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  • 1. Deepwater Horizon Investigation Deepwater Horizon Accident Investigation 1
  • 2. Investigation Context Terms of Reference Investigation Team Data and Analysis Investigation Limitations Deepwater Horizon Accident Investigation 2
  • 3. 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 BOPSea 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
  • 4. IntroductionTechnical Presentation Deepwater Horizon Accident Investigation 4
  • 5. Well Integrity Was Not Established or Failed Deepwater Horizon Accident Investigation 5
  • 6. 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 19:30Sea 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 Deepwater Horizon Accident Investigation 6
  • 7. 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 windowSea 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’ Deepwater Horizon Accident Investigation 7
  • 8. Key Finding #1The 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 ppgRiser 14.3 ppg Cap Cement Mud Channeling 16.74 ppg Foam slurry recommended was a 14.17 ppg Cap Cement complex design 16.74 ppgBOP Risk of contamination using smallSea Floor Foam volume of cement Cement Foam 14.5 ppg Cement No fluid loss additives 14.5 ppg Incomplete pre-job cement labCasing 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 TrackReservoir Reamer Shoe Tail Cement Nitrogen Breakout Deepwater Horizon Accident Investigation 8
  • 9. 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 conditionsOriginal 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 Deepwater Horizon Accident Investigation 9
  • 10. 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 Deepwater Horizon Accident Investigation 10
  • 11. 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, 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 Deepwater Horizon Accident Investigation 11
  • 12. Hydrocarbons Entered the WellUndetected and Well Control Was Lost Deepwater Horizon Accident Investigation 12
  • 13. 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 Deepwater Horizon Accident Investigation 13
  • 14. 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 AnnularSea 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) Deepwater Horizon Accident Investigation 14
  • 15. Negative Pressure Test The negative-pressure test checks the 17:52 – 18:00 integrity of the shoe track, casing and Open killline 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 wellBled 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 FloorKill 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 Bleed volumes higher than calculated Cement Tank Total Drill pipe built pressure to 1400 psi with Volume no flow on the kill line 15 bbls Primary reservoir sands (12.6 ppg) Deepwater Horizon Accident Investigation 15
  • 16. 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 18:42 is displaced to seawater. BOP Pumped into kill line to confirm full April 20th 15:04 – 19:55 Kill line opened forSea 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 Bleed volumes higher than calculated Cement Tank Total Drill pipe built pressure to 1400 psi with Volume no flow on the kill line 18 bbls Additional 15 bbls 3 bbl influx Primary reservoir sands (12.6 ppg) Deepwater Horizon Accident Investigation 16
  • 17. Key Finding #3The negative pressure test was accepted although well integrity hadnot 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’ Deepwater Horizon Accident Investigation 17
  • 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 18
  • 19. 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 seawaterSea 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) Deepwater Horizon Accident Investigation 19
  • 20. Key Finding #4The 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 20:58Flow 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 Deepwater Horizon Accident Investigation 20
  • 21. Key Finding #4The 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 20:58Flow Rate (gpm) 1200 Indication #1 to 21:08 1000 1500 800 #2: Drill pipe pressure 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 Deepwater Horizon Accident Investigation 21
  • 22. Key Finding #4The 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 (expected decreased); Pump Pressure (psi) 2000 ~39 bbl gain from 20:58Flow Rate (gpm) 1200 Indication #1 to 21:08 1000 1500 800 #2: Drill pipe pressure 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 Deepwater Horizon Accident Investigation 22
  • 23. Key Finding #5Well 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 Deepwater Horizon Accident Investigation 23
  • 24. Hydrocarbons Ignited on the Deepwater Horizon Deepwater Horizon Accident Investigation 24
  • 25. 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 PortOverboard 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 Deepwater Horizon Accident Investigation 25
  • 26. 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 StarboardOverboard 14” Diverter Line 14” Diverter Line Overboard 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 Deepwater Horizon Accident Investigation 26
  • 27. 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
  • 28. 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. FwdAftSecondary 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 Deepwater Horizon Accident Investigation 28
  • 29. Key Finding #6Diversion to the mud gas separator resulted in gas venting onto the 12” Ventrig 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 Overboard 14” Diverter Line 14” Diverter Line Overboard Slip Joint Overboard Caisson Boost Kill Choke BOP BOP Sealed at Seawater 21:47 Seawater/Mud Mix Influx Deepwater Horizon Accident Investigation 29
  • 30. Key Finding #7The 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 Deepwater Horizon Accident Investigation 30
  • 31. Emergency Well Control System Did Not Seal the Well Deepwater Horizon Accident Investigation 31
  • 32. 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 Deepwater Horizon Accident Investigation 32
  • 33. 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 theStripping Element annulus Blind Shear RamCasing Shear Ram Activation of VBR (Non Sealing) Upper VBR Middle VBRLower (Test) VBR Wellhead Connector Wellhead Sea Bed Deepwater Horizon Accident Investigation 33
  • 34. 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 RamCasing Shear Ram (Non Sealing) Upper VBR Middle VBR Lower (Test) VBR Wellhead Connector Wellhead Sea Bed Deepwater Horizon Accident Investigation 34
  • 35. 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 BSRCasing 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 Sea Bed Deepwater Horizon Accident Investigation 35
  • 36. Key Finding #8The BOP emergency mode did not seal the wellExplosions & Fire: The AMF provides an automaticLoss of communication means of closing the BSR withoutLoss 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 Deepwater Horizon Accident Investigation 36
  • 37. Summary of Findings and Recommendations Deepwater Horizon Accident Investigation 37
  • 38. 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 Deepwater Horizon Accident Investigation 38
  • 39. 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 BOPSea 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