BP plc · LSE:BP.
BP — Technical Presentation (September 2010)
39 slides from BP's technical presentation, September 2010
Slide 1: Deepwater Horizon Investigation
Deepwater Horizon Investigation Deepwater Horizon Accident Investigation 1
Slide 2: Investigation Context
Investigation Context Terms of Reference Investigation Team Data and Analysis Investigation Limitations Deepwater Horizon Accident Investigation 2
Slide 3: Eight Barriers Were Breached
Eight Barriers Were Breached Well integrity was not established or failed 6 7 − 1 Annulus cement barrier did not isolate hydrocarbons 3 5 − 2 Shoe track barriers did not isolate hydrocarbons Hydrocarbons entered the well undetected and Riser 4 well control was lost − 3 Negative pressure test was acc
Slide 4: Introduction Technical Presentation
Introduction Technical Presentation Deepwater Horizon Accident Investigation 4
Slide 5: Well Integrity Was Not Established or Failed
Well Integrity Was Not Established or Failed Deepwater Horizon Accident Investigation 5
Slide 6: Production Casing Installation
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
Slide 7: Cement Job
Cement Job Cement is pumped down casing through the float collar and up the annulus to isolate the primary reservoir sands. Choke Pull out ofKillhole 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
Slide 8: Key Finding #1
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 16.7 ppg 6.7 ppg annulus to isolate hydrocarbon bearing sands. Spacer 14.3 ppg Riser 14.3 ppg Cap Cement Channeling Mud 1
Slide 9: Cement Slurry Design Issues
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
Slide 10: Flow Through Shoe Track - Supporting Evidence
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
Slide 11: Key Finding #2
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
Slide 12: Hydrocarbons Entered the Well Undetected and Well Control Was Lost
Hydrocarbons Entered the Well Undetected and Well Control Was Lost Deepwater Horizon Accident Investigation 12
Slide 13: Casing (Positive) Pressure Test
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 r
Slide 14: Negative Pressure Test
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
Slide 15: Negative Pressure Test
Negative Pressure Test The negative-pressure test checks the 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 -
Slide 16: Negative Pressure Test
Negative Pressure Test The negative-pressure test checks the 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
Slide 17: Key Finding #3
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 Te
Slide 18: Well Monitoring – Driller's Console and Mudlogging unit
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 availabl
Slide 19: Undetected Flowing Conditions
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 op
Slide 20: Key Finding #4
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
Slide 21: Key Finding #4
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
Slide 22: Key Finding #4
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, 1400 Indication #3 2000
Slide 23: Key Finding #5
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 -Dive
Slide 24: Hydrocarbons Ignited on the Deepwater Horizon
Hydrocarbons Ignited on the Deepwater Horizon Deepwater Horizon Accident Investigation 24
Slide 25: Diverting to the Mud Gas Separator at about 21:42
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 pressur
Slide 26: Gas flow to Surface at high rate: 21:46 to 22:00
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 M
Slide 27: Gas Dispersion across the Deepwater Horizon 21:46 to 21:50 hrs
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 Deepwater Horizon Accident Investigation 27
Slide 28: Secondary protective systems did not prevent ignition
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,
Slide 29: Key Finding #6
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
Slide 30: Key Finding #7
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 elect
Slide 31: Emergency Well Control System Did Not Seal the Well
Emergency Well Control System Did Not Seal the Well Deepwater Horizon Accident Investigation 31
Slide 32: Blowout Preventer (BOP)
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 Accumul
Slide 33: BOP Response (Before the Explosions)
BOP Response (Before the Explosions) BOP is designed to seal the wellbore and April 20th 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
Slide 34: BOP Response (Impact of Explosions)
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 loca
Slide 35: BOP Response (After the Explosions)
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 sta
Slide 36: Key Finding #8
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
Slide 37: Summary of Findings and Recommendations
Summary of Findings and Recommendations Deepwater Horizon Accident Investigation 37
Slide 38: 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 Integrit
Slide 39: Summary of Key Findings
Summary of Key Findings Well integrity was not established or failed 6 7 − 1 Annulus cement barrier did not isolate hydrocarbons 3 5 − 2 Shoe track barriers did not isolate hydrocarbons Hydrocarbons entered the well undetected and Riser 4 well control was lost − 3 Negative pressure test was accepted