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Deepwater Horizon Accident Investigation 1
Deepwater Horizon Investigation
Deepwater Horizon Accident Investigation 2
Investigation Context
Terms of Reference
Investigation Team
Data and Analysis
Investigation Limitations
Deepwater Horizon Accident Investigation 3
Well integrity was not established or failed−
Annulus cement barrier did not isolate hydrocarbons
−
Shoe track barriers did not isolate hydrocarbons
Hydrocarbons entered the well undetected and well control was lost−
Negative pressure test was accepted although well integrity had not been established
−
Influx was not recognized until hydrocarbons were in riser
−
Well control response actions failed to regain control of well
Hydrocarbons ignited on the Deepwater Horizon−
Diversion to mud gas separator resulted in gas venting onto rig
−
Fire and gas system did not prevent hydrocarbon ignition
Blowout preventer did not seal the well−
Blowout preventer (BOP) emergency mode did not seal well
1
2
3
4
4
5
Sea Floor
Casing
Riser
BOP
Reservoir1
3
Eight Barriers Were Breached
2
5
6
7
8
6 7
8
Deepwater Horizon Accident Investigation 4
Introduction
Technical Presentation
Deepwater Horizon Accident Investigation 5
Well Integrity Was Not Established or Failed
Deepwater Horizon Accident Investigation 6
Sea Floor
ChokeBoost
BOP
Kill
17:30 –
19:30
Circulated prior
to cement job36”
28”
22”
18”
16”
13-5/8”
11-7/8”
9-7/8”14.17 ppg
SOBM
Bottoms–up Marker
Cement
Mud
Spacer
After drilling to total depth, casing is run to bottom in preparation for the cement job. A double valve float collar is used to prevent backflow or ingress of fluids through the shoe track until the cement hardens and
creates a permanent barrier.
April 18th 00:30 – April 19th 19:30
Long string design robust, consistent with similar wells in the area
9 attempts made to establish circulation to convert float valves
Circulate ~6 times open hole volume, limited circulation due to concerns over creating losses and hole washout
No evidence that hydrocarbons entered the wellbore prior to the cementing operation
Primary reservoir sands
(12.6 ppg)
Production Casing Installation
Deepwater Horizon Accident Investigation 7
April 19th 19:30 – April 20th 07:00Nitrogen cement slurry chosen
–
To achieve light weight slurry due to limited pore pressure / fracture gradient window
Possible risk–
Stability of foam–
Relatively small volume–
Susceptible to contamination
Mitigation of risk by–
Thorough testing of slurry design–
Precise placement
Centralization –
6 inline centralizers spaced across the reservoir sands
–
Additional centralizers not run because incorrectly thought to be wrong type
–
Risk of channeling above reservoir sands known and accepted
Cement is pumped down casing through the float collar and up the annulus to isolate the primary reservoir sands.
Sea Floor
ChokeBoost
BOP
Base Oil
Spacer
Cap Cement
Foamed Cement
Tail Cement
Mud
Nitrogen Breakout
36”
28”
22”
18”
16”
13-5/8”
11-7/8”
Shoe –
17,168’
Bottoms–up Marker
Kill
9-7/8”
Shoe –
18,304’
Float Collar –
18,115’ 6 centralizers Primary reservoir sands
(12.6 ppg)
Primary Reservoir
Sands (12.6 ppg)
Centralizer
00:35 –
02:50
Drill-Quip seal assembly installed
and successfully tested.
No lock down sleeve installed.
02:50 –
07:00
Pull out hole with drill pipe.
Set and test casing hanger seal assembly
Pull out of hole with running tool and drill
pipe
Top of
cement 17,260’
Cement Job
Deepwater Horizon Accident Investigation 8
Sea Floor
Casing
Riser
BOP
Reservoir
12.6 ppg
Bottom Wiper Plug
Mud
14.17 ppg
Cap
16.74 ppg
Foam
Cement
14.5 ppg
Shoe
Track
Spacer
14.3 ppg
6.7 ppg
Spacer
14.3 ppg
Top Wiper Plug
Bottom Wiper PlugBottom Wiper Plug
Mud
14.17 ppg
Spacer
14.3 ppg
Top Wiper PlugTop Wiper Plug
Bottom Wiper Plug
Spacer14.3 ppg
16.74 ppg
CapCement
FoamCement14.5 ppg
Cement
Channeling
ShoeTrack
Nitrogen Breakout
Cement is pumped down the landing string and casing into the annulus to isolate hydrocarbon
bearing sands.
Foam slurry recommended was a complex design
Risk of contamination using small volume of cement
No fluid loss additives
Incomplete pre-job cement lab testing
Foam slurry was likely unstable and resulted in nitrogen breakout
Base Oil16.7 ppg
Cement Slurry Placement
Float Collar
Tail Cement16.74 ppg
Reamer Shoe Tail Cement
Key Finding #1The annulus cement barrier did not isolate the reservoir hydrocarbons
Centralizers
Deepwater Horizon Accident Investigation 9
Cement Slurry Design Issues
50% quality foam at surface conditions was not stable
18.5% quality foam (downhole quality) was not stable
Yield point of the Halliburton slurry was too low for the foam cement (2 lb / 100 ft2
yield point at 135 deg F)
Fluid loss for the base slurry was excessive compared to industry recommendations (302 cc versus 50 cc per 30 min)
Note: QUALITY = Nitrogen Volume / (Nitrogen + Base Slurry Volume)
Unstable Foam Sample
Original Height
Final Height
Cement
An independent lab completed over 500 tests on a representative cement slurry and reported the following:
Deepwater Horizon Accident Investigation 10
16ppg Spacer
14.17ppg SOBM (Mud)
8.6ppg Seawater
Influx
Flow Through Shoe Track - Supporting Evidence
CasingShoe
Failure
SealAssembly
FailureYY
YY
YY
YY
YY
YY
YY
YY
NN1400 psi recorded on drill pipe during negative test at 18:30
NNStatic Kill
NNTiming for Gas Arrival to Surface
NNPressure Response from 21:31 to 21:34
NNPressure Increase from 21:08 to 21:14
NNAbility to flow from 20:58
NNRealistic Net Pay Assumption
YYMechanical Barrier Failure Mode Identified
Key Observations for FlowThrough Shoe vs. Seal
Assembly
CasingShoe
Failure
SealAssembly
Failure
YY
YY
YY
YY
YY
YY
YY
YY
NN1400 psi recorded on drill pipe during negative test at 18:30
NNStatic Kill
NNTiming for Gas Arrival to Surface
NNPressure Response from 21:31 to 21:34
NNPressure Increase from 21:08 to 21:14
NNAbility to flow from 20:58
NNRealistic Net Pay Assumption
YYMechanical Barrier Failure Mode Identified
Key Observations for FlowThrough Shoe vs. Seal
Assembly
CasingShoe
Failure
SealAssembly
Failure
Deepwater Horizon Accident Investigation 11
Sea Floor
Casing
Riser
BOP
Reservoir
Key Finding #2The shoe track mechanical barriers did not isolate the hydrocarbons
Tail cement is displaced down the casing into the shoe track. The tail cement is
designed to prevent flow from the annulus into the casing. The float collar valves, which provide a second barrier, must close and seal to prevent flow up
the casing.
Shoe track had two types of mechanical barriers: cement in the shoe track and the double check valves in the float collar
Shoe track cement failed to act as a barrier due to contamination of the base slurry by break out of nitrogen from the foam slurry
Hydrocarbon influx was able to bypass the float collar check valves due to either:
Valves failed to convert orValves failed to seal
Flow through shoe confirmed by fluid modeling and Macondo static kill data
Float Collar
Check Valves
Flow Ports
Shoe track cement
Centralizers
Hydrocarbon Flow Path
Deepwater Horizon Accident Investigation 12
Hydrocarbons Entered the Well Undetected and Well Control Was Lost
Deepwater Horizon Accident Investigation 13
Sea Floor
A positive pressure test verifies the integrity of the casing and seal
assembly.
April 20th 07:00 – 12:00Casing was pressure tested to:
250 psi (low)
2700 psi (high)
Test successful
Proved integrity of blind shear rams, seal assembly, casing and wiper plug
Test does not test the shoe track due to presence of wiper plug
Kill
Cement
Mud
Spacer
2700 psi
Primary reservoir sands
Casing (Positive) Pressure Test
Deepwater Horizon Accident Investigation 14
ChokeBoost
BOP
Kill
Cement
Mud
Spacer
Seawater
Influx
Sea Floor15:56 –
16:53
424 bbls of 16 ppg
spacer followed by 30 bbls
of freshwater and 352 bbls
of seawater pumped into well
16:54 -
Close Annular
15:04 –
15:56
Seawater pumped into
Boost, Choke, and Kill lines
16:54 –
16:59
50 bbls bled off
drill pipe due to
leaking annular
Primary reservoir sands
(12.6 ppg)
April 20th 15:04 – 19:55Negative test simulates underbalanced condition
Spacer used between mud and seawater
Leaking annular at start of test moved spacer across kill line inlet
Negative test started on drill pipe but changed to kill line
Bleed volumes higher than calculated
Drill pipe built pressure to 1400 psi with no flow on the kill line
The negative-pressure test checks the integrity of the shoe track, casing and
wellhead seal assembly. This simulates conditions during temporary
abandonment when a portion of the well is displaced to seawater.
Negative Pressure Test
Deepwater Horizon Accident Investigation 15
ChokeBoost
BOP
Kill
Cement
Mud
Spacer
Seawater
Influx
Sea Floor
Cement Tank
Total
Volume
15 bbls
Primary reservoir sands
(12.6 ppg)
17:27Bled 15 bbls of
seawater from drill pipe
Decision made to
change test to kill line
April 20th 15:04 – 19:55Negative test simulates underbalanced condition
Spacer used between mud and seawater
Leaking annular at start of test moved spacer across kill line inlet
Negative test started on drill pipe but changed to kill line
Bleed volumes higher than calculated
Drill pipe built pressure to 1400 psi with no flow on the kill line
The negative-pressure test checks the integrity of the shoe track, casing and
wellhead seal assembly. This simulates conditions during temporary
abandonment when a portion of the well is displaced to seawater.
Negative Pressure Test17:52 –
18:00
Open kill
line to conduct
negative test
Bled 3 -
15 bblsinto kill line
Flow did not
stop and
“spurted”
Kill line closed
16:59 –
17:08
Annular seals with
increased hydraulic
closing pressure
Fill riser with 50 bbls of mud
17:08 –
17:27
Monitored that the
annular sealed
Deepwater Horizon Accident Investigation 16
ChokeBoost
BOP
Cement
Mud
Spacer
Seawater
Influx
Sea Floor
1400psi
Cement Tank
Total
Volume
15 bbls18 bbls
0
psi
Additional
3 bbl influx
18:00 –
18:35
Drill pipe pressure gradually
increased to 1400 psi
Primary reservoir sands
(12.6 ppg)
April 20th 15:04 – 19:55Negative test simulates underbalanced condition
Spacer used between mud and seawater
Leaking annular at start of test moved spacer across kill line inlet
Negative test started on drill pipe but changed to kill line
Bleed volumes higher than calculated
Drill pipe built pressure to 1400 psi with no flow on the kill line
The negative-pressure test checks the integrity of the shoe track, casing and
wellhead seal assembly. This simulates conditions during temporary
abandonment when a portion of the well is displaced to seawater.
Negative Pressure Test
18:42 –
19:55
Monitored kill line for 30 min
1400 psi on drill pipe described
as a “bladder effect”
19:55
Negative pressure test
was concluded and
considered a good test
18:42Pumped into kill
line to confirm full
Kill line opened for
monitoring negative test
Deepwater Horizon Accident Investigation 17
Sea Floor
Shoe – 18,304’
FC – 18,115’
TOC – 17,260’
Shoe – 17,168’
KillChokeBoost
SOBM
Spacer
Seawater
Influx
SOBM
Spacer
Seawater
Influx
BOP
1400
PSI0
PSI
Key Finding #3The negative pressure test was accepted although well integrity had not been established
Spacer
Sea Floor
Casing
Riser
BOP
Reservoir
Bleed volumes not recognized as a problem
Anomalous pressure on drill pipe with no flow from kill line
Test incorrectly accepted as successful
Negative testing not standardized
Deepwater Horizon Accident Investigation 18
Well Monitoring – Driller’s Console and Mudlogging unit
Well monitoring is performed to understand if the well has losses or gains
Driller is responsible for monitoring and shutting in the well
The mudlogger provides monitoring support to the driller
Displays and trending capability available in both Driller’s and Mudlogger’s cabins
Flow, pressure and pit sensors can indicate flow
Simultaneous activities were taking place on April 20th to prepare for rig move
Standards for monitoring do not specifically address end-of-well activities
Deepwater Horizon Accident Investigation 19
Choke
Boost
Kill
Cement
Mud
Spacer
Seawater
Mud + Seawater Mix
Influx
Sea Floor
20:00 –
21:08
Resumed pumping
Displaced riser with seawater
until spacer is at surface
21:08
Spacer arrived at surface
Shut pumps down
for sheen test
20:58 -
21:08
39 bbl gain
20:02
Annular opened
after negative
test
20:52
Well becomes underbalanced
Primary reservoir sands
(12.6 ppg)
BOP
Mud in the riser is displaced with seawater in preparation for temporary
abandonment.
April 20th 19:55 – 21:14
20:02 Resume displacement of mud with seawater
20:52 Well becomes underbalanced and starts to flow
After 20:58 gain being taken and pressure begins increasing
–
Flow from well masked by emptying of trip tank
21:08 Pumping stops for sheen test
–
Pressure increases with pump off
21:14 Sheen test complete, displacement resumes
Undetected Flowing Conditions
Deepwater Horizon Accident Investigation 20
Flow Indications
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20:4
5
20:5
0
20:5
5
21:0
0
21:0
5
21:1
0
21:1
5
21:2
0
21:2
5
21:3
0
21:3
5
Flow
Rat
e (g
pm)
0
500
1000
1500
2000
2500
3000
Pum
p Pr
essu
re (p
si)
Flow Out (calibrated)Flow In (rig pumps)DP Press (rig pumps)
Key Finding #4The influx was not recognized until hydrocarbons were in the riser
Flow indications:
#1: Drill pipe pressure increased by 100 psi, (expected decreased); ~39 bbl gain from 20:58 to 21:08
21:08
1,017 psi
SOBM (mud)
Seawater
Influx
SOBM + seawater mix
39 bbl
300 bbl
Cumulative Gain
Indication #1
0 bbl
20:52-Flow starts
Decreasing trend should have continued
Based on Real-time Data
Deepwater Horizon Accident Investigation 21
Flow Indications
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20:4
5
20:5
0
20:5
5
21:0
0
21:0
5
21:1
0
21:1
5
21:2
0
21:2
5
21:3
0
21:3
5
Flow
Rat
e (g
pm)
0
500
1000
1500
2000
2500
3000
Pum
p Pr
essu
re (p
si)
Flow Out (calibrated)Flow In (rig pumps)DP Press (rig pumps)
Key Finding #4The influx was not recognized until hydrocarbons were in the riser
Flow indications:
#1: Drill pipe pressure increased by 100 psi, (expected decreased); ~39 bbl gain from 20:58 to 21:08
#2: Drill pipe pressure increased by 246 psi with pumps off
–
Flow out does not immediately drop after shutting down pump
21:08
1,017 psi
SOBM (mud)
Seawater
Influx
SOBM + seawater mix
39 bbl
300 bbl
Cumulative Gain
Indication #1
Indication #2
0 bbl
20:52-Flow starts
Decreasing trend should have continued
Overboard line openedFlow out available only
to driller after 21:10
Based on Real-time Data
Normal Flow Back
0
200
400
600
800
1000
1200
16:5
0
16:5
5
17:0
0
17:0
5
Flow
Rat
e (g
pm) Flow Out
Flow In
Deepwater Horizon Accident Investigation 22
Flow Indications
0
200
400
600
800
1000
1200
1400
1600
1800
2000
20:4
5
20:5
0
20:5
5
21:0
0
21:0
5
21:1
0
21:1
5
21:2
0
21:2
5
21:3
0
21:3
5
Flow
Rat
e (g
pm)
0
500
1000
1500
2000
2500
3000
Pum
p Pr
essu
re (p
si)
Flow Out (calibrated)Flow In (rig pumps)DP Press (rig pumps)
Key Finding #4The influx was not recognized until hydrocarbons were in the riser
Flow indications:
#1: Drill pipe pressure increased by 100 psi, (expected decreased); ~39 bbl gain from 20:58 to 21:08
#2: Drill pipe pressure increased by 246 psi with pumps off
–
Flow out does not immediately drop after shutting down pump
#3: Drill pipe pressure increased by 556 psi with pumps off; ~300 bbl gain
No well control actions taken
21:08
1,017 psi
21:31
1,200 psi
SOBM (mud)
Seawater
Influx
SOBM + seawater mix
39 bbl
300 bbl
Cumulative Gain
Indication #1
Indication #2
0 bbl
Indication #3
20:52-Flow starts
Based on Real-time Data
Deepwater Horizon Accident Investigation 23
0
500
1000
1500
2000
2500
3000
21:3
0
21:3
2
21:3
4
21:3
6
21:3
8
21:4
0
21:4
2
21:4
4
21:4
6
21:4
8
21:5
0
Drill Pipe Presssure (psi)
Pumps shut down
Discussion about “Differential Pressure”
Attempt to bleed pressure
Close Drill Pipe
Mud overflowing onto rig floor
BOP Sealing
Pressure increase due to annular activation
BOP
Key Finding #5Well control response actions failed to regain control of the well
Exp
losi
on
at
21:4
9
-
Mud and water raining onto deck
-
TP calls WSL, getting mud back, diverted to MGS, closed or was closing annular
-
AD calls Senior TP, Well blowing out, TP is shutting it in now
Mud shoots up derrick-Diverter closed-BOP activated
First indication of well control response:49 minutes and 1000 bbls after initial influx
Influx enters riser
Annular leaking
Based on Real-time Data
Deepwater Horizon Accident Investigation 24
Hydrocarbons Ignited on the Deepwater Horizon
Deepwater Horizon Accident Investigation 25
When responding to a well control event the riser diverter is closed and fluids
sent to either the mud gas separator or to the overboard diverter lines.
KillBoost
Choke
BOP
14”
Diverter LinePort
Overboard 14”
Diverter Line
Mud
System
Starboard Overboard
6”
Vacuum
Breaker
Rated to 60 psi
working pressure
IBOP
Slip Joint
Rotary
Hose
Diverter
12”
Vent
MGS
Bursting Disk
Starboard Overboard
Rated to 100 or 500 psiOverboard
Caisson
Diversion to the MGS
Rig crew has the option to divert flow to port/starboard overboard lines or the MGS
Diverting to port or starboard will result in fluids venting overboard
Liquid outlet from MGS goes to the Mud System under the main deck
Seawater
Seawater/Mud Mix
Influx
Diverting to the Mud Gas Separator at about 21:42
Deepwater Horizon Accident Investigation 26
Hydrocarbon flow from surface equipment
Instantaneous gas rates reached 165 mmscfd
Pressures exceeded operating ratings (above 100 psi)
Gas would probably have vented from:
Slip joint packer into the moon pool
12” MGS “gooseneck” vent
6” MGS vacuum breaker vent
6” overboard line through burst disk
10” mud line under the main deck
When responding to a well control event the riser diverter is closed and fluids
sent to either the mud gas separator or to the overboard diverter lines.
KillBoost
Choke
BOP
14”
Diverter LinePort
Overboard 14”
Diverter Line
Mud
System
Starboard Overboard
6”
Vacuum
Breaker
IBOP
Rotary
Hose
Diverter
12”
Vent
MGS
Bursting Disk
Starboard Overboard
Overboard
Caisson
Slip Joint
Seawater
Seawater/Mud Mix
Influx
Gas flow to Surface at high rate: 21:46 to 22:00
Deepwater Horizon Accident Investigation 27
Animation of Gas Dispersion
Upper Explosive Limit
Lower Explosive Limit
Cut Section Through Derrick Towards Aft3D View
Gas Dispersion across the Deepwater Horizon 21:46 to 21:50 hrs
Deepwater Horizon Accident Investigation 28
Aft
Fwd
3D view
Secondary Protective Systems
Gas cloud reached the supply air intakes for engine rooms 3, 4, 5 & 6
The Fire and Gas system did not automatically trigger a shutdown of the HVAC system for the engine rooms
Limited areas of the rig are designated as electrically classified zones
Secondary protective systems are designed to reduce the potential
consequence of an event once the primary protective systems have failed.
Secondary protective systems did not prevent ignition
Deepwater Horizon Accident Investigation 29
Hydrocarbons were routed to the mud gas separator instead of diverting overboard
Resulted in rapid gas dispersion across the rig through the MGS vents and mud system
Key Finding #6Diversion to the mud gas separator resulted in gas venting onto the rig
When responding to a well control event the riser diverter is closed and fluids are sent to either the mud gas separator or
to the overboard diverter lines.
KillBoost
Choke
BOP
14”
Diverter LinePort
Overboard 14”
Diverter Line
Mud
System
Starboard Overboard
6”
Vacuum
Breaker
IBOP
Rotary
Hose
Diverter
12”
Vent
MGS
Bursting Disk
Starboard Overboard
Overboard
Caisson
Slip Joint
Seawater
Seawater/Mud Mix
Influx
BOP Sealed at
21:47
Deepwater Horizon Accident Investigation 30
Key Finding #7The fire and gas system did not prevent hydrocarbon ignition
Gas dispersion beyond electrically classified areas
Gas ingress into engine rooms via main deck air intakes
The on-line engines were one potential source of ignition
Aft
Fwd3D view
Aft
Aft
Gas Dispersion at 4 minutes
Fwd3D view
Section through derrick
(Upper Explosive Limit)
(Lower Explosive Limit)
Secondary protective systems are designed to reduce the potential
consequence of an event once the primary protective systems have
failed.
Deepwater Horizon Accident Investigation 31
Emergency Well Control System Did Not Seal the Well
Deepwater Horizon Accident Investigation 32
Blowout Preventer (BOP)
Surface HPU & Accumulators
Lower Stack Accumulators
Mux Cable
Blue Control
Pod
Yellow Control
Pod
Hydraulic Conduit
LMRP Accumulators
BOP Control Panel
Manual Automatic ROV Intervention
EDS
HP BSR Close AMF
HOT StabAMF
Auto-shear
Emergency Methods of BOP Operation Available on DW Horizon
Sea Bed
Wellhead Connector
Wellhead
Upper Annular
Lower Annular
Stripping Element
Casing Shear Ram
(Non Sealing)
Upper VBR
Middle VBR
Lower (Test) VBR
Blind Shear Ram
Flex Joint LMRP
BOP Stack
Deepwater Horizon Accident Investigation 33Sea Bed
Wellhead Connector
Wellhead
Upper Annular
Lower Annular
Stripping Element
Casing Shear Ram
(Non Sealing)
Upper VBR
Middle VBR
Lower (Test) VBR
Blind Shear Ram
BOP is designed to seal the wellbore and shear casing or drill pipe if necessary.
April 20th
21:41 annular BOP closed but appears not to have sealed the annulus
21:47 a VBR likely closed and sealed the annulus
Activation of
Lower Annular BOP
Activation of VBR
April 20th
21:38 –
Hydrocarbons
enter the riser
BOP Response (Before the Explosions)
Deepwater Horizon Accident Investigation 34Sea Bed
Wellhead Connector
Wellhead
Upper Annular
Lower Annular
Stripping Element
Casing Shear Ram
(Non Sealing)
Upper VBR
Middle VBR
Lower (Test) VBR
Blind Shear Ram
MUX cables provide electronic communication and electrical power to
the BOP control pods.
Annular BOP
gradually opens
BOP Response (Impact of Explosions)
April 20th
Damage to MUX cables and hydraulic line
–
Opening of annular BOP
Rig drifted off location
–
Upward movement of the drill pipe in the BOP
Deepwater Horizon Accident Investigation 35Sea Bed
April 20th
EDS attempts failed to activate BSR
AMF sequence likely failed to activate BSR
April 21st – 22nd
ROV hot stab attempts to close BOP were ineffective
ROV simulated AMF function likely failed to activate BSR
ROV activated auto-shear appears to have activated but did not seal the well
April 25th – May 5th
Further ROV attempts using seabed deployed accumulators were unsuccessful
Wellhead Connector
Wellhead
Upper Annular
Lower Annular
Stripping Element
Casing Shear Ram
(Non Sealing)
Upper VBR
Middle VBR
Lower (Test) VBR
Blind Shear Ram
BSR activated byAuto-shear
BOP Response (After the Explosions)
There are several emergency methods of activating the BSR to seal the well.
Deepwater Horizon Accident Investigation 36
AMF
Key Finding #8The BOP emergency mode did not seal the well
EDS function was inoperable due to damage to MUX cables
AMF could not activate the BSR due to defects in both control pods
Auto-shear appears to have activated the BSR but did not seal the well
Potential weaknesses found in the BOP testing regime and maintenance management systems
The AMF provides an automatic means of closing the BSR without
crew intervention.
Manual Automatic ROV Intervention
EDS
HP BSR Close
Emergency Methods of BOP Operation Available on DW Horizon
HOT StabAMF
Auto-shear
Damaged MUX Cable
Blue Control
Pod
Yellow Control
Pod
Damaged Hydraulic Conduit
Explosions & Fire: Loss of communicationLoss of electrical power
Loss of hydraulics
Deepwater Horizon Accident Investigation 37
Summary of Findings and Recommendations
Deepwater Horizon Accident Investigation 38
Recommendations25 Recommendations Specific to the 8 Key Findings
BP Drilling Operating Practice and Management SystemsEngineering Technical Practices and Procedures
Further Enhance Deepwater Capability and Proficiency
Strengthen Rig Audit Action Closeout and Verification
Introduce Integrity Performance Management for Drilling and Wells Activities
Contractor and Service Provider Oversight and AssuranceCementing Services
Drilling Contractor Well Control Practices and Proficiency
Oversight of Rig Safety Critical Equipment
BOP Configuration and Capability
BOP Minimum Criteria for Testing, Maintenance, System Modifications and Performance Reliability
BP has accepted all the recommendations and is reviewing how best to implement across its world wide operations
Deepwater Horizon Accident Investigation 39
Well integrity was not established or failed−
Annulus cement barrier did not isolate hydrocarbons
−
Shoe track barriers did not isolate hydrocarbons
Hydrocarbons entered the well undetected and well control was lost−
Negative pressure test was accepted although well integrity had not been established
−
Influx was not recognized until hydrocarbons were in riser
−
Well control response actions failed to regain control of well
Hydrocarbons ignited on the Deepwater Horizon−
Diversion to mud gas separator resulted in gas venting onto rig
−
Fire and gas system did not prevent hydrocarbon ignition
Blowout preventer did not seal the well−
Blowout preventer (BOP) emergency modes did not seal well
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Sea Floor
Casing
Riser
BOP
Reservoir1
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Summary of Key Findings
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