Deepwater Horizon Accident - ida.dk Horizon Accident.pdf · Well was drilled by Transocean’s Deepwater Horizon rig from February 2010 until April 20, 2010, ... Well Control response

22 September 2010Corporate Drilling#1

Mark Ratchinsky – Head of International Operations, Corporate Drilling

Deepwater Horizon Accident

22 September 2010#2 Corporate Drilling

AgendaDeepwater Horizon – The Rig and the Macondo prospect

Well schematic and Sequence of events

What happened?

BP Key Findings

Remedial actions

Summary


Maersk (and IADC) Definitions:

Deepwater 3000 – 6500 feet

Ultra Deepwater > 6500 feet

The Deepwater arena is growing in importance as a supply source for energy

Due to high volume, high permeability reservoirs

Tupi, Brazil, estimated 8 billion bbls recoverable

Brief Perspective on Deepwater

Macondo

Deepwater production capacity has more than tripled since 2000


Deepwater Horizon – the rig

• Deepwater semi-submersible drilling unit

• capable of operating in harsh environments and water depths up to 8,000 ft

• 18¾in 15,000 psi BOP and 21in OD marine riser.

• Rig Type - 5th Generation built in

2001.

• Contracted to BP in the Gulf of Mexico, since delivery from yard.


The Macondo prospect is located in a water depth of 4,993 feet (1,522 meters) and with a reservoir depth of 13,000 feet below seabed.

BP is operator and holds a 65% interest in the prospect, while Anadarko holds a 25% interest and Mitsui holds a 10% interest.

Well was drilled by Transocean’s Deepwater Horizon rig from February 2010 until April 20, 2010, when the accident happened.

The Macondo prospect

Macondo


11 persons dead

$9.5 billion spent (17.Sep.10)

including the cost of the spill response, containment, relief well drilling, static kill and cementing, grants to the Gulf states, claims paid and federal costs.

BP created a $20 billion escrow account to satisfy certain obligations arising from the oil and gas spill.

BP Latest News

Macondo




What happened?

BP Key Findings

Remedial actions

Summary


Well Schematic• Well drilled to 18,380 ft, but incurred losses in

primary target and stopped well short of secondary targets

• 9 7/8” x 7” tapered long casing RIH and cemented in place using N2 Foam Cement system

• Wellhead seal assembly installed, positive test indicates seal assembly is in place and holding pressure from above

• ~16hrs after cementation drill pipe RIH and the well is displaced to seawater in order to inflow test all the barriers

• Inflow test accepted and well was further put underbalanced with seawater




What happened?

BP Key Findings

Remedial actions

Summary


What happened?

• During the replacement from mud to seawater gas entered the casing, through the float collar into the 7” casing putting pressure on the drill pipe.

• Flow indications were not recognised by the crew allowing oil and gas to enter the riser above the blow-out preventer and once on surface caused the explosion when it flowed out over the rig.


What happened

• After a series of explosions, the rig catches fire on April 20, and sunk on April 22.

• The sinking of the rig destroyed the riser and lead to three leaks in the riser and thus to the oilspill.




What happened?

BP Key Findings

Remedial actions

Summary


BP Key Finding

• The Annulus cement barrier did not isolate the reservoir

Foam cement slurry used is a very complex design

High risk of cement contamination due to small volumes being used

Tests indicate that, in this particular situation, the system was unstable and that there was N2 breakout

1


BP Key Finding

• The Shoe Track Mechanical Barriers did not isolate wellbore from hydrocarbons

Shoe track cement failed to act as a barrier due to cement contamination and N2 breakout

Hydrocarbon influx was able to bypass the float collar check valves

2


BP Key Finding

• The Negative (in-flow) test was accepted even though well integrity had not been established

Bleed volumes not recognised as a problem

Anomalous pressure on drill pipe with no flow from kill line not recognised as an issue

Test procedure was not done in a standardised manner.

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BP Key Finding

• The influx was not recognised until hydrocarbons were in the riser

#1 Drill pipe pressure increased by 100 psi from 20:58 to 21:08 indicating a 39 bbl gain

#2 Drill pipe pressure increased by 246 psi from 21:08 to 21:14

#3 Drill pipe pressure increased by 556 psi indicating a 300 bbl gain

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BP Key Finding• Well Control response fails to regain control of the well5


BP Key Finding

• Influx was diverted to mud gas which resulted in gas being dispersed throughout the rig

Hydrocarbons were routed to the mud gas separator rather being diverted overboard

Resulted in rapid gas dispersion across the rig via the MGS vents and mud system

Due to pressure on the system the slip joint would have vented hydrocarbons as well

6


BP Key Finding

• The fire and gas systems did not prevent explosion

Gas dispersion was beyond electrically classified areas

Gas ingress to main engine rooms were one potential ignition source

7


BP Key Finding

• The BOP emergency control systems did not work

EDS was inoperable due to damage to MUX cables

AMF did not funtion

Auto shear did not seal wellbore

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What happened?

BP Key Findings

Remedial actions

Summary


Remedial actions

1. April 28, BP announces that the controlled test to burn oil off the surface was successful.

2. May 4, BP started to prepare containment dome and attempts installation. However, the dome fails due to hydrates.


3. May 7, BP starts to drill the first of two relief wells.

4. May 14, BP inserts a 4” wide riser into the 21” burst pipe to collect oil to surface. Some oil was captured.

Remedial actions


5. May 16, the work on the second relief well has been initiated.

6. May 26, BP initiates plan for “top-kill” project. Despite pumping large volumes of high density fluids at high rates and pressures, the attempt to kill the well fails.

Remedial actions


7. May 29, BP moved to the next contingency option the Low Marine Riser Package (LMRP) Cap Containment System.

May 31, BP cuts the leaking pipe and places a cap on it to channel the oil to the surface.

Remedial actions


8. For more than a month, the new cap enables BP to gather up to 25,000 Barrels of oil per day. Estimated total flow from the well is now between 30 and 60,000 barrels per day!Despite the more effective cap, oil is still leaking into the sea and work continues on other options.

Remedial actions


9. On 14 July, BP replaces the LMRP cap with a new sealing cap system, in reality a ‘small’ BOP designed to fit on top of the Deep Horizon BOP.

Remedial actions


10.Finally on July 15th BP is able to close in the well and eventually stop the biggest oil spill since the first Gulf War in 1991

Remedial actions


11.On the 3rd August, BP commences the static kill operation and follows immediately with cement behind, thus eventually sealing off the well.

Work on the two relief wells continue, in order to ensure complete isolation from the well of the reservoir.

Remedial actions




What happened?

BP Key Findings

BP Remedial actions

Summary


Summary of Key Findings• Well Integrity was not established or Failed

Cement did not isolate reservoir

Shoe Track Barriers did not isolate hydrocarbons

• Hydrocarbons entered the well undetected

Negative test accepted but well integrity had not been established

Influx was not recognised until hydrocarbons were in the reservoir

Well Control response actions failed to regain control

• Hydrocarbons ignited on the Deepwater Horizon

Diversion of flow to MGS resulted in gas being dispersed on to the rig

Fire and gas systems did not prevent ignition

• Blowout Preventer did not seal the Well

Blowout Preventer (BOP) emergency control systems did not seal the well

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Documents

Deepwater Horizon Accident - ida.dk Horizon Accident.pdf · Well was drilled by Transocean’s Deepwater Horizon rig from February 2010 until April 20, 2010, ... Well Control response