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Deepwater Horizon Deepwater_Horizon - Coggle Diagram

- - - - The fire fuelled hydrocarbons from the well which continued for 36 hours until the rig sank
        
        Hydrocarbons continued to flow from the reservoir through the wellbore and the blowout preventor (BOP) for 87 days
        
        A spill was created which was considered a national/ significant event
  - - - Fault Tree Analysis applied and found eight key causes of the accident
        
        Annulus cement barrier did not isolate the hydrocarbons
        
        The shoe track barriers did not isolate the hydrocarbons
        
        The negative pressure test was accepted although well integrity test had not been established
        
        Influx was not recognised until hydrocarbons were in the riser
        
        Well control response actions failed to regain control of the well
        
        Diversion to the mud gas separator resulted in gas venting onto the rig
        
        The fire and gas system did not prevent hydrocarbon ignition
        
        The BOP emergency mode did not seal the well
  - - - allowed for the release and ignition of hydrocarbons
        
        BOP functions failed to seal the well after the initial explosion
- - - - Test confirmed integrity of blind shear rams, casing, seal assembly, and top wiper plugs
        
        The shoe track which plays a key role in isolating hydrocarbons was NOT tested
    - - Tests purpose was to place the well in a controlled under-balanced state to test all mechanical barriers
        
        Test was conducting by displacing some mud in the well with a spacer, followed by seawater. After displacement the upper annular preventer was closed in attempt to bleed the system down to zero psi but fluid in the riser was leaking past the annular preventer
    - - The riser was filled with up to 50 barrels of mud to replace the volume that had leaked past the annular
    - - Drill pipe valve was closed and testing reconfigured for flow to be monitored on the kill line
        
        Kill line valve was opened and seawater was bled off before it was closed again and then the drill pipe pressure gradually increased
    - - Signs of flow was monitored for 30mins but did not occur however the drill pipe pressure remained
        
        No flow showed and test was deamed successful
  - - - Infrastructure-led development
      - Engineering team and subsurface specialists estimate pore pressures and strengths of geologic formations
      - Shallow hazard assessment and peer reviewed designed completed
      - Multiple plan stages comprising technical and mechanical review and changes
        
        Mud weights and well casing setting depths changed from original design
        
        Revised casing design was prepared to address high formation pressure that led to well control
      - Final design involved nine casing strings for drilling where plan included eight
      - Differing pore pressures and fracture gradients resulted from design basis
      - Logging and evaluation was achieved to determine reservoir intervals which was followed by a clean-out trip to condition the wellbore and verify operating condition
      - April 16, 2010, MMS approved procedure for temporary abandonment of well
    - - Commenced in December 1998
      - The Keel was laid on 21 March 2000
      - Rig was delivered on 23 February 2001
      - Built by R&B Falcon which became part of Transocean by Hyundai Heavy Ind. in South Korea
      - Cost production
    - - Rig commissioned by R&B Falcon and registered in Majuro before being leased to BP in 2001
      - Testing
      - Stablising
      - Approval
      - Operating rights
    - - Risk Assessment
      - Well monitoring measures and control practices
      - Integrity testing practices
      - BOP system maintenance
      - Mechanical repairs
      - Regular equipment inspection
      - Pre-job inspection, testing and maintenance of blowout prventor
      - Ineffective Maintenance Management
        
        Batteries in pod fully depleted
        
        No indications that the AMF and ROV intervention systems were tested as required by policy
        
        non-original equipment manufacturer (non-OEM) was found on solenoid valve during examination
      - History
        
        Testing and modifications conducted since commissioning provides information regarding likely condition of BOP at time of incident
        
        Audit findings relating to maintenance found that the sub-sea personnel recorded well control equipment maintenance manually on separate spreadsheets and in a daily logbook instead of in the Maintenance Management System
        
        The lower, middle, and upper BOP ram bonnets had not been re-certified since 2000. The OEM recommended re-certification period is 5 years
        
        Maintenance records did not substantiate that it was compliant with 5-year replacement policy for high-pressure holes/ equipment
    - - Drill a well to tap into the reservoir on the Macondo Prospect
      - Oil is meant to be reached and once this is achieved, the plan is to cap the well column with three cement plugs so that another rig could return at a later time and remove the oil
      - Operations and design involved sealing the well at approx. 1500m deep in water before oil production commenced
      - Ultra deep-water dynamically positioned
      - Semi-submersible offshore drilling rig
      - Wight: 52,590 tons
      - Length: 112m
      - Mass production of oil per day (approx 100k+ barrels of oil
      - Comprises cranes for operational purposes (e.g. lift containers, pipelines etc.)
      - Designed to drill in water depths of up to 10k feet
    - - Drill operates through a hole in the hull
      - Several wells drilled from one platform (rig)
      - Directional drilling is required to access several locations in the formation
      - Sonic equipment is used to determine drilling sites most likely to produce oil
      - Mobile Offshore Drilling Unit (MODU) used to dig a well
      - Guiding stands of drill pipe into fingers at top of derrick
      - Monitor viscosity and mud density while adding chemicals or oil-based fluids
      - Casing string were installed to drill well to a depth of 18k feet
      - Cement used as a barrier to seal the wellbore from the reservoir
- - - - This would allow hydrocarbons to enter the wellbore annulus
  - - - The shoe rack is installed at the bottom of the production casing
    - - This occurs when both barriers in the shoe track fail to prevent hydrocarbon entry in the production casing
        
        The first barrier (cement in shoe track)
        The second barrier (float collar)- device that is located at the top of the shoe track, designed to prevent fluid ingress into the casing
  - - - The shoe track, production casing, and casing hanger seal assembly
    - - Indicated flow-path communication with the reservoir which signified the integrity of the barriers was not achieved
        
        The crew and BP site leaders were of the incorrect view that the test was successful and well integrity was achieved
  - - - This increased the potential for gas to reach an ignition source
- - - - Riser
        
        Influx was not apparent until hydrocarbons were in the riser
        
        3 drill pipe pressure increases/ indicators were recorded with no well control actions taken
      - BOP
        
        Blowout Preventor emergency modes did not seal the well
        
        Emergency systems failed to seal the well after initial explosion
        
        Initial explosions and fire damaged the control cables (MUX Cables) and hydraulic lines which caused emergency disconnect system failing to activate the blind shear ram which was triggered by personnel on the bridge
        
        AMF did not complete due to to MUX cable damage
        
        Solenoid valves/ pods were modified and miswired
        
        Miswiring caused battery to drain
        
        2 x coils of electrical wire designed to work together to generate a magnetic field to operate the valve
        1 x coil failed
        
        Weaknesses and testing/ maintenance of BOP was evident
        
        19 known modifications occurred which changed the functionality of the BOP, but likely did not contribute to accident
        
        Maintenance records were not accurately reported where conditions of critical components were not discovered until after the accident
        
        Six leaks were identified in the hydraulic system
        
        Whilst testing requirements were in accordance with policy/ industry standards, intervention systems tests were not conducted at the surface as required by company policy
        
        Diagnostic practices did not recover all critical components of the control system and were not utilised effectively to detect control system defects
      - Casing
        
        Shoe track barriers did not isolate hydrocarbons
        
        Shoe track has two types of mechanical barriers:
        1- Cement in shoe track
        2- Double check valves in float collar
        
        Hydrocarbons bypassed float collar check valves as they were damaged
      - Reservoir
        
        Annular cement barrier did not isolate hydrocarbons
        
        Centralizer
        
        BP rely on service provider to determine an appropriate cement slurry for the well
        
        Halliburton (service provider) did not conduct comprehensive lab tests that could have identified problems with cement product
      - Fire and gas system did not prevent hydrocarbon ignition
        
        Gas dispersed rapidly across the rig
        
        Gas entered engine room through air intakes
        
        Engines went into over-speed, resulting in loss of power
    - - Continuous psi pressure rise through tests and operation
    - - Influx and hydrocarbons were not recognised until they were in the riser
      - Diverted to mud gas separator
      - Communication was lost and resulted in various decisions (including unauthorized or trained) to occur
      - Hydraulic system leaks, solenoid valve coil faults etc. should have been detected by BOP diagnostic capability that was available to rig crew and sub-sea personnel through routine testing/ maintenance requirements
      - High pressure BSR function is one of six emergency methods that may have reduced/ prevented the accident. This is crew-initiated but was not achieved.
      - EDS function is crew initiated (rig personnel) from a control panel which was designed to mitigate the risk of losing containment but was not activated
      - AMF is designed to to mitigate risk caused by a catastrophic failure of the riser which had to be manually armed by rig personnel from BOP control panel but did not function
      - Rig crew attempted normal mode of BOP system operation using an annular preventer prior to accident
    - - Negative pressure test was accepted although the well integrity was not established
        
        Negative test was conducted to confirm the integrity of the annulus cement, shoe track, casing, and wellhead seal assembly
        
        Increase in pressure on drill pipe should have lead to further inquiry by personnel regarding integrity of well rather than test result assumed to be attributed to a phenomenon known as the 'bladder effect'
        
        Negative test was deamed a success by BP and transocean rig personnel
      - Well control response actions failed to regain control of the well
        
        Well must be shut in upon influx and if necessary, hydrocarbons diverted safely away from the vessel. Response by rig crew was not 'typical' in accordance with training and awareness of control events
        
        Diverter was closed and routed flow to mud gas separator
        
        Annular preventer was activated which did not seal the well
      - Decision to divert mud gas separator resulted in gas venting onto the rig
        
        In a well control event, the riser converter can be closed and the fluids directed
      - BP responsible for assuring cement slurry providers work and accepting proposal
      - BP decided to use six centralisers and a long string production casing in the well which is consistent design to others. This decision increased likelihood of channeling above the main hydrocarbon zone
      - BP and Halliburton could have improved technical assurance, risk management, and change management could have altered decision making on outcome
      - Well site leader was aware something was wrong and did not wish to proceed with normal operations, instead wanted to wait until more testing could verify mechanical accuracy.
        BP responsible for encouraging operations to continue and disregard pressure increase on drill pipe
    - - Sea Floor
      - Wellbore
      - Sea Pressure
      - Hydrocarbons
        
        Hydrocarbons entered well undetected and well control was lost
      - Energy/ Force
    - - Procedures and Engineering Technical practices
        
        Update and clarify current practices to ensure clear and comprehensive cementing guidelines are available and controlled
        
        Clearly defined mandatory practices
        
        Recommended practices and operational guidance
        
        Definitions of critical cement jobs
        
        Description of technical authority's (TA's) role
        
        Establish minimum requirements for ram types, numbers, capability, emergency well control activation systems
        
        Update relevant technical practices
      - Testing and Review
        
        Review and understand the purpose of the tests
        
        Define barriers to be tested
        
        Identify and evaluate consequences of failure
        
        Develop contingency plan of action in failure events/ likelihood
        
        Develop detailed procedure that requires comprehension
        
        Clearly define success and failure criteria for tests
        
        Apply authorisation instructions if results are outside defined success criteria
      - Management
        
        Review/ assess effectiveness of risk management and change management processes
        
        Develop/ implement action plan to address areas of improvement
        
        Define minimum standard of functional teams to deliver quality performance
        
        Assess high-consequence drilling activities
        
        Provide regular training to all staff on Incident and Emergency Response (IERP) procedures
        
        Develop and conduct Crisis Management Procedure where Crisis Management Team (CMT) are allocated roles and understand responsibilities
        
        Schedule and conduct high-level audits for safety, quality, and system/ operational compliance and verify/ correct audit findings
        
        Establish leading and lagging indicators for well integrity/ operational performance including well control and safety critical equipment
      - Competency
        
        Review all critical zones of isolation engineering plans and procedures
        
        Implement assurance and technical services including quality/ comprehension to industry standards
        
        Implement competency programs to deepen capabilities of personnel in operational and management/ lead positions
        
        Review current personnel level of knowledge, proficiency and determine necessary training for professional development (PD)
- - - - Installation Manager
      - Control room management
      - Ground floor senior manager
  - - - Muster Station
      - Control Room
      - Kitchen
      - Laundry
      - Social/ Games
      - Helicopter Platform
      - Crane Area
      - Fire Room
    - - Inadequate communication and understanding between rig manager and BP leader
      - Conversation between site well leader and rig crew regarding integrity testing was not communicated
      - As part of normal operations to temporarily abandon the well, the crew began to displace the remaining drilling fluid of seawater. The annular preventer was opened and the well returned to an overbalance position preventing further influx into the wellbore
      - Displacement continued as planned and the well went under-balanced resulting in pressure of the well dropping below the reservoir pressure
      - Well started to flow and crew emptied trip-tank which likely masked any flow indications on the flow meter
      - Failure
        
        Constant pump rate pressure should have declined as the mud (heavier) was replaced with seawater (lighter). Instead pressure on drill pipe increased by 100 psi, indicating well problem
        
        Sheen test on spacer is to check that no free fluid will be discharged to the sea. The pumps were shut down when the spacer reached the surface. A machine test was performed and the spacer was determined to be suitable for discharge.
        
        The drill pipe pressure continued to increase by the minute
        
        Fluid returned from the riser was routed to the overboard depth line
        
        All mud pumps were shut down before an attempt was made to bleed the drill pipe
        
        Mud shot up through the derrick and the diverter was closed so flow was diverted to the mud gas separator when the rig crew closed an annular preventor
        
        First gas alarm sounded
        
        Combustible gas cloud reached the aft starboard quadrant of main deck and entered air intakes for engine rooms. The main power generation engines went into over-speed, shutting off all electrical power and controls.
        
        Two explosions ocurred
        
        Emergency disconnect system did not function when activated and the lower marine riser package failed to unlatch from the BOP which did not seal the well
        
        Failure to recognise hydrocarbons entered well
        
        19 known modifications to the BOP and its control system were identified
  - - - Equipment conditions
      - Critical decision making
        
        Rig crew attempt to shut in the well and disconnect the lower riser package from the BOP stack
        
        Emergency disconnect sequence for the BOP was activated from the bridge. While lights changed on the control panel, no flow was observed on the flow meters
      - BP site leaders decided to continue production after negative pressure test
    - - After second integrity test was conducted, site well leader informed rig crew that negative test procedure needed to be conducted on the kill line
      - Site well leader informed rig crew to conduct first integrity test
      - Drill pipe valve was to be closed, tested, and reconfigured for flow and monitored on the kill line
      - Kill line valve was opened then closed by rig crew and monitored for 30 minutes for flow but no flow showed
      - Discussion around drill pipe pressure occurred and the source of the 1400 psi took place where it was explained as a phenomenon called the 'bladder effect;
      - Rig crew discussed the differential pressure on the drill pipe
      - When disconnection from the well failed, order to abandon the rig was called
      - Maintenance records were not accurately reported in maintenance management system
      - BOP complete record tracking of specific individual components was not achieved