Deep Water Horizon Accident Investigation Lessons Learned
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Accident Investigation Findings of Macondo Well, Deep Water Horizon Accident in the Gulf of Mexico Apr 20, 2010.
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Deep Water Horizon Accident Investigation Lessons Learned
- 1. A Study of the BP Accident Investigation Report September 8 , 2010 J. M. Drake P.E. CSP, CQE, F.NSPE
- 2. 1/31/2015Deep Water Horizon Accident Investigation Report 2
- 3. Investigation Lines of Inquiry Key Events of the Accident Timeline Macondo Well Details, Geology and Well Design 4 Critical Factors Leading up to the Accident 8 Key Findings of the Investigation Estimates of the Total Spill Size Recommendations to Prevent Recurrence 1/31/2015 Deep Water Horizon Accident Investigation Report 3
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- 7. 1/31/2015 8 Deep Water Horizon Accident Investigation I. II. III. IV.
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- 10. 1/31/2015Deep Water Horizon Accident Investigation Report 11 The annual cement barrier did not isolate the hydrocarbons
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- 19. 1/31/2015 20 Deep Water Horizon Accident Investigation • A Cement Bond Log was not run to evaluate the cement job
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- 34. 1/31/2015 35 Deep Water Horizon Accident Investigation Test success/fail criteria not specified
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- 54. 1/31/2015 Deep Water Horizon Accident Investigation Report 56 April 20, 2010
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- 80. 1/31/2015 82 Deep Water Horizon Accident Investigation I. II. III. IV.
- 81. Flow Rate Technical Group ◦ Estimated flow rates 15,000 to 40,000 brls/day 95% Confidence Interval Calculations based on the duration and flow rates yield total spill size ◦ Between 1.3 to 3.5 MMB (million barrels of oil) ◦ Published media articles (NY Time and CNN) place values between 4.1 and 4.3 MMB Ranks between the fifth to tenth largest crude oil spills in the world 1/31/2015 Deep Water Horizon Accident Investigation Report 83
- 82. Actions To Prevent Recurrence 1/31/2015 Deep Water Horizon Accident Investigation Report 84
- 83. 1/31/2015Deep Water Horizon Accident Investigation Report 85
- 84. 1/31/2015 Deep Water Horizon Accident Investigation Report 86 (DWOP and OMS)
- 85. Topics Covered: Investigation Lines of Inquiry Critical Events during the Accident Timeline Macondo Well Details, Geology and Well Design 4 Critical Factors, Lines of Inquiry, Leading up to the Accident 8 Key Findings of the Investigation Estimates of Size of Spill Recommendations of Actions to Prevent Recurrence This study clearly demonstrates that the Deep Water Horizon accident was preventable. With sound application of engineering and safety practices, similar accidents need never occur again. 1/31/2015 Deep Water Horizon Accident Investigation Report 96
- 86. 1/31/2015 Deep Water Horizon Accident Investigation Report 97
- 87. 1. BP Deepwater Horizon Macondo Well Accident Report Page: http://www.bp.com/sectiongenericarticle.do?categoryId=9034902&contentId=7064891 2. Wikipedia ,Timeline, Deep Water Horizon Accident: http://en.wikipedia.org/wiki/Timeline_of_the_Deepwater_Horizon_oil_spill#April http://en.wikipedia.org/wiki/Deepwater_Horizon_explosion http://en.wikipedia.org/wiki/Deepwater_Horizon 3. Wall Street Journal: http://online.wsj.com/article/SB10001424052748704302304575213883555525958.html 4. CNN: http://www.cnn.com/2010/US/05/03/timeline.gulf.spill/index.html?iref=obnetwork 5. Times Picayune: http://www.nola.com/news/gulf-oil-spill/index.ssf/2010/08/graphic_brings_together_multip.html http://media.nola.com/2010_gulf_oil_spill/photo/six-steps-that-doomed-the-rigjpg-bd73481b6f076ab0.jpg 6. Offshore Technology: http://www.offshore-technology.com/features/feature84446/ 7. Energy and Commerce Committee U.S. Congress: http://energycommerce.house.gov/index.php?option=com_content&view=article&id=1985:energy-a-commerce-committee-investigates-deepwater-horizon-rig-oil- spill&catid=122:media-advisories&Itemid=55 8. Bureau of Ocean Energy Management http://www.boemre.gov/deepwaterreadingroom/QuestionDocuments.aspx http://www.boemre.gov/DeepwaterHorizon.htm 9. Deep Water Response Unified Command http://www.deepwaterhorizonresponse.com/go/site/2931/ 1/31/2015 Deep Water Horizon Accident Investigation Report 98
Notas do Editor
- Deep Water Horizon Lessons Learned A Study of the BP Accident Investigation Report of September 8 , 2010 prepared by J. M. Drake P.E. CSP, CQE, F.NSPE Notes 1. References and Credits: Graphics and Text for this presentation were extracted from References 1 through 9, Slide 98. 2. Paragraph and Figure numbers used in this presentation are from the following official copy of the BP Accident Investigation Report, Reference 1, Slide 98: Deepwater_Horizon_Accident_Investigation_Report.pdf dated Sep 8, 2010 3. A copy of the Deep Water Horizon Accident Investigation Report is available at: http://www.bp.com/sectiongenericarticle.do?categoryId=9034902&contentId=7064891
- On the evening of April 20, 2010, a well control event allowed hydrocarbons to escape from the Macondo well onto the Transocean’s Deepwater Horizon, resulting in explosions and fire on the rig. Eleven people lost their lives, and 17 others were injured. The fire, which was fed by the hydrocarbons from the well, continued for 36 hours until the rig sank. Hydrocarbons continued to flow from the reservoir through the wellbore and the blowout preventer (BOP) for 87 days, causing a spill of national significance.
- Presentation Agenda Investigation Lines of Inquiry Key events of the accident timeline Macondo Well Details, Geology and Well Design 8 Critical Factors Leading up to the accident Estimates of the total spill size Recommendations to preclude recurrence
- The investigation pursued four primary lines of inquiry based on the review of the facts surrounding the event: Well integrity was not established or failed Hydrocarbons entered the well undetected and well control was lost Hydrocarbons ignited on the Deepwater Horizon The blowout preventer (BOP) did not seal the well
- The dates and times of key events of the Deep Water Horizon, Macondo Well Accident. Notice two entries on the timeline, on Apr 20, 2010 at 5:08 PM the drill pipe pressure increased from 273 to 1250 psi in 6 minutes indicating a significant change in down hole conditions, 4 hours and 45 minutes later at 9:45 pm the well blew out followed by two explosions, loss of power and fire. The semisubmersible sunk two days later at 10:22 AM
- A table of the dates and times of key events in the timeline of the Deep Water Horizon, Macondo Well Accident. Notice two entries on the timeline, on 5:08 pm the drill pipe pressure increased from 273 to 1250 psi in 6 minutes indicating a significant change in down hole conditions, 4 hours and 45 minutes later at 9:45 pm the well blew out followed by two explosions, loss of power and fire. The semisubmersible sunk two days later at 10:22 AM.
- Figure 1 Barriers breached and the relationship of barriers to the critical factors of the accident
- Graphic of 8 barriers that were breached associated with each of the four critical factors: 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 the well Hydrocarbons ignited on the Deepwater Horizon Diversion to mud gas separator resulted in gas venting onto the rig Fire and gas system did not prevent hydrocarbon ignition Blowout preventer did not seal the well 8. Blowout preventer (BOP) emergency mode did not seal the well
- Background and details of the Macondo Well and areas of discussion, the shoe track and bottom of the well, the well casings and configuration, and the subsea equipment including the Blow Out Preventer (BOP) and BOP control pods.
- The originally the well plan consisted of eight casing strings, Figure 2. However, during the drilling , nine casing strings were needed, including a 9 7/8” production casing at the bottom of the well were installed.
- The annual cement barrier did not isolate the hydrocarbons
- Figure 3 shows the actual casing runs and their depths used in the Macondo well
- The discovery phase of the well was completed. At the time of the accident the well was being prepared for the removal of the drilling rig by placing it in a static, suspended mode, until additional work at a future date would be performed to prepared the well for production. This work requires that a cement barrier be installed in the well at the reservoir depth to prevent the hydrocarbons from entering the well after drilling operations are suspended. Work had been performed at the bottom of the well using a portion of the well string called the Shoe Track.
- The investigation team determined that the annulus barrier failed to prevent hydrocarbons from migrating into the wellbore. Analysis identified a probable technical explanation for the failure and also includes the non technical interactions between BP and Halliburton personnel specifically shortcomings in the planning, design, execution and confirmation of the cement job which reduced the prospects for a successful cement barrier.
- Cement is pumped down the casing through the float collar and up the annulus to isolate the primary reservoir sands. Nitrogen cement slurry was chosen Risks included stability of the foam, relatively small volume and possible contamination. Mitigation of risk includes: Testing of the slurry design Precise Placement Use of centralizers Discussion 6 inline centralizers were used instead of recommended 21 because 15 additional units received on the rig were incorrectly thought to be wrong type.
- Synthetic Oil Based Mud (SOBM) fills the drill string during drilling operations. The cement is injected using a controlled sequence of chemicals between two wiper plugs which land on a float collar which is part of the shoe track: Base oil weighing 6.7 pounds per gallon (ppg) Spacer fluid 14.3 ppg Cap cement 16.74 ppg Foam cement 14.5 ppg Tail cement 16.74 ppg Spacer fluid 14.3ppg
- Planned locations of the cement slurry after placement. Not the weights of the various components such as the Synthetic Oil Based Mud (SOBM) at 14.7 pounds per gallon (ppg) compared to the other fluids in the cement job column.
- An independent lab reported that a representative samples of the foam cement slurry used the Macondo were not stable.
- The investigation team arrived at the following conclusions: Communication between BP and Halliburton personnel was not effective in relation to the challenges and associated risks with the slurry design. The BP Macondo well team did not provide effective quality assurance on Halliburton’s technical services. 3. The BP Macondo well team did not provide zonal isolation experts the opportunity to perform sufficient QA (i.e. a well bond log) on the cement design and procedures.
- Key Finding 1 The annulus cement barrier did not isolate the reservoir hydrocarbons. The recommended foam slurry cement was a complex design. There was risk of contamination, no fluid loss additives were used. The pre-job cement lab testing was inadequate. The foam slurry was unstable and likely resulted in nitrogen breakout. A cement bond log was not performed.
- Key Finding 2 the shoe track barriers did not isolate the hydrocarbons. A mechanical barrier failure enabled hydrocarbons to enter the wellbore. Three flow paths were possible. Available evidence lead the investigation team to conclude that flow into the well occurred through the shoe track barriers.
- Potential flow paths are illustrated here. Flow could have entered the wellbore through the production casing and components, the casing hanger seal assembly or the shoe track.
- Observations for flow through shoe track verses the seal assembly are compared in this slide
- Possible failure modes that contributed to the shoe track’s cement failure were contamination by nitrogen breakout, contamination by drilling mud, inadequate design of cement chemistry, swapping of cement with mud in the rat hole or a combination of these failure modes.
- Three possible failure modes of the float collar were identified by the investigation team: Damage by the high load conditions required to establish circulation Failure to convert due to insufficient flow rate Check valves failed to seal
- Summary of Key Finding 2. The shoe track had two types of mechanical barriers. Cement in the shoe track and double check valves in the float collar. The shoe track cement failed to act as a barrier due to contamination by break out of nitrogen from the foam slurry. Hydrocarbons bypassed the float collar check valves due to either failure to convert or failure to seal.
- Key Finding 3 The negative-pressure test was accepted although well integrity had not been established. 10 ½ hours after the cement job a positive-pressure test was conducted at 2700 psi. A negative-pressure test was then conducted. The team concluded that the negative-pressure test results indicated that well integrity had not been established. The situation was not recognized and remedial steps were not taken.
- Following the completion of the cement job, a positive pressure test verifies the integrity of the casing and seal assembly. The casing was pressure tested to 2700 psi successfully proving integrity of the blind shear rams, seal assembly and casing. The shoe track is not tested due the presents of the wiper plug.
- The negative-pressure test checks the integrity of the shoe track, casing and wellhead seal assembly. It simulates conditions during temporary abandonment when a portion of the well in displaced to seawater. During the test the following conditions occurred. A spacer fluid is used to separate the sea water from mud. A leaking annular preventer allowed spacer to move across the kill line inlet The test was started using the drill sting but was changed to the kill line The volumes bled during the test were higher than the calculated values indicating flow into the wellbore The drill pipe pressure increased to 1400 psi with no flow on the kill line indicating that the kill line was not in communication with the drill pipe
- The annular preventer failed to seal during initial portion of the test allowing spacer to flow across the inlet to the kill line.
- Between 1649 and 1708 hours the Annular preventer seals with increased hydraulic pressure. The drill pipe was filled with 50 bbls of mud and monitored, 15 bbls of seawater was bled from drill pipe at 1727 hrs. Decision is made to change test to the kill line. At 1800 the kill line is opened, 3 to 15 bbl flowed from the kill line, flow did not stop and spurted. The kill line was closed.
- Leakage of the annular preventer caused spacer fluid to move into the kill line. This could have caused a blockage of the line and isolated the kill line from the drill pipe pressure.
- Between 1800 and 1845 hrs the drill pipe pressure gradually increased to 1400 psi. At 1945 hrs pumped into kill line to confirm full. The opened kill line was monitored for 30 minutes between 1842 hrs and 1955 hrs with no flow. 1400 psi on drill pipe was described at “bladder pressure”. On duty crew agreed without seeking consultation. Differential pressure between the drill pipe and kill line remained unexplained. At 1955 hrs negative pressure test was concluded and considered a good test. During the test the cement tank increased in volume by 3 bbls indicating flow into the wellbore.
- Real time data which was available to the crew during the test confirms the pressure and flow anomalies. Note the 1400 psi drill pipe pressure, item 10 green line, while the kill line, item 9 blue line, varies in pressure and then remains flat for 30 minutes. Discussions among the crew members took place about “annular compression” and “bladder effect” while monitoring the kill line. Crew did not seek consultation about the unexplained pressure differential.
- Summary of key finding 3. The bleed volumes were not recognized as a problem Anomalous pressure on drill pipe with no flow from kill line not recognized as a problem Test incorrectly accepted as successful No standardization of test procedure No definitive success/fail criteria stipulated
- Key Finding 4 Influx was not recognized until hydrocarbons were in the riser. Fluid returns, pressure and flow indicators must be monitored continuously to detect influx into the wellbore. The rig crew did not recognize significant indications of influx during displacement of the mud by seawater.
- Well monitoring is critical to understanding well losses and gains. The Driller assisted by the Mud logger is responsible for monitoring and shutting in the well.
- The negative pressure test is a critical test to verify the integrity of the shoe track, casing and wellhead seal assembly. It simulates conditions during temporary abandonment when the well is displaced to seawater. Activities associated with the test were being conducted between 1504 and 1955 hrs.
- Top orange line is the real time drill pipe pressure available to the crew. Between 2100 and 2115 hours the drill pipe pressure continued to increase indicating flow into the well. Notice the gap between the blue and the green line between 2108 and 2110. Flow out (green line) exceeded flow in (blue line) and continued after pumps were shut down indicating a 39 bbl increase in the drill sting. This is an abnormal signature and indicated flow into the well.
- At 2138 hrs the wellbore had been filled with hydrocarbons and flow continued up the drill pipe riser toward the Deep Water Horizon
- A sheen test is conducted to see if the returns contain any detectible level of hydrocarbons prior to further discharged overboard. During this test between 2108 and 2114 the drill pipe pressure continued to increase when the pumps were turned off.
- At 2002 hrs the crew resumed displacement of mud with seawater
- The following illustrated the continued influx of hydrocarbons into the wellbore between 2131 and 2141 hrs when the oil began to come up the drill pipe riser.
- The next three slides show three opportunities the crew had to realize that hydrocarbons were flowing into the well. Flow indication 1 was the drill pipe pressure increasing by 100 psi when it should have decreased. 39 bbls of hydrocarbons entered the well from 2058 to 2108 hrs.
- Flow indication number two drill pipe pressure increased 246 psi with the pumps off and the flow out does not immediately drop off after shutting the pumps off which normally occurs.
- Flow indication 3 drill pipe pressure increased by 556 psi with pumps off indicating a 300 bbl gain to the well bore.
- During a well control event rapid response is critical. The rig crew diverted hydrocarbons coming through the riser inboard to the MGS. Diversion of the hydrocarbons overboard could have prevented high concentrations of flammable gases from entering the rig.
- The mud gas separator is a low pressure system designed for normal drilling operations. It has a 14” inflow line from the Riser Diverter, a 12” gas outlet line, a 10” liquid outlet line to the mud system, 6” relief line set at 15 psi and a 6” vacuum breaker line. The vacuum breaker line vents down onto the main drilling platform under the derrick.
- The real time data during the final 35 minutes before power was lost shows that drill pipe pressure and corresponding response actions taken during the well event. Note 8 shows diversion to the MGS at 2142 and activation of the BOP annular preventer, note 9 at 2144 hrs.
- Diversion of the flow to the MGS separator began at 2142 hrs, crew has the option of diverting flow overboard. Note that the liquid outlet from the MGS goes to the mud system located inboard under the main deck.
- Well flow modeling provides a means of illustrating the hydrocarbon influx during the last hour before the explosion. Note the geometric growth in the cumulative gains as time progresses.
- Gas flow to the surface could have reached 165 mmscfd overwhelming the operating ratings of the system. Gas probably vented from five locations Slip joint around moon pool 12” MGS gooseneck vent 6” MGS vacuum breaker vent 6” MGS relief line through burst disk 10” mud line under the deck
- The first well response was taken 49 minutes and 1000 bbls after influx into the well.
- If the BOP Annular Preventers had been closed and sealed around the drill pipe any time prior to 2138 hrs the chance of hydrocarbons entering the drill pipe riser to the surface would have been prevented.
- The crew diverted the flow of hydrocarbons to the MGS as 2141 hrs. The main 12” vent line from the MGS directs the flow of gas down onto the rig from the derrick. Additional flow lines from the MGS directed gas onto the rig and into confined spaces under the deck.
- Some key items in the time line during the final ten minutes, mud flowed out to the MGS vent, gas vented to the atmosphere, the BOP sealed around the drill pipe 9 minutes after 2138 hrs, the gas alarms go off, engines over speed, power is lost and the explosions occur.
- Time needed to stop the flow of hydrocarbons by closure of the BOP Annular Preventer is shown to be about ten minutes had the explosions not occurred is illustrated using Well Flow Modeling
- Flow of hydrocarbons through the MGS resulted in rapid dispersion across the rig through the vents and mud system
- The hydrocarbons gasses vented onto the Deep Water Horizon.
- The 6” MGS Vacuum breaker vents down onto the aft deck of the Deep Water Horizon. The 12” MGS Main Vent also vents down onto the deck from top of the derrick.
- Gas dispersion modeling show where the explosive gases would have migrated given the conditions on board at the time of the accident.
- Limited hazardous area classifications of the rig shows gas enveloped non-protected areas including the aft deck which contained the air intakes to the main engine rooms. The blast vector diagram shows the location of the 17 injured crew members at the time of the explosions.
- Gas cloud reached supply air intakes to engine room. HVAC did not automatically shut down. Limited areas of vessel were designated electrical class 1 division 1 zones.
- Gas jet off the starboard side of the vessel during the rig fires is believed to be the 6” MGS relief line
- None of the emergency methods were successful in isolating the wellbore. After the explosion because the operational methods were not independent single failures affected more than one emergency method of operation. Ultimately the only way to isolate the well at the BOP was to activate the Blind Shear Ram (BSR). This component also failed making the BOP ineffective.
- Overview of Blowout Preventer (BOP) and its emergency modes of operation. Features include Lower Marine Riser Package (LMRP) with Blue and Yellow Control Pods, Upper and lower Annular Preventers, Blind Shear Ram (BSR) the multiple Variable Bore Rams (VBR). The modes available to the Deep Water Horizon included the Emergency Disconnect Sequence (EDS) BSR Closure, Automatic Mode Function (AMF), and Remotely Operated Vehicle (ROV) hot stab (hydraulic access receptacle) AMF to activate Auto-Shear
- Three factors could have prevented contributed to the inability of the annular preventer to seal the annulus. Flow and pressures conditions exceeded available hydraulic pressure settings. Insufficient hydraulic pressure due to multiple BOP functions initiated in rapid sequence Failure of the annular preventer elastomeric element
- Before the explosion the following BOP responses occurred At 2138 hrs hydrocarbons enter the riser At 2141 the annular preventer closed but did not seal the annulus At 2147 the Variable Bore Rams (VBR) likely sealed the annulus
- Following the Explosion Damage to the MUX cables and hydraulic line could have allow the annular preventer to open Rig drift off created upward motion to the drill pipe in the BOP
- Following the explosion Electrical and Hydraulic communication between the rig and the BOP was lost. Electrical communication is maintained through two reels, the blue muliplex (MUX) reel and the Yellow MUX reel, located near the moon pool at the center of the well.
- Loss of electrical and hydraulic communications between the rig and the BOP is sufficient for the AMF to activate Autoshear Function. The likely positions of the BOP rams is shown. in this
- The investigation found two critical failures of the BOP AMF Control System, one in each of the two control pods. The blue Pod batteries were not sufficiently charged to activate the sequence. The yellow control pod solenoid valve failed to activate. Together these failure caused the AMF function to fail to activate the High Pressure Autoshear Rams.
- Photos of typical yellow solenoids and blue battery packs found in BOPs.
- BOP Response after the explosions were ineffective Emergency Disconnect Sequence (EDS) failed to activate the Blind Shear Rams (BSR) Automatic Mode Function (AMF) sequence likely failed to activate the BSR Remote Operated Vehicle (ROV) stimulated AMF likely failed to activate the BSR ROV auto-shear appears to have activated but did not seal the well ROV attempts using seabed accumulators were unsuccessful
- Hydraulic leaks found in the BOP during ROV operations
- Effects of the accident on the Drill Pipe (Riser) configuration at the BOP. The drift off of the rig following power loss pulled the riser pipe up and away from the BOP. Following collapse the pipe separated and snapped back down into the flex joint.
- Condition of the riser at the BOP interface is shown after being retrieved. The effect of high pressure, high speed fluid movements on the riser pipe apparent at the tool joint shows probably cause contributing to failure of shear rams to seal the well.
- Summary of Key Finding 8 the BOP emergency mode did not seal the well. The explosion and fire caused damage to the hydraulic lines and MUX cables causing loss of electrical power, loss of hydraulics to the BOP. The AMF did not activate the BSR due to defects in both control pods. Auto-shear activated by did not seal the well. Deficiencies existed in both testing and maintenance management of the emergency systems.
- Conclusions of the investigation team concerning the BOP before and after the accident Prior to accident The annulus was sealed likely by the Variable Bore Rams (VBR) less than 2 minutes before the explosion. Overall response of the BOP to seal the annulus after being activated at 2141 hrs was slow. It is likely that about ten minutes following closure of the annulus flow of hydrocarbons would have stopped had the explosion not occurred. Post Accident The Explosions damaged the MUX and hydraulic lines located near the moon pool with little resistance to fire and explosion, disabling two methods of emergency response available to the rig crew, activation of the high pressure Blind Shear Rams (BSR) and the Emergency Disconnect Sequence (EDS). Automatic Mode Function (AMF) would have been met shortly after the explosion with loss of electric and hydraulic power. It is likely that the AMF sequence failed because of two unrelated failure in the BOP Control Pods, the blue pod batteries and the yellow pod solenoid valve. ROV activation of the auto shear function appeared to close the Blind Shear Rams but failed to seal the wellbore.
- Graphic of 8 barriers that were breached associated with each of the four critical factors: 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 the well Hydrocarbons ignited on the Deepwater Horizon Diversion to mud gas separator resulted in gas venting onto the rig Fire and gas system did not prevent hydrocarbon ignition Blowout preventer did not seal the well 8. Blowout preventer (BOP) emergency mode did not seal the well
- The spill likely unleashed between 1.3 and 3.5 million barrels (MMB) ranks between the fifth and the tenth largest crude oil spills in the world
- The following slides contain a summary of the investigation team’s recommendations to prevent recurrence of a similar accident
- Recommendations based on eight key findings covering two broad areas: Drilling and Well Operations Practices (DWOP) and the Operating Management System (OMS) Contractor and service provider oversight and assurance
- Recommendations related to DWOP and OMS are: Engineering Technical Practices and Procedures Enhancement of Deepwater Capability and Proficiency Rig Audit Action Closeout and Verification Integrity Performance Management for Drilling and Well Activities Recommendations related to Contractor Oversight and Assurance Cementing Services Drilling Contractor Well Control Practices and Proficiency Rig Safety Critical Equipment BOP Configuration and Capability BOP Criteria for Testing, Maintenance, Modification and Performance Reliability
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- Specific DWOP and OMS Recommendation of the report
- The Eight Key Findings of the Investigation
- Concluding Remarks- Main topics covered during the presentation
- Comments and Questions
- References and Credits BP Deepwater Horizon Macondo Well Accident Report Page: http://www.bp.com/sectiongenericarticle.do?categoryId=9034902&contentId=7064891 Wikipedia ,Timeline, Deep Water Horizon Accident: http://en.wikipedia.org/wiki/Timeline_of_the_Deepwater_Horizon_oil_spill#April http://en.wikipedia.org/wiki/Deepwater_Horizon_explosion http://en.wikipedia.org/wiki/Deepwater_Horizon Wall Street Journal: http://online.wsj.com/article/SB10001424052748704302304575213883555525958.html CNN: http://www.cnn.com/2010/US/05/03/timeline.gulf.spill/index.html?iref=obnetwork Times Picayune: http://www.nola.com/news/gulf-oil-spill/index.ssf/2010/08/graphic_brings_together_multip.html http://media.nola.com/2010_gulf_oil_spill/photo/six-steps-that-doomed-the-rigjpg-bd73481b6f076ab0.jpg Offshore Technology: http://www.offshore-technology.com/features/feature84446/ Energy and Commerce Committee U.S. Congress: http://energycommerce.house.gov/index.php?option=com_content&view=article&id=1985:energy-a-commerce-committee-investigates-deepwater-horizon-rig-oil-spill&catid=122:media-advisories&Itemid=55 Bureau of Ocean Energy Management http://www.boemre.gov/deepwaterreadingroom/QuestionDocuments.aspx http://www.boemre.gov/DeepwaterHorizon.htm Deep Water Response Unified Command http://www.deepwaterhorizonresponse.com/go/site/2931/