Kick while drilling underbalanced to a poorly isolated tight formation behind casing.
With pressure regressions or depleted reservoirs, the drilling mud density might need to be reduced to less than the pore pressure encountered shallower in the well. A casing or liner string is used to maintain integrity and to prevent the shallower zones from flowing. In this incident, gas from a shallower zone found a path into that casing and up to the surface during displacement to a lower density fluid. The incident escalated because of operational factors and challenges. What extra caution steps does your organization take when you are reducing the fluid density to less than the pore pressures isolated behind casing?
The Wells Expert Committee/Well Control Incident Subcommittee believes that this incident description contains sufficient lessons to be shared with the industry. We further encourage the recipients of this mail to share it further within their organization.
A 12-1/4" hole had been drilled with 14.5 ppg oil mud (OBM) to a depth of 4108 m. 9-5/8" casing had been set at 4104m MD. Cement was displaced and plugs bumped with 10.8 ppg OBM, as the casing shoe was set in the "depleted" reservoir, which was expected to have a 6 ppg equivalent (EMW) pore pressure. The 8-1/2" hole was planned to be drilled with 9.0 ppg OBM.
The 9-5/8" float collar, shoe track cement, and reamer shoe were drilled out with a Turbine drilling assembly with the 10.8 ppg OBM. 3 metres of new formation were drilled, to a measured depth of 4111 metres. (Note, this is a directional well, with a hole angle at TD of 53 deg, TVD=3889.9 m.) After 3 metres of new formation was drilled, the 10.8 ppg OBM began being displaced with a 9.0 ppg OBM.
While displacing 10.8 ppg OBM with 9.0 ppg OBM (just after midnight local time), the gas detector spiked abruptly from 18 units to 1393 units and Bell Nipple overflowed with mud.
Crew spaced out and closed the Annular BOP.
Initial shut-in casing pressure (SICP) = 50 psi, started first circulation of drillers method at 30 strokes per minute (spm). Saw casing pressure increase to 200 psi, shut down pump, closed in well and recorded shut-in drill pipe pressure (SIDPP) = 1050 psi & SICP = 200 psi.
Pumped 11.1 ppg OBM at 30 spm, observed reduction in returns, and gas bubbles at shakers. Circ pressure 770 psi, casing pressure = 350 psi. Shut in well. SIDPP = 0, as drill pipe float preventing reading a true value. SICP rose from 770 psi to 2200 psi in 60 min. Rocked open float and observed a SIDPP of 920 psi.
Mixed and circulated 13 ppg kill weight OBM, took several bottoms up (BU) to remove all gas from system. Raised MW to 13.5 prior to POOH for BHA inspection.
Found filter sub plugged above turbine, as one of contributors to higher initial circulating pressure (ICP). Wrong slow circulating rate (SCR) pressure on report and kill sheet (not updated from prior BHA) was a second factor.
What Went Wrong?:
Reservoir assumed to be depleted and high pressure shale isolated with 9-5/8" cement job.
Drilling program written with the assumption that target reservoir will be depleted to 6 ppg EMW or less. Two offset production wells, each less than 2km away with known reservoir pressures. Wireline log pressures confirmed the main reservoir is depleted to a 6.6 ppg EMW.
MW was reduced from 14.5 ppg to 10.8 ppg during cementing operations and 9 ppg OBM was being circulated at full rate into the well without any indications of a kick occurring.
Later analysis confirmed that the gas was from a low permeability shale formation behind 9-5/8" casing. Evaluation logs showed the casing was not damaged but there were channels in the cement, supporting gas migration downwards into the 8-1/2" hole.
The gas kick went into solution in the OBM, and didn't appear until coming out of solution near top of well, and observed when the bell nipple started overflowing.
ICP values were mishandled, due to incorrect SCR pressure and unknown factor of a partially plugged BHA. This allowed well to continue to kick, and contributed to an extended number of circulations.
Corrective Actions and Recommendations:
MW reductions result in an "inflow test" on the wellbore. Consider controlling such reductions with use of choke, or verify with a dedicated inflow test prior to full wellbore displacement.
Verify SCR values (real time data review by the centre identified the actual values after several circulations).
Reviewed and updated training for bringing pump up to speed and managing actual ICP if different from calculated.
safety alert number: 340
IOGP Well Control Incident Lesson Sharing http://safetyzone.iogp.org/
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