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Gas break-out from oil-based mud while running casing

• The event took place on a 3000 HP Land Drilling Rig while running 9 7/8” casing in the 12 ¼” hole section of an unconventional well. Well was vertical.
• Well architecture consists of 20” Surface Casing at 945m, 13 3/8” casing at 3348 m at 12 ¼” hole section at 4794m.
• Run 9 7/8” casing to 4793m.
• After landing casing, circulated 9 7/8” casing, increasing pump rates from 0.70 m³/min to 1.45 m³/min and SPP of 450 kPa.
• At 2000 strokes into bottoms up, returns diverted through the manifold. Maximum gas of 2500 units observed prior to going through MGS.
• Circulate through choke at 1.0 – 1.5 m³/min. Initial casing pressure of 170 kPa and SPP of 570 kPa. Casing pressure spiking at 5800 strokes to 9500 kPa and decreasing to 2100 kPa as bottom up strokes expired.
• Significant amount of gas observed at surface. Approximately 5 m³ of invert drilling fluid was spilled over from open bottom poor boy degasser (MGS) while circulating bottoms up.
• Shut in well & monitored for pressure evaluation.
• Observed increase in SIDPP & SICP.
• Continued to monitor pressure evolution.
• Pressure stabilized at SIDPP 300 kPa & SICP 450 kPa.
• Performed drillers method well kill and stabilized well with mud weight of 1750 kg/m³.
• Well was static prior to bottoms up circulation (some reports noted minor flow when landing mandrel hanger).
• During the bottoms up, returns were diverted to MGS as a precaution for trip gas and because pump pressure was much less than expected.
• The gain was not noticed until the well was circulated once the casing was on bottom.
• The section was drilled with a narrow mud-weight window.

What Went Wrong?:

• Gas entered the wellbore while well was static.
• Insufficient hydrostatic pressure to prevent influx of formation fluid.
• Well flow checks were inconsistent prior to tripping to run casing and were not sufficient to indicate potential influx of formation fluid into the well.
• Circulation rate was adjusted to take into account the reduced volume of the annulus associated with the casing as compared to the large annular volume associated with drill pipe to ensure that the annular velocity was the same. However, this still resulted in the gas entrained in the drilling fluids coming to surface at a rate that exceeded the capacity of the MGS.
• Choke was in the 100% open position as it should be when gas arrived at the surface because of concerns about exceeding MAASP. This resulted in maximum flow to the MGS exceeding the off-gassing and flaring capacity of the MGS flare system.
• Possibly drilled too far into the HPHT pressure ramp in 12 ¼” hole section.

Corrective Actions and Recommendations:

A definitive HPHT well control procedure will be developed for drilling operations in noted area.

• Review MGS Sizing calculations for maximum anticipated gas rates. Understand capacity of oil based mud to absorb gas.
• Develop a log sheet to better monitor and finger print trip gas, bottom’s up gas, connection gas and background gas to better understand potential behaviour at surface.
• Drilling engineering team initiate and lead researching and acquiring a better way of determining needed mud weight trip margin requirements for making trips to log or run casing, with a better understanding of the fluids system EMW and ECD’s.

safety alert number: 266
IOGP Well Control Incident Lesson Sharing http://safetyzone.iogp.org/

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