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What happened?
During the 12¼ in (311 mm) reservoir drilling phase, drilling resumed after replacement of the bottom-hole assembly (BHA).
While the managed pressure drilling (MPD) hydraulic model was being calibrated, mud pump cavitation reduced the circulation flow rate and annular friction.
The reduced flow rate was not detected, so the reduced annular friction was not compensated by the MPD system surface back pressure (SBP).
Bottom-hole pressure fell and 4.7 bbl (0.75 m³) of fluid entered the well. The well was shut in and the hydrocarbons were bullheaded.
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Why did it happen?
A dedicated skid pump was used to pump lost-circulation material. Flushing the skid to the active tanks contaminated the drilling fluid and pump 3 cavitated.
After maintenance, air remained trapped in the pump and was pumped into the well, causing pump-pressure oscillation and reducing flow through the drill string.
The MPD system did not detect the pump cavitation. The recalibrated hydraulic model therefore used 110 psi (7.73 bar) of annular friction when the actual value was 40 psi (2.8 bar).
Surface back pressure did not increase to compensate for the reduced annular friction. Pressure-while-drilling (PWD) memory data later confirmed the reduction in bottom-hole pressure.
Severe losses required continuous drilling-fluid preparation. The fluid engineer was isolated due to COVID-19 and adjusted the fluid remotely, making the designed fluid properties difficult to maintain. Fluid-property deviation was suspected during recalibration.
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What did they learn?
After pump maintenance and before drilling resumes, air should be removed from the system.
The pump should be aligned to a separate tank and circulated until the system is free of air.
Circulating to a separate tank should also be used to identify any leaks before the pump is aligned to the well.
Hydraulic-model calibration should begin with a higher overbalance. After feedback is received from the pressure-while-drilling system, the set point should be adjusted.
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Ask yourself or your crew
How can something like this happen here, for example on our site?
What procedures, controls or barriers do we have to prevent trapped air entering the well after pump maintenance?
How do we verify that circulation flow rate and annular friction are accurate before accepting a recalibrated hydraulic model?
How do we know that our managed pressure drilling controls respond correctly when pump performance or drilling-fluid properties change?
What improvements should we make to pump alignment, fluid-property monitoring or calibration set points?
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What happened?
During the 12¼ in (311 mm) reservoir drilling phase, drilling resumed after replacement of the bottom-hole assembly (BHA).
While the managed pressure drilling (MPD) hydraulic model was being calibrated, mud pump cavitation reduced the circulation flow rate and annular friction.
The reduced flow rate was not detected, so the reduced annular friction was not compensated by the MPD system surface back pressure (SBP).
Bottom-hole pressure fell and 4.7 bbl (0.75 m³) of fluid entered the well. The well was shut in and the hydrocarbons were bullheaded.
Why did it happen?
A dedicated skid pump was used to pump lost-circulation material. Flushing the skid to the active tanks contaminated the drilling fluid and pump 3 cavitated.
After maintenance, air remained trapped in the pump and was pumped into the well, causing pump-pressure oscillation and reducing flow through the drill string.
The MPD system did not detect the pump cavitation. The recalibrated hydraulic model therefore used 110 psi (7.73 bar) of annular friction when the actual value was 40 psi (2.8 bar).
Surface back pressure did not increase to compensate for the reduced annular friction. Pressure-while-drilling (PWD) memory data later confirmed the reduction in bottom-hole pressure.
Severe losses required continuous drilling-fluid preparation. The fluid engineer was isolated due to COVID-19 and adjusted the fluid remotely, making the designed fluid properties difficult to maintain. Fluid-property deviation was suspected during recalibration.
What did they learn?
After pump maintenance and before drilling resumes, air should be removed from the system.
The pump should be aligned to a separate tank and circulated until the system is free of air.
Circulating to a separate tank should also be used to identify any leaks before the pump is aligned to the well.
Hydraulic-model calibration should begin with a higher overbalance. After feedback is received from the pressure-while-drilling system, the set point should be adjusted.
Ask yourself or your crew
How can something like this happen here, for example on our site?
What procedures, controls or barriers do we have to prevent trapped air entering the well after pump maintenance?
How do we verify that circulation flow rate and annular friction are accurate before accepting a recalibrated hydraulic model?
How do we know that our managed pressure drilling controls respond correctly when pump performance or drilling-fluid properties change?
What improvements should we make to pump alignment, fluid-property monitoring or calibration set points?
Following a trip to change the BHA, while calibrating the MPD hydraulic model mud pump cavitation resulted in reduced circulation flowrate and reduced annular friction. The reduced flowrate was not detected and therefore the reduced annular friction was not compensated by the MPD system Surface back Pressure (SBP). This resulted in a lower bottom hole pressure and influx into the well.
