Deepwater horizon accident_investigation_static_presentation

Deepwater Horizon Investigation

Deepwater Horizon Accident Investigation 1

Investigation Context

Terms of Reference

Investigation Team

Data and Analysis

Investigation Limitations


Eight Barriers Were Breached
Well integrity was not established or failed
6 7 − Annulus cement barrier did not isolate hydrocarbons
1
3 5
− Shoe track barriers did not isolate hydrocarbons
2

Hydrocarbons entered the well undetected and
Riser
4 well control was lost
− Negative pressure test was accepted although well
3
8
integrity had not been established
BOP
Sea Floor − Influx was not recognized until hydrocarbons were in
4
riser
− Well control response actions failed to regain control of
5
Casing
well

Hydrocarbons ignited on the Deepwater Horizon
− Diversion to mud gas separator resulted in gas venting
6
onto rig
− Fire and gas system did not prevent hydrocarbon
7
ignition

Blowout preventer did not seal the well
1
Reservoir − Blowout preventer (BOP) emergency mode did not
8
seal well
2 Deepwater Horizon Accident Investigation 3

Introduction
Technical Presentation


Well Integrity Was Not Established
or Failed


Production Casing Installation
After drilling to total depth, casing is run to
bottom in preparation for the cement job. A
Choke
double valve float collar is used to prevent
Kill
Boost backflow or ingress of fluids through the
shoe track until the cement hardens and
creates a permanent barrier.
BOP
April 18th 00:30 – April 19th 19:30
Sea Floor 17:30 – 19:30 Long string design robust, consistent with
Circulated prior
Cement 36” to cement job similar wells in the area
Mud 9 attempts made to establish circulation
28”

Spacer
to convert float valves
22”

Circulate ~6 times open hole volume,
18”

limited circulation due to concerns over
16”
creating losses and hole washout
13-5/8”

No evidence that hydrocarbons entered
11-7/8”
the wellbore prior to the cementing
9-7/8”
operation
14.17 ppg
SOBM

Primary reservoir
sands
(12.6 ppg)

Bottoms–up
Marker

Cement Job
Cement is pumped down casing through
the float collar and up the annulus to
isolate the primary reservoir sands.
Choke Pull out of hole
Kill April 19th 19:30 – April 20th 07:00
Boost with running
tool and drill Nitrogen cement slurry chosen
pipe
– To achieve light weight slurry due to
BOP Set and test limited pore pressure / fracture
casing hanger
seal assembly
gradient window
Sea Floor
00:35 – 02:50
Possible risk
36” Drill-Quip seal assembly installed – Stability of foam
Base Oil and successfully tested.
Centralizer
No lock down sleeve installed. – Relatively small volume
Spacer 28”

02:50 – 07:00 – Susceptible to contamination
Cap
Pull out hole with drill pipe.
Cement 22” Mitigation of risk by
Foamed 18”
– Thorough testing of slurry design
Cement
Bottoms–up
16” Marker – Precise placement
Tail Cement
Mud 13-5/8” Centralization
Primary
Nitrogen 11-7/8”
Reservoir – 6 inline centralizers spaced across
Breakout Sands the reservoir sands
Shoe – 17,168’
(12.6 ppg)
Top of
9-7/8” cement 17,260’ – Additional centralizers not run
because incorrectly thought to be
wrong type
Primary reservoir
Float Collar – 18,115’ 6 centralizers sands – Risk of channeling above reservoir
(12.6 ppg)
sands known and accepted
Shoe – 18,304’

Key Finding #1
The annulus cement barrier did not isolate the reservoir hydrocarbons
Cement is pumped down the
Cement Slurry Placement landing string and casing into the
Base Oil
ppg
16.7ppg
6.7
annulus to isolate hydrocarbon
bearing sands.
Spacer
14.3 ppg
Riser 14.3 ppg
Cap
Cement Mud
Channeling 16.74 ppg
Foam slurry recommended was a
14.17 ppg Cap
Cement
complex design
16.74 ppg

BOP
Risk of contamination using small
Sea Floor Foam volume of cement
Cement
Foam
14.5 ppg
Cement No fluid loss additives
14.5 ppg
Incomplete pre-job cement lab
Casing Centralizers
Spacer testing
14.3 ppg
Foam slurry was likely unstable
Float Collar
Top Wiper Plug
Top Wiper Plug and resulted in nitrogen breakout
Bottom Wiper Plug
Bottom Wiper Plug Shoe

Tail Cement Track
16.74 ppg 12.6 ppg Shoe
Track

Reservoir Reamer Shoe Tail Cement

Nitrogen Breakout

Cement Slurry Design Issues

An independent lab completed over 500
tests on a representative cement slurry and
reported the following:

50% quality foam at surface conditions
Original Height
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
Final Height 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)
Cement

Note: QUALITY = Nitrogen Volume /
(Nitrogen + Base Slurry Volume)

Unstable Foam Sample

Flow Through Shoe Track - Supporting Evidence

Casing Key Observations for Flow Seal
Shoe Through Shoe vs. Seal Assembly
Failure Assembly Failure

Y Mechanical Barrier
Failure Mode Identified Y
Y
Realistic Net Pay
Assumption N
Y
1400 psi recorded on
drill pipe during negative N
test at 18:30

Y
Ability to flow from
20:58 N
Y
Pressure Increase from
21:08 to 21:14 N
16ppg Spacer Y
Pressure Response from
21:31 to 21:34 N
14.17ppg SOBM (Mud)
8.6ppg Seawater
Influx
Y
Timing for Gas Arrival to
Surface N
Seal
N
Casing Static Kill
Shoe
Failure
Y Assembly
Failure


Key Finding #2
The 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,
Riser
must close and seal to prevent flow up
Hydrocarbon Flow the casing.
Path
Shoe track had two types of mechanical
BOP Float Collar
barriers: cement in the shoe track and the
Sea Floor
double check valves in the float collar
Shoe track cement failed to act as a
Check Valves
Casing barrier due to contamination of the base
slurry by break out of nitrogen from the
foam slurry

Shoe track cement
Hydrocarbon influx was able to bypass
the float collar check valves due to either:
Valves failed to convert or
Valves failed to seal
Centralizers
Flow through shoe confirmed by fluid
modeling and Macondo static kill data

Reservoir

Flow Ports

Hydrocarbons Entered the Well
Undetected and Well Control Was Lost


Casing (Positive) Pressure Test
2700
psi

Kill
A positive pressure test verifies the
integrity of the casing and seal
assembly.

April 20th 07:00 – 12:00
Sea Floor
Casing was pressure tested to:

Cement
250 psi (low)
Mud 2700 psi (high)
Spacer 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

Primary
reservoir sands


Negative Pressure Test
The negative-pressure test checks the
integrity of the shoe track, casing and
wellhead seal assembly. This simulates
Choke
Boost
Kill
15:04 – 15:56 conditions during temporary
Seawater pumped into abandonment when a portion of the well
Boost, Choke, and Kill lines
is displaced to seawater.
BOP
April 20th 15:04 – 19:55
16:54 - Close Annular

Sea Floor
Negative test simulates underbalanced
15:56 – 16:53
424 bbls of 16 ppg
condition
spacer followed by 30 bbls
Cement of freshwater and 352 bbls
Spacer used between mud and seawater
of seawater pumped into well
Mud Leaking annular at start of test moved
Spacer 16:54 – 16:59 spacer across kill line inlet
50 bbls bled off
Seawater drill pipe due to Negative test started on drill pipe but
Influx leaking annular changed to kill line
Bleed volumes higher than calculated
Drill pipe built pressure to 1400 psi with
no flow on the kill line

Primary reservoir
sands
(12.6 ppg)


17:52 – 18:00 integrity of the shoe track, casing and
Open kill
line to conduct wellhead seal assembly. This simulates
Choke
negative test Kill conditions during temporary
Boost

16:59 – 17:08 abandonment when a portion of the well
Bled 3 - 15 bbls
into kill line
Annular seals with is displaced to seawater.
increased hydraulic
BOP
closing pressure
Flow did not April 20th 15:04 – 19:55
stop and
Fill riser with 50 bbls of mud
“spurted” Negative test simulates underbalanced
Sea Floor

Kill line closed
17:08 – 17:27 condition
Monitored that the
Cement
annular sealed Spacer used between mud and seawater
Mud 17:27 Leaking annular at start of test moved
Bled 15 bbls of spacer across kill line inlet
Spacer
seawater from drill pipe
Seawater Negative test started on drill pipe but
Decision made to
Influx change test to kill line changed to kill line
Cement
Tank Total
Volume

15 bbls

Primary reservoir
sands
(12.6 ppg)


1400 0 integrity of the shoe track, casing and
psi psi
18:00 – 18:35 wellhead seal assembly. This simulates
Choke Drill pipe pressure gradually
Boost increased to 1400 psi
conditions during temporary
abandonment when a portion of the well
18:42
is displaced to seawater.
BOP Pumped into kill
line to confirm full April 20th 15:04 – 19:55
Kill line opened for
Sea Floor monitoring negative test Negative test simulates underbalanced
condition

Cement 18:42 – 19:55 Spacer used between mud and seawater
Monitored kill line for 30 min
Mud 1400 psi on drill pipe described Leaking annular at start of test moved
as a “bladder effect” spacer across kill line inlet
Spacer
Seawater 19:55
Negative pressure test
Negative test started on drill pipe but
Influx was concluded and changed to kill line
considered a good test
Cement
Tank Total
Volume
18 bbls Additional
15 bbls 3 bbl influx

Primary reservoir
sands
(12.6 ppg)


Key Finding #3
The negative pressure test was accepted although well integrity had
not been established

1400 0
PSI PSI
Riser

Choke Kill Bleed volumes not recognized as a
Boost

problem
BOP
Sea Floor

BOP
Anomalous pressure on drill pipe with no
Sea Floor
flow from kill line
Spacer
Casing SOBM Test incorrectly accepted as successful
Spacer
Seawater Negative testing not standardized
Influx

Shoe – 17,168’

TOC – 17,260’

FC – 18,115’

Reservoir

Shoe – 18,304’


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


Undetected Flowing Conditions
Mud in the riser is displaced with
seawater in preparation for temporary
abandonment.
Choke Kill

Boost 21:08
Spacer arrived at surface April 20th 19:55 – 21:14
Shut pumps down
for sheen test
BOP 20:02 Resume displacement of mud with
20:02 seawater
Sea Floor
Annular opened
after negative
test
20:52 Well becomes underbalanced and
starts to flow
Cement 20:00 – 21:08
Resumed pumping
Mud Displaced riser with seawater After 20:58 gain being taken and pressure
Spacer until spacer is at surface
begins increasing
Seawater
20:52 – Flow from well masked by emptying
Mud + Seawater Well becomes underbalanced
of trip tank
Mix
Influx 21:08 Pumping stops for sheen test
– Pressure increases with pump off
20:58 - 21:08
39 bbl gain 21:14 Sheen test complete, displacement
resumes

Primary reservoir
sands
(12.6 ppg)


Key Finding #4
The influx was not recognized until hydrocarbons were in the riser
2000 3000
Flow Indications
Based on Real-time Data Flow indications:
Flow Out (calibrated)
1800
Flow In (rig pumps)
DP Press (rig pumps)
2500 #1: Drill pipe pressure
1600
increased by 100 psi,
Decreasing trend should
1400 (expected decreased);

Pump Pressure (psi)
have continued 2000
~39 bbl gain from 20:58
Flow Rate (gpm)

1200
Indication #1 to 21:08
1000 1500

800
1000
600

400
20:52-Flow starts 500
200

Cumulative Gain
0
0 39 300 0
bbl bbl bbl
20:45

20:50

20:55

21:00

21:05

21:10

21:15

21:20

21:25

21:30

21:35
1,017 psi

SOBM (mud)
Seawater
Influx
SOBM + seawater mix

21:08


Key Finding #4
2000 3000
Flow Indications
1800
Flow In (rig pumps)
1600
Decreasing trend should
1400 (expected decreased);

Pump Pressure (psi)
have continued 2000
Flow Rate (gpm)

1200
1000 1500

Indication #2 increased by 246 psi with
1000
600
Overboard line opened pumps off
400
20:52-Flow starts Flow out available only
500
to driller after 21:10 – Flow out does not
200
immediately drop
Cumulative Gain 0 39 300
0
bbl bbl bbl
0 after shutting down
20:45

20:50

20:55

21:00

21:05

21:10

21:15

21:20

21:25

21:30

21:35
pump
1,017 psi
1200 Normal Flow Back
1000 Flow Out
Flow Rate (gpm)

Flow In
800
SOBM (mud)
Seawater
600
Influx
SOBM + seawater mix
400

200
21:08
0
16:50

16:55

17:00

17:05


Key Finding #4
2000 3000
Flow Indications
1800
Flow In (rig pumps)
1600
1400
Indication #3 (expected decreased);

Pump Pressure (psi)
2000
Flow Rate (gpm)

1200
1000 1500

Indication #2 increased by 246 psi with
1000
600
pumps off
400
20:52-Flow starts 500
– Flow out does not
200
immediately drop
Cumulative Gain 0 39 300
0
bbl bbl bbl
0 after shutting down
20:45

20:50

20:55

21:00

21:05

21:10

21:15

21:20

21:25

21:30

21:35
pump
1,017 psi 1,200 psi
#3: Drill pipe pressure
increased by 556 psi with
pumps off; ~300 bbl gain

SOBM (mud)
Seawater
No well control actions taken
Influx
SOBM + seawater mix

21:08 21:31


Key Finding #5
Well control response actions failed to regain control of the well

Influx enters riser
3000 Based on Real-time Data First indication of well control response:
49 minutes and 1000 bbls after initial influx
Drill Pipe Presssure (psi)
2500 BOP
Mud shoots up derrick
Attempt to bleed -Diverter closed
pressure -BOP activated
2000

Explosion at 21:49
Close Drill Pipe
BOP Sealing
1500

Annular
Discussion about leaking
1000 “Differential Pressure”
- Mud and water raining onto deck
Mud overflowing
onto rig floor - TP calls WSL, getting mud back,
500 diverted to MGS, closed or was
Pumps shut down closing annular

Pressure increase due - AD calls Senior TP, Well blowing
0 to annular activation out, TP is shutting it in now
21:30

21:32

21:34

21:36

21:38

21:40

21:42

21:44

21:46

21:48

21:50

Hydrocarbons Ignited on the
Deepwater Horizon


Diverting to the Mud Gas Separator at about 21:42
12” Vent When responding to a well control event
the riser diverter is closed and fluids
6” Vacuum
Breaker sent to either the mud gas separator or
Bursting Disk to the overboard diverter lines.

Diversion to the MGS
MGS Rated to 60 psi
working pressure Rig crew has the option to divert flow to
Rotary
Hose
Mud port/starboard overboard lines or the
System IBOP
MGS
Starboard
Diverter Overboard Diverting to port or starboard will result in
Starboard
fluids venting overboard
Port
Overboard 14” Diverter Line 14” Diverter Line Overboard

Slip Joint Rated to 100 or 500 psi Liquid outlet from MGS goes to the Mud
Overboard
Caisson Boost Kill
System under the main deck
Choke

BOP

Seawater
Seawater/Mud Mix
Influx


Gas flow to Surface at high rate: 21:46 to 22:00
12” Vent When responding to a well control event
the riser diverter is closed and fluids
6” Vacuum
Breaker sent to either the mud gas separator or
Bursting Disk to the overboard diverter lines.

Hydrocarbon flow from surface
MGS
equipment
Rotary
Hose
Mud
Instantaneous gas rates reached
System IBOP
165 mmscfd
Starboard
Diverter
Overboard Pressures exceeded operating ratings
(above 100 psi)
Port Starboard
Gas would probably have vented from:
Slip Joint
Overboard
Caisson Boost Kill Slip joint packer into the moon pool
Choke 12” MGS “gooseneck” vent
BOP
6” MGS vacuum breaker vent
6” overboard line through burst disk
Seawater
10” mud line under the main deck
Seawater/Mud Mix
Influx


Gas Dispersion across the Deepwater Horizon 21:46 to 21:50 hrs

Animation of Gas Dispersion

Upper Explosive Limit

Lower Explosive Limit

3D View Cut Section Through Derrick Towards Aft


Secondary protective systems did not prevent ignition
Secondary protective systems are
designed to reduce the potential
consequence of an event once the
3D view primary protective systems have failed.

Fwd

Aft

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


Key Finding #6
Diversion to the mud gas separator resulted in gas venting onto the
12” Vent
rig
6” Vacuum
Breaker When responding to a well control event
Bursting Disk the riser diverter is closed and fluids are
sent to either the mud gas separator or
to the overboard diverter lines.
MGS

Rotary
Hose Hydrocarbons were routed to the mud gas
Mud
System IBOP separator instead of diverting overboard
Starboard Resulted in rapid gas dispersion across
Diverter Overboard
the rig through the MGS vents and mud
system
Port Starboard

Slip Joint
Overboard
Caisson Boost Kill

Choke

BOP

BOP
Sealed at
Seawater 21:47
Seawater/Mud Mix
Influx


Key Finding #7
The fire and gas system did not prevent hydrocarbon ignition
Gas Dispersion at 4 minutes
Secondary protective systems are
designed to reduce the potential
(Upper Explosive Limit) consequence of an event once the
primary protective systems have
Aft failed.
Gas dispersion beyond electrically
classified areas
Section through derrick
3D view Gas ingress into engine rooms via main
(Lower Explosive Limit)
Fwd
deck air intakes

The on-line engines were one potential
source of ignition

Fwd
3D view
Aft

Aft


Emergency Well Control System
Did Not Seal the Well


Blowout Preventer (BOP)
BOP Control Panel

Surface HPU &
Accumulators Flex Joint LMRP
Upper Annular

Lower Annular
Stripping Element
Mux Cable
Hydraulic Conduit
LMRP
Accumulators

Blind Shear Ram
Blue Yellow
Control Control
Casing Shear Ram
Pod Pod (Non Sealing)
Upper VBR

Lower Stack Middle VBR
Accumulators Lower (Test) VBR
BOP
Stack
Emergency Methods of BOP Operation Available on DW Horizon Wellhead Connector

Manual Automatic ROV Intervention
Wellhead
HOT Stab
EDS
AMF AMF Sea Bed
HP BSR Close
Auto-shear

BOP Response (Before the Explosions)
BOP is designed to seal the wellbore and
20th
April shear casing or drill pipe if necessary.
21:38 – Hydrocarbons
enter the riser
April 20th
21:41 annular BOP closed but appears
Activation of
Upper Annular
Lower Annular BOP not to have sealed the annulus

Lower Annular
21:47 a VBR likely closed and sealed the
Stripping Element
annulus

Blind Shear Ram

Casing Shear Ram Activation of VBR
(Non Sealing)

Upper VBR

Middle VBR

Lower (Test) VBR

Wellhead Connector

Wellhead

Sea Bed Deepwater Horizon Accident Investigation 33

BOP Response (Impact of Explosions)
MUX cables provide electronic
communication and electrical power to
the BOP control pods.

April 20th
Damage to MUX cables and hydraulic line
Upper Annular

– Opening of annular BOP
Lower Annular
Annular BOP
Stripping Element gradually opens
Rig drifted off location
– Upward movement of the drill pipe in
the BOP
Blind Shear Ram

Casing Shear Ram
(Non Sealing)

Upper VBR

Middle VBR

Lower (Test) VBR

Wellhead Connector

Wellhead


BOP Response (After the Explosions)
There are several emergency methods of
activating the BSR to seal the well.

April 20th
EDS attempts failed to activate BSR
Upper Annular
AMF sequence likely failed to activate BSR

Lower Annular
April 21st – 22nd
Stripping Element

BSR activated by ROV hot stab attempts to close BOP were
Auto-shear
ineffective
ROV simulated AMF function likely failed to
Blind Shear Ram activate BSR
Casing Shear Ram
(Non Sealing) ROV activated auto-shear appears to have
Upper VBR
activated but did not seal the well
Middle VBR
April 25th – May 5th
Lower (Test) VBR
Further ROV attempts using seabed
deployed accumulators were unsuccessful
Wellhead Connector

Wellhead


Key Finding #8
The BOP emergency mode did not seal the well
Explosions & Fire: The AMF provides an automatic
Loss of communication means of closing the BSR without
Loss of electrical power crew intervention.
Loss of hydraulics

EDS function was inoperable due to
Damaged Hydraulic Conduit
damage to MUX cables

Damaged MUX Cable AMF could not activate the BSR due to
defects in both control pods

Auto-shear appears to have activated
Blue Yellow the BSR but did not seal the well
Control Control
Pod Pod
Potential weaknesses found in the
BOP testing regime and maintenance
management systems

Emergency Methods of BOP Operation Available on DW Horizon

Manual Automatic ROV Intervention

HOT Stab
EDS
AMF AMF
HP BSR Close
Auto-shear

Summary of Findings and
Recommendations


Recommendations
25 Recommendations Specific to the 8 Key Findings

BP Drilling Operating Practice and Management Systems
Engineering 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 Assurance
Cementing 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


Summary of Key Findings
Well integrity was not established or failed
6 7 − Annulus cement barrier did not isolate hydrocarbons
1
3 5
− Shoe track barriers did not isolate hydrocarbons
2

Hydrocarbons entered the well undetected and
Riser
4 well control was lost
− Negative pressure test was accepted although well
3
8
integrity had not been established
BOP
Sea Floor − Influx was not recognized until hydrocarbons were in
4
riser
− Well control response actions failed to regain control of
5
Casing
well

Hydrocarbons ignited on the Deepwater Horizon
− Diversion to mud gas separator resulted in gas venting
6
onto rig
− Fire and gas system did not prevent hydrocarbon
7
ignition

Blowout preventer did not seal the well
1
Reservoir − Blowout preventer (BOP) emergency modes did not
8
seal well
2 Deepwater Horizon Accident Investigation 39

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