume bled, fluid returns were noted at surface. At this juncture, the fluid returns were a barrel out for a barrel in and the return mud weight was 10.7 ppg. The only reason that exceeding MASP did not result in casing shoe failure incident is because there was only a gas gradient down to the weak point versus a fluid gradient – as confirmed by the volume of gas bled off prior to fluid returns at the choke.
What Went Wrong?:
The investigation team identified two common threads that contributed to all of the findings:
Corrective Actions and Recommendations:
Finding: Failure to honour the requirements in the well plan contributed to using incorrect test pressure requirements to verify surface integrity and a lack of proper mitigations for exposure to hydrates.
Finding: Procedures do not specify when a deviation from the original well plan requires a risk assessment.
Recommendation: Establish a means to incorporate the proper level of risk assessment associated with the change.
Finding: Incorrect kick tolerance calculations allowed drilling to move forward with the shallowest kick-off point without requesting a deviation from well control management requirements.
Recommendation: Implement a process where critical calculations are cross checked prior to issuance.
Finding: Exposing a Hydrate Zone during intermediate drilling and pumping out of the hole prior to running casing lead to increased gas in the wellbore above the window.
Finding: Lack of Total Gas Detection capabilities contributed to the rig crew believing the sensor was faulty rather than being able to verify gas was present and led to the inability to identify the gas source.
Recommendation: Explore options for adding gas detection capability to the rig.
Finding: Loss of Primary Well Control due to gas dissociation with the hydrates resulted in underbalance to the free gas zone.
Recommendation: Initial gas influx not detected due to reverting back to normal well monitoring limits.
Finding: Delay in shutting-in the well led to the gain of an additional 25 bbls of influx.
Recommendation: Develop well control complexity drills for dealing with kicks generated while running casing with floats and low MASP scenarios.
IOGP Well Control Incident Lesson Sharing 18-6
safety alert number: 305
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