Safety Alert for the Macondo Well Blowout

Cause & Consequence

• Other

Incident Location

Drilling unit

Incident Activity

Drilling, workover

Lessons Identified

The investigation found, in part, that:

• The operator did not follow the cementing recommendations identified in American Petroleum Institute (API) Recommended Practice (RP) 65 –Cementing Shallow Water Flow Zones in Deep Water Wells and API RP 65, Part 2 – Isolating Potential Flow Zones During Well Construction. Specifically, the operator did not:
  • circulate full bottoms up prior to pumping cement;
  • pump heavier weight mud into the rat hole before pumping cement to prevent swap out of the lighter rat hole mud (14.0 ppg) with the heavier (14.5 – 16.4 ppg) cement;
  • achieve a static gel strength; and
  • meet the minimum annular space guidelines between production casing and hole size in their well design.
• Pressure differential anomalies identified during negative pressure tests were not recognized as possible hydrocarbon influx and were instead misinterpreted as “annular compression” or “bladder effect.”
• The rig crew did not detect the hydrocarbon influx, likely due at least in part to fluid movement among the various pits and fluid movement from the rig to the Damon Banskston.
• Even though various cementing anomalies occurred, the operator did not set a mechanical/cement plug above the float collar/wiper plugs prior to displacing the well to an underbalanced condition.
• In responding to the blowout, the rig crew used the mud-gas separator (MGS) to handle the hydrocarbon flow rather than diverting the well directly overboard through the diverter line(s).
• The MGS vent piping was located in the derrick and directed flow back down toward the rig floor.
• The operating philosophy of a dynamically-positioned MODU is to maintain power at all times for the purpose of keeping on station. This adds complexity to the response to a well control event. Further, this philosophy creates a conflict because the rig needs to maintain power to get off location while maintaining that power creates a possible ignition source.
• The air intakes for two of the engine room compartments were located in close proximity (~20 feet) to the edge of the rig floor classified area.
• A forensic examination of the BOP stack conducted by Det Norske Veritas and supported by a multi-party technical working group revealed that elastic buckling of the drill pipe had forced the drill pipe up against the side of the wellbore and outside the cutting surface of the (BSR) blades. As a result, the BSR did not completely shear the drill pipe nor seal the well which allowed hydrocarbons to continue to flow after the blowout.

Incident Recommendations

Based on the investigation, BSEE recommends that Lessees and contractors:

• Minimize the amount of fluid transfers during well operations so that accurate monitoring of flow-in versus flow-out can be achieved. Refer to Safety Alert #284 – Diverter Flow Event, for additional information regarding surface fluid system and fluid movement.
• Recognize the potential for a well to flow during a negative pressure test. It is recommended that Lessees and contractors ensure that their procedures for conducting negative pressure tests outline expected test results including failure indicators. These expected test results should be discussed at a pre-kill meeting prior to conducting the negative pressure test.
• Review their well control procedures to ensure that the initial response actions default to routing the well flow to the overboard diverter line(s) when appropriate.
• Evaluate and consider relocating the MGS vent line(s) to prevent directing gas, condensate and oil back down toward the rig floor.
• Inspect all dynamically-positioned MODUs and determine if all air intakes are located as far as practically possible from the rig floor.
• Evaluate the configuration and operation of subsea BOP stacks to maintain central alignment of the drill pipe and minimize the effects of elastic buckling during emergency activation of BSRs.