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9 Important Points about the BP Blowout – Part 1

Here is what a couple of offshore drilling engineers told me about the BP Blowout…

However, everything is consistent with a well way over budget, company men taking heat from the home office to finish the job, and a series of decisions, none catastrophic by themselves, that eventually accumulated to cause this disaster.   I have worked with several majors in my career, and the BP/Amoco E&P guys were as good as they come.  I can't comment first hand on their drilling engineering practices in general, because I don't know.  Here are a few items on THIS well that are notable.

1. On a footage or day rate job, (this was a day rate, reportedly $1 MM/Day), the drilling contractor doesn’t do anything without operator approval or direction.

2. There is no reason to believe the blow out preventer was defective. The probability of a similar result is high for any crew using the same casing and cement program that was used here. 

3. The well was drilled to 18,360 ft and final mud weight was 14.0 ppg. The last casing long string was 16 inch and there were 3 drilling liners (13 5/8”, 11 7/8” and 9 7/8”) with 3 liner tops. 16 inches is a massive annulus, with attendant massive forces.  A 9-7/8” X 7” tapered casing long string was run to TD.  Normal practice would be to run a liner with 9-7/8” liner top packer, followed by tieback string. Perhaps they ran the long string at the last minute to make up for being over time and budget?  That would explain why there was no lock ring, since a last minute change would not allow time for fab or prep of a lock ring. 

4. Apparently they had indications of mud losses, but efforts to control these were incomplete at best, and perhaps they decided to depend on the cement job to handle this for them.

5. This section of casing was cemented using only 51 barrels of nitrogen-aerated cement, a product choice and volume that seems peculiar and “tricky”. Normal practice would be to pump heavy cement all the way back up to the seabed. Also, why nitrified cement?

6. The casing seal assembly was set in wellhead and pressure tested from above to 10,000 psi. Reportedly, a lock down ring was not run on the 9 7/8” hangar/seal assembly casing hanger, as stated above.

7. After only 16.5 hours after cementing, the casing string was pressure tested against the shear rams. Typically you wait 24 hours before pressure testing, because of the danger of expanding the casing and cracking the cement, causing a pathway up the annulus for gas. Were they trying to get off this hole?  A negative test on the wellhead packoff was performed.  No cement bond log was run, perhaps to save a few hours of precious rig time.

8. The rig crew HAD to believe that the well was successfully cemented, capped and secured at this point. No one would remove their heavy (14 ppg) drilling mud and replace with seawater if they believed otherwise, and they did so before setting final cement plugs. Yet they did so less than 20 hours after primary cement job.  At this point, they had NO effective barriers between reservoir and surface.  They should have had at least 2 proven barriers.  They chose the fastest way to displace the much with seawater, by pumping sweater down the drill string and sloughing the returns to a work boat, so you lose the benefit of monitoring influx via the pit level.  All of this had to be operator mandated. 

9. During the displacement failure, the casing collapsed or otherwise failed, causing the well to unload and ignite.  According to the first photos, the crew was able to get the diverter closed since flames were shown coming out of diverter lines.

It is likely that pressure built up between the 9 7/8” and 16" casing under the casing hanger. For a mud weight of 14 ppg, the reservoir formation pressure was over 13,000 psi. The pressure differential below the casing hanger would have caused casing to collapse at one of the connections.  I have heard speculation that it was one or two joints below the wellhead.  This violent production through collapsed casing caused the blowout. Because the hangar didn’t have a lockdown ring, the casing hanger and joint(s) rammed up into the BOP, explaining why the BOP is unable to seal or shear. The parted casing section is probably found up into the riser.
   
Apparently they showed a bump, or gain in the mud at 8:41 p.m.  Had they shut down and closed the pipe rams, they had a good chance of pumping out the gas from the riser in a controlled fashion.  They didn’t, and continued pumping for another 30 minutes to disastrous effect.

By. Allen Gilmer




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