SUMMARY OF MACONDO INQUIRIES

SAFER, SMARTER, GREENER

SUMMARY OF MACONDO INQUIRIES

OIL & GAS

Summary of Macondo InquiriesPAGE 2

The Macondo Event and Major InvestigationsThe Deepwater Horizon (DWH) drilling rig was operating on the Macondo prospect 90 miles south of Louisiana at a depth of 5000ft. It suffered a major blowout event on April 20, 2010 that led immediately to 11 fatalities and 17 seriously injured, to the rig sinking 36 hours later, and thereafter to a prolonged subsea release of gas and crude oil. A massive intervention was organized by multiple US Government agencies, BP, and many organizations, including DNV GL. The release was capped and the discharge halted on July 15th and by mid-September, a relief well intercepted the Macondo well and permanently sealed it with cement. The spill was estimated by the US Government to be 5 million barrels – the largest recorded offshore blowout event.

Given the significance of the event and the potential for other events associated with deepwater drilling where response is difficult, there have been multiple investigations and lessons-learned exercises. DNV GL has reviewed 21 major investigations and this report attempts to summarize these impartially – but there was necessarily some selection involved and we apologize in advance to the many authors if we might have inadvertently missed some points. Clearly no single investigation provides a full overview of needed actions.

SUMMARY OF MACONDO INQUIRIESBackgroundDNV GL is one of the largest advisory, verification and certification companies serving the global oil and gas, energy and maritime industries. Our corporate purpose is “to safeguard life, property and the environment” and one way we do this is to distill diverse information of importance and to share this publicly. This report which summarizes the many Macondo investigations is an example of this. There have been over 20 major inquiries – and many have quite different key lessons and recommendations. It can be difficult for people in the industry to have an overview of what recommendations were made and by whom. This report provides a short summary of each investigation and highlights important points it makes. Further investigation reports are likely, especially on the long-term environmental impacts, but DNV GL feels that this current summary would be timely.

The Deepwater Horizon drill rig (from National Commission Chief Counsel’s Report)Type: Deepwater, dynamically positioned, semi-submersible mobile offshore drilling unitConstructed: Hyundai Heavy Industries, KoreaCompleted: 2001Cost: $560 millionLength: 112 m (367 ft)Beam: 78 m (256 ft)Gross Tons: 32,588Persons on Board: 126Flag state: Marshall IslandsClassification: ABS A1, Column Stabilized DrillingUnit; AMS; ACCU; DPS-3

Figure 1. Deepwater Horizon Rig features© T

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Summary of Macondo Inquiries PAGE 3

1) National Commission – BP Deepwater Horizon Oil SpillThe National Commission was established by President Obama soon after the event with a mandate to report within 6 months. The Commission was chaired by Bob Graham and William K. Reilly, along with 5 other members and supported by a chief counsel and technical team. The main report was issued in January 2011 and was structured into 3 main sections: I) Path to the

Tragedy, II) Explosion and Aftermath, and III) Lessons Learned for Industry, Government, and Energy Policy. The Commission had an extensive support staff to collect and analyze evidence, but their report was one of the first published and thus many technical features were still unknown and were addressed in

later reports. The Commission staff issued 21 working papers on specific engineering and regulatory topics to aid the Commission’s understanding of the issues and current practices. Links to these papers are available at the IADC website.

In Part I, the history of development of drilling in the Gulf of Mexico (GoM) and particularly in deepwater was summarized, along with the technical challenges. The development of offshore regulations from the late 1970’s was summarized along with the potential conflict of interest within the Minerals Management Service (MMS) which issued leases and collected revenue from drilling activities, but which also regulated offshore safety. Potential overlaps with USCG regulations of offshore facilities are resolved through a memorandum. The Commission highlighted the prescriptive nature of MMS regulations and a lack of resources to enable the MMS and its staff to keep up with rapid developments and

No. Author Title Release Date

1 DWH Commission National Commission on the BP Deepwater Horizon Oil Spill and Offshore Jan 2011 Drilling – Main Report and multiple topic papers

2 DWH Commission Chief Counsel’s Report Feb 2011

3 BP DWH Accident Investigation Report Sep 2010

4 Transocean Macondo Well Incident: Transocean Investigation Reports, Vol. I and II Jun 2011

5 USCG Report of Investigation into the Circumstances Surrounding the Explosion, Apr 2011 Fire, Sinking and Loss of Eleven Crew Members Aboard the Mobile Offshore Drilling Unit DWH Vol.1 (MISLE 3721503)

6 BOEMRE JIT - BOEMRE Final Report regarding Macondo Well Blowout Sep 2011

7 Republic of the Deepwater Horizon Marine Casualty Investigation Report Aug 2011 Marshall Islands

8 Adm Thad Allen Incident Commanders Report Oct 2010

9 DNV GL Forensic Examination of Deepwater Horizon Blowout Preventer, Mar 2011 Vol. I and II (Appendices).

10 Chemical Safety Board Investigation Report (Vols 1-2) Jun 2014

11 Center for Catastrophic Risk Final Report on the Investigation of the Macondo Well Blowout Mar 2011 Management (UC Berkeley)

12 National Academy Macondo Well-Deepwater Horizon Blowout: Lessons for Improving 2012 of Engineering Offshore Drilling Safety

13 National Research Council Ecosystem Services Approach to DWH 2013

14 US District Court Court Judgment Sep 2014 Eastern Louisiana

15 Norway Petroleum Interim report – DWH Accident Jun 2011 Safety Authority

16 Norway Petroleum PSA’s Concluding report on its follow-up for the DWH accident Feb 2014 Safety Authority

17 OGP Getting it Right Jan 2013

18 OLF DWH Lessons Learned and Follow-up Jun 2012

19 SINTEF Report on DWH (A19148) May 2011

20 UK HSL DWH Fire & Explosion Issues Apr 2014

21 US Transportation Evaluating the Effectiveness of Offshore Safety and Environmental 2012 Research Board Management Systems (Special Report 309)

Table 1. Major Macondo Investigation reports summarized in this study (Numbers refer to the following sections, a full Table of Acronyms appears at the end of the document)

Table 3 in the Conclusions summarizes the topic areas addressed in the findings and recommendations of each inquiry.


to carry out its inspection activities. This ultimately led to “a departure from the normal standards of excellence the nation expects”. Specifically, these deficiencies led to an inadequate review and permitting of the Macondo well, and for BP’s inadequate Oil Spill Response Plan. The Commission contrasted this situation to regulatory developments in Norway and UK after major accidents where they adopted risk-based performance regulations, complementing prescription. The MMS had been pushing for a formal safety and environmental management approach (SEMS), but this was subject to much industry and internal government opposition. SEMS was mandated soon after the Macondo event.

In Part II, the causes and consequences of the disaster were reviewed. Many aspects of the Macondo well involved compromises affecting safety; and in accumulation they gave rise to a high risk well. The well cementing job was difficult and the subsequent pressure tests were misinterpreted by the drilling team. As they replaced heavy drilling mud with lighter seawater, a well kick event commenced but was not recognized immediately. Soon gas appeared on the rig, and the drill team diverted flow to the mud-gas separator and shut a BOP annular ram (Figure 2), but these actions were too late and soon afterwards a major explosion and fire occurred, killing 11 people and injuring 17 others. The BOP did not stop the flow – and questions remained as to when the shear rams were actuated. The commission identified several errors by the Drill Team, but went much wider to consider root causes due to failures in the companies involved, the industry and government. The Commission listed nine decisions taken in the weeks preceding, mostly to save time – all of which increased risk. This accumulation of additional risk was not assessed. Similarly, the MMS failed to pose any significant challenges to BP’s proposed abandonment procedure. The response activities were also summarized, and they document how the response increased in scale as the magnitude of the event was recognized. USCG Commandant Thad Allen was selected as National Incident Commander and he controlled a response that involved up to 45,000 people from government agencies, the oil industry, local populations and fishermen. Technical changes to the BOP had been made by Transocean but this was not recognized for 10 days and this affected interventions. Efforts to minimize the impact of the spill included closing fishing areas, use of dispersants, and deploying a containment dome. The initial well release rate was significantly underestimated and this meant dispersant injection was insufficient to be fully effective. The containment dome failed due to accumulation of hydrates formed at the cold temperatures prevailing and these blocked the collection system. Further interventions included a top kill and a junk shot – these also failed. Surface interventions – offshore booms and berms protecting islands were tried with some success. Offshore oil skimmed by booms was collected when possible or burned. But use of dispersants continued and that caused controversy. A capping stack installed above the BOP was successful in stopping the release of oil on July 15th and this allowed a static kill followed by cementing by Aug 4th. The relief well was completed in mid-September and cement injected to permanently seal the well. The Commission documented the many environmental, social and economic impacts. A six month Moratorium was declared on new deepwater drilling on May 30, 2010.

Figure 2. BOP design

Part III addressed lessons learned for industry, government and for energy policy and contained the Commission recommendations. The report emphasized safety culture as a key factor for enhancing safety and discussed culture issues affecting BP, its contractors, and the GoM industry generally. The Commission also identified a conflict of interest in API, which serves as coordinator for industry expertise and standards, but also acts as the industry chief lobbyist. API standards were characterized as “lowest common denominator” rather than “best practice” standards, and since these standards underpin the Department of Interior regulations, the whole reg-ulatory system was compromised. The opposition to regulations for a SEMS program was a quoted example; API preferred a voluntary system. The Commission gave other examples of lessons learned from the nuclear Navy, the Exxon Valdez, Shell, and Bhopal. The experience in the civilian nuclear industry and its use of INPO (Institute of Nuclear Power Operations) to carry out regular demanding audits and assessments was suggested as a possible model for the O&G industry. The Commission also addressed spill containment and response requirements and liability issues. Two new industry cooperatives – the Marine Well Containment Company and Helix were mentioned as necessary solutions – but with a need to address long term R&D challenges. Commission recommendations were grouped into nine areas (A – G):


A. Improving the Safety of Offshore Operations (A1-A5)DOI should develop a blend of risk management and prescriptive regulations; it should adopt a safety case like approach for specific installations; it should adopt selected best practices from international approaches; Congress should separate the safety and revenue aspects of MMS; and ensure adequate finances

B. Safeguarding the Environment (B1-B3)Environmental analysis, transparency and consistency must be improved; interagency environmental cooperation to be enhanced; and lease fees should pay for these extra costs

C. Strengthening Oil Spill Response, Planning, and Capacity (C1-C6)

DOI should carry out oil spill risk analysis and implement better response strategies; EPA and USCG should develop better plans for major oil spills including State and local agencies; there needs to be adequate R&D funding; the control and use of dispersants should be enhanced; and the use of shore berms should be discouraged

D. Advancing Well-Containment Capabilities (D1-D3)Government must enhance its expertise in source control technologies, and be able to estimate release volumes more accurately; Operators must enhance their oil spill response plans; demonstrate that their wells have provide adequate diagnostics and that well design mitigates risks to well integrity after a blowout event

E. Overcoming the Impacts of the Deepwater Horizon Spill and Restoring the Gulf (E1-E7)

USCG to provide timely access to scientists during a spill event; compensation for remediation needs to be transparent; EPA to assure that human health issues are addressed; efforts are needed to restore consumer confidence; 80% of revenue from penalties should be directed to restoration; government to assure that restoration is carried out on a strong footing; and better holistic management of the OCS areas including monitoring and planning

F. Ensuring Financial Responsibility (F1-F4)The $75m liability cap must be increased; payouts per incident should be increased; the DOI should enhance auditing and evaluation of offshore risks; and the claims payment system should be reviewed and enhanced

G. Promoting Congressional Engagement to Ensure Responsible Offshore Drilling (G1-G2)

Congressional oversight capabilities should be enhanced; ensure adequate funding is directed to relevant government agencies.

The Commission concluded that deepwater resources are key to future US oil supply security and these must be managed better. These ideas need to be applied to areas beyond the GoM OCS such as Alaska and to address the challenges of the Arctic.

2) National Commission – Chief Counsel’s reportThe Chief Counsel’s report complements the Commission’s main report and contains significantly more technical details. This report focuses on the direct technical and managerial causes of the accident and does not address response activities or environmental, social or economic impacts. Main chapters deal with deepwater drilling topics and the Macondo well, deepwater well design,

cementing, the temporary abandonment, the negative pressure test, kick detection and response, and the blowout preventer and its maintenance. Many findings are made on technical and management issues, but the report does not make recommendations – these are presented in the Commission main report (1). But the findings do highlight important issues and lessons learned.

The specific technical findings presented align with knowledge at the time – the well design issues, the abandonment process, cementing failure, the faulty pressure tests, replacement of heavy mud with seawater, and failure to recognize the kick and to respond sufficiently quickly. The report was based mainly on their own investigations, witness interviews and company statements, and included some recovered equipment from the seabed; but this was before the DNV GL forensic investigation (9) and the CSB investigation (10) which better explained the reasons for the BOP failure. The report included a very detailed and well-illustrated explanation of deepwater well design issues and explained some of the reasons for the specific design selected by BP and also some of the risks it created – for example the cementing challenges involved with the long production string used.

It is not possible to list all the findings identified in this lengthy report, but some main findings are presented. The use of a long production casing made the cementing job more difficult and the use of rupture disks to prevent annular pressure build-up compromised later containment efforts as these were believed to have failed inwards. BP selected the long-term benefits of using the long string without adequate assessment of the short-term risks. The report was clear that the cement job failed but there were several possible reasons and it was not possible to select amongst these. Contributory factors may have included the limited number of pipe centralizers used, the low pre-cementing mud circulation, the low volume of cement used, and some other factors. Management findings focused on BP’s systems that did not force the Macondo team to identify and evaluate all cementing risks; and changes to the well plan that were not adequately assessed. The BP team did not assess contractor data in sufficient detail and made too simple an analysis of well data as an indicator of cementing success. Similar detailed analysis with technical and management findings applied to foamed cement stability, temporary abandonment, the negative pressure test, kick detection and response, and the BOP and its maintenance was presented.

A final chapter dealt with overarching failures of management. The Chief Counsel‘s team observed at least the following management failures: (1) ineffective leadership at critical times; (2) ineffective communication and silo’ing of information; (3)


failure to provide timely procedures; (4) poor training and supervision of employees; (5) ineffective management and oversight of contractors; (6) inadequate use of technology; and (7) failure to appropriately analyze and appreciate risk. Ultimately, the companies placed undue reliance on timely intervention and human judgment, in light of their failure to provide individuals with the information, tools, and training necessary to be effective.

The Chief Counsel’s report emphasized the influence of costs – the DWH rig was chartered at $533K/day and was the largest expense of the well. Many decisions were taken both onshore and offshore that saved time, but increased risk and these risks were not assessed. Examples include: BP did not run a cement evaluation log, nor did it perform further well integrity tests after the unexpected results of the negative pressure test, it did not install additional barriers during temporary abandonment, nor did it elect to install the surface cement plug closer to the wellhead. The BP incentive system focused on cost savings and encouraged top quartile performance. Safety was also an important factor in the incentive program – but this measured occupational safety, not major accident well safety. However, the report admitted this would have been difficult to measure.

The report addressed regulatory deficiencies, but these mirror the findings in the Commission main report and they are not repeated here.

The Chief Counsel’s report concluded: “the blowout occurred in large part because the companies diffused knowledge, responsibility for, and ownership of safety among themselves and among groups of people. The people onshore and on the rig had a false sense of security. They did not recognize the need for individual leadership in addressing the multiple anom-alies and uncertainties that they observed. Instead, they relied on many ambiguous “dotted line” relationships within and between the companies and personnel involved.”

3) BP Report: Deepwater Horizon Accident Investigation Report The BP team commenced their investigation very soon after the blowout event. They focused on the direct technical causes of the incident and did not address management related issues or alternative risk management strategies that might have been employed nor the sequence of emergency actions immediately after the explosion. As with the Commission report, the

authors provided a clear description of the technology employed for deepwater drilling and showed key safety provisions. They identified a sequence of eight key barriers that failed and permitted the accident to occur. These are shown in the Swiss Cheese barrier diagram format in Figure 3.

Figure 3. Barrier failures leading to DWH blowout event

The eight barrier failures identified by BP and shown in Figure 3 were:1) The annulus cement barrier did not isolate the hydrocarbons2) The shoe track barriers did not isolate the hydrocarbons3) The negative-pressure test was accepted although well integrity had not been established4) Influx was not recognized until hydrocarbons were in the riser5) Well control response actions failed to regain control of the well6) Diversion to the mud gas separator resulted in gas venting onto the rig7) The fire and gas system did not prevent hydrocarbon ignition8) The BOP emergency mode did not seal the well

The BP team made recommendations in eight areas that would apply to BP and to its contractors:

1) Procedures and technical practices Update practices related to cementing, well control, well design, negative-pressure testing, review risk management and management of change processes as practices by drilling teams, and recommend that API develop a recommended practice for foam cement

2) Capability and competency Strengthen the BP Technical Authority role for cementing and zonal isolation, and enhance personnel competency in key operational and leadership roles, develop an advanced deepwater well control training program, establish in-house expertise on subsea BOP’s and BOP control systems, request IADC to consider a certification program for personnel who maintain deepwater BOP’s

3) Auditandverification Strengthen BP’s audit and verification program on BP owned and contracted drilling rigs

4) Process safety performance management Establish leading and lagging indicators for well integrity, well control and safety critical equipment, require drilling contractors to implement an auditable integrity monitoring system,

5) Cementing services assurance Review immediately the quality of services provided by cementing contractors


6) Well control practices Confirm that essential well control and monitoring practices are clearly defined and rigorously applied offshore and at high hazard onshore wells

7) Rig process safety Require HAZOP studies on key parts of the surface gas and drilling fluid systems, including all surface system vents

8) BOP design and assurance Establish minimum levels of reliability for BOP systems, develop ROV intervention strategies, and for contractors strengthen minimum requirements for BOP tests, maintenance management systems and MOC processes, and to develop a qualification process verifying shearing performance for all types of drill pipe in use

4) Transocean: Macondo Well IncidentThe Transocean investigation is presented in Vol 1 with supporting appendices in Vol 2. The report had three main objectives – to establish 1) how the reservoir fluids reached the rig floor, 2) why the BOP failed to stop the

flow, and 3) how did the fluids ignite. The Transocean report did not make specific recommendations. Their main conclusion was: “The Macondo incident was the result of a succession of interrelated well design, construction, and temporary abandonment decisions that compromised the integrity of the well and compounded the risk of its failure.” Their findings were summarized into four main categories:

1) Risk management and communications BP was responsible for all planning and design details, and it approved the work of all contractors. It failed to assess, manage and communicate risks and these failures led the Transocean drill team to make faulty actions on the assumption that the cement job had been successful.

2) Well design and construction The Macondo well was difficult with a narrow margin of pore pressure to fracture pressure and the well had experienced both lost circulation and kick events. Rather than change its long-string production casing design BP decided to adopt a complex nitrogen foam cement with little margin for error. This was poorly installed and not tested adequately and the cement may have been compromised.

3) Risk assessment and process safety Halliburton and BP failed to test the cement adequately given the risks and test data showing the cement might not have been stable. BP generated five different abandonment procedures over an eight day period and the final plan called for an unnecessary displacement of the mud. There was no documented management of changes and risks were not assessed.

4) Operations The negative pressure test was incorrectly approved by all present, including BP. When mud was displaced the well became underbalanced and hydrocarbons entered the well

through the faulty cement. None of the drill team detected the influx. Data analysis shows the influx was occurring but it is unknown if the team was aware of this data. The DNV GL forensic examination (9) showed the BOP functioned but failed to seal the well due to the drill pipe bowing outside of the shear ram cutting zone

Following the ignition and initial blast, 115 staff mustered and safely evacuated, assisted by the presence of an offshore supply vessel

BP made several changes from its initial well plan: reduced the target depth of the well; considered changes to the well casing; used a lower circulating rate than the parameters specified to convert the float collar; reduced cement density with nitrogen foam; used a lesser quantity of cement than that specified in BP procedures; and decided not to perform a complete bottoms-up circulation before cementing.

5) USCG JIT - Vol.1 Report into the Deepwater Horizon (Ref: 3721503)

This investigation was conducted under a Memorandum of Agreement with BOEMRE. That agency was responsible for incidents related to drilling, production, and pipeline operations, and USCG was responsible for

fatalities/injuries, property loss, vessel safety systems, and environmental damage. The USCG also coordinated data requests for this report with the Flag State – Republic of the Marshall Islands. To aid their work, a Joint USCG-BOEMRE Investigation Roadmap was developed. This defined interested parties, the 7 public hearings, and the various safety activities that would be reviewed. The USCG aspects relevant here are: 1) the explosions, 2) the fire, 3) the evacuation, 4) the flooding and sinking of the MODU, and 5) the safety systems of the Deepwater Horizon and its owner-operator, Transocean. The USCG concluded there were multiple systems deficiencies on-board the vessel contributing to the event. These included poor maintenance of electrical equipment that may have ignited the explosion, bypassing of gas alarms and automatic shutdown systems that could prevent an explosion, and lack of training of personnel on when and how to shutdown engines and disconnect the MODU from the well to avoid a gas explosion and to mitigate the damage from an explosion and fire. These deficiencies indicated that Transocean’s failure to have an effective safety management system and instill a culture that emphasized and ensured safety contributed to this disaster. The USCG also was critical of the oversight from the Flag State (RMI). They had delegated all of its inspection activities to “recognized organizations” and thus in the view of the USCG it had abdicated its inspection responsibilities.

The report summarized detailed findings on each of the five aspects for which the USCG was responsible. Regarding explosions they found multiple problems with safety systems – for example gas detectors did not automatically actuate safety systems and many were bypassed to avoid false alarms. There was insufficient protection of staff from blast loads. There was some organizational confusion between the OIM and the Master that may have affected actuation of the Emergency Disconnect


System. The firewater system was electrically powered and the explosions rendered the power system inoperative – a diesel fire pump would have helped. The A-Class bulkheads (a lesser standard than H-Class) did not prevent the spread of fire as they were not designed for the heat experienced. Several practical fire protection recommendations were made to address observed deficiencies. The evacuation was affected by the intense fires and some staff could not reach the two available lifeboats and had to jump. A lack of proper drills and heat protection of the area meant that one liferaft was improperly launched, with a line still attached to the rig. Several recommendations were made to enhance practice drills, to protect launch areas from heat exposure, and to address the need for fast rescue craft. Firefighting was not well coordinated as the initial focus was towards saving lives. This meant that excess water may have been applied from responding vessels and when combined with known prior violations of watertight integrity, may have contributed to the sinking. The USCG identified several deficiencies in compliance to the ISM Code. The BOP was recertified after 10 years rather than every 3-5 years, there had been two prior serious incidents but neither was properly investigated, and there were deficiencies in Master and crew training, and these gaps in emphasizing safety led to staff bypassing important gas alarms.

The USCG made a large number of detailed recommendations related to its areas of responsibilities (these are listed in Table 2). Some were made to IMO and others to Congress to amend local regulations. Flag states need to enhance their own inspection activities and to audit recognized organizations acting on their behalf – in this case ABS and DNV GL.

Although the report focused on deficiencies, a final section did commend the heroic actions of staff onboard the Deepwater Horizon, the Damon B Bankston, and the Ramblin’ Wreck vessels. Detailed appendices provided design and

operational details of the Deepwater Horizon, a timeline of the event, a synopsis of audits and ISM non-compliances, and results of surveys.

6) BOEMRE – Report into Causes of Macondo Well Blowout The BOEMRE investigation was carried out as part of the Joint Investigation Team (JIT) with USCG. It focused on BOEMRE responsibilities, especially the drilling activity and the cause of the blowout. The introduction provided a

little background on deepwater drilling in GoM and the Deepwater Horizon drilling activities, but this was less “educative” than in the Presidential Commission Chief Counsel’s report which had appeared 7 months prior and thus had no need to be repeated. The report provided an analysis of the available drilling margin, the casing program, and various mud issues. It also covered casing design issues around a long string vs. a liner system and discussed key factors in the selection. A third option would have been to abandon the well without setting any production casing, as BP had done in other narrow margin GoM wells, and BOEMRE noted this might have made sealing the well easier.

The BOEMRE report provided a good discussion on cementing approaches and particularly the nitrified (i.e. foamed) cement slurry as was used. Nitrified cement is less dense than unfoamed cement and therefore exerts less pressure on the formation. However, the use of foamed cement creates the risk of nitrogen breakout and hence a non-uniform density. Overall, it still remains a viable option, but requires greater care.

The Halliburton OptiCem model was used for the well, with 30-40 model runs trialing different options. BOEMRE identified a number of faults with the model parameters used. They noted that BP did not query the model parameters nor did it share the results with Transocean – and cementing was critical to well integrity. There was also an issue with centralizers. There were only 6 on-board and the Halliburton cementing model suggested 21 were needed. BP located 15 additional centralizers and these were delivered to the rig, but these would have taken longer to install and they were not used. BOEMRE concluded however that the lesser number of centralizers did not cause the blowout event. The float collar suffered a blockage problem during conversion. There is doubt that conversion actually occurred properly and this would affect cement effectiveness. BP could have used a more debris tolerant design, but BOEMRE could not establish exactly what caused the blockage.

BOEMRE then developed about a dozen contributing causes to the blowout – mostly ascribed to BP failings. They also considered alternative flow paths but decided that the primary flow path was through the 9⅞ x 7” production casing from the shoe track as a result of float collar and shoe track failures.

BOEMRE then examined multiple technical challenges and organizational issues (schedule and personnel changes and conflicts, cost overruns) and the details of the actual abandonment process – including the failed negative pressure test. They then addressed reasons why the Transocean team

Ref Recommendation summary

1A Labelling of rated electrical equipment in hazardous areas.

1B Guidance on design of detection and alarm systems.

1C Guidance on fire and explosion strategies for units with DP.

1D Specification of minimum explosion design loads.

1E Explosion risk analysis for each existing facility.

1F/G Control of location of ventilation inlets. Shut down of ventilation in the event of gas detection.

2A Fire pumps to be self-contained.

2B H-60 rated separation between drill floor and adjacent accommodation areas.

2C Guidelines on engineering evaluations of fire partitions.

2D Fixed deluge or monitors provided for drill floor.

2E Fire risk analysis to supplement the prescriptive requirements of the MODU code.

3A Standards for maximum radiant heat allowable at muster stations and lifeboat stations.

Table 2. Summary of USCG Recommendations – related to fire & explosion


might have failed to recognize the kick, the later flawed drill floor response, and the failure to activate the emergency disconnect system which would have actuated the shear rams. Possible ignition sources were discussed.

The reasons for the BOP failure to seal the well referred mainly to the DNV GL Forensic examination (9). BP company policies were a contributing factor.

BOEMRE did review regulatory processes and how these may have contributed to the event. However in most instances they concluded these had no contribution to the blowout event.

A final section provided 41 recommendations and was divided into six sections (with recommendations counts in each): wells (6), kick detection and response (8), ignition source (4), BOP (6), regulatory agency (11), and OSC Companies (6).

Some of the more significant recommendations included: ■ require the negative pressure testing of wells where

appropriate ■ require at least two barriers (one mechanical and one

cement barrier) for a well that is undergoing temporary abandonment procedures, and to clarify that a float collar/valve is not to be considered to be a “mechanical barrier.”

■ revise the incident reporting rule at 30 CFR§ 250.188 to capture well kick incidents

■ enhance BOP operation and intervention ■ expand 30 CFR § 250.446 to include documentation and

record keeping requirements for major (3-5 year) inspections as required by BOEMRE’s adoption of API RP 53

Note, there was no recommendation regarding safety and environmental management systems as BOEMRE had already decided by this time to require adoption of SEMS based on API RP 75.

7) Marshall Islands Registry – DWH Marine Casualty Investigation Report

The Flag State for the DWH was the Republic of the Marshall Islands. Under international conventions, the Flag State must report the causal factors of all serious and very serious marine casualties. Therefore the

Marshall Islands issued a report to the IMO on 17 Aug 2011 outlining its findings with respect to the accident. The focus of this report was to identify non-compliances with relevant international regulations, including the United Nations Convention on the Law of the Sea, 1983 (UNCLOS), the International Convention for the Safety of Life at Sea, 1974, as amended (SOLAS), and the Code of the International Standards and Recommended Practices for a Safety Investigation into A Marine Casualty or Marine Incident.

The report provided a detailed timeline of the incident including witness statements. The report then addressed the functioning of the safety and other equipment and human and organizational factors. There were instances of unclear command and control, evacuation systems that did not function well (as power had been lost), and the Emergency Disconnect

System did not function as intended. All inspections required by Flag State and USCG were in place and classification surveys by ABS were current. The vessel complied with its Minimum Safe Manning Certificate and all marine crew and officer positions were held by staff holding appropriate credentials. The vessel sank due to damages sustained in the explosion and this led to its listing. Further ingress of fluids caused greater listing and once the deck reached the sea surface, further ingress occurred and the vessel sank.

The report concluded that the causal factors were: deviations from standards of well control engineering; deviation from the well abandonment plans submitted to and approved by the Minerals Management Service; and failure to react to multiple indications that a well control event was in progress.

The report also identified a number of non-causal factors. These included:

■ Better communications between the Flag State and the coastal state on inspections might have increased awareness of safety issues

■ The DWH structure withstood the explosion sufficient to allow evacuation of most staff, but the power failure affected any possible fire response – but that would have been futile due to the damage and hydrocarbon leak

■ The Emergency Disconnect System did not function as intended

■ There was evidence of confusion in chain-of-command during the emergency but this was not a causal factor

■ Rapid evacuation., although not as planned, is a testament to the robustness of the regulatory system and the redundancy of life saving equipment

The report contained 17 recommendations, but the Marshall Islands highlighted four: enhanced communications between the Flag State and the Coastal State; IMO should review the MODU code related to aspects of this incident; there should be better definition of responsibilities of the Master and OIM especially during emergencies; and better procedures for actuating the Emergency Disconnect System.

8) Adm Thad Allen: Incident Commander’s ReportOnce the scale of the incident was established, the event was declared to be a Spill of National Significance and Thad Allen, then Commandant of the USCG, was declared the National Incident Commander. These were the first applications of these terms and the event tested existing laws and regulations very hard. The Oil Pollution Act (OPA 90) and the National Contingency Plan (NCP – 40

CFR Part 300) provided the guiding regulations but there was overlap with a Homeland Presidential Directive for domestic incidents. Allen recommended these two documents need to be reconciled before another emergency occurs.

The NCP had been deployed successfully for thousands of spill events over the past 20 years. However, it started to break down during the Deepwater Horizon spill as some aspects were not accepted by the public or by state officials – notably the role of the responsible party (here BP) was not understood and some


states/local authorities did not accept federal authority. There was concern that BP would not sufficiently prioritize the environment over its shareholder interest. Allen stressed that the Federal Government directs and oversees the response – the responsible party must implement these instructions. Adm Allen and the Federal On-Scene Coordinator issued many directives to BP, and BP provided the resources and capabilities as required by law, but he notes that BP and its subcontractors often executed these without direct government supervision.

State and local actions were in many cases outside the NCP structure and this was partly due to the 9/11 attacks that resulted in substantial emergency resources having been channeled to these bodies. Adm Allen concluded unequivocally that the NCP is a sound framework and allowed for the needed discretion and freedom of action to address contingencies during the response.

The response involved 47,000 people, 120 aircraft controlled from a dedicated air center, a fleet of 6,500 vessels (more vessels than the D-Day landing in Normandy), and boosted manufacture of booms from around a thousand feet/week to over a quarter million feet/week. Figure 4 from BP shows the scale of response efforts.

Figure 4. Massive scale of response to spill event

The National Incident Commander (NIC) concluded that the Oil Pollution Act of 1990 and the NCP provided a sound basis for response and any changes should not change its fundamental governance structure. But many changes were required. There must be better integration of all necessary government agencies before there is an emergency, actions are needed to de-conflict and reconcile the role of the NIC, the NIC must have adequate authorities to execute the role properly and work with the National Response Team (15 relevant federal agencies), and the private sector must be encouraged to develop modern oil spill response capabilities, matching the challenges of deepwater activities.

9) DNV GL Forensic Examination of Deepwater Horizon BOPThe Justice Department commissioned DNV (now DNV GL) to carry out a forensic examination of the Transocean BOP recovered from the sea floor once the well had been killed. The objectives were to determine the performance of

the BOP system during the well control event, any failures that may have occurred, the sequence of events leading to failure(s) of the BOP and the effects, if any, of a series of modifications to the BOP stack that BP and Transocean officials implemented.

The BOP was transported to NASA’s Michoud facilities in Louisiana where tests were conducted. A detailed set of tests was agreed amongst the interested parties. This included the ST Locks, Choke and Kill Valves, the five rams on the lower BOP, the HP accumulator, and the hydraulic and electronic circuits of the AMF/Deadman and autoshear systems. Drill pipe was recovered from inside the BOP, from the riser, and from the sea floor – these segments were matched together to determine the failure mode.

The report was designed to support legal proceedings, if required, and thus contains a very detailed set of information with 149 figures and 30 tables. The equipment examined is shown in Figure 5.

Figure 5. BOP and associated equipment

Selected conclusions on the event include: ■ Evidence supports that the Upper VBRs were closed at

21:56 prior to the EDS activation on April 20, 2010 (the date of the accident)

■ Forces from the flow of the well induced a buckling condition on the portion of drill pipe between the Upper Annular and Upper VBRs

■ The portion of the drill pipe located between the shearing blade surfaces of the Blind Shear Rams was off center and held in this position by buckling forces

■ As the BSRs (Blind Shear Rams) closed, this portion of the drill pipe became trapped between the ram block faces, preventing the blocks from fully closing and sealing (Figure 6)

■ Trapping of the drill pipe between the ram faces would have taken place regardless of which means initiated BSR closure (AMF/Deadman or Autoshear)


■ When the drill pipe was sheared on April 29, 2010, using the CSRs (Casing Shear Rams), the well flow pattern changed to a new exit point through the open drill pipe at the CSRs expanded to flow up the entire wellbore to the BSRs and through the gap along the entire length of the block faces.

Figure 6. Location of drill pipe inside BSR and its effect on BSR cutting ability

The DNV GL report made a number of detailed recommendations to industry regarding BOP design and operation issues. These included:

■ Study of elastic buckling of drill pipe – as this is what prevented the BSR from functioning properly

■ Study of the shear blade surfaces of shear rams – as they could not shear the off-center drill pipe

■ Study of well control procedures or practices – as the timing of the closure of the Upper Annular and the Upper VBR’s contributed to the drill pipe buckling and moving off center

■ Better testing of back-up control systems – as some system components did not perform as intended

■ Better processes to prevent common mode failure of back-up control systems

■ Provide better means to verify the operation or state of various components of BOPs in an emergency

■ Study of the effectiveness of Remotely Operated Vehicle interventions

■ Stipulating requirements for back-up control system Performance – as now for primary control functions

10) CSB Investigations (Vols 1-2)The US Chemical Safety Board, which is well known for its onshore investigations, undertook an investigation into the Macondo offshore event at the request of Congress. They issued two reports in June 2014. Vol 1 addressed the

relationship between the parties involved and described the many technical challenges associated with the drilling at Macondo. Vol 2 is much more detailed and this focused on the CSB technical findings on the Deepwater Horizon BOP and its ongoing management as a safety critical element (SCE). The report presented the technical evidence carefully with many detailed figures and tables. The CSB noted that two further reports (Vols 3-4) will be issued addressing human factors issues and organizational issues. The CSB Vol 2 report contained many photographs and diagrams to explain the relatively complex sys-

tems around the BOP and their analysis, which involved additional BOP function tests, went beyond prior investigations by the National Commission and others.

Vol 2 had five main objectives: 1) to review the BOP reliability issues; 2) to account for drill pipe buckling inside the BOP; 3) to explore possible barriers (hardware, operational and organizational) to prevent such accidents; 4) to outline a management system for SCE’s; and 5) to identify regulatory enhancements related to SCE’s.

The CSB participated in some of the forensic examinations of the BOP and carried out its own additional tests. They identified gaps in BOP effectiveness due to when it might be actuated – either manually or by one of the automatic systems. Although the DWH BOP contained multiple redundant systems designed to achieve a very high reliability, the CSB identified many deficiencies in components of this system. The CSB found evidence of miswiring of two systems (one each in the blue and yellow control pods – see Figure 7). This drained one battery making the blue pod inoperative on the day, and the yellow pod miswiring would have prevented its operation as well except a battery failure in it allowed the yellow pod to actuate the BSR. A separate issue identified in (9) and accepted by the CSB was the buckling of the drill pipe inside the BOP and this prevented the BSR knife edge from cutting through the pipe. The CSB noted that while the BOP was frequently tested for operational function, these deeper latent individual component failures could not be identified by those system-level tests. However, the BOP manufacturer recommended tests that would have identified the component failures. Changes in testing protocols post-Macondo by the industry have improved, but not eliminated, AMF/deadman failure to actuate the BOP.

Figure 7. Example of BOP miswiring*

*Note: Photograph of Y103 wire arrangement from Phase II testing with pins 1 and 4 connected to white wires and 2 and 3 connected to black wires. (Right) Schematic of correct arrangement of wires, with pins 1 and 3 connected to white wires and 2 and 4 connected to black wires.

The CSB noted several opportunities to improve US regulations. These should include risk based concepts with a focus on major accident events; that safeguards for such accidents be based on a sound philosophy; that there should be an explicit target for risk reduction (e.g. ALARP); and that SCE’s be identified and managed through life to attain defined performance standards.

The report addressed a number of specific faults for the BOP, but the CSB decided not to make detailed BOP design recommendations, rather to focus on a higher level on issues

Drill pipe properly centered in BSR

Drill pipe buckled beyond BSR cutting zone


relating to all Safety Critical Elements. These include that BSEE should develop regulations requiring SCE’s to be identified and performance standards defined for each, and that risks be reduced to an ALARP target level. SCE’s should be monitored through life; that there should be an independent verification scheme for these; and deficiencies identified be documented and corrected. The CSB recommended that API support this process by developing guidance documents for identifying SCE and reducing risks to ALARP. More specifically also, the API should revise Blowout Preventer Equipment System for Drilling Wells (API Standard-53, 4th edition) to establish additional component level tests to supplement the current system level tests.

11) Center for Catastrophic Risk Management (UC Berkeley)A group of experienced risk management and organizational specialists resides at the UC Berkeley Center for Catastrophic Risk Management and this includes members who developed the high reliability organization

model. The Center formed an investigation team to assess this accident – the Deepwater Horizon Study Group. The final report was issued in March 2011, and this was preceded by 3 progress reports. The study group addressed both technical and organizational causes. The report contained a useful deepwater drilling technology overview and provided a clear description of the technical and organizational failings. They made multiple findings and recommendations.

In the three progress reports the Center concluded: 1) this disaster was preventable had existing progressive guidelines and practices been followed; 2) the failures (to contain, control, mitigate, plan, and clean-up) appear to be deeply rooted in a multi-decade history of organizational malfunction and shortsightedness; and 3) thus, as a result of a cascade of deeply flawed failure and signal analysis, decision-making, communication, and organizational - managerial processes, safety was compromised to the point that the blowout occurred with catastrophic effects. At the time of the Macondo blowout, BP’s corporate culture remained one that was embedded in risk-taking and cost-cutting.

Key findings in the Center final report included: ■ Deepwater exploration and production poses greater risks

than are commonly understood ■ Risks can be orders of magnitude greater than in shallow

waters and to be ALARP much greater precautions are necessary than displayed at Macondo

■ Ongoing developments should be at a measured pace and require deployment of BAST technologies (Best Available and Safest Technologies)

■ A step change process is required matching BAST technologies with high reliability type organizations and collaborative industry government relations.

The Center recommendations included: ■ Develop technology systems between government and

industry to develop high hazard wells sustainably ■ Develop institutions capable of effective risk assessment

and management of high hazard wells

■ Implement such risk based systems in the context of high reliability organizations and capable of responding to major blowout events

■ Utilize validation projects to show such characteristics.

12) National Academy of EngineeringThe National Academy of Engineering convened a review panel of 15 experts in response to a request from the Department of Interior. Their report included main sections on well design and construction, the BOP system,

MODUs, industry management of offshore drilling, and regulatory oversight; each of these with multiple findings, observations and recommendations.

Appendix C in the report grouped together all 38 findings, 23 observations, and 68 recommendations. While these are all important, space does not permit listing all of these here, however the Summary chapter highlighted the most important and those 13 recommendations are listed here:1) Develop guidelines for drilling and completion that address credible risks and safety margins2) Tests should be defined with acceptance criteria for primary cement and mechanical barriers3) BOP systems need to provide reliable cutting, sealing and separation, with suitable maintenance and training4) Instrumentation / expert systems should warn of loss of well control with automatic functions if response is delayed5) Consequences of loss of well control should be mitigated by access to well capping and containment capabilities6) US regulations should be updated to be a hybrid of prescription with proactive goal-setting7) BSEE should identify and approve safety critical points in well construction and abandonment8) A single US agency should have responsibility for an integrated approach to system safety for offshore drilling9) Operating companies should have ultimate responsibility for well integrity and the drilling contractor for equipment10) Industry should carry out more R&D on all aspects of drilling safety including design, equipment, human factors, and management11) There needs to be formal education and training of offshore staff to properly implement system safety12) Develop industry-wide systems for incident reporting, including confidential reporting, and share lessons learned openly13) Enhance safety culture through training, addressing human factors, system safety, and leading indicators

13) National Research Council – Ecosystem Services Approach to DWH (2013)The NRC team adopted a newer approach to damage assessment and restoration by means of an ecosystem services approach. This focused not on the natural resources themselves, but on the valuable goods and services these resources supply to people. At the current stage, the team could only assess four case studies for ecosystem services. The aim is to support agencies in their duties under the Oil Pollution Act of 1990 to make the environment and the public whole.


Wetlands: The Committee identified that 1100 miles of coastal salt marsh were affected during the event. Only some limited areas are not expected to recover. Some areas where root systems have died are being converted from marshland to open water, and subsequent storm activity resulted in additional erosion. However, where roots and rhizomes survived, little or no long term impairment is expected. A complicating factor is significant and ongoing losses of wetlands due to many other factors.

Fisheries: Fisheries in the GoM provide some of the most important and lucrative services through the production of seafood, industrial fish products, and recreational fishing. Fishery closures ordered by NOAA in the aftermath of the spill resulted in decreased fishery landings of up to 20% of the GoM total in 2010.

The committee also examined marine mammals (blue nose dolphins) and the deep Gulf of Mexico ecosystem – but no direct conclusions were offered on either of these.

14) US District Court Eastern Louisiana– Judgment (Sept 4 2014)While this judgment by Judge Barbier is not an inquiry like the others – it does represent a detailed examination of the evidence with several key findings. Unlike inquiries, it is subject to appeal and findings may be subject to change. This court was assigned responsibility for most federal cases under a judgment for multi-district litigation.

The Court ruling reviewed the accident sequence in some detail, but focused primarily on technical issues and human errors involved. It assessed the well design options, the faults with the float collar conversion, cement placement and composition problems, and the misinterpretation of the negative pressure test. The Court reviewed the kick event and the failure of the AMF and some BOP functions due to maintenance problems. Finally the emergency response was reviewed. However, the Court did not address organizational factors.

The Court found that the discharge of oil was the result of BP’s “gross negligence” and “willful misconduct”. This is an important finding as the fine per barrel of oil discharged is normally $1,100 but this is nearly quadrupled in the case of gross negligence. In this context ordinary negligence is a failure to exercise the degree of care that someone of ordinary prudence would have exercised in the same circumstances, whereas gross negligence is an extreme departure from the care required under the circumstances or a failure to exercise even slight care. The Court further finds that BP’s conduct was reckless. Transocean’s conduct was negligent. Halliburton’s conduct was also negligent. In assigning percentage liability the split was as follows: BP 67%, Transocean 30%, and Halliburton 3%. Although BP’s conduct warranted the imposition of punitive damages under general maritime law, BP cannot be held liable for such damages under Fifth Circuit precedent.

15) Norway PSA – Interim Report DWHThe Petroleum Safety Authority is the safety regulator for offshore developments in Norway. It established an internal review team after the Macondo event, but considered also Montara (2009), Snorre A (2004) and

Gullfaks C (2010) events and that work generated an interim report in 2011. The extensive report is in Norwegian, but there is a short English summary which contains its key findings. Some lessons for Norwegian Operators are listed here.

The full report provided a detailed description of the accident with numerous figures explaining the drilling strategy, the BOP design and the formation of the gas cloud and explosion on the rig. Following chapters then discuss various issues identified and from these the PSA extracted lessons for Norwegian offshore industry. There are a large number of lessons.

The PSA does not believe that the Macondo accident challenged the critical philosophies underpinning the Norwegian regulatory system such as the division of responsibility for regulatory compliance and the demand for systematic and risk-based compliance with functional requirements. But it did challenge whether the PSA is continuously improving the way it seeks to influence safety. An overall observation was that industry needs to significantly improve how it manages major accident risk and that safety culture must be enhanced.

The PSA addressed lessons specific for Macondo-style drilling and well operations, but also for major accidents offshore in general. The PSA noted the Macondo accident did not arise due to some new causal mechanism unique to deepwater GoM or to the companies involved, thus its lessons were relevant to the management of major accident risks on the Norwegian Continental Shelf.

The need for effective barrier management covering all barrier elements is emphasized. There should be an integrated approach to well barriers, including the principle of two independent and tested well barriers as well as barrier monitoring. The DWH accident confirms the importance of defining the ambition level of performance standards for barrier elements and ongoing monitoring of these. In Norway, the effects of cold climate and aging facilities are important in this regard. The BOP may need to have an associated SIL level to ensure its reliability.

The DWH accident has highlighted the need for an effective capping and containment capability. Furthermore there is a need for better training of key staff in dealing with emergencies. Better systems are needed for disconnection from the well, and for enhanced ignition controls especially related to air intakes of power generators. Maintenance of the BOP was an issue and the PSA reemphasized the need to maintain safety critical equipment.

The PSA highlighted that offshore safety needs a systems perspective – complex systems fail in complex ways and simplistic solutions are not likely to be effective. There needs to be a program to develop better tools for managing major


accident risk, especially related to decision support. These would provide information on uncertainties, highlight safety critical priority areas, and prompt robust solutions.

Initiatives are needed to enhance safety culture and the development of a culture of accountability. Companies need to demonstrate their commitment to safety by participating actively in standards development.

The PSA should enhance safety by fostering strong and competent players. It could do this by making safety performance an important factor in awarding licenses, assessing company financial capacity, and determining whether management of major accidents are properly considered in company planning. The PSA concluded it needs to continue to support research into various topics related to major accident risks, both technical and social.

Finally, the costs associated with the DWH have exceeded the cost of all previous accidents and this leads to a need to assess financial incentives and how these impact safety decisions, the quality of information characterizing major accident risks and how such risks might be priced, and how audits might address this.

16) Norway PSA – Concluding report on DWH accidentThe Interim Report was issued in 2011 and the PSA decided that a follow-up report was justified in 2014 addressing new information that appeared after the Interim Report. The central findings did not change, but extra

emphasis was given in several areas, and some recent changes are documented.

The original work concluded that the Macondo accident did not challenge the central principles used in Norway for systematic risk-based compliance with functional requirements (i.e. a goal-based regulatory system under-pinned by thorough risk assessment). The PSA studied well control events on the Norwegian Continental Shelf and identified four main challenges:

■ the need for a stronger commitment to technical measures to improve safety

■ a bigger commitment to planning, barrier management and better-adapted risk analyses

■ paying greater attention to major accident risk – more investigation of incidents

■ creating operational parameters for good collaboration in the operator/supplier hierarchy.

In the area of risk assessment, the PSA noted that the DWH accident demonstrated a need for better risk management and processes which lead to more robust solutions and operations. The impression may be that awareness of major accident risk and robust solutions/operations has increased, but the PSA concluded that the industry still has a further way to go in adopting a more proactive approach to managing risk.

Barrier management has been a PSA focus area for several years, but there is an ongoing need to maintain industry commitment to barrier management and to link this to overall

risk management. Finally, with respect to safety culture and organization, the DWH accident highlighted the need for companies to be open to the unknown and pay attention to signals of vulnerability. The Interim PSA report called for development of tools and data to assess accident costs from a social perspective. The PSA initiated a several projects including “Culture and system for learning” and this produced communication and audit tools. The Norwegian industry has initiated several projects relating to safety culture, organization and management. The NORSOK D-010 standard for well control has been updated, including key performance indicators and change management.

BOP equipment is the subject of ongoing work by IADC and OGP, and PSA is awaiting the results of this. The PSA quoted OGP as believing that the BOP as an isolated system has a SIL rating of 3, but this drops to 2 when connected to the wellhead, and maintaining this SIL level over the BOP lifetime poses a challenge. PSA agreed with BSEE’s four main expectations for the BOP:

■ that shear rams have the capacity to cut the equipment being run into the well through the BOP

■ that the BOP is maintained as a critical safety system ■ that real-time condition monitoring is established by

instrumenting the BOP ■ that requirements are developed for the competence of BOP

maintenance personnel.

Capping and containment was an area of concern in 2011, but this has been adequately addressed in recent years with the formation of international consortia to provide for capping and containment equipment. For example, the OGP Subsea Well Response Project (17) has established equipment depots in international locations – Stavanger, Singapore, South Africa and soon in Brazil, and this is suitable for water depths up to 3000m (10,000ft). This is matched with the expertise needed to operate the equipment. Access to such equipment and expertise before drilling commences has been proposed in new regulations. The PSA recommended that industry conducts a full scale test of this equipment in Norway.

17) OGP Offshore Safety – Getting it RightAfter Macondo, the OGP (International Association of Oil & Gas Producers – based in London) quickly established the Global Industry Response Group. This had a mandate to improve well incident prevention, intervention and

response capabilities. The team involved 100 specialists from 20 companies working on these three topics. A series of reports were produced with numerous recommendations.

In the area of prevention four areas required work and OGP reports progress in all four areas:

■ Creation of an industry-wide well control incident database ■ Assessment of BOP reliability and potential for improvement ■ Improved training and competence and more attention to

human factors ■ Development of international standards for well design and

operations management


In the area of intervention there has been tangible progress. This resulted in the creation of the Subsea Well Response Project (SWRP). This included capping stacks and dispersant toolboxes available in four international locations and suitable for air transport.

Finally, related to Oil Spill Response a Joint Industry Project has been initiated involving 18 member companies to build on the lessons from Macondo. This is investigating optimal use of dispersants, including in sensitive arctic environments, in-situ burning procedures, and development of Recommended Practices on environmental risk assessment, and response resource planning. The JIP developed 19 separate work packages and many of these have completed their work and documentation is available on the oilresponseproject.org website. This work has converted many recommendations into practical guidance documents for industry.

18) OLF – DWH Lessons Learned and Follow-upThe Norwegian Oil Industry Association (OLF), now renamed Norwegian Oil and Gas Association, in collaboration with NOFO (the Norwegian Clean Seas Association for Operating Companies) carried out a

review of the DWH incident, compared regulations in the US and Norway, and made recommendations to enhance Norwegian operations and engineering standards. The group commissioned DNV GL to review regulatory differences between the USA and Norway. They concluded that the Norwegian Continental Shelf is characterized by robust legislation and safe operations, however, opportunities exist for further improvements in prevention, intervention and response.

Figure 8. Recommendation count and types from 10 major Macondo inquiries

The group made 45 recommendations for improvements, summarized below.

Prevention: The focus for improvement is to enhance the Norwegian NORSOK drilling standards (D-001: drilling facilities and D-010: well integrity in drilling and well operations). Specific recommendations addresed critical cementing jobs, lockdown requirements for tubing and casing hangers, negative pressure testing, fluid displacement requirements, well control exercises, BOP backup control systems, and enhanced BOP testing requirements. Enhancement to well management systems, process safety, and teamwork and communications were also proposed. Action on drill crew expertise is being addressed by OGP (17).

Intervention and Response: Capping and containment is being addressed through the OGP SWRP Project (17). The Macondo unified command system proved to be effective and is now considered a best practice approach and it is recommended for Norway. There are lessons to be learned about protecting workers from chemical exposure during a response through protective equipment and training. OLF commissioned the Norwegian Institute for Water Research to assess the environmental impact to fisheries and of dispersant usage. Fortunately, environmental damage from DWH was less than expected and the use of in-situ burning and underwater use of dispersants was considered beneficial. There remain gaps in knowledge regarding Corexit dispersant and its potential to delay natural degradation of oil. While fisheries have recovered, there were very large costs to the fishing industry due to an extensive closure of the resource.

OLF provided a useful summary of recommendations related to well control and response issues (Figure 8).


19) SINTEF Report on DWH (A19148, May 2011)SINTEF is a large independent, non-commercial research group headquartered in Trondheim Norway. It was commissioned by the PSA to summarize lessons learned and provide recommendations for the

industry in order to reduce the likelihood of a similar accident to occur in the Norwegian petroleum activity. Its report, mostly in Norwegian, but with an English Executive Summary contains much useful analysis of the Macondo event and of other offshore accidents.

SINTEF developed a very detailed timeline integrating inputs from BP, UC Berkeley, USCG and the National Commission and its Chief Counsel’s reports (all summarized above). The diagram showed time steps across the page with the key players down the page – here covering BP, Transocean and Halliburton with each having onshore and offshore players. The diagram (Figure 9, in Norwegian) covered 3 pages and mapped the interactions between all the players very clearly. This diagram highlighted the communication problems and SINTEF described the process of offshore drilling into complex reservoirs as a “continuous process of problem-solving” and this created a need “to interact and make decisions in an environment of increasing complexity and uncertainty.” SINTEF reviewed 134 recommendations from all the DWH reports issued by April 2011, as well as recommendations from the Montara and Snorre A blowouts and the Gullfaks well incident.

Figure 9. Extract of SINTEF timeline of event

SINTEF makes 13 recommendations to the industry and 5 to the authorities (in the Executive Summary in English). In overview, the industry list included: 1) the cement barrier; 2) strategies for two independent and tested barriers; 3) to evaluate whether BOP’s with a single shear ram are acceptable; 4) better design guidance for diverters; 5) enhance safety instructions relating to watertight integrity; 6) manage driller maintenance backlogs; 7) enhance blowout control strategies; 8) enhance organizational and individual awareness of early warnings of loss of control; 9) enhance competency and working environment for drilling staff; 10) enhance communications between players offshore and onshore; 11) develop new methods for operational risk evaluation and decision making; 12) develop safety management strategies to ensure compliance and resilience; and 13) facilitate sharing of lessons learned globally.

The recommendations to the authorities included: 1) consider requiring better redundancy in BOP – e.g. double shear rams; 2) confirm performance standards exist on safety critical drilling well operations; 3) revise the stability code with respect to watertight integrity; 4) maintain a focus on maintenance activities; and 5) build better well control knowledge in the regulator.


20) UK Health & Safety Laboratory - DWH Fire & Explosion Issues (Apr 2014)

The HSE requested the HSL to study fire & explosion issues related to the Macondo event. HSL relied on several key investigations including the BOEMRE, USCG, BP, Transocean, and RMI reports (all summarized above). The

HSL focus was on technical issues related to fire and explosion.

Based on their analysis, the HSL made several recommendations: ■ Control of ignition sources across the rig in the event of

blowout should be considered in ALARP demonstrations ■ Substantial reductions in risk can be achieved by improving

the reliability of detection systems and simplifying or eliminating reliance on human responses

■ Preventing the ingestion of gas into large spaces deep within the rig should be a priority

■ If there is a residual risk of gas accumulation in internal spaces, the consequences of explosion should be considered. The risks of explosions venting through vulnerable areas of the rig should be minimized; this may involve strengthening some internal partitions and/or providing explosion relief to the outside.

The HSL report summarized fire and explosion related recommendations in other Macondo investigations and found that these generally matched UK offshore recommendations. Some later chapters worked through examples of mitigations of ignition likelihood, flammable gas dispersion, and explosion damage.

21) US Transportation Research Board Evaluation of SEMS SystemsBSEE (BOEMRE at the time) requested that the Transportation Research Board assist them shift their focus from inspection of hardware compliance matters to a broader focus on safety and environmental management activities as these have greater influence on accidents. The request related to implementation of SEMS-I which was based on API RP 75 – an element based management system, similar to OSHA PSM requirements onshore, and which was developed in the early 1990s. While the work was underway, extra requirements related to SEMS-II were promulgated in Sept 2011 (e.g. including stop work and ultimate work authorities, employee participation, external certification of SEMS programs, and job safety assessment). The Committee believed that a good SEMS program does contribute to a positive safety culture in the workforce. Culture was defined as the intrinsic value of the importance of safety, not as an exercise to convince people to comply with regulations and procedures. This aligns well with the Nuclear Regulatory Commission view on safety culture and BSEE published this as guidance for the offshore industry.

The Committee addressed nine different means to assess SEMS effectiveness (e.g. inspections, audits, peer reviews, KPI’s, etc.). They concluded all of these could have some value at various times in assessing effectiveness. They also surveyed oth-er management system assessment programs managed by the USCG, OSHA, Mine Safety and Health Administration, California State Lands Commission, the Center for Offshore Safety (an API group), the UK HSE, and Norway PSA.

Their overall conclusions were:1) To encourage a positive safety culture, assessment should focus on attitudes and actions, not paperwork2) Complying with all elements of SEMS is not sufficient on its own to create a culture of safety3) The operator and its top management must own the SEMS program4) SEMS must be dynamic and evolve with the hazards as they change in offshore developments5) BSEE can have a positive or negative influence on safety culture by the way it measures SEMS6) A holistic combination of methods is needed to evaluate and ensure continuous improvement of SEMS7) BSEE must not dictate solutions to achieve safe operations, the operator needs to develop these8) Competent BSEE inspectors should be present routinely offshore to verify SEMS9) BSEE inspectors need to spend sufficient time offshore to identify problems in an operator’s safety culture10) Audits alone are insufficient to improve safety11) BSEE driven audits are a regulatory requirement, but an operator’s own audit program is fundamental12) BSEE must ensure the quality of audits carried out13) Such audits must have sufficient qualified personnel and time availability14) Qualified auditors have different skills and competencies to qualified inspectors15) BSEE is in a unique position to combine audit and inspection reports and to generate best practices and trends

The Committee made a number of other observations on how BSEE might encourage a culture of safety. These included many suggestions on audit procedures, key performance indicators, whistleblower /anonymous reporting programs, and ensuring an adequate budget.

ConclusionsThere have been many investigations into the Macondo accident and these have addressed several different aspects of the accident. Some investigations took a purely technical cause perspective whereas others emphasized more compliance with regulations or addressed organizational or human causes. Early investigations provided very detailed tutorials on deepwater drilling challenges. An indication of the range of recommendations is shown in Table 3 and a more specific focus on technical recommendations appears in the OLF Figure 8.

Many of the key recommendations have been adopted in one form or another. The USA has seen major changes to the MMS regulator, now BSEE and BOEM, with an updated style of operation emphasizing goal-based safety and increased inspector staff to allow greater presence offshore. BSEE has issued new requirements for drilling safety, for BOP recertification, negative pressure tests, and professional engineer sign-offs on casing and cement, and a requirement to estimate worst case blowout events. API and IADC have worked on an interface requirement between lessee and contractor, and several new API standards have been developed. SEMS I and SEMS II have been implemented with the Center for Offshore Safety defining the protocols and approving third party audit service providers. BSEE has provided guidance on safety culture and is working with another federal agency to


implement a confidential reporting system. BSEE has established the Ocean Energy Safety Institute to research several longer term problems (e.g. risk, reliability data, BAST). USCG has issued guidance on additional fire and explosion assessments it would like to see. There have been consortia established in the USA and by OGP at 4 international locations to provide emergency response support. There have been standards updates for drilling and well control by API and by NORSOK, and they have made their safety standards freely available. Detailed assessments of fire and explosion lessons have been made and these are starting to find their way into designs.

The National Commission (1) co-chairs maintain a website (oscaction.org) monitoring progress on implementation of their recommendations. They have issued 3 annual progress reports up to 2014. Generally they conclude that industry and the Executive Branch have done a good job implementing recommendations, but Congress lags.

Environmental findings of long term damage are too soon to be available, but initial indications are that the damage is less than might have been feared.

There have been changes overseas. The EU has decided to adopt a safety case approach (similar to that in the UK) for all offshore developments in the EU, and Australia expanded coverage of its regulator (NOPSEMA) to address drilling and environmental impacts to achieve close to a single offshore regulator. The UK and Norway both believe their goal-setting approach was not challenged by the Macondo accident, but that many detailed aspects of drilling safety did need enhancement and HSE, PSA and OGP are working on these issues.

There are some important recommendations for the US regulatory system which have not yet been adopted. These include suggestions to adopt a safety case approach with a greater focus on risk assessment with a risk target, and to nominate safety critical items with defined performance standards. It is not yet known if these will be adopted, or perhaps addressed in some other equivalent manner.

No. Title Prevention BOP Design Contain & Management US International & Operation Respond & culture Regulatory Regulatory

1 DWH Commission Main X X X X X

2 DWH Chief Counsel’s report X X X X

3 BP Investigation X X X

4 Transocean Investigation X X X

5 USCG X X X X X

6 BOEMRE X X X X

7 Republic of the Marshall X X X X X Islands

8 Adm Thad Allen Report X X

9 DNV GL Forensic Investigation X

10 Chemical Safety Board X X X X

11 Center for Catastrophic Risk X X X X X Management (UC Berkeley)

12 National Academy of X X X X X Engineering

13 National Research Council X

14 US District Court X X X Eastern Louisiana

15 Norway Petroleum Safety X X X X X Authority – Interim

16 Norway Petroleum Safety X X X X X Authority – Final

17 OGP X X X X

18 OLF X X X X

19 SINTEF X X X X

20 UK HSL X

21 US Transportation X X Research Board

Table 3. Range of Findings and Recommendations


Table of Acronyms ALARP – As Low As Reasonably Practicable AMF – Automatic Mode Function API – American Petroleum InstituteBAST – Best Available and Safest TechnologiesBOEMRE – Bureau of Ocean Energy Management, Regulation and EnforcementBOP – Blowout PreventerBSEE – Bureau of Safety and Environmental EnforcementBSR – Blind Shear RamCFR – Code of Federal RegulationsCSB – Chemical Safety BoardCSR – Casing Shear RamDOI – Department of InteriorDWH – Deepwater Horizon RigEDS – Emergency Disconnect SystemEPA – Environmental Protection AgencyGoM – Gulf of MexicoHP – High PressureHSE – Health and Safety Executive (UK)HSL – Health & Safety Laboratory (UK)IADC – International Association of Drilling ContractorsIMO – International Maritime OrganizationINPO – Institute of Nuclear Power Operations ISM – International Safety Management CodeJIP – Joint Industry Project JIT – Joint Investigation Team (USCG / BOEMRE)MMS – Minerals Management ServiceMOC – Management of ChangeMODU – Mobile Offshore Drilling UnitNCP – National Contingency PlanNIC – National Incident CommanderOCS – Outer Continental ShelfOGP – International Association of Oil & Gas ProducersOLF – Norwegian Oil and Gas AssociationOIM – Offshore Installation ManagerOSHA – Occupational Safety and Health AdministrationPSA – Petroleum Safety Authority (Norway)PSM – Process Safety ManagementRMI – Republic of Marshall IslandsROV – Remotely Operated Vehicle RP – Recommended PracticeSCE – Safety Critical ElementSEMS – Safety and Environmental Management SystemSIL – Safety Integrity Level (ISO 61511)USCG – United States Coast GuardVBR – Variable Bore Ram

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