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Binders 43-49
43. IADC Comments on Volume 1 of JIT Investigation on DWH, web posted May 31, 2011, 28 pages, with accompanying BOE blog entry, web posted June 2, 2011 44. Australian Government Final Response to Montara Commission of Inquiry Report, Web published on unknown date 45. The Psychology of Well Control, Paul Sonnemann, 1992 web posted June 2, 2011, 7 pages, with accompanying BOE blog entry, web posted June 2, 2011 46. The DWH Accident — assessments and recommendations for the Norwegian petroleum industry, Petroleum Safety Authority, Norway, web posted June 10, 2011, , 12 pages, with accompanying BOE blog entry, web posted June 11, 2011 47. Transocean Releases Macondo Report, web posted June 22, 2011, 4 pages (total report not downloaded) with accompanying BOE blog entry, web posted June 22, 2011 48. SINTEF, Deepwater Horizon Report, Executive Summary web posted June 29, 2011, 11 pages, with accompanying BOE blog entry, web posted June 29, 2011 49. The National Academies Marine Board, Interim Report on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations, web posted June 30, 2011, 47 pages, with accompanying BOE blog entry, web posted June 30, 2011 • Bud's Offshore Enemy (BOE) Energy Production, Safety, Pollution Prevention, and More IADC Comments on Volume I (Coast Guard) of the Joint Investigation Team's Deepwater Horizon Report June 2, 2011 by offshoreenergy Like the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, the Montara Commission of Inquiry, the Norwegian government, and leading safety and regulatory authorities around the world, the IADC recognizes the risks associated with complex, multi -agency regulatory regimes. A single authority should be responsible and accountable for safety and pollution prevention at offshore facilities, and should draw on the expertise of other agencies and organizations as necessary to achieve performance objectives. The safety and environmental risks associated with fragmented or compartmentalized regulation include gaps, overlap, confusion, inconsistencies, and conflicting standards. Industry and governmental personnel spend too much time coordinating with multiple • parties and not enough time managing safety and environmental risks. Link to IADC comments. http://www.iadc.org/committees/offshore/Documents/20110531 %20USCG%20on%20D HW%20Investi ation.pdf Main Web Site: http://www.iade.org/committees/offshore/index.html Key quotes: IADC continues to be concerned by seemingly duplicative regulatory requirements imposed by the Coast Guard and BOEMRE, particularly where the agencies appear to have divergent views regarding the placement of regulatory responsibility. One cannot holistically address safety when faced with the unyielding and overlapping demands of multiple narrowly focused regulatory agencies. 1p�10N OF nq o f All) z a a C � Al\ � ti� INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS P.O. Box 4287 • Houston, Texas 77210-4287 USA 10370 Richmond Ave., Suite 760 • Houston, Texas 77042 USA Phone: 1/713-292-1945 • Fax:1/713 292-1946 • vA,\Nrv,,.iadc.org 31 May 2011 Commandant (CG-545) United States Coast Guard 2100 Second Street, SW - STOP 7581 Washington, DC 20593-5781 Re: DEEPWATER HORIZON Investigation To whom it may concern: Via e-mail: Timothy.J.Farley@uscg.miI The International Association of Drilling Contractors (IADC) is a trade association representing the interests of drilling contractors, onshore and offshore, operating worldwide. IADC's membership includes the vast majority of drilling contractors currently operating mobile offshore drilling units (MODUs) in the areas subject to the jurisdiction of the United States and MODUs registered in the United States. The purpose of this letter is to provide comments on the Recommendations contained in • Volume 1 of the Joint Investigation Team's "Report of Investigation into the Circumstances Surrounding the Explosion, Fire, Sinking and Loss of Eleven Crew Members aboard the Mobile Offshore Drilling DEEPWATER HORIZON in the Gulf of Mexico, April 20 - 22, 2010" (the Report). Except as noted, IADC's comments are based solely on IADC's assessment of the Recommendations. They should not be interpreted as implying either support or disagreement with the Conclusions of the Report. They are offered without prejudice to comments that may be offered directly by IADC's members. Transocean, a member of IADC, and a Party -in -Interest to the Investigation, did not participate in the development of these comments. Genera/ Comments Prevention versus mitigation IADC finds the recommendations of the Report to be overly focused on mitigation rather than prevention. It is unfortunate that BOEMRE's report of the investigation was not promulgated in time to be considered in parallel to the Coast Guard's Report. In IADC's view, the primary goal should be to concentrate all reasonably practicable measures on the prevention of the loss of well control, thus preventing the reoccurrence of such an incident. This said, IADC recognizes that the Report does identify weaknesses in certain barriers intended to mitigate the effects of such incidents and that these weaknesses need to be addressed. HouSTON • WASHINGTON D.C. • THE NETHERLANDS • DIM • BANGKOK DEEPWATER HORIZON Investigation • Regulatory Structure IADC had considerable difficulty reconciling many of the Report's recommendations with IADC's understanding of the regulatory structure governing Mobile Offshore Drilling Units (MODUs) operating on the U.S. Outer Continental Shelf (OCS). Many of the recommendations seemingly focus on the operation of MODUs as vessels, rather than on the broader underlying issues associated with working conditions on the OCS. IADC believes that it is critical that the Coast Guard articulates a clear regulatory structure, particularly as it applies to MODUs and other vessels, and that the Coast Guard's view of the regulatory structure is shared by the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). In particular, IADC believes that there is need for further clarity and coordination between the Coast Guard and BOEMRE with respect to: Those regulations which are interpreted by the Coast Guard and/or BOEMRE as applying to MODUs and other vessels or floating facilities that are temporarily attached to the seabed under the direct application of the provisions of 43 U.S.C. 1333(a)(1), i.e.: "(a)(1) The Constitution and laws and civil and political jurisdiction of the United States are hereby extended to the subsoil and seabed of the outer Continental Shelf and to all artificial islands, and all installations and other devices permanently or temporarily attached to the seabed which may be erected thereon for the purpose of exploring for, developing, or producing resources therefrom, or any such installation or other device (other than a ship or vessel) for the purpose of transporting such resources, to the same extent as if the outer Continental shelf were an area of exclusive Federal jurisdiction located within a state .. . Those regulations promulgated by the Coast Guard that apply to MODUs and other vessels and floating facilities engaged in "activities on the Outer Continental Shelf" that are issued pursuant to 43 U.S.C. 1347(c), i.e.: "(c) The Secretary of the Department in which the Coast Guard is operating shall promulgate regulations or standards applying to unregulated hazardous working conditions related to activities on the Outer Continental Shelf when he determines such regulations or standards are necessary. The Secretary of the Department in which the Coast Guard is operating may from time to time modify any regulations, interim or final, dealing with hazardous working conditions on the Outer Continental Shelf." Those regulations promulgated by BOEMRE that apply to MODUs and other vessels and floating facilities that are issued pursuant to the Secretary's general authority over the administration of the leasing of the OCS under 43 U.S.C. 1334(a), i.e.: "(a) The Secretary shall administer the provisions of this Act relating to the leasing of the outer Continental Shelf, and shall prescribe such rules and regulations as may be necessary to carry out such provisions. The Secretary may at any time prescribe and amend such rules and regulations as he determines to be necessary and proper in order to provide for the prevention of waste and conservation of the natural resources of the outer Continental Shelf, • and the protection of correlative rights therein, and, not withstanding any other HOUSTON • WASHINGTON D.C. • THE NETHERIANDS • DUBAI • BANGKOK -2- DEEPWATER HORIZON Investigation • provisions herein, such rules and regulations shall, as of their effective date, apply to all operations conducted under a lease issued or maintained under the provisions of this Act. In the enforcement of safety, environmental, and conservation laws and regulations, the Secretary shall cooperate with the relevant departments and agencies of the Federal Government and of the affected States...." There is obviously room for considerable overlap between the Coast Guard's jurisdiction over "unregulated hazardous working conditions" and BOEMRE's general authority over the administration of the leasing of the OCS. Over time, a series of Memoranda of Agreement have been developed to identify and clarify the responsibilities of the Minerals Management Service (BOEMRE's predecessor) and the Coast Guard. In IADC's view, these have been helpful; however, the Coast Guard's chronic inattention to the continued evolution of activities on the OCS, and its failure to complete the rulemaking to amend 33 CFR chapter I, subchapter N, has forced BOEMRE (and previously, the MMS) to expand its regulatory reach beyond the terms of these Agreements. IADC continues to be concerned by seemingly duplicative regulatory requirements imposed by the Coast Guard and BOEMRE, particularly where the agencies appear to have divergent views regarding the placement of regulatory responsibility. For example, the Coast Guard's expectation that a self-propelled foreign -flag MODU would be certified to the International Safety Management Code (presumably under the application of 43 U.S.C. 1333(a)(1) and the derivative application of 46 U.S.C. 3302), with responsibilities placed with the unit's master, must operate in parallel with BOEMRE's expectation that the same unit would be subject to a Safety and Environmental Management System in accordance with 30 CFR, part 250, subpart S (SEMS Rule), with responsibilities placed with the lessee/operator. Amendment of the MODU Code The report makes numerous recommendations that the Commandant work with the IMO to amend the "MODU Code" without clearly specifying whether the proposed amendments are intended to be applied prospectively (i.e., through amendment of the 2009 MODU Code so as to apply to future new construction) or retrospectively (i.e., through amendment of the 1979, 1989 and 2009 MODU Codes so as to apply to existing units). As the Coast Guard is aware, it would be possible to amend the 2009 MODU Code by resolution of the IMO's Maritime Safety Committee; however, amendment of the 1979 MODU Code or 1989 MODU Code would require an IMO Assembly resolution and would be more burdensome. IADC is willing to work with the Coast Guard and other interested parties to consider, and as may be appropriate, develop amendments to the MODU Code(s). IADC notes the general absence in the Report of any recommendations for amendment of either 33 CFR chapter I or subchapter N or 46 CFR chapter I, subchapter I -A. IADC believes that amendment of both will be necessary; however, in order to promote the use of international standards (i.e., the MODU Code), except where specifically noted, IADC would recommend that: • No rulemaking be initiated to amend 46 CFR chapter I, subchapter I -A until after any related amendments to the MODU Code(s) are agreed by the International Maritime Organization; and HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -3- DEEPWATER HORIZON Investigation In its rulemaking to amend 33 CFR chapter I, subchapter N, and associated guidance, the Coast Guard clarifies its intent regarding the acceptance of the various editions of the MODU Code. Specific Comments related to the Recommendations The following are IADC's specific comments on the recommendations of the Report. For ease of reference, the text of the recommendations (in italics) has been reproduced below followed by IADC's comments. 1. Explosion Protection I.A. It is recommended that Commandant work with the IMO to amend the MODU Code to include clear requirements for the long term labeling and control of all electrical equipment in hazardous areas. In addition, requirements should be established for the continued inspection, repair and maintenance of electrical equipment in hazardous areas in the unit's safety management system. IADC agrees in part. IADC agrees that it is appropriate to consider amendments to the MODU Code(s) to include clear requirements for the long term control of electrical equipment in hazardous areas through a requirement to create and maintain a register of such equipment. Maintenance of the register could also be addressed in guidance associated with the ISM Code, API RP 75, or BOEMRE's SEMS Rule. • IADC disagrees with the recommendation for labeling of such equipment. Existing standards for labeling/marking of such equipment were not developed to assure that the labels/marks would remain reliably visible for the life of the equipment; Installation of the equipment so that the label/marking remains visible is problematic; and From its experience with labeling requirements on inspected vessels, Coast Guard should be well aware of the long term problems associated with the maintenance of labels on equipment and practical problems associated with replacing such labels should they be damaged or destroyed. • IADC would also note that the underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility having electrical equipment installed or utilized in potentially hazardous (classified) locations. Therefore, other Coast Guard, BOEMRE and SOLAS regulations are also implicated by this recommendation. 1.8. It is recommended that Commandant work with the IMO to amend the MODU Code to provide more detailed guidance for the design and arrangement of fixed automatic gas detection and alarm systems as specified in paragraph 9.8 of the MODU Code (paragraph 9.11). The guidelines should include as a minimum, the recommended type and number of gas detectors, their arrangement, alarm set points, response times, wiring protocols and survivability requirements. IADC disagrees with this recommendation. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -4- DEEPWATER HORIZON Investigation IADC questions whether it is the need for more detailed guidance that is at issue, or whether it is the visibility of the guidance that exists. As with fire detection systems, purchasers of such systems rely upon the expertise of the system's manufacturer to determine the number of gas detectors, their arrangement, alarm set points, response times and wiring protocols. For MODUs, most fire and gas detection systems are under a type approval by the unit's classification society. Specifics of the wiring, layout, equipment used are reviewed by the flag State or Recognized Organization acting on its behalf. However, unlike fire detection systems, there are currently no regulatory requirements established by the IMO (or the Coast Guard) for such systems to obtain "system" approval. At this time, IADC is not convinced that creation of a regulatory requirement for type or "system" approval is warranted. If type approval of such systems is to be considered, IADC would note that the underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility where there is a need for fixed gas detection and alarm systems. Therefore, other Coast Guard, BOEMRE and SOLAS regulations are also implicated by this recommendation. I.C. It is recommended that Commandant work with the IMO to amend the MODU Code to provide more detailed guidance for establishing fire and explosion strategies on board units using dynamic positioning systems for station keeping. The guidelines should provide a hierarchy of recommend automatic and manual emergency shutdown actions following gas detection in vital areas. The guidelines should also provide accepted approaches for the • design and arrangement of the emergency power source necessary for station keeping in the event of a flammable gas release. • IADC believes that consideration of an amendment to the MODU Code (or IMO MSC/Circ.645, Guidelines for Vessels with Dynamic Positioning Systems) is premature and may be inappropriate in any case. As the Coast Guard is aware, IADC identified the need for stationkeeping capabilities of DP units to be considered as part of emergency power management during the development of the 2009 MODU Code, so this is clearly an issue of concern to IADC. There is a much broader underlying issue here - determining an appropriate response strategy for detection of flammable (or toxic and flammable) gas on a MODU or other OCS facility, bearing in mind that such a problem might arise during combined operations (e.g., a jack -up cantilevered over a fixed platform). In testimony provided to the Congress, BOEMRE, and the Chemical Safety Board, IADC has highlighted that many of the major hazards for which risk controls on MODUs must be established relate to matters falling under the jurisdiction of multiple regulatory agencies. Accordingly, the controls that are established must not only satisfy the MODU owner's risk tolerance, along with that of the client (the lessee/operator), but also that of the Coast Guard and BOEMRE. And, as recognized in the recommendation, theses controls must address not only equipment (automatic shutdowns) but matters of personnel competence and professional judgment (manual shutdowns). HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -5- DEEPWATER HORIZON Investigation • IADC would hope that the basic premise during examination of this issue would be to prioritize, in order: (1) The protection of life; (2) The protection of the asset, to the extent that protection of the asset may be preferable to its abandonment in terms of protection of life; and (3) The protection of the environment. IADC is working with the American Petroleum Institute to develop API/IADC Bulletin 97, Well Construction Interface Document Guidelines, which will provide guidance on a framework for such holistic discussions between the lessee/operator and the drilling contractor with respect to drilling operations. On the narrower issue of power management for DP operations, IADC notes that this issue was introduced for discussion at the April 2011 DNV Rig Owners' Committee meeting. IADC suggests that an appropriate preliminary step would be to hold focused discussions involving the Coast Guard, BOEMRE, ABS, DNV and the owners of DP MODUs operating on the OCS. I.D. It is recommended that Commandant work with the IMO to amend the MODU Code to require specific minimum values for explosion design loads to be used in calculating the required blast resistance of structures. In addition, unified guidelines for performing the required blast resistance calculations should be developed. IADC believes this recommendation is premature. IADC does not believe that this is an issue where a technical solution can developed in the IMO. The solution must first . be developed outside IMO and then, if deemed appropriate, taken to IMO for consideration. Further, there are implications for other vessel types (e.g., liftboats) and facilities that are not subject to the MODU Code. • The primary goal should be to concentrate all reasonably practicable measures on prevention of the release of materials that could threaten life, lead to escalation or cause unacceptable loss. This said, loss of well control and the threat of a consequential explosion are hazards that should be mitigated and current regulatory and industry standards for assessing the threat and mitigating the hazard are lacking. Since the Piper Alpha incident in July 1998, there has been considerable effort expended by the oil and gas industry, along with certain government participants, to disseminate knowledge and best practices and to develop guidance on the prevention and mitigation of fires and explosions and on the protection of facilities and personnel against fires and explosions. However, this effort has not focused on the risks specifically associated with MODU operations. So while the general methodologies may be appropriate, the standards and guidelines that have been developed are not directly applicable to MODUs. An initiative to reach a consensus agreement on fire and blast scenarios applicable to MODUs and MODU operations would be appropriate. It is IADC's view that the existing standards for determining the required fire and blast resistance of oil and gas industry facilities are generally of a goal -setting nature and are not well suited for prescriptive application. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK DEEPWATER HORIZON Investigation • These standards are also most effectively applied in the design stage. While they can be used for assessing existing facilities, cost-effective solutions can be elusive. 1. E. It is recommended that Commandant work with the IMO to amend the MODU Code to require an explosion risk analysis of the design and layout of each facility. The analysis should use accidental blast loads defined by the Organization, to determine whether the levels of protection for accommodation areas, escape paths and embarkation stations provided by the prescriptive requirements in the Code are adequate. See IADC's response to 1.D. above. I.F. It is recommended that Commandant work with the IMO to amend the MODU Code to require ventilation inlets for machinery spaces containing primary and emergency sources of power to be located as far as practicable from hazardous locations. IADC believe this is already addressed in the 2009 MODU Code. IADC believes that it may be appropriate to consider amending the 2009 MODU Code to recommend that ventilation inlets be separated when redundancy is needed. 1.G. It is recommended that Commandant prepare and submit a "lessons learned" information paper to the IMO strongly recommending that existing facilities reevaluate the placement of supply air intakes for main and emergency power sources, coordinated with the fire and gas detection system logic. The paper should recommend that training, policies and procedures are implemented to shut down ventilation systems and close dampers in the event flammable gas is detected in critical locations. • IADC agrees. However, IADC believes that such a report must also include appropriate information from the anticipated BOEMRE report providing recommendations on measures that could have prevented the incident. I.H. It is recommended that Commandant pursue the regulatory changes for dynamic positioned vessels recommended in Appendix I, including clear designation of the person in charge under both operating and emergency conditions for all MODUs operating on the U.S. OCS. IADC's General Comments regarding Regulatory Structure (above) are applicable. IADC is concerned that the regulatory changes recommended in Appendix I are far more reaching in their implications than they may appear on casual reading, particularly with regard to the issues of ship design, manning, and operations. While, in theory, IADC's concerns and IADC's individual member's concerns could be addressed during the rulemaking process, IADC is all too well aware of recent instances where industry comments to the rulemaking docket on issues unique to the offshore oil and gas industries were not understood by the Coast Guard, with the result that compliance with the final rules, when promulgated, was impossible. If this rulemaking is pursued, it will raise complex issues, and it will be vitally important that a mutual understanding of these issues is reached. IADC notes the reference to both the OCS Lands Act and the reciprocity provisions in 46 U.S.C. 3303 in paragraph 24 of Appendix I. IADC would specifically seek clarification that the provisions of the existing 33 CFR 140.101(s), 143.207(c), and • 146.205(c) are intended to give effect to 46 U.S.C. 3303 with respect to both MODUs HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -7- DEEPWATER HORIZON Investigation • attached' to the seabed and those engaged in "activities on the Outer Continental Shelf." IADC understands the concern identified regarding the designation of the Person in charge. In this regard IADC would note the definition in 33 CFR 141.10 is somewhat ambiguous in that it infers that a master may be a Person in charge without further designation. The definition reads: Person in charge means the master or other individual designated as such by the owner or operator under § 146.5 of this subchapter or 46 CFR 109.107. As a related matter, IADC would express concerns regarding: • The possible need for identification of an "overall" Person in charge for combined operations, e.g., a jackup cantilevered over a fixed platform; and • The lack of requirements or guidance regarding the training and qualifications for a person designated as the Person in charge. (See also IADC's comments regarding Recommendations 3.D. and 3.E., below.) 1.I. It is recommended that Commandant work with the IMO to evaluate the need to create a requirement for flag states to audit classification societies acting on their behalf as a recognized organization. IADC is aware of ongoing work by the IMO to develop a Code for Recognized Organizations that would appear to satisfy this Recommendation. • 1.1. It is recommended that Commandant evaluate the need to establish unannounced regulatory inspections. IADC views this as an internal Coast Guard issue. Such inspections are authorized by statute. • 1.K. It is recommended that Commandant work with Recognized Organizations to evaluate the need to create a complete stand-alone regulatory check list that does not rely on the result of other surveys to ensure a 100% regulatory check of the MODU. IADC would express the following concerns regarding this recommendation: • A complete stand-alone regulatory check list would include many items that, while specified in regulation, do not warrant verification, inspection or examination, e.g., elements of design that are not easily altered. • A complete stand-alone regulatory check list would be counter to initiatives aimed at structuring "risk -based" inspections. • Certain "regulatory checks" are performed by technical specialists, e.g., those leading to issuance of a Cargo Ship Safety Radiotelephone Certificate. • Certain regulatory requirements seemingly defy codification, e.g., those associated with responsibility of the United States to act as Administration when it is the coastal State in accordance with Article 2 of MARPOL 73/78, as amended. IADC would also note that the underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility, whether or not engaged in activities on the OCS. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK DEEPWATER HORIZON Investigation • I.L. It is recommended that Commandant evaluate the need for improving inspection guidance documents and case work entry standards to ensure the proper documentation of Certificate of Compliance examinations. IADC views this as an internal Coast Guard issue. 2. Fire Protection 2.A. It is recommended that Commandant work with the IMO to amend the MODU Code to require that fire pump systems should be self contained and depend on no other onboard systems. This should include dedicated fuel supplies for at least 18 hours of operation. IADC cannot support this recommendation. The underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility, including those US flag vessels subject to inspection and certification by the Coast Guard. This recommendation could not be assessed without referring to the Conclusions portion of the Report so as to ascertain that the intent was to mandate the installation of a diesel -driven fire pump. It appears necessary to state that pumps operate by creating low pressure at the inlet which allows the liquid to be pushed into the pump by atmospheric or head pressure (pressure due to the liquid's surface being above the centerline of the • pump). Even with a perfect vacuum at the pump inlet, atmospheric pressure limits how high the pump can lift the liquid. Thus, for a pump to be directly driven by a diesel engine, it would either need to be installed within the pontoons of a semi - submersible unit (or within the legs of a jack -up unit), which would create extreme difficulties with respect to the air inlets and exhausts for the engines; or if installed on deck, would require mechanical coupling of the pump to the engine by a drive shaft extending from the deck to the pump's location; which may exceed 30 meters in distance. Further, evolving demands for emission controls on diesel engines seem to be driving toward a requirement that diesel engines, even those dedicated to emergency operations, be fitted with selective catalytic reduction units, which would present further challenges to the installation and operation of such engines. • 2.8. It is recommended that Commandant work with the IMO to amend the MODU Code to require H-60 fire separations between the drilling area and adjacent accommodation spaces as well as any spaces housing vital safety equipment. IADC would not rule out the possibility that a fire and blast study (see Recommendation 1.D.) would lead to the conclusion that a level of protection may be required that is greater than that provided by "A-60" class bulkheads and decks. To meet coastal -State requirements, several IADC members have installed structural fire protections systems meeting "H" class standards. In order to allow such systems to be accurately reflected in required fire control plans, IADC has previously suggested that provisions be made in the IMO's guidelines for fire control plans to indicate the installation of "H" rated bulkheads and decks, where fitted. These suggestions were rejected by the IMO. HouSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK DEEPWATER HORIZON Investigation • IADC would note that any proposal to amend the MODU Code to require "H" class standards would need to be preceded or accompanied by a proposal to amend the Fire Test Procedures (FTP) Code to establish standards within IMO for a "H" (hydrocarbon) fire and corresponding performance standards for bulkheads and decks intended to resist such fires. It would also be necessary to agree to amended standards for equipment penetrations of such bulkheads and decks, for openings and passages transiting such bulkheads and decks, and for the aforementioned fire control plans. 2.C. It is recommended that Commandant work with the IMO to amend the MODU Code to develop uniform guidelines that can be used as a basis for performing engineering evaluations to ensure that the level of fire protection of the bulkheads and decks separating hazardous areas from adjacent structures and escape routes is adequate for likely drill floor fire scenarios. IADC's response to Recommendation 1.D. applies to this recommendation. 2.D. It is recommended that Commandant work with the IMO to amend the MODU Code to require a fixed deluge system or multiple high capacity water monitors for the protection of the drill floor and adjacent areas. Consideration should be given to requiring automatic operation upon gas detection. Even after reference to the Conclusions, IADC is unable to discern a clear objective for the installation of these systems. . Mandating the installation of such systems has been considered by several coastal State petroleum regulatory authorities, with varying results. Such a mandate was considered, and dismissed, during the development of the 2009 MODU Code, with the conclusion that any regulatory mandate for the installation of such systems should be left to the discretion of individual coastal State regulatory authorities. • Consideration of this recommendation should be preceded by the development of agreed fire and blast scenarios for MODUs (see Recommendation 1.D.) 2.E. It is recommended that Commandant work with the IMO to amend the MODU Code to require a fire risk analysis to supplement the prescriptive requirements in the MODU Code. The risk analysis should be a performance -based engineering evaluation that utilizes defined heat flux loads to calculate the necessary levels of protection for structures, equipment and vital systems that could be affected by fires on the drill floor, considering the unique design, arrangement and operation of each MODU. IADC does not believe that the MODU Code is an appropriate vehicle for implementation of such a recommendation. The recommendation states that consideration should be given to the unique design, arrangement and operation of each unit. A MODU's unique design, arrangement and operation are tailored, at the direction of the client (lessee/operator) to a particular operation or well (e.g., the risks associated with an exploratory high-pressure, high -temperature well differ significantly from those associated with re-entry into a producing well with little or no associated gas production). It would be inappropriate for a flag State or Recognized Organization acting on behalf of a flag State to undertake this responsibility. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -10- DEEPWATER HORIZON Investigation • IADC would also remind the Coast Guard that similar risks are associated with open - hole operations that are conducted by vessels that are not certified as MODUs, such as liftboats and well stimulation vessels. IADC would note that BOEMRE's SEMS Rule mandates the completion of a facility - level hazards assessment. If BOEMRE's SEMS Rule requires the evaluation envisioned by this recommendation, IADC does not see the need for Coast Guard action in this regard. (See IADC's comments related to Recommendation 5.E., below.) 3, Evacuation / Search and Rescue 3.A. It is recommended that Commandant work with the IMO to amend the IMO MODU Code to establish performance standards concerning the maximum allowable radiant heat exposure for personnel at the muster stations and lifesaving appliance lowering stations, along with guidelines for calculating the expected radiant heat exposure for drill floor fire events for each MODU hull type. IADC's responses to Recommendations 1.D. and 1.E apply to this recommendation. 3.8. It is recommended that Commandant work with the IMO to harmonize the IMO MODU Code with International Convention for the Safety of Life at Sea (SOLAS) regulation 111116.7 to require adequate emergency lighting of Muster Areas, Lifeboat and Liferaft Lowering Stations and the corresponding waters into which the lifeboats/liferaats will be launched. IADC agrees with this recommendation. IADC would also note the lack of standards in this regard under 33 CFR chapter I, subchapter N, to address this issue on other vessels and facilities engaged in operations on the OCS for which this could also be an issue. 3.C. It is recommended that Commandant work with the IMO to amend the Lifesaving Appliances (LSA) Code and its testing recommendations to ensure the adequacy of lifesaving appliance standards. IADC has previously recommended to the Coast Guard, and to the IMO that the standards for lifesaving equipment be revised to reflect a range of assumed occupant mass (e.g., to supplement the existing standards for 75 kg and 82.5 kg with standards for 90 kg, 97.5 kg and 105 kg, with corresponding body sizes). In making this recommendation, IADC presumed that requirements would be established to assure that the lifesaving equipment provided was appropriate for the population to be accommodated. This recommendation was not supported by the IMO. IADC continues to believe that it is appropriate to do so. The underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility engaged in activities on the US OCS. In this instance, IADC believes this issue should first be addressed in Coast Guard regulations in titles 33 and 46 of the Code of Federal Regulations. IADC would note that this issue has been addressed by the petroleum regulatory authorities of several countries, including Australia, Canada, Norway and the United Kingdom. IADC views the lack of internationally recognized standards associated . with the policies adopted by these countries as problematic. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -11- DEEPWATER HORIZON Investigation • 3.D. It is recommended that Commandant remove or specifically define the term "when practicable" in Title 46 Code of Federal Regulations (CFR) § 109.213(d)(1)(vii). It is further recommended that Commandant work with the IMO to amend the IMO MODU Code, Section 14.11.2.7. IADC did not find the term 'when practicable" in the cited regulation. The Recommendation fails to provide a specific suggestion for the amendment to section 14.11.2.7 of the MODU Code. As Chapter 14 of the 2009 MODU Code includes provisions for training manuals and onboard training aids paralleling the requirements of SOLAS, IADC believes that it may not be necessary to amend the MODU Code. 3.E. It is recommended that Commandant work with the IMO to amend the International Convention on Standards for Training, Certification and Watchstanding (STCW) to establish MODUs as a "Special Ship" within Chapter V and develop specialized training standards and competencies for masters, officers, particular ratings and special personnel assigned to MODUs to include training for crowd control and crisis management. The underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility engaged in activities on the US OCS. In this instance, IADC believes that this issue should first be addressed in Coast Guard regulations in 33 CFR chapter I, subchapter N. IADC also disagrees with the premise that STCW is the appropriate instrument to address this concern. In IADC's view, it would be more appropriate to amend IMO resolution A.891(21) to include training for crowd control and crisis management. IADC believes that resolution A.891(21) is already in need of amendment to reflect the Manila Amendments to the STCW Convention and Code. IADC is willing to work with the Coast Guard and other interested flag -States to develop a justification for amendment of resolution A.891(21) along with the text of the proposed amendments, for submission to the IMO's Maritime Safety Committee for its consideration. 3. F. It is recommended that Commandant work with the IMO to amend the IMO MODU Code to include the type, frequency, extent, randomness and evaluation criteria for all emergency contingency drills. The underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility engaged in activities on the US OCS. In this instance, IADC believes this issue should first be addressed in Coast Guard regulations in 33 CFR chapter I, subchapter N. IADC also disagrees with the premise that STCW is the appropriate instrument to address this concern. These concerns are already addressed in resolution A.891(21), and the provisions resolution A.891(21) could be expanded, if necessary. Resolution A.891(21) is referenced in the 2009 MODU Code. IADC is willing to work with the Coast Guard and other interested flag -States to • develop a justification for amendment of resolution A.891(21) along with the text of HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -12- DEEPWATER HORIZON Investigation • the proposed amendments, for submission to the IMO's Maritime Safety Committee for its consideration. 3.G. It is recommended that Commandant work with the IMO to amend the STCW to develop standards and competencies for the operation of lifesaving appliances that serve liferafts. IADC has interpreted the recommendation as intending to address the operation of launching appliances servicing liferafts. The underlying issue being addressed with this recommendation is not restricted solely to MODUs, but would be common to any vessel or facility engaged in activities on the US OCS using davit launched liferafts. In this instance, IADC believes this issue should first be addressed in Coast Guard regulations in titles 33 and 46 of the Code of Federal Regulations. With respect to MODUs, IADC would note that Chapter 14 of the 2009 MODU Code includes provisions for training manuals and onboard training aids paralleling the requirements of SOLAS which addresses, in part, this concern. If the Coast Guard accepts this recommendation, IADC believes that any justification for new work that is submitted to IMO should be accompanied by the complete text of any proposed amendments to the STCW Code. 3.H. It is recommended that Commandant evaluate the adequacy of inflatable liferafts • served by a launching appliance installed on MODUs whose hull design is not of a traditional ship's hull and determine if other suitable lifesaving appliances could enhance occupant safety. IADC would support such a study. However, such a study must also evaluate the alternatives, recognizing that the challenges associated with launching survival craft (of any type) from great heights on OCS facilities and vessels that do not have a traditional ship's hull form are not limited to MODUs. IADC believes that relevant comments were submitted in response to the Coast Guard's 7 December 1999 proposal to amend 33 CFR chapter I, subchapter N. Those comments may warrant re-examination in light of the recent addition of 46 U.S.C. 3304 affecting the conditions of approval for certain survival craft. 3.1. It is recommended that Commandant work with the IMO to develop a symbol for "knife" and require the placement of a label to identify its location in all lifesaving appliances requiring the tool. IADC supports the recommendation as it applies to davit -launched liferafts. Further study is warranted with respect to knives as required equipment in other lifesaving appliances. Corresponding amendments to the provisions of 46 CFR part 160 would seem appropriate. 3.1. It is recommended that Commandant work with the IMO to amend the IMO MODU Code to prohibit the dual purpose acceptance of life boats as rescue boats, and adopt the "widely separated location" philosophy applied to the quantity and location of rescue boats on board • MODUs. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK N&C DEEPWATER HORIZON Investigation IADC does not agree with this Recommendation. The underlying issue being addressed with this Recommendation is not restricted solely to MODUs, but would be common to all SOLAS vessels as well as any vessel or facility engaged in activities on the US OCS. Are rescue boats provided to respond to a man overboard, or to effect the retrieval of persons who may either be forced to directly enter the water (or choose to do so) in the event of an incident of a vessel or facility? IADC believes it is the former. In this instance, if the Coast Guard accepts this Recommendation, IADC believes this issue should first be addressed in titles 33 and 46 of the Code of Federal Regulations. IADC believes that relevant comments were submitted in response to the Coast Guard's 7 December 1999 proposal to amend 33 CFR chapter I, subchapter N. Addressing this issue at IMO would require amendments to both SOLAS and the LSA Code. IADC would also note that the Emergency Evacuation Plan in 33 CFR chapter I, subchapter N, which is subject to approval by the Coast Guard, requires the identification of the means and procedures for retrieving persons from the water during an evacuation. 3.K. It is recommended that Commandant revise the 33 CFR, Subchapter N regulations, to establish designated standby vessels for MODUs engaging in oil and gas drilling activities on the U.S. Outer Continental Shelf (OCS). • IADC does not agree with this Recommendation. This issue has been the subject of prior rulemakings, i.e., CGD 84-098b, 54 FR 21572, May 18, 1989, as amended by USCG-1998-3799, 63 FR 35530, June 30, 1998. Despite this tragic incident, IADC does not believe that a change is warranted. If the Coast Guard accepts this recommendation, IADC notes that the underlying issue being addressed with this Recommendation is not restricted solely to MODUs, but would be seemingly common to any vessel or facility engaged in drilling or open - hole operations on the US OCS. A significant percentage of loss -of -well -control incidents (blowouts), both on the US OCS and worldwide, have occurred during operations other than "drilling" operations. 3. L. It is recommended that Commandant work with the IMO to amend the IMO MODU Code to address the need for a fast rescue boat/craft on board MODUs. IADC does not agree with this Recommendation. IADC's response to Recommendation 3.1. applies to this Recommendation. 3. M. It is recommended that Commandant amend 46 CFR § 109.213 and work with the IMO to amend the IMO MODU Code to require the performance of a man overboard drill on at least a quarterly basis. IADC disagrees with the specifics, but not the substance, of this recommendation. The underlying issue being addressed with this Recommendation is not restricted • solely to MODUs, but would be seemingly common to any vessel or any permanently HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -14- DEEPWATER HORIZON Investigation • or temporarily manned facility engaged in operations on the US OCS. Accordingly, it is appropriate to firstly address this issue in 33 CFR chapter I, subchapter N. Any amendment of the MODU Code to include requirements for man overboard drills should be accompanied by a corresponding amendment to IMO resolution A.891(21) to better describe such drills. IADC notes that any mandate for such drills would be subject to the same challenges as are associated with the mandates for launching and recovery of lifeboats, i.e., weather conditions may preclude strict adherence to a quarterly schedule. IADC understands that Brazil's recent proposal to consider issues related to the periodic launching of lifeboats with a view to amending the 2009 MODU Code has been accepted by the IMO's Maritime Safety Committee. 3. N. It is recommended that Commandant revise the 33 CFR, Subchapter N regulations, to require the owner/operator of a MODU operating on the U.S. OCS, instead of the leaseholder, to develop and submit an emergency evacuation plan (EEP). IADC strongly disagrees with this Recommendation. To be effective, the EEP must be able to draw on the resources available to the lessee/operator which are employed for routine logistics support of the lessee's OCS operations. It would be cost -prohibitive for a drilling contractor to attempt to maintain these resources available on a standby basis in order to meet the requirements of the EEP. • Further, it is the lessee/operator who ultimately determines the number of persons on board that must be accounted for in the EEP as well as the timing and nature of operations that might require special consideration under the EEP. 0 3.0. It is recommended that Commandant revise the 33 CFR, Subchapter N regulations, to establish performance and evaluation criteria and require the annual exercise of the EEPs, including all identified emergency resources, equipment and agencies necessary to perform a mass evacuation. IADC agrees in general with this Recommendation, but notes that it is, in part, a matter internal to the Coast Guard. IADC believes that the preparation and review for approval of EEPs has likely suffered from both complacency and habituation. EEPs may have become too focused on the 'routine' evacuation of personnel for hurricanes, rather than giving full consideration to the infrequent instance that might require abandonment of a facility. Any effort in this regard should be coordinated with BOEMRE. 3.P. The Joint Investigation Team concurs with the proposed improvements identified in Appendix G, Final Action Report On the SAR Case Study Into the Mass Rescue of Personnel off the Mobile Offshore Drilling Unit DEEPWATER HORIZON. The Joint Investigation Team concurs with the analysis in the report. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -15- DEEPWATER HORIZON Investigation • IADC agrees with this Recommendation. Again, IADC notes that these are not issues that are exclusive to MODUs. 4. Flooding & Sinking 4.A. It is recommended that Commandant revise the current policy with respect to response plan requirements for vessels engaging in oil and gas drilling activities on the U.S. OCS. Operator's response plans should specifically address responses to vessel fires in addition to well fires. IADC finds this recommendation confusing. IADC is unaware of any Coast Guard policy with respect to response plan requirements for vessels engaging in oil and gas drilling activities on the OCS. IADC believes that the current regulatory requirements of the Coast Guard are appropriate. Under current regulations, the responsibility for review and approval of lessee/operator response plans rests with BOEMRE. Is it the intent of this Recommendation to suggest that the Commandant recommend that BOEMRE revise their response plan requirements and review criteria? If so, this and other related issues are addressed in far greater detail in the 18 March 2011, Incident Specific Preparedness Review (ISPR) on the Deepwater Horizon Oil Spill. 4.B. It is recommended that Commandant evaluate regulatory requirements for operators of • vessels engaging in oil and gas drilling activities on the U.S. OCS to maintain a continuously manned shore based operations center for monitoring operations and maintaining primary and emergency communications for responding to casualties. • IADC has no objection to the Commandant undertaking such an evaluation. IADC would question why such an evaluation would be limited to "vessels" when other OCS facilities engage in "oil and gas drilling activities" and that their complexity and manning may exceed that of the largest MODU. IADC also notes that the "engaging in oil and gas drilling activities" would require further definition and clarification. With regard to MODUs, IADC's members have indicated that they generally view the suggestion of a continuously manned shore based operations center as infeasible. IADC is aware that BOEMRE is exploring the use of operations centers by the lessee/operators. It is IADC's view that this issue is more appropriately addressed as a general requirement of the administration of the lease than a vessel -specific activity. 4.C. It is recommended that Commandant evaluate regulatory requirements for vessels engaging in oil and gas drilling activities on the U.S. OCS to relay daily loading information to a designated person ashore. IADC has no objection to the Commandant undertaking such an evaluation. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DLIBAI • BANGKOK -16- DEEPWATER HORIZON Investigation While IADC is not certain of definition of the universe of "vessels engaging in oil and gas drilling activities", IADC presumes that this would encompass most operations undertaken by MODUs. In this regard, several of IADC's members have indicated that they receive this information on a daily basis. However, it should be understood that the activities on a MODU are dynamic; the conditions stated in a morning report could have changed significantly from the time the report was submitted, and therefore, might not be suitable for carrying out a post -casualty stability evaluation. 4.D. It is recommended that Commandant require that MODUs and floating production, storage and offloading vessels engaging in oil and gas drilling activities on the U.S. OCS be subject to the salvage and marine firefighting requirements of 33 CFR § 155, Subpart I. IADC's comments regarding Recommendation 4.A. are applicable. This is an issue that should be examined jointly with BOEMRE. It would make little sense for the Coast Guard to establish salvage and marine firefighting requirements for 'vessels engaging in oil and gas drilling activities on the U.S. OCS" (whatever they may be) when similar requirements for other OCS facilities, posing similar or greater hazards, do not exist. 4. E. It is recommended that area committees evaluate the adequacy of their area contingency plans for responding to incidents involving vessels engaging in oil and gas drilling activities on the U.S. OCS. IADC views this as an internal Coast Guard issue. • 4.F. It is recommended that Commandant evaluate the current policy regarding the implementation of an incident commander to perform both the search and rescue mission coordinator and federal on scene coordinator duties during an event consisting of a mass rescue operation and a major marine casualty. • IADC views this as an internal Coast Guard issue. 4.G. It is recommended that Commandant review all organization policy on marine firefighting to ensure consistency. IADC views this as an internal Coast Guard issue. 4.H. It is recommended that Commandant update the regulations to include the requirement to conduct a deadweight survey every five years for all (U.S. and foreign - flagged) column stabilized MODUs to be consistent with the current IMO MODU Code. IADC agrees that that the Coast Guard should update its regulations (presumably in title 46 of the Code of Federal Regulations) to reflect the 2009 MODU Code. IADC notes that this would be a significant undertaking as these regulations were never updated to reflect the 1989 MODU Code. IADC also suggests that this is a matter of low priority because there is a low likelihood that new MODUs will be built for US registry and believe that, as a commercial matter and to conform with classification society rules, should a US -flag unit be built, it would be designed to conform to the 2009 MODU Code. HouSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BAN6 )k -17- DEEPWATER HORIZON Investigation • 5. Safety Systems: Personnel & Process 5.A. It is recommended that Commandant develop a risk -based Port State Control targeting program to provide additional oversight for foreign -flagged MODUs working on the OCS based on predetermined evaluation criteria, including the identity of the flag state. IADC does not support the recommendation as presented. IADC supports the establishment of a risk -based program for targeting of inspections of vessels and facilities engaged in operations on the OCS. IADC sees no reason for not including US -flag vessels in the program. The purpose of the program should be to focus the Coast Guard's resources on "high risk" vessels and facilities engaged in activities on the OCS, irrespective of their flag. IADC's view of the appropriate structure for such a program differs from the program description provided at the National Offshore Safety Advisory Committee (NOSAC) meeting in May 2011. IADC recommends that for a MODU (or for other vessels that may be determined to be OCS units subject to examination under future amendments to 33 CFR chapter I, subchapter N) arriving from a foreign location, in conjunction with the examination for the Certificate of Compliance, the Coast Guard should perform a Port State Control Inspection as it would for foreign -flag ship arriving at a US port, in a manner that would lead to the results of this examination being included in the PSC report provided to the IMO. If this step is included in the program described at NOSAC, it is • not evident. Once on the US OCS, most foreign flag MODUs typically remain in service in the US OCS, and depart only if there are disturbances in the commercial arena. IADC recognizes that the details of the targeting matrix to be used by the Coast Guard for this program remain under discussion and will evolve as experience with the program is obtained. IADC has no comments to offer regarding the details of the targeting matrix at this time, except to note that the Safety and Environmental Management System (under BOEMRE's SEMS Rule) of a MODU engaged in OCS activities has on -shore components, some of which are under the lessee/operator. These on -shore components, as well as the interface between the SEMS of lessee/operator and that of the vessel owner are vitally important. 5.8. It is recommended that Commandant develop more comprehensive inspection standards for foreign -flagged MODUs operating on the OCS. IADC has no objection to this Recommendation, but would suggest the need to re- evaluate the inspection standards applied to US -flagged MODUs as well. 5.C. It is recommended that Commandant work with the IMO to develop a code of conduct for Recognized Organizations to ensure that verification of all flag state requirements are being conducted properly. IADC's comment regarding Recommendation 1.I. is applicable to this Recommendation. • HouSTON • WASHINGTON D.C. • THE NEIHERLANDS • DUBAI • BANGKOK N:� DEEPWATER HORIZON Investigation 5.D. It is recommended that Commandant further develop the Operational Risk Assessment model (Appendix M) for use by MODU personnel and government inspectors. While IADC views this a primarily an internal issue for the Coast Guard, IADC offers the following comments: • ISO has already developed recommendations for risk assessment, with ISO 31000 providing general guidance and ISO 17776 (which predates ISO 31000) providing guidance specifically for the petroleum and natural gas industries. • Drawing upon principles of the ISM Code as the basis for an overall health, safety and environmental management system, and the principles of ISO 17776 for risk assessment, IADC has developed HSE Case Guidelines for MODUs. These guidelines are available (without charge) from the IADC website at: http://www.iadc.org/hsecase/index.htmi The IADC HSE Case Guidelines for MODUs have been developed specifically to address the control of risks associated with MODU operations. IADC notes in this regard that they address both the marine risks and the drilling risks associated with such operations. While as a marine regulator, it may be comfortable for the Coast Guard to attempt to ignore the drilling risks, it is IADC's view that these risks, along with the actions taken to mitigate these risks, are often interrelated and must be addressed holistically. • As previously noted, IADC is working with API to develop Bulletin 97, which will provide guidance on integrating the health, safety and environment management systems of drilling contractors with those of their clients with • respect to both marine and industrial risks. • IADC believes that it is the guidelines applied to the audit of the combined health, safety and environmental management systems of the drilling contractor and the client, both onshore and offshore, that should be used to assess organizational risk. It is IADC's understanding that the Center for Offshore Safety is developing protocols for third parties performing audits of BOEMRE-required SEMS for (at this time) deepwater facilities. IADC understands that BOEMRE has been involved in the review of these protocols. It may be appropriate for the Coast Guard to be involved as well. • 5.E. It is recommended that Commandant work with International Association of Classification Societies to improve implementation of its Procedural Requirement 17. While IADC understands why the Report has identified this issue, it is IADC's view that too much emphasis is being placed on the ISM Code in relation to activities on the OCS - Focusing on the ISM Code does not address the broader underlying issues associated with the management of OCS activities. • Only a relatively small percentage of the MODUs (and other vessels) engaging in activities on the OCS are subject to the ISM Code. • The ISM Code is not well suited for addressing the risks associated with drilling operations, particularly with regards to the hazards that must be assessed and controlled by the lessee/operator, e.g., the design and construction of the well. • Drilling operations undertaken on moored MODUs (not self-propelled), jack - ups, and on both fixed and floating platforms are similar to those being undertaken on the DEEPWATER HORIZON at the time of the incident. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -19- DEEPWATER HORIZON Investigation • BOEMRE's SEMS Rule requires the lessee/operator to establish a SEMS to manage virtually all activities on the OCS, including drilling operations by MODUs. MODU owners may use their compliance with the ISM Code as part of their demonstration to the lessee/operator that they have the necessary safety and environmental management system program elements in place to support the lessee/operator. However, as previously noted, from the standpoint of the placement of regulatory responsibility for overall operations, the ISM Code and BOEMRE's SEMS Rule are not aligned. • BOEMRE has indicated that it will be issuing a Notice of Proposed Rulemaking to further refine its SEMS Rule. IADC would strongly recommend that, with respect to safety and environmental management systems related to activities on the OCS, the Coast Guard's primary efforts should be directed towards working with BOEMRE to assure that its regulatory needs are being met and to gain mutual understanding of the placement of regulatory responsibility, particularly with regard to the ISM Code. 5.F. It is recommended that Commandant initiate a rulemaking project that updates Title 33 CFR Subchapter N with respect to requirements for dynamic positioned vessels as per the guidance from Commandant (CG-0941). IADC's response to Recommendation 1.H. applies to this recommendation. 5.G. It is recommended that Commandant revise the current marine casualty reporting requirements and drug testing requirements for foreign -flagged MODUs operating on the . OCS and make them consistent with the requirements for U.S.-flagged MODUs. During the development of, and in response to proposed amendments to the marine casualty reporting requirements and drug testing requirements, IADC attempted to identify and correct ambiguities in the regulations, and to assure that there were in inadvertent differences in the applicability of the regulations to foreign -flagged vessels and U.S.-flagged vessels performing identical operations. After the promulgation of these regulations, IADC worked with the Commander, Eighth Coast Guard District (CCGD8) to continue to address the ambiguities as they existed in the regulations. The results of this effort were memorialized in the CCGD8's letter of 15 June 2007, a copy of which is provided as enclosure (1). Based on IADC's experience during the development of the regulations, it is IADC's view that it may be necessary to seek legislation if these requirements are to be made consistent. IADC's efforts were directed solely towards providing clarification of the requirements with respect to MODUs. IADC did not attempt to address other vessels engaged in activities on the OCS or to other OCS facilities which suffer from similar ambiguity or deficiencies. IADC would question why, from a public policy standpoint, there should be a mandate for post -incident drug testing of personnel on a MODU involved in a serious well control incident, when such testing would not be required with respect to an incident involving identical circumstances on a fixed or floating platform. If consistency of casualty and drug reporting requirements is necessary, does the Coast HouSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -20- DEEPWATER HORIZON Investigation • Guard have authority to promulgate drug testing requirements under the provisions of 43 U.S.C. 1347(c)? 5.H. It is recommended that Commandant evaluate the benefit of combining current OCS inspection responsibilities assigned to multiple OCMI zones into one inspection office responsible for covering all OCS inspection activities. (Conclusion 5.1) IADC views this as an internal Coast Guard issue. IADC would note, however, that the Coast Guard's OCS inspection responsibilities are not limited to the Gulf of Mexico. 5.1. It is recommended that Commandant determine how to continue to maintain a properly trained and educated Coast Guard work force for MODU and OCS inspections. IADC views this as an internal Coast Guard issue. 5.1. It is recommended that Commandant investigate the role of Safety Management System failures in recent marine causalities and based upon those investigation findings, determine if a change in the current inspection and enforcement methods is required to increase compliance with the ISM Code. The investigation should include a request to the National Research Council, Commission on Engineering and Technical Systems, Marine Board to perform a comprehensive investigatory assessment of the effectiveness of the ISM Code as used in the marine environment. IADC's response to Recommendation 5.E. applies to this recommendation. • IADC believes it would be instructive to have the report of BOEMRE's investigation into this casualty in order to assess the degree to which failures of the safety management system of the lessee/operator contributed to this casualty. While an examination of the effectiveness of the ISM Code may be a worthwhile endeavor, IADC does not see how such an examination can be predicated on this casualty alone. Nor does IADC believe that either the Commandant or the Marine Board would have sufficient information available to undertake such an examination, given that the vast majority of experience with the ISM Code lies outside the jurisdiction of the United States. Again, IADC would strongly recommend that, with respect to safety and environmental management systems related to activities on the OCS, the Coast Guard's primary efforts should be directed towards working with BOEMRE to assure that its regulatory needs are being met. 5.K. It is recommended that Commandant work with BOEMRE to evaluate the benefits of shifting to a "Safety Case" approach similar to that used in the North Sea, a method in which there is a more holistic approach to safety. In testimony provided to the Congress, BOEMRE, and the Chemical Safety Board, as well as in meetings with senior Coast Guard officials, IADC has advocated the use of a Safety Case approach, particularly with respect to deepwater drilling operations. In this testimony IADC has emphasized the need for a holistic approach - particularly with regard to hazard identification and risk management. IADC has highlighted that 40 the major hazards and associated controls associated with MODU operations rarely HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -21- DEEPWATER HORIZON Investigation fall within the jurisdiction of a single regulatory agency, and that overlapping requirements of regulatory agencies may complicate the effective application of the controls. One cannot holistically address safety when faced with the unyielding and overlapping demands of multiple narrowly -focused regulatory agencies. There is no single "Safety Case" approach. While several offshore petroleum regulatory authorities have mandated or created the expectation of a Safety Case, the actual 'requirements' for the Safety Case vary considerably. As noted in the Introduction to IADC's HSE Case Guidelines for Mobile Offshore Drilling Units, the IADC Guidelines were developed to provide guidance that, if followed, would lead to the development of a Safety Case acceptable to multiple regulatory authorities. Some of the principle differences IADC has observed in the approach amongst differing regulatory authorities relate to: • The degree to which health, safety, and/or environment are emphasized and are required to be addressed; • The degree to which reliance on prescriptive regulations or prescriptive application of industry standards was replaced by the use of broadly described performance standards when the Safety Case approach was adopted; • The level of review or acceptance of the Safety Case, in particular the hazard analyses, by the regulatory authority; • The emphasis placed on, and the methods of conducting, audits of the safety management system; and • Transparency in relation to the public release of information regarding audits of the Safety Case. • IADC has completed a gap analysis comparing BOEMRE's SEMS Rule against the IADC Guidelines and has concluded that the SEMS Rule contains all the essential elements of a Safety Case. This said, BOEMRE has declared that they do not believe that they have required a Safety Case. Further, IADC notes that BOEMRE has increased, rather than decreased, its reliance on prescriptive requirements as it moves toward full implementation of its SEMS Rule, which is contrary to the approach of most regulatory authorities that have chosen to implement a Safety Case. BOEMRE's SEMS Rule is in place. The Congress is considering and is likely to pass legislation (S.917) that would mandate that BOEMRE promulgate regulations requiring a safety case be submitted along with each new application for a permit to drill on the OCS. IADC sees no benefit in further evaluation of the Safety Case approach by the Coast Guard at this time. Rather, IADC would urge the Coast Guard to work with BOEMRE to assure that the SEMS Rule (as it may be amended) holistically addresses the hazards that pose risks to health, safety and the environment so that regulatory conflicts between BOEMRE and the Coast Guard are minimized and the concerns of both agencies are satisfied. 5.L. It is recommended that Commandant require and coordinate expanded International Safety Management (ISM) Code examinations of all Transocean vessels that are subject to the ISM Code and engaging in oil and gas drilling activities on the U.S. OCS. While this will directly affect one of IADC's members, IADC views this as an internal • Coast Guard issue. HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -22- DEEPWATER HORIZON Investigation • • • 5.M. It is recommended that Commandant work with the Republic of the Marshall Islands to require an immediate annual verification of the safety management system of Transocean offices (Main and North America). Because this investigation has questioned DNV's performance as the recognized organization for the RMI, another approved recognized organization should perform the verification. While this will directly affect one of IADC's members, IADC views this as an internal Coast Guard issue. IADC appreciates the opportunity to provide comments on this Report and requests that IADC's comments be given due consideration. If you have any questions about these comments, please contact me by phone at (713) 292-1945, ext. 207. Sincerely, Alan Spackman Vice President, Offshore Technical and Regulatory Affairs End: CCGD8 letter 16213 of 15 June 2007 HOUSTON • WASHINGTON D.C. • THE NETHERLANDS • DUBAI • BANGKOK -23- U.S. Department of Homeland Security • United States Coast Guard Mr. John Pertgen International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, TX 77042 Dear Mr. Pertgen: Commander Eighth Coast Guard District Hale Boggs Federal Bldg. 500 Poydras Street New Orleans, LA 70130-3310 Staff Symbol: (dpi-3) Phone: (504) 671-2152 Fax: (504) 671-2269 16213 June 15, 2007 This is in response to your inquiry regarding recent changes to the regulations for post incident chemical testing of individuals involved in a serious marine incident (SMI) on a foreign flagged Mobile Offshore Drilling Units (MODUs) and questions regarding the immediate notification and written reports required following various marine casualty. I applaud the partnership formed between the Eighth Coast Guard District and the IADC to develop a MODU casualty reporting matrix which details the applicable notification and follow- on chemical testing requirements based on the vessel's flag, location and current activity. The matrix reflects the current Federal Regulations and should aid your membership to determine the appropriate reporting and chemical testing requirements for any reportable marine casualty. I truly appreciate the time you spent working with members of my staff during the development of this document. As always, it is a pleasure assisting you with Coast Guard matters affecting your organization and member companies. If you have any additional questions regarding this issue, please contact Lieutenant Commander Stewart, a member of my Inspections and Investigations staff, at (504) 671-2164. Sincerely, T. D. HOOPER Captain, United States Coast Guard Chief, Prevention Division By direction of the Commander Eighth Coast Guard District Encl: (1) MODU Matrix for Marine Casualty Reporting and Chemical Testing Requirements 40 0 0 0 MODU Matrix for Marine Casualty Reporting and Chemical Testing Requirements NO. CLASS OF CASUALTY DESCRIPTION US FLAG VESSEL (MODU) FOREIGN FLAG VESSEL FOREIGN FLAG VESSEL (MODU) FOREIGN FLAG VESSEL CASUALTY ANYWHERE IN THE WORLD (MODU) ON U.S. NAVIGABLE OUTSIDE U.S. NAVIGABLE (MODU) OUTSIDE U.S. WATERS (within 12 Miles) WATERS (beyond 12 Miles) NAVIGABLE WATERS [OPERATING OR NOT WHILE ON THE U.S. OUTER (beyond 12 Miles) WHILE ON OPERATING] CONTINENTAL SHELF ENGAGED THE U.S. OUTER IN OCS ACTIVITIES CONTINENTAL SHELF NOT ENGAGED IN OCS ACTIVITIES [NOT OPERATING - i.e. STACKED, UNDER TOW OR TRANSITING] (Note 1) (Notes 2 & 3) (Notes 2 & 4) (Notes 2 & 5) MARINE CASUALTY An occurrence causing property damage in 1) Immediate notification, and 1) Immediate notification, and NA NA excess of $25,000 (Includes costs for labor and 2) Written notification via 2) Written notification via 1 materials, Excludes cleaning, gas freeing, CG-2692(within 5 days) CG-2692(within 5 days) drydocking and demurrage) MARINE CASUALTY Unintended grounding; OR intended grounding 1) Immediate notification, and 1) Immediate notification; and NA NA that creates a hazard to navigation, the 2) Written notification via 2) Written notification via 2 environment or the safety of the vessel. CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Stranding (which affects the vessel's 1) Immediate notification; and 1) Immediate notification, and NA NA seaworthiness or fitness for service or route) 2) Written notification via 2) Written notification via 3 CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Foundering (which affects the vessel's 1) Immediate notification; and 1) Immediate notification, and NA NA 4 seaworthiness or fitness for service or route) 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Flooding (which affects the vessel's 1) Immediate notification; and 1) Immediate notification; and NA NA 5 seaworthiness or fitness for service or route) 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Collision (which affects the vessel's 1) Immediate notification; and 1) Immediate notification, and NA NA 6 seaworthiness or fitness for service or route) 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Allision (Including intended or unitended strike 1) Immediate notification; and 1) Immediate notification; and NA NA 7 with a bridge) 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Explosion (which affects the vessel's 1) Immediate notification; and 1) Immediate notification; and NA NA 6 seaworthiness or fitness for service or route) 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Fire (which affects the vessel's seaworthiness or 1) Immediate notification; and 1) Immediate notification; and NA NA fitness for service or route) 2) Written notification via 2) Written notification via 9 CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Loss of vessel's main propulsion, primary 1) Immediate notification, and 1) Immediate notification; and NA NA steering, or any associated componenttcontrol 2) Written notification via 2) Written notification via system(s) that affects vessel maneuverability. CG-2692(within 5 days) CG-2692(within 5 days) 10 Page 1 of 4 6/19/20071: 52 PM MODU Matrix for Marine Casualty Reporting and Chemical Testing Requirements NO. CLASS OF CASUALTY DESCRIPTION US FLAG VESSEL (MODU) FOREIGN FLAG VESSEL FOREIGN FLAG VESSEL (MODU) FOREIGN FLAG VESSEL CASUALTY ANYWHERE IN THE WORLD (MODU) ON U.S. NAVIGABLE OUTSIDE U.S. NAVIGABLE (MODU) OUTSIDE U.S. WATERS (within 12 Miles) WATERS (beyond 12 Miles) NAVIGABLE WATERS [OPERATING OR NOT WHILE ON THE U.S. OUTER (beyond 12 Miles) WHILE ON OPERATING] CONTINENTAL SHELF ENGAGED THE U.S. OUTER IN OCS ACTIVITES CONTINENTAL SHELF NOT ENGAGED IN OCS ACTIVITES [NOT OPERATING - i.e. STACKED, UNDER TOW OR TRANSITING] (Note 1) (Notes 2 & 3) (Notes 2 & 4) (Notes 2 & 5) MARINE CASUALTY Failures imparing or impacting any aspect of the 1) Immediate notification; and 1) Immediate notification; and NA NA 11 vessel's operation, components, or cargo 2) Written notification via 2) Written notification via CG-2692(within 5 days) CG-2692(within 5 days) MARINE CASUALTY Impairment of the vessel's seaworthiness, 1) Immediate notification; and 1) Immediate notification, and NA NA efficiency or fitness for route or service 2) Written notification via 2) Written notification via (including failure/damage to fire extinguishing CG-2692(within 5 days) CG-2692(within 5 days) 12 system, lifesaving equip, power generating equip, or bilge pump syst) MARINE CASUALTY Any person employed on a vessel with an injury 1) Immediate notification; and 1) Immediate notification; and NA NA / SERIOUS MARINE that requires professional medical treatment 2) Written notification via: 2) Written notification via: 13 INCIDENT beyond first aid (which renders them unfit to a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days), AND (Note 6) perform routine duties) b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test results) results) MARINE CASUALTY Injury to five (5) or more persons in a single Refer to # 13 Refer to # 13 1) Immediate notification via most rapid NA (FOREIGN VESSEL incident means available 14 OPERATING ON 2) Written notification via: CG-2692 THE OCS) (within 10 days) MARINE CASUALTY Injury causing any person to be incapacitated for Refer to # 13 Refer to # 13 1) Immediate notification via most rapid NA (FOREIGN VESSEL more than 72 hours. means available 15 OPERATING ON 2) Written notification via: CG-2692 THE OCS) (within 10 days) DIVING CASUALTY Injury or loss of life while diving from a MODU 1) Immediate notification; and 1) Immediate notification; and 1) Immediate notification, and 1) Immediate notification; and (Injury is defined as incapacitation greater than 2) Written notification via: 2) Written notification via: 2) Written notification via: 2) Written notification via: 72 hours or requiring hospitalization for greater a) CG-2692 (within 5 days), AND a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days); AND than 24 hours) b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test results) b) CG-2692B (upon receipt of test 16 results) results) [46 CFR 197.484 - 488] results) [46 CFR 197.484 - 4881 [46 CFR 197.484 - 488] [46 CFR 197.484 - 488] SERIOUS MARINE Death (one or more) 1) Immediate notification; and 1) Immediate notification, and 1) Immediate notification via most rapid NA INCIDENT 2) Written notification via: 2) Written notification via: means available (Note 6) a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days), AND 2) Written notification via: CG-2692 17 b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test (within 10 days) results) results) Page 2 of 4 6/1920071'.52 PM 0 0 NIIIIIIII" MODU Matrix for Marine Casualty Reporting and Chemical Testing Requirements NO. CLASS OF CASUALTY DESCRIPTION US FLAG VESSEL (MODU) FOREIGN FLAG VESSEL FOREIGN FLAG VESSEL (MODU) FOREIGN FLAG VESSEL CASUALTY ANYWHERE IN THE WORLD (MODU) ON U.S. NAVIGABLE OUTSIDE U.S. NAVIGABLE (MODU) OUTSIDE U.S. WATERS (within 12 Miles) WATERS (beyond 12 Miles) NAVIGABLE WATERS [OPERATING OR NOT WHILE ON THE U.S. OUTER (beyond 12 Miles) WHILE ON OPERATING] CONTINENTAL SHELF ENGAGED THE U.S. OUTER IN OCS ACTIVITES CONTINENTAL SHELF NOT ENGAGED IN OCS ACTIVITES [NOT OPERATING - i.e. STACKED, UNDER TOW OR TRANSITING] (Note 1) (Notes 2 & 3) (Notes 2 & 4) (Notes 2 & 5) SERIOUS MARINE Damage to property in excess of $100,000 1) Immediate notification; and 1) Immediate notification; and NA NA INCIDENT (Includes costs for labor and materials; Excludes 2) Written notification via: 2) Written notification via: (Note 6) cleaning, gas freeing, drydocking and a) CG-2692 (within 5 days), AND a) CG-2692 (within 5 days); AND 18 demurrage) b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test results) results) SERIOUS MARINE Total loss of any United States inspected vessel 1) Immediate notification; and NA NA NA INCIDENT 2) Written notification via: (Note 6) a) CG-2692 (within 5 days), AND 19 b) CG-2692B (upon receipt of test results) SERIOUS MARINE Discharge of oil of 10, 000 gallons or more into 1) Immediate notification; and 1) Immediate notification; and NA NA INCIDENT the navigable waters of the United States. 2) Written notification via: 2) Written notification via: (Note 6) a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days); AND 20 b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test results) results) SERIOUS MARINE Discharge of reportable quantity of hazardous 1) Immediate notification; and 1) Immediate notification; and NA NA INCIDENT substance into the navigable water or 2) Written notification via: 2) Written notification via: (Note 6) environment of United States a) CG-2692 (within 5 days); AND a) CG-2692 (within 5 days), AND 21 b) CG-2692B (upon receipt of test b) CG-2692B (upon receipt of test results) results) SIGNIFICANT Significant harm to environment within 12 NM, 1) Immediate notification; and 1) Immediate notification; and NA NA HARM TO THE U.S.Territorial Sea (A film or sheen upon or 2) Written notification via 2) Written notification via ENVIRONMENT discoloration of surface of water or adjoining CG-2692(within 5 days) CG-2692(within 5 days) 22 shoreline; or sludge or emulsion deposited beneath the surface of water or adjoining shoreline) [46 CFR 4.03-65] SIGNIFICANT Significant harm to environment beyond 12NM 1) Immediate notification; and 1) Immediate notification; and 1) Immediate notification; and 1) Immediate notification; and HARM TO THE to the limit of the EEZ (Exceeding allowable limit 2) Written notification via 2) Written notification via 2) Written notification via CG-2692 2) Written notification via CG-2692 ENVIRONMENT from Oily Water Separator, 15 ppm; or discharge CG-2692(within 5 days) CG-2692(within 5 days) (within 5 days) (within 5 days) of a Noxious Liquid Substance in bulk) 23 [46 CFR 4.03-651 Page 3 of 4 6/1920071',52 PM 0 0 0 MODU Matrix for Marine Casualty Reporting and Chemical Testing Requirements NO. CLASS OF CASUALTY DESCRIPTION US FLAG VESSEL (MODU) FOREIGN FLAG VESSEL FOREIGN FLAG VESSEL (MODU) FOREIGN FLAG VESSEL CASUALTY ANYWHERE IN THE WORLD (MODU) ON U.S. NAVIGABLE OUTSIDE U.S. NAVIGABLE (MODU) OUTSIDE U.S. WATERS (within 12 Miles) WATERS (beyond 12 Miles) NAVIGABLE WATERS [OPERATING OR NOT WHILE ON THE U.S. OUTER (beyond 12 Miles) WHILE ON OPERATING] CONTINENTAL SHELF ENGAGED THE U.S. OUTER IN OCS ACTIVITES CONTINENTAL SHELF NOT ENGAGED IN OCS ACTIVITES [NOT OPERATING - i.e. STACKED, UNDER TOW OR TRANSITING] (Note 1) (Notes 2 & 3) (Notes 2 & 4) (Notes 2 & 5) Note 1 - Requirements per 46 CFR 109.411, 46 CFR 4.03-1 and 46 CFR 4.05 Note 2 - For the purpose of this matrix, a MODU is considered to be "operating" when it is engaged in an OCS activity (any offshore activity associated with exploration for, or development or production of, the minerals of the Outer Continental Shelf.) as defined in 33 CFR 140.10. Note 3 - Requirements per 46 CFR 4.03-1 and 46 CFR 4.05. Note 4 - Reporting requirements per 33 CFR 146.301, 33 CFR 146.303 and 33 CFR 151.15 Note 6 - Foreign MODUs outside U.S. Navigable Waters and not engaged in OCS activities are not subject to the provisions of 33 CFR 146.301. However, reporting requirements remain for certain oil discharges (33 CFR 151.15) and commercial diving casualties (46 j CFR 197.484 and 486). Note 6 - 46 CFR 16.240 requires testing of all personnel directly involved in a Serious Marine Incident. This means any individual whose order, action or failure to act is determined to be, or cannot be ruled out as, a causative factor in the events leading to or causing the serious marine incident. GENERAL NOTE: These CG-2692 reporting requirement do not supercede or replace any other reporting such as: MARPOL, National Response Center (NRC), OSHA, MMS, EPA, etc. Page 4 of 4 611920071'.52 PM CNNIVA A �r�v�PKJMENT REcP(-NK14,w- TO THE REPORT OF THE MONTARA COMMISSION OF INQUIRY • • © Commonwealth of Australia 2011 ISBN 978-1-921812-36-1 (paperback) ISBN 978-1-921812-37-8 (online PDF) This work is copyright. Apart from any use as permitted under the Copyright Act 1968, no part may be reproduced by any process without prior written permission from the Commonwealth. Requests and enquiries concerning reproduction and rights should be addressed to the Commonwealth Copyright Administration, Attorney -General's Department, National Circuit, Barton ACT 2600 or posted at http://www.ag.gov.au/cca For more information about this report please contact: Manager Media and Communications Department of Resources, Energy and Tourism GPO Box 1564 Canberra ACT 2601 Telephone: + 612 6276 7003 Facsimile: + 61 2 6243 7037 Email: ret@ret.gov.au Produced by the Department of Resources, Energy and Tourism 0 Contents • Executive Summary 2 Introduction 2 Australia's Regulatory regime for offshore petroleum activities 2 Oil Spill Response Management 4 The Montara Incident 5 Summary of the Report of the Montara Commission of Inquiry 5 Draft Response to the Report of the Montara Commission of Inquiry 7 Final Response to the Report of the Montara Commission of Inquiry 7 Commonwealth Actions addressing the Recommendations of the Report 8 Actions on the Key Recommendations of the Report 10 PTTEP Australasia (Ashmore Cartier) Pty Ltd (PTTEP AA) 10 Actions of the Northern Territory Designated Authority 10 International Considerations 10 Offshore Petroleum Regulatory Reform 11 Key Actions Undertaken by the Offshore Petroleum Industry 12 • Commonwealth Final Response 12 Chapter 3 - The Circumstances and Likely Cause(s) of the Blowout 13 Chapter 4 - The Regulatory Regime: Well Integrity and Safety 57 Chapter 5 - Arresting the Blowout 73 Chapter 6 - Environmental Response 83 Chapter 7 - Review of PTTEP AA's Permit and Licence at Montara and other Matters 103 Additional Recommendations for Industry - Review of PTTEPAustralasia's Response to the Montara Blowout 109 Implementation Plan - Report of the Montara Commission of Inquiry and the Review of PTTEPAustralasias Response to the Montara Blowout 113 Appendix 1 - Summary of Stakeholder Submissions on the Commonwealth's Draft Response 119 0 E Executive Summary Introduction The 21 August 2009 uncontrolled oil and gas release at the Montara oil field, operated by PTTEP Australasia (Ashmore Cartier) Pty Ltd (PTTEP AA), and the more recent incident on 20 April 2010 at the BP -operated Macondo oil field in the Gulf of Mexico, where 11 lives were lost, serve as strong reminders to governments, regulators, the offshore petroleum industry and the broader community of the risks of complacency in the operation and regulation of offshore petroleum activities. The Commonwealth Government (the Commonwealth) has moved quickly to learn the lessons from the Montara and Gulf of Mexico incidents and is working to improve the protection of human health and safety and the protection of the marine environment so as to ensure that Australia continues to have a safe, strong and competitive offshore petroleum industry which is able to contribute to Australia's ongoing energy security and economic prosperity, and that of our major trading partners. Australia's regulatory regime for offshore petroleum activities Offshore petroleum operations beyond the designated state and territory coastal waters (three nautical mile baseline to 200 nautical miles of Australia's Exclusive Economic Zone) are governed by the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) and related regulations. While ultimate responsibility for Australia's offshore areas beyond the three nautical miles from the . territorial baseline rests with the Commonwealth, the Commonwealth currently jointly administers the regulatory regime and supervises offshore petroleum industry activities with the State and Northern Territory governments through a Joint Authority/Designated Authority arrangement. The establishment of the single national regulator will see the proposed National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) become the regulator for all offshore petroleum activities beyond three nautical miles from the territorial sea baseline. In addition, under this model, the States and Northern Territory will be able to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA for coastal waters (ie up to the three nautical mile limit). In 1991, in responding to The Public Inquiry into the Piper Alpha Disaster by the Hon Lord Cullen, the Commonwealth made a policy decision to implement the key outcomes of that report, in particular that a safety case regime be adopted and new performance/objective-based regulations be developed to replace the then prescriptive regulations. Today, Australia's regime is largely a performance/ objective -based regime, in which the operator of an offshore facility is responsible for the safe and effective operation of the petroleum facility. An important feature of objective -based regulation is that it encourages continuous improvement rather than a compliance mentality. The Australian objective -based regime places the onus on the industry to ensure and demonstrate to regulators that the risks of an incident relating to oil and gas operations are reduced to 'as low as reasonably practicable' The regime ensures flexibility in operational matters to meet the unique nature of differing projects, and avoids a 'lowest common denominator' approach to regulation that can be observed in a prescriptive regime. The objective -based regime is not self -regulation by industry, as industry must demonstrate to regulators - and regulators must assess and approve or not approve - that it has reduced the risks of an incident to 'as low as reasonably practicable' in order to conduct operations. It is essential that a regulatory system encourage the creator of the risk to move beyond minimum standards in a continuous effort for improvement, and not just accept the minimum standard. The risk of specific standards is that they can shift the burden of responsibility from the operator to the government and stifle innovation. The Australian objective -based regime seeks to maintain clarity that the operator is responsible for evaluating risk and achieving fit -for -purpose design that reduces risk to 'as low as reasonably practicable'. Prescriptive -based regulation focuses on minimum compliance, requires frequent amendment and relies heavily on the ability of legislative drafters to understand and anticipate the risks and operational environment of the industry. Until late April 2011, the structural integrity -related regulatory functions for offshore petroleum activities were exercised pursuant to the Petroleum (Submerged Lands) (Management of Well Operations) Regulations 2004 and the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations2009 (Safety Regulations) and were fulfilled by: • Designated Authorities assessing Well Operations Management Plans (WOMPs) and applications to conduct well activities in order to ensure that well operations were conducted in accordance with sound engineering principles and good oil field practice. • The National Offshore Petroleum Safety Authority (NOPSA) assessing and challenging the facility operator's safety cases and seeking through oversight to ensure that occupational health and safety risks were properly managed by the operator. In November 2010, the Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Miscellaneous Measures) Act 2010 extended the functions and powers of NOPSA to include non - occupational health and safety aspects of structural integrity for petroleum facilities, wells and well -related equipment in Commonwealth waters, in addition to its existing occupational health and safety -related functions and powers under the OPGGS Act and the Safety Regulations. This amendment in effect provides NOPSA with regulation and oversight of the whole of structural integrity of petroleum facilities (including pipelines), wells and well -related equipment in Commonwealth waters. This includes assessment of WOMPs and individual well activities. This responsibility is given effect through the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. These amendments have addressed the issues arising from the Montara incident in respect of wells operation approvals, compliance and monitoring. Commonwealth, state and territory governments require petroleum companies operating in state/territory waters to conduct their activities in a manner that meets a high standard of environmental protection. The OPGGS Act contains a broad requirement for titleholders to operate in accordance with 'good oil field practice' Specific environmental provisions relating to work practices require operators to control and prevent the escape of wastes and petroleum. The OPGGS Act also requires activities to be carried out in a manner that does not interfere with other rights, including the conservation of the resources of the sea and seabed. Key objectives of the Environment Regulations under the OPGGS Act include encouraging industry to: • continuously improve its environmental performance; • adopt best practice to achieve agreed environment protection standards in industry operations; and • ensure operations are carried out in a way that is consistent with the principles of ecologically sustainable development. Australia's national environment law, the Environment Protection and BiodiversityConservationAct 7999 (EPBC Act), also plays a key role in the regulation of offshore petroleum activities. The EPBC Act establishes a national approach to the protection and conservation of Australia's environment, and sets 40 out a regulatory framework to protect those aspects of the environment considered to be matters of national environmental significance (NES), which includes the Commonwealth marine area. Offshore petroleum activities that are likely to significantly impact NES matters require assessment under the EPBC Act and approval by the Environment Minister. The Environment Minister may attach conditions to an approval to protect, repair or mitigate damage to NES matters. The EPBC Act includes a wide range of coercive powers as well as criminal, civil and administrative sanctions for breaches of the Act. Oil Spill Response Management Australia is a State Party to both the International Convention on Oil Pollution Preparedness, Response and Cooperation 7990 and the Protocol on Preparedness, Response and Cooperation to Pollution Incidents by Hazardous and Noxious Substances (HNS) 2000. These conventions require Parties, individually or jointly, to take all appropriate measures in accordance with their provisions to prepare for and respond to a pollution incident by oil and HNS. Since October 1973, Australia has had in place a pre -planned national strategy to respond to marine spills. The original strategy dealt only with oil spills and was known as the National Plan to Combat Pollution of the Sea by Oil. In April 1998, the strategy was extended to deal with the response to maritime chemical spills in Australian waters and is now the National Plan to Combat Pollution of the Sea by 0il and other Noxious and Hazardous Substances, more commonly known as the 'National Plan'. A The National Plan is a national integrated government and industry organisational framework enabling effective preparedness and response to marine pollution incidents. On behalf of the Commonwealth, the Australian Maritime Safety Authority (AMSA) manages the National Plan, working with State/ Northern Territory governments and the shipping, oil, exploration and chemical industries and emergency services to maximise Australia's marine pollution response capability. The aim of the National Plan is to protect the community and the environment of Australia's marine and foreshore zones from the adverse effects of oil and other noxious or hazardous substances. It also aims to minimise those effects where protection is not possible. Under the National Plan, AMSA has responsibility for the response effort, as the Combat Agency, where an incident takes place in Commonwealth waters (more than three nautical miles from the coastline). This responsibility involves: • management and application of the National Oil and Chemical Contingency Plans; • fixed wing aerial dispersant spraying of the spill site; • maintenance of the oil spill response equipment stockpiles at the Australian Marine Oil Spill Centre (AMOSC); • leadership of the National Response Team; • provision of on -site advice during the incident in the role of the Combat Agency; • facilitation of training programs in relation to spill response, research and development and oil • spill trajectory modelling; and • reviewing and reporting of incident responses and field exercises. A comprehensive assessment and strengthening of the National Plan has been instigated by AMSA. This work, to be completed by the end of 2011, will consider Australia's marine oil and HNS spill preparedness and response capability and the National Maritime Emergency Response Arrangements (NMERA), which includes emergency towage capability. The aim of the work is to determine if current arrangements are adequate to provide an effective response to marine casualties and pollution of the sea by oil and HNS, and where deficiencies are identified, make recommendations to rectify them. It will provide an analysis of accountabilities, roles and resources required to meet the needs of AMSA and its National Plan/NMERA stakeholders for marine casualties and marine oil/HNS spill preparedness and response. The review will also provide details on the gaps in response preparedness and capabilities and any efficiencies that can be gained through improvements, as well as recommendations for the enhancement of the preparedness and response regime currently in place in Australia. The Montara Incident On Friday 21 August 2009, during activity being undertaken by the West Atlas jack -up drilling rig operated by Atlas Drilling, a hydrocarbon release was observed from the H1-ST1 well through the Montara Wellhead Platform at 0530 (WST). On 14 September 2009, work commenced on drilling a relief well. On 1 November 2009, a fire broke out on the West Atlas drilling rig and the Montara Wellhead Platform after the West Triton, which was drilling a relief well, successfully intercepted the leaking well on the fifth attempt. On 3 November 2009, successful well -kill operations were undertaken, the fire was extinguished and the oil leak was contained. Summary of the Report of the Montara Commission of Inquiry The Report contains 100 findings and 105 recommendations which have implications for governments, regulators and the operational processes and procedures of the offshore petroleum industry. It addresses the likely causes of the incident, the adequacy and effectiveness of the regulatory regime for offshore petroleum (including safety and environmental management), the level of compliance with legislative obligations, adequacy of the incident response by governments and the offshore petroleum industry, and the environmental impacts of the incident. Chapter 3 The Circumstances and Likely Causes of the Blowout Chapter 3 of the Report specifically focuses on the circumstances and technical causes of the Montara incident. The Report identifies 'direct causes' and 'systemic contributory factors' The chapter also considers employee competency and the level of compliance by technical staff with the regulatory obligations for well activity. The Report concluded that the source of the blowout was largely uncontested and was a result of the primary well control barrier failing. The Report further notes that initial cementing problems were compounded by the fact that only one of the two secondary well control barriers - pressure containing anti -corrosion caps - was installed. Chapter 4 The Regulatory Regime: Well Integrity and Safety Chapter 4 of the Report concludes that the existing regulatory regime supporting offshore petroleum activities provides sufficient powers to the regulator to enable the effective monitoring and enforcement of offshore petroleum -related operations. The inadequacies identified by the Inquiry primarily relate to the implementation of this regime. Despite the deficiencies in the administration by the Northern Territory Department of Resources (DoR) of its Designated Authority functions, the Report concluded that the incident could have been avoided . if PTTEP AA had adhered to the well control practices approved by the regulator and its own well construction standards. The Report recommended pursuing regulatory reform through the establishment of a single, independent regulatory body looking after safety as a primary objective, well integrity and environmental management. The Commonwealth notes that the performance objective -based regulatory regime will be further enhanced by the establishment of a single national regulator for offshore petroleum, mineral and greenhouse gas storage activities. Chapter 5 Arresting the Blowout Chapter 5 of the Report concludes that, in considering the initial response to the incident at the Montara Wellhead Platform and the steps taken by all parties involved in arresting blowout, it commends the response efforts by PTTEP AA and AMSA as the Combat Agency, NOPSA as the offshore petroleum safety regulator, and the former Department of Environment, Water, Heritage and the Arts (now the Department of Sustainability, Environment, Water, Population and Communities (DSEWPaC)) as the environmental regulator. The Report does however recommend changes to the Commonwealth's response to future incidents involving the offshore petroleum industry under the National Plan. The recommendations are aimed at improving the operation of the National Plan, including matters regarding the environmental response to future incidents. It has also recommended there be greater clarity regarding the roles and responsibilities of agencies in responding to future incidents under Australia's current incident response framework, which has been accepted by the Commonwealth. The review of the National Plan is currently underway. Chapter 6 Environmental Response Chapter 6 of the Report concludes that the protection and management of the marine environment is critical to the Australian community's confidence in the ability of the offshore petroleum industry to undertake operations in a safe and environmentally sound manner. The Inquiry considered those matters relating to the impact on, and remediation of, the surrounding environment during and post the response to the uncontrolled oil and gas release at the Montara Wellhead Platform. The Report notes a lack of clarity regarding the implementation of the 'polluter pays' principle for costs associated with both preparedness and response capability for the offshore petroleum industry, as articulated through the National Plan. The Inquiry has recommended amendments to the EPBC Act and the OPGGS Act to reaffirm the Commonwealth's support of the 'polluter pays' principle as it applies to the offshore petroleum industry. Other recommendations made by the Inquiry include the establishment of "off -the -shelf" monitoring programs to be implemented following incidents in Commonwealth waters, and publication of Oil Spill Contingency Plans. Chapter 7 Review of PTTEPAA's Permit and Licence at Montora and Other Matters Chapter 7 of the Report details views regarding the conduct of PTTEP AA in respect of its interaction with the regulators and the Inquiry. The Report concludes that PTTEP AA, as operator of the Montara oil field, did not observe sensible oil field practices and that the company's widespread and systemic procedural shortcomings were a direct cause of the incident. Specifically the Report recommends that a review should be undertaken of PTTEP AA's permit and licence to operate through the issuing of a 'show cause' notice under the OPGGS Act. The Report does note that PTTEP AA provided the Commission of Inquiry with a Montara Action Plan to address the technical and governance issues identified through the Inquiry process. The Montara Action Plan was also provided to the Commonwealth Minister for Resources and Energy. The Commissioner noted it was "comprehensive and impressive': Draft Response to the Report of the Montara Commission of Inquiry On 24 November 2010, the Commonwealth released the Report of the Montara Commission of Inquiry (the Report) and the Commonwealth's draft response to the Report's 105 recommendations. The Commonwealth's draft response was also informed by the incident in April 2010 at the BP -operated Macondo oil field in the Gulf of Mexico. In the draft response, the Commonwealth outlined its policy direction and draft position regarding the Commissioner's recommendations and findings. In respect of the 105 recommendations made by the Commissioner, the Commonwealth proposed accepting 92 recommendations, noting 10 and not accepting three. In ensuring that the final response was achievable and considered both community expectations and current industry operating practices, a comprehensive three-month stakeholder and community consultation period was initiated on the draft response. Seventeen submissions (including three that were confidential and one that was not relevant to the draft response) were received from governments, industry and environmental stakeholders, with the non -confidential submissions published on the Montara Inquiry Response website. In general the submissions were positive and demonstrated broad support for the Commonwealth's draft response to the majority of the 105 recommendations. The key issues identified by the submissions specifically related to industry operations (both technical and procedural). A summary of the submissions is included as an Appendix to the final response. Final Response to the Report of the Montara Commission of Inquiry This document sets out the Commonwealth's final response to the Report of the Montara Commission of Inquiry. The final response remains similar with 92 recommendations accepted, including two amended to "accepted in principle", 10 noted and three not accepted due to being technically inappropriate. While the Commonwealth's position is consistent with its draft response to the Report, the changes to the final response reflect the information received in submissions from government, industry and environmental stakeholders. These changes provide greater clarification to the draft response, specifically in regards to the industry -related recommendations, and outline the Commonwealth's implementation activities since the release of its draft response. The findings and recommendations of the Report of the Montara Commission of Inquiry are just one element of the Commonwealth's broader reform agenda for Australia's offshore petroleum industry. In addition to the implementation of the accepted recommendations of the Report, the Commonwealth continues to move forward in establishing a single national regulator for all offshore petroleum activities in Commonwealth waters. The "Review of PTTEPAustralasia's Response to the Montara Blowout" report, which was released by the Minister for Resources and Energy on 4 February 2011, made numerous recommendations specific to PTTEP AA which are being implemented by the company. The report also identified a series of lessons arising from the Montara incident that may have relevance to the offshore petroleum industry. The lessons identified reflect internationally recognised themes supporting good governance and best practices, and are to be continually considered and implemented through education and development by the industry, its representative bodies and the Commonwealth. The Department of Resources, Energy and Tourism (DRET), in conjunction with APPEA, will consider these recommendations as part of the high level International Offshore Petroleum Regulators and Operators Summit scheduled for 10-11 August 2011 and in addition as part of the 2011 APPEA Conference and Exhibition on 10-13 April 2011 and the APPEA Health and Safety Conference on 8-10 August 2011. The Commonwealth remains firmly committed to improving the protection of human health and safety and the protection of the marine environment to ensure that Australia' s offshore petroleum industry is the best and safest in the world and is able to contribute to Australia's ongoing energy security and economic prosperity. Commonwealth Actions addressing the Recommendations of the Report The Commonwealth has taken decisive action, in five key areas as follows, to address the recommendations of the Report of the Montara Commission of Inquiry. Since the release of the Report and the Commonwealth's draft response on 24 November 2010, the Commonwealth has: Regulatory Regime • Amended the OPGGS Act to strengthen the activities of NOPSA and to ensure that well operations are conducted in accordance with good oil field practice. NOPSA's powers to undertake occupational health and safety inspections have also been expanded to ensure greater levels of monitoring and verification of offshore petroleum titleholders. • • Progressed the Commonwealth's proposal to establish a single national offshore petroleum regulator for Commonwealth waters by January 2012 by expanding NOPSA's existing functions to include regulation of environment plans and day-to-day operations. NOPSA will become the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA). • Agreed to separate offshore regulation and titles administration to avoid any potential or perceived conflicts of objectives. Titles administration will be undertaken by a National Offshore Petroleum Titles Administrator (NOPTA) within DRET. • Agreed to a way forward to provide regulator and industry clarification in respect of when a ship -like petroleum facility transitions from the offshore petroleum regime under the OPGGS Act to the maritime regime under the Navigation Act 1912. Regulator Operating Practices Provided ongoing support to the NT DoR to fully address the deficiencies identified by the Montara Commission of Inquiry in its actions as the Designated Authority under the OPGGS Act. This included a consistent approach to approval, assessment and compliance monitoring of all offshore petroleum activities, until such time as the single national offshore petroleum regulator comes into effect. • Worked with the Northern Territory Designated Authority to finalise the integrity testing program of the remaining wells at the Montara Wellhead Platform and all of PTTEP's suspended wells. • Commissioned a consultancy to develop a National Legislative Compliance Framework to ensure a consistent best practice approach by regulators in the regulation of Australia's offshore petroleum industry in the areas of well operations, environment and integrity. • Issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the expectations of the Minister for Resources and Energy of these agencies when performing their regulatory duties. Response Arrangements Commenced a review of Australia's national incident response framework through the National Plan to Combat Pollution of the Sea by Oil and Other Noxious and Hazardous Substances. The review will be completed by the end of 2011. • Developed a set of principles to inform a framework of equitable cost -sharing arrangements between the shipping and offshore petroleum industries in relation to oil spill preparedness and response capacities. Environmental Management Enhanced environmental assessment processes under the EPBC Act by including 11 week spill scenarios for oil spill modelling for all drilling related actions. The requirement for scientific monitoring and environmental remediation in the event of an accident has been included in approval conditions for oil and gas developments since the Montara incident. • Conducted a compliance audit of PTTEP AA under the EPBC Act. The outcomes of the audit will be published on the DSEWPaC website. Review of PTTEPAustralasia's Response to the Montara Blowout • • Commissioned an Independent Review of the PTTEP AA Montara Action Plan. The Independent Review report, "Review of PTTEP Australasia's Response to the Montara Blowout", was made public by the Minister for Resources and Energy on 4 February 2011. • Considered whether to issue a 'show cause' notice to PTTEP that could lead to the cancellation of its petroleum titles. In releasing the Independent Review of the PTTEP AA Montara Action Plan, the Minister for Resources and Energy announced that he would not be issuing a 'show cause' notice at this time. • Entered into a binding Deed of Agreement on 22 February 2011 with PTTEP which requires that the Montara Action Plan be implemented in full across all of PTTEP's Australian operations, and has appointed an independent consultant to conduct an 18-month program to monitor the implementation. • Attached additional conditions of title to all of PTTEP's current Australian petroleum titles and any future renewals or granting of offshore petroleum title applications to PTTEP in Australia. • Worked with all of the Designated Authorities to review the status and integrity of all suspended wells in Commonwealth waters since 2005, to the satisfaction of the Minister for Resources and Energy. • Incorporated the Commonwealth's response to the industry recommendations identified in the "Review of PITEPAustrolosia's Response to the Montara Blowout" report, which relate to the areas of acquisition and integration of production assets and governance and oversight, as part of the Commonwealth's final response to the Report of the Montara Commission of Inquiry. • Undertaken an investigation into potential non -occupational health and safety breaches of the OPGGS Act with a brief of evidence to be provided to the Commonwealth Director of Public Prosecutions within the first half of 2011. Actions on the Key Recommendations of the Report . PTTEP A ustrolosia (Ashmore Cartier) Pty Ltd (PTTEPAA) On 4 February 2011, the Minister for Resources and Energy released the report of the Independent Review of the PTTEP AA Montara Action Plan, entitled the "Review of PTTEPAustralasia's Response to the Montara Blowout". The Independent Review found that the Montara Action Plan effectively responds to the issues identified by the Montara Commission of Inquiry and sets PTTEP AA on the path to achieving industry best practice standards for both good oil field practice and good governance. In releasing the Independent Review report, the Minister also announced his decision not to issue a 'show cause' notice to the company at this time. This decision was subject to a binding Deed of Agreement between the Commonwealth and the Thai -based parent company PTTEP. On 22 February 2011, a Deed of Agreement was signed that formalised the arrangements for the implementation of the Montara Action Plan and an 18-month monitoring program. On 16 March 2011, Noetic Solutions Pty Ltd was engaged to monitor the implementation of the Montara Action Plan. In addition to the Deed of Agreement, the Minister for Resources and Energy has imposed an additional set of conditions on all of PTTEP's current Australian petroleum titles and any future renewals or granting of offshore petroleum title applications to PTTEP in Australia. The Commonwealth also acknowledges the changes to the leadership roles and structures at PTTEP AA and notes the appointment of Mr Ken Fitzpatrick as the new Chief Executive Officer of PTTEP AA. Mr Fitzpatrick, who was formerly the Senior Vice President of Assurance and Controls at Woodside Petroleum Ltd, will oversee the implementation of the Montara Action Plan. • Actions of the Northern Territory Designated Authority In response to the issues identified in the Report of the Montara Commission of Inquiry regarding the performance of the Northern Territory DoR in discharging its legislative and regulatory obligations as the Commonwealth's delegated Designated Authority for the offshore area of Ashmore and Cartier Islands, the Northern Territory Government and DoR have implemented changes that provide greater rigour to the way it conducts its offshore petroleum regulatory activities. The Northern Territory DoR: • Reviewed and implemented more robust approval assessment processes; • Implemented a well operation activity approvals co -assessment system with the Western Australian Designated Authority; and • Recruited petroleum engineers to address the gap in technical expertise. The Commonwealth through Geoscience Australia and DRET will continue to work closely with the Northern Territory DoR by providing it with assistance in meeting its ongoing regulatory obligations until the establishment of a national offshore petroleum regulator. International Considerations The Commonwealth has taken note of the actions of the United States (US) Government following the Macondo oil spill in the Gulf of Mexico. The final report of the US National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling concluded that the Macondo incident could have been prevented, stating that the immediate causes were a series of identifiable mistakes made by BP, Halliburton and Transocean and that serious systemic failures were also identified in relation to risk management and the role of the regulator. These findings identify a number of similarities with the failings identified by the Montara Commission of Inquiry and have been considered closely in the development of the Commonwealth's final response to the Report of the Montara Commission of Inquiry. Significantly, the National Commission's report recommends a shift in the US policy position for the regulation of offshore drilling from the current prescriptive model to a less prescriptive, "safety case" approach - similar to that in Australia. In addition to the findings of the Montara Report, DRET intends to draw upon the findings of US Commission's Report to form the basis for the scope of the International Offshore Petroleum Regulators and Operators Summit. The Commonwealth will be hosting an International Offshore Petroleum Regulators and Operators Summit on 10-11 August 2011 in Perth, Western Australia, following the APPEA Health and Safety Conference. The summit is targeting global senior -level policy makers, regulators, industry representatives and leading academics with the aim of developing a common understanding and consistent approach to the regulation of the global offshore petroleum industry. With representatives from Australia, Brazil, Canada, Norway, the US and the UK and regionally from Indonesia, Timor-Leste and Papua New Guinea, the conference will provide delegates with a forum for the exchange of first-hand experiences and lessons learnt and applied particularly from the Montara and Macondo incidents. In recognition of the importance of Australia and the US working together to discover and implement • the lessons from both the Montara and Macondo incidents, the Commonwealth was a participant at the 14 April 2011 high-level US Ministerial Forum on Offshore Drilling Containment that was hosted by the US Secretary of the Interior in Washington DC. Offshore Petroleum Regulatory Reform The Commonwealth remains committed to the establishment of a national regulator for offshore petroleum activities by January 2012, as recommended by the Productivity Commission's Review of Regulatory Burden on the Upstream Petroleum (Oil & Gas) Sector(PC Review). The Commonwealth's final response to the PC Review will be released during 2011. In recognition of the fundamental connection between the integrity of wells and structures, the safety of people and the protection of the environment, the Commonwealth will further expand the functions of NOPSA to become NOPSEMA. NOPSEMA will become the regulator for all offshore petroleum activities in Commonwealth waters beyond three nautical miles from the territorial sea baseline. In addition to NOPSA's current regulatory functions, NOPSEMA will assume responsibility for environmental approvals, including Oil Spill Contingency Plans under the OPGGS Act. NOPSEMA will also regulate safety, integrity and environment plans for minerals extraction and greenhouse gas storage activities in Commonwealth waters. AMSA will work with NOPSEMA to develop agreed arrangements to review Oil Spill Contingency Plans. The procedural framework supporting the agreed arrangements will be developed by DRET and AMSA in consultation with DSEWPaC. NOPTA will be established within DRET to administer titles and data relating to offshore petroleum, minerals and greenhouse gas storage activities in Commonwealth waters. In addition, under the Commonwealth's model for NOPSEMA and NOPTA, the legislation will also allow State and Northern Territory jurisdictions to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA and NOPTA for the coastal waters (up to the three nautical mile limit). Legislative amendments to implement this institutional reform will be introduced into the Australian Parliament during the Winter sitting period from May —June 2011. The reforms reflect extensive consultation with jurisdictions, industry and NOPSA and are supported by the offshore petroleum industry. Key Actions undertaken by the Offshore Petroleum Industry The offshore petroleum industry understands that in order to maintain its social licence to operate, it must put the safety of workers and the environment first as part of the responsible development of natural resources. The industry must be front and centre in the development of new international standards around the deployment of equipment and the competencies and training of personnel in safety -critical roles. Australia's offshore petroleum industry has taken significant steps since the Montara incident. Petroleum companies have individually and collaboratively comprehensively reviewed their prevention and response operations and procedures. Companies have conducted forensic analyses of well design, integrity and operations, and have reviewed oil spill response capacities and preparedness, and blowout contingency plans. Industry has also reviewed accepted drilling practices, including the processes and procedures relating • to the identification and reduction of risk, and for performance monitoring and assurance. In addition, industry has conducted a detailed analysis of all critical rig equipment and verified preventive maintenance requirements and integrity assessments. Industry bodies such as the Australian Petroleum Production Et Exploration Association (APPEA) are leading the industry through safety programs and best practice standards. As part of a strategic overhaul of collaborative safety leadership and strategy for the Australian oil and gas industry, APPEA's Health, Safety and Operations Committee has endorsed a new Safety Strategy for the Australian oil and gas industry. The strategic priorities include Safety Culture and Leadership; Process Safety; Structural and Asset Integrity; Emergency Management; Skills Et Competence; Contractor Engagement; and Sharing Lessons and Good Practice. The Safety Strategy is due to be finalised by the end of 2011. Industry, through APPEA's Montara Response Taskforce, has also identified a number of key tasks to implement the lessons from the Montara and Macondo incidents. These include a self -audit tool for the management of well operations; an agreed Australian industry position on cap and containment procedures; development of a mutual aid agreement; and a set of agreed strategies for oil spill response and preparedness. Industry also continues to promote training workshops and initiatives. Commonwealth Final Response The following chapters provide the Commonwealth's final response to the Report of the Montara Commission of Inquiry recommendations and to the nine recommendations that were made by Noetic Solutions Pty Ltd in the "Review of PTTEPAustralosia's Response to the Montara Blowout" that may have relevance to the offshore petroleum industry. Chapter 3 of the Report - The Circumstances and Likely Cause(s) of the Blowout focuses on the circumstances and technical causes of the Montara incident. The chapter contains 65 of 105 recommendations. 0 0 0 Chapter 3 —The Circumstances and Likely Cause(s) of the Blowout Recommendations The Minister should appoint a senior policy adviser to Accepted. On 15 July 2010, the Minister for Resources and Energy investigate and report on the best means to implement tasked the Secretary of DRET with the responsibility for the recommendations contained in this Chapter. commissioning the preparation of a Commonwealth response to the Report. The Secretary established the Montara Response Team in the Resources Division of DRET to progress the Commonwealth's response to the Report and give effect to the Report's recommendations as appropriate. On 24 November 2010, the Commonwealth's draft response to the Report was released. The draft response accepted 92, noted 10 and did not accept three of the Report's 105 recommendations. 0 0 0 WOMPs submitted by licensees to the regulator(s) should continue to be the primary framework document for achieving well integrity. Accepted. This recommendation is consistent with existing practice. In accordance with the existing regime under the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011, the Well Operations Management Plan (WOMP) is the primary document for the approval and management of well operations and integrity. The WOMP demonstrates how an operator will safely manage the lifecycle of a well/field and refers to other key documents from the Operator's Safety Management System that set out standards and procedures for the management of well operations and integrity. This allows industry to target operational standards to a particular well being drilled. The requirement for a WOMP was introduced under the Commonwealth's policy of establishing an objective -based petroleum regulatory regime. An objective -based regime allows for processes and procedures to be changed in response to technology development and provides flexibility for industry to implement continuous improvement while adhering to legislative principles. The Commonwealth has commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry in the areas of well operations, environment and integrity. The NLCF will be completed in the second half of 2011. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGS Act) and associated regulations; the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule ofSpecific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. • 0 0 WOMPs should be comprehensive and freestanding, rather than an overarching document cross- referencing many other documents (although the Inquiry also recommends a freestanding well control manual; this should be a guide to rig and onshore personnel on good oilfield practice). Noted. In accordance with the regime under the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 and accepted industry practice, the WOMP is the principal document for the approval and management of well operations and integrity. The WOMP demonstrates how an operator will safely manage the lifecycle of a well/field and refers to other key documents from the Operator's Safety Management System. The Commonwealth considers that a free-standing document on the drilling rig would not add value to the operator's process or enhance operational safety. The Commonwealth notes that it is accepted industry practice to maintain a drilling operation manual covering all aspects of drilling, completion and well control activities on the rig. This manual is considered by the Regulator as part of the well approvals and management process. • • 0 The concept of 'good oilfield practice' should be supplemented by the requirement to incorporate into WOMPs non -exhaustive minimum compliance standards in relation to well control: for example, stipulations as to when BOPS and/or well control systems must be in place and when they can be removed and minimum barrier requirements (a number of other factors that should be stipulated are outlined in other recommendations below). Accepted. While this is primarily a matter for industry and the Regulator, the Commonwealth considers that it would be appropriate for industry and the Regulator to apply this recommendation in appropriate circumstances. However, the Commonwealth considers that minimum compliance standards in relation to drilling and production should not be included in the WOMP. The WOMP is the principal document for the approval and management of well operations and integrity. The WOMP demonstrates how an operator will safely manage the lifecycle of a well/field. It references other key documents from the Operator's Safety Management System that set out standards and procedures for the management of well operations and integrity. Australia's objective -based regulatory regime allows for processes and procedures to be changed in response to technological development and provides flexibility for industry to implement continuous improvement while adhering to legislative principles. As part of the broader consideration of all Commonwealth legislation applicable to the marine environment and petroleum legislation, the Commonwealth will consider if elements of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011. This process will also consider the definition of 'good oil field practice'. The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. In addition the Commonwealth notes that industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool which provides companies with guidance in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. 0 0 0 Well construction and management plans should include provision(s) for reviewing the integrity of barriers at safety -critical times or milestones, such as (i) prior to suspension involving departure of the rig from the platform; (ii) prior to re-entry of a well after suspension; (iii) prior to removal of any barrier. Well construction and management plans, and drilling programs, should include provision for testing and verifying the integrity of all barriers as soon as practicable after installation. Accepted. While this is primarily a matter for industry and the Regulator, the Commonwealth considers that it would be appropriate for industry and the Regulator to carefully consider adopting these recommendations. The Commonwealth notes that, pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2071, these matters are addressed in the WOMP. • • • Well construction and management plans should include provision for an independent compliance review of well integrity (i) in the event of stipulated triggers; and (ii) at least once in the period between perceived achievement of well integrity and production. The independent compliance review should be undertaken by an expert who is not involved in the day-to-day drilling operations. Reviews should be completed in sufficient time to enable results to be implemented in a meaningful manner. Wellbore gas bubbling should be regarded as a trigger for independent review of well integrity. Industry and regulators should identify and document other triggers. Accepted. While this is primarily a matter for industry and the Regulator, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation in appropriate circumstances. However, the Commonwealth considers that independent compliance reviews of well construction and management plans should be undertaken prior to submission of the well plan to the Regulator. The Regulator may require a further compliance review of well integrity in the event of a stipulated trigger and/ or prior to production. The Commonwealth notes that it is accepted industry practice to have operation and management plans reviewed by qualified individuals, who can be internal but are not involved in day-to-day operations. Furthermore, industry already has in place formal "Management of Change" approvals and requirements. Finally, consistent with current regulatory requirements, the Regulator must be notified of any deviations from an approved WOMP. Not Accepted. As immediate well control action is required in the case of'gas bubbling', the Commonwealth believes undertaking an independent review of well integrity would compromise safety by delaying an appropriate response. • • • If a risk assessment or compliance review is triggered by the happening of a pre -determined event, specific consideration should be given to whether a 'hold point' should be introduced such that work must cease until the problem is resolved (and the subject of appropriate certification). Accepted. While this is primarily a matter for industry and the Regulator, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations in appropriate circumstances. The Commonwealth notes that it is accepted industry practice that any deviation from the approved drilling, completion or testing program be considered through a formal "Management of Change" process, which is reported to the Regulator. This process incorporates an appropriate level of risk assessment with hold points and reviews where appropriate to the risk control strategy. • • • lim A separate, identifiable barrier manual should be agreed upon and used by licensees, rig operators, and cementing contractors. These manuals should set out best industry practice in relation to achieving and maintaining well integrity. They should describe barrier types, barrier standards, general principles of well integrity, testing and verification methods and technologies, standard operating procedures (including procedures for the capture and communication of relevant information within and between relevant stakeholder entities). Barrier manuals should address blowout control during drilling, completion, re-entry, tie -back of casing strings and so on. Barrier manuals should be the subject of expert external review, and should be regularly updated. 11 Memoranda of Agreement should be entered into between operators in relation to provision of emergency assistance in the event of blowouts. Noted. The Commonwealth notes that numerous industry - accepted procedures, standards and operating manuals apply to petroleum operations, and that it is accepted industry practice to have a well control manual and a separate barrier manual. Both manuals are considered by the Regulator as part of the well approvals and management process. The Commonwealth also notes that the facility safety case addresses safety at or near a facility in relation to: • Identification of hazards and assessment of risks, including blow out control; • The implementation of measures to eliminate the hazards or otherwise control the risks; • A comprehensive and integrated system for management of the hazards and risks, including communication between stakeholders; and • Monitoring, audit and review. Accepted. While this is primarily an industry operating matter, the Commonwealth considers that it would be appropriate for industry to formalise assistance arrangements. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, is working to formalise assistance arrangements for the offshore petroleum industry and facilitate the sharing of resources and/or equipment through a memorandum of understanding around mutual aid. • • • 12 13 Pre -drilling assessments should include a risk assessment of the worst -case blowout scenario. Problems which arise in the course of installing barriers must be the subject of consultation between licensees, rig operators, and contractors (if used). A proper risk assessment should then be carried out and remedial steps (including further testing/verification) should be agreed upon, and documented in writing before the performance of remedial work whenever practicable. Joint written certification as to resolution of the problem should take place before resumption of drilling operations. Senior onshore representatives of stakeholder entities should be involved in that certification process. Accepted. The Commonwealth notes that this recommendation is consistent with accepted industry practice in which contingency planning is based on risk assessments that take into account probability and consequence specific to a well. The Commonwealth understands that accepted industry practice is to ensure that credible scenarios consider such attributes as well type (surface or subsea), the presence of drillpipe or tubulars in the wellbore, and offset production data. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations in appropriate circumstances. The Commonwealth notes that, in accordance with accepted industry practice, "Management of Change" processes and Well Acceptance Criteria apply to well operations. Any operational deviations are approved through formal "Management of Change" processes which are reported to the Regulator. The level of certification for activity during well operations is dependent on the risk of the situation. Furthermore, the Commonwealth notes that ultimate responsibility for the design and operation of a well lies with the operator. The operator should ensure that decisions made during the course of drilling involve full information and consultation with all parties on the rig. Although the likelihood of such events remains low, the Commonwealth now requires that offshore petroleum drilling proposals (both exploration and production) assess a 'worst case scenario' loss of well control and describe the measures in place to prevent and respond to such an incident. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • • r1 14 Licensees should be subject to an express obligation to inform regulators of problems which arise in the course of installing barriers, even if they consider that well integrity is not thereby compromised. The information should be provided by way of special report, rather than included in a standard reporting document (such as a DDR). The information provided should include risk assessment details. Accepted in part. The Commonwealth notes that this recommendation is consistent with current regulatory practice and that, pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011, an obligation exists for operators to inform the Regulator of well activity operations and well integrity hazards, including problems encountered during barrier installation. This information is provided to the Regulator through the daily drilling report. The Commonwealth considers that this method of reporting is sufficient. • C , • ILI As soon as a risk of barrier failure arises, no other activities should take place in the well other than those directed to removal of the risk. Accepted. The Commonwealth notes that this is accepted industry practice. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition, NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. 0 0 0 16 The use/type of barriers (including any change requests relating thereto) must be the subject of consultation between licensees and rig operators prior to installation. A proper risk assessment should be carried out, agreed upon, and documented in writing before installation. Joint written certification as to the appropriateness of the use of particular barriers should take place before installation. Senior onshore representatives of stakeholder entities should be involved in that certification process. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation. The Commonwealth notes that, prior to the commencement of any drilling activity, the use/type of barriers and associated risks must be approved by the Regulator through the WOMP. Only the titleholder has overall responsibility for the design and approval of all well operating activities being undertaken in the petroleum title area. This is a regulatory requirement under Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. Furthermore, any variation to the WOMP must also be approved by the Regulator. Again, only the titleholder is responsible for variation of an approved WOMP. The Commonwealth notes that the role of the Regulator is to determine if the activity is in accordance with the regulatory regime requirements as part of the approval process. Consistent with this principle, the Commonwealth further notes that implementation of a formal internal certification process would not add value to the approvals process but instead would add further regulatory burden and potential liability exposure to individuals within the organisation. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • .7 • 17 The successful installation of every barrier should be the subject of written verification within and between licensees and rig operators; and should be the subject of explicit reporting to the relevant regulator(s). Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation. The Commonwealth notes that, pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011, the titleholder must inform the Regulator of well activity as a requirement of the WOMP. This information is provided to the Regulator through the daily drilling report. The Commonwealth considers that this method of reporting is sufficient and that an explicit report after the installation of every barrier is not required. Furthermore, industry already has in place formal "Management of Change" approvals and requirements, and consistent with current regulatory requirements, the Regulator must be notified of any deviations from an approved WOMP. • 0 • 18 Removal of a barrier must be the subject of consultation between licensees and rig operators prior to removal. A proper risk assessment should be carried out and agreed upon, and documented in writing before removal. Joint written certification as to the appropriateness of removal should take place before removal. Senior onshore representatives of stakeholder entities should be involved in that certification process. Accepted in principle. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation. The Commonwealth notes that the licensee has overall responsibility for the design and approval of all well operating activities being undertaken in the petroleum title, not the rig operator. The Commonwealth further notes it is accepted industry practice for the operator to undertake the risk assessment for barrier removal during the detailed design phase of the well construction planning process, not just prior to the installation. The necessity for risk assessment and "Management of Change" should only be required if removal of a barrier(s) is non -compliant with the approved well program. The Commonwealth notes that the Regulator determines if the activity is in accordance with the regulatory requirements as part of the approval process. Consistent with this principle, the implementation of a formal internal certification process would not add value to the approvals process but instead would add further regulatory burden and potential liability exposure to individuals within the organisation. 19 Licensees should be subject to an express obligation to inform regulators of the proposed removal of a barrier, even if they consider that well integrity is not thereby compromised. The information should be provided by way of special report, rather than included in a standard reporting document (such as a DDR). The information provided should include risk assessment details. Removal of a barrier should not take place without prior written approval of the relevant regulator(s). 20 If a dispute arises between a licensee and a rig operator in relation to a well control issue, and is not resolved between them, the matter must be raised with the relevant regulator before discretionary operations proceed. Accepted in part. This recommendation is consistent with current regulatory practice and requirements. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011, all activities relating to the installation, removal or change of barriers must be approved by the Regulator through the WOMP. The Commonwealth notes the daily drilling report is sufficient to address these matters. Furthermore, any deviation from the approved drilling program would be subject to formal "Management of Change" processes which must be approved by the Regulator. Not accepted. The Commonwealth considers that Australia's objective - based regime imposes responsibility on operators for maintaining well control and well integrity. Well control issues need to be resolved quickly by the operator so the issue does not escalate further and any delays in seeking the Regulator to arbitrate disputes may result in additional complications. Such action would also in effect transfer the risk to the Regulator rather than the operator who is best placed to assess and understand the risks. Any well control issues should be reported to the Regulator in the daily drilling report. Section 569 of the OPGGS Act requires petroleum titleholders to carry out their petroleum recovery operations in accordance with good oilfield practice. The Commonwealth has commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. • 21 22 Perceived time and cost savings relating to any matters Accepted. impacting upon well control should be subjected to rigorous safety assessment. Wells drilled into hydrocarbon zones should be treated as live wells, with the potential to blowout unless a documented risk assessment establishes otherwise. Accepted. The Commonwealth agrees that wells drilled into hydrocarbon zones should be treated as live wells, and notes that all well activity should be reported to the Regulator in the daily drilling report. In this regard the Commonwealth notes that this recommendation is consistent with current regulatory practice and requirements. Reporting of a well activity is a legislative requirement under Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. • • 23 Use of single strings of intermediate casing to penetrate hydrocarbon bearing zones should be carefully risk assessed. Multiple strings of intermediate casing have the advantage of isolating lost circulation zones and sealing off anomalous pressure zones. If intermediate casing is set in a hydrocarbon zone it should be treated as production casing. Accepted. The Commonwealth accepts that the use of single casing strings should be risk assessed and notes that all well activities must be approved by the Regulator through the WOMP. The Commonwealth further notes that casing design and placement was addressed in Clause 503 of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production, which has been adopted by the industry as accepted industry practice. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of theSeoActs, the Navigation Act 1912and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule ofSpecific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. 24 25 26 A minimum of two barriers should be in place at all times (including during batched operations) whenever it is reasonably practicable to do so. Reliance upon one barrier against a blowout must not take place except with the prior written approval of the relevant regulator and then only in a true emergency situation (see below). Regulatory approval to rely on only one barrier should not be given unless (i) a proper risk assessment is carried out; (d) exceptional circumstances exist; and (iii) risks involved are reduced to 'as low as reasonably practicable' The default position must be that well integrity must be assured. Accepted. While this is primarily a matter for industry and the Regulator, the Commonwealth considers that it would be appropriate for industry and the Regulator to carefully consider adopting these recommendations in appropriate circumstances. The Commonwealth understands that the accepted industry practice is for two tested/verified well barriers to be available during all well activities and operations, including suspended and abandoned wells, where a pressure differential exists that may cause uncontrolled outflow from the borehead/wellhead to the external environment. Furthermore, the Commonwealth notes that these recommendations are consistent with current regulatory practice. The use of barriers and associated risks must be approved by the Regulator through the drilling program, and the Regulator has the power to request additional barriers should it be considered necessary. Any changes to the drilling program are subject to formal "Management of Change" processes and must be reported to the Regulator. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Furthermore, the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. Furthermore, the Commonwealth has commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. • • 27 Licensees and rig operators should install an additional barrier whenever (i) there is any real doubt as to the integrity of any barrier; (ii) whenever the risk of flow from a reservoir increases materially in the course of operations; and (iii) where the consequences of a blowout are grave (for example, for reef systems or shorelines). Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry and the Regulator to carefully consider adopting these recommendations. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011, titleholders are required to inform the Regulator of well activity as a requirement of the WOMP. This information is by accepted industry practice provided to the Regulator through the daily drilling report. Furthermore, the Commonwealth notes that the use of barriers and associated risks must be approved by the Regulator through the WOMP, and that the Regulator can request additional barriers if appropriate prior to any activity being undertaken. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • E 28 The industry standard of two barriers should be replaced with the concept of 'two or more barriers' as a minimum standard. A minimum standard when operations proceed normally should never be regarded as a sufficient standard in other circumstances. Accepted. The Commonwealth accepts that two barriers should be available during all well activities and operations and further notes that this is an existing, accepted industry practice. The Commonwealth also notes that this recommendation is consistent with current regulatory practice, where the Regulator has the power to request additional barriers as a part of the approval of the WOMP. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Mortara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. 0 0 0 29 Industry, regulators, and training/research institutions should develop standards that address best practices for cementing operations (including liaising, as appropriate, with overseas regulators) with a view to overcoming problems which can effect the integrity of cemented casing shoes, annulus and cement plugs. 30 Tracking and analysis of cementing problems/failures should occur to assess industry trends, principal causes, remedial techniques and so on. 31 It is recommended that industry, regulators, and training/research institutions liaise with one another with a view to developing better techniques for testing and verifying the integrity of cemented casing shoes as barriers (particularly in atypical situations such as where the casing shoe is located within a reservoir in a horizontal or high angle position at great depth). 32 Cement integrity should be evaluated wherever practicable by way of cement evaluation tests, rather than relying on pre -operational calculations of cement and displacement fluid volumes. Accepted. The Commonwealth considers that it would be appropriate for industry and the Regulator to carefully consider adopting these recommendations. The Commonwealth notes that industry has implemented accepted industry practices for cementing operations, which are reviewed and updated where appropriate. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Industry has also established a Drilling Steering Committee and an Emergency Management Steering Committee to identify and implement cross -industry learnings from the Montara and Gulf of Mexico incidents. There are also numerous Industry Skills Councils and Education Taskforces that provide a framework in which accepted competency standards are developed. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. 33 34 It should be standard industry practice to re -test a cemented casing shoe (that is, after WOC) whenever the plugs do not bump or the float valves apparently fail. Standard industry practice should require consideration of other tests in addition to a repeat pressure test. Any indication of a compromised cemented shoe which cannot be resolved with a high measure of confidence should result in the installation of additional well control barrier(s). Accepted. The Commonwealth considers that it would be appropriate for industry and the Regulator to carefully consider adopting these recommendations. The Commonwealth notes that industry has implemented accepted industry practices for cementing operations, which are reviewed and updated where appropriate. In addition, the Commonwealth notes industry advice that barrier and cementing manuals already define the process of testing well integrity and explanation of any deviations made subject to "Management of Change" processes. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. • • • 35 36 Volumes of cement used in connection with barrier installation should be calculated with the assistance of a pro -forma which records all relevant baseline data, which should be verified by onshore personnel. If performance of barrier installation is outsourced by a licensee, the contractor (for example, the cementing company) should be engaged on terms which clearly require the provision of expert advisory services by the contractor with respect to barrier integrity. Accepted in part. The Commonwealth notes that this recommendation is consistent with accepted industry practice. Preliminary cement volume calculations are included in the WOMP, which is approved by the Regulator before activity commences. As such, an additional requirement for a pro -forma is not required. The Commonwealth notes that according to accepted industry practice, cement volume calculations should be verified by the on -rig technical specialist once the actual measured depths and hole and casing sizes are finalised, and reported to the Regulator in the daily drilling report. Accepted. Noting this is an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations in appropriate circumstances. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. • • • 37 38 Consideration should be given to ways to ensure that contractors who are involved in barrier installation (such as cementing companies) have a direct interest in the performance of works to a proper standard. In particular, consideration should be given to (i) preventing contractors from avoiding the economic consequences of negligent installation of barriers; and/or (ii) imposing specific legislative standards of workmanship on contractors with respect to well control (similar to those which presently apply to licensees). Horizontal or high angle penetration of a reservoir should be avoided wherever practicable until such time as the apparent problems associated with the cementing of a casing shoe in these situations are satisfactorily overcome. If a casing string does penetrate a well horizontally or at a high angle, standard practice should be to install two secondary barriers in addition to the cemented casing shoe. Accepted. The Commonwealth notes that this recommendation, if progressed, may have significant commercial and contractual impacts for the operations of the offshore petroleum industry. The Commonwealth considers that it is appropriate to address standards of workmanship by all parties involved in a drilling operation through contractual arrangements, rather than legislative mechanisms. The Commonwealth understands that it is accepted industry practice to include in contracts between operators and contractors clauses relating to contractor liability which provide recourse where the contractor has been negligent. Not accepted. The Commonwealth notes the Commissioner's views but does not agree that horizontal, multi -lateral and high -angle drilling methods should be avoided. Horizontal, multi -lateral and high -angle production wells are commonly drilled worldwide and are essential technology for efficient reservoir drainage. The Montara incident was caused by operator complacency and a lack of adherence to standard operating procedures, not the extension of casing in the horizontal well section. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. • • • 39 The BOP and rig should not move from a well until barrier integrity has been verified. 40 Barriers should not be installed or removed off-line. The derrick should be located over a well at the time of removal and installation of any barrier. This will enable more decisive action to be taken in the event a problem arises. Accepted. The Commonwealth agrees that the BOP and rig should not be moved from a well until the integrity of all barriers has been verified. Accepted. The Commonwealth accepts that the derrick should be over the well during installation or removal of a barrier to allow for timely action in the event of a problem arising. However, the Commonwealth notes that there are a number of well operations that are performed during the well production life that do not require a derrick above the well, such as wireline, slick line, coil tubing, hydraulic snubbing unit, subsurface safety valve and tree removal operations. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011, titleholders are required to comply with the standards and processes in the WOMP, which has been approved by the Regulator. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • • 41 42 Secondary barriers (including PCCCs) should only be installed, tested, and removed with a BOP in place unless a documented risk assessment indicates that well control can be maintained at all times. PCCCs should be installed in a timely manner (for example, to prevent corrosion in the MLS apparatus). Non -installation in order to park a BOP is not acceptable. Accepted. The Commonwealth accepts the Commissioner's view. In the case of Montara, the BOP could not be installed on the H1 well prior to removal of the PCCC. A BOP is not applicable in every possible well operation as a well control measure. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2071, titleholders are required to comply with the standards and processes in the WOMP, which has been approved by the Regulator. Accepted. The Commonwealth accepts that this recommendation is consistent with current regulatory requirements and practices. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011, operators are required to inform the Regulator of well activity as a requirement of the WOMP, including installation of PCCCs. This information is by accepted industry practice provided to the Regulator through the daily drilling report. This requirement is enforced under Australia's objective -based regime which imposes responsibility on operators for maintaining well control and integrity. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. • • LI 43 Wells should be re-entered with a BOP in place unless a documented risk assessment indicates that well control can be maintained at all times. Accepted. The Commonwealth accepts the Commissioner's view but notes that a BOP is not applicable in every possible well operation as a well control measure. This recommendation is consistent with current regulatory requirements and accepted industry practices. Activities relating to the installation, removal or change to barriers must be approved by the Regulator through the WOMP. The Commonwealth also notes that the daily drilling report is sufficient to address these matters. • I -] :7 44 Any equipment (including PCCCs) used as, or to install, a barrier should be manufactured for that purpose and be generally recognised as fit for purpose. If equipment is designed in-house by a licensee or rig operator it should not be approved for use unless and until it is subjected to expert external analysis. Accepted in principle. While this is primarily a matter for industry, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations. The Commonwealth notes the Commissioner's view and suggests that industry consider carefully if all barrier equipment needs to be subject to specific expert external analysis. Materials and equipment used in drilling operations are assessed in the WOMP, and were also considered in Clause 502 of the Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production, which has been adopted by the industry in general as part of accepted industry practices. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912 and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2017. • • E 45 46 Manufacturers should be consulted about how to address non -routine operational problems affecting their well control equipment. Drilling programs dealing with barrier installation should incorporate relevant aspects of manufacturer's instructions. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation. Accepted. The Commonwealth notes the Commissioner's views and considers that as part of any drilling program the detailed manufacturer's operating manual and service procedures for equipment used should be available onsite. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • 47 Any pro-formas used by licensees, rig operators and contractors for recording information about installation of barriers should explicitly provide for 'exception reporting', that is, the form should include provision for recording any unforseen or untoward events which occur in the course of installation. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations. The Commonwealth notes that, pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011, titleholders must inform the Regulator of well activity as a requirement of the WOMP. This information is provided to the Regulator through the daily drilling report. The Commonwealth considers that this method of reporting is sufficient. Industry through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. • • L 48 Careful consideration must be given to equipment compatibility as part of well construction design. Accepted. The Commonwealth accepts that equipment compatibility should be considered in the well construction design phase. Materials and equipment used in drilling operations are considered by the Regulator in the WOMP, and were also considered in Clause 502 of the previously legislated Schedule ofSpecific Requirements as to Offshore Petroleum Exploration and Production, which has been adopted by the industry in general as part of accepted industry practices. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. The Commonwealth has commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry in the areas of well operations, environment and integrity. The NLCF will be completed in the second half of 2011. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. 9 49 Batched drilling operations should only be undertaken after careful assessment of the special risks which such operations give rise to; well control must be maintained during the course of batched drilling operations. Accepted. The Commonwealth accepts the Commissioner's view but considers that these recommendations are essentially the same as 'batched drilling operations' which occur when multiple wells are drilled. Operators are responsible under the OPGGS Act for maintaining well control and well integrity. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. • 0 50 Where multiple wells are drilled, operations and occurrences at one well must be carefully assessed for any implications with respect to well control at other wells. Accepted. This recommendation is consistent with current regulatory requirements and accepted industry practices. Pursuant to Part 5 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011, drilling activities and associated risks are assessed by the Regulator through the WOMP. Section 569 of the OPGGS Act also requires petroleum titleholders to carry out their petroleum recovery operations in accordance with good oil field practice. • 0 • 51 The mere fact that the rig is over the platform should not be regarded by licensees or regulators as sufficient justification for reliance on only one barrier. The default position should be that producible wells are shut-in when a rig is moved on and off a platform, or when a drilling unit is moved between wells on a platform. Accepted. The Commonwealth accepts that the placement of the rig over the platform should not justify reliance on one barrier. Under Australia's objective -based regime, responsibility for maintaining well control and well integrity is placed on operators. The Commonwealth understands that accepted industry practice is for two tested/verified well barriers to be available during all well activities and operations, including suspended and abandoned wells, where a pressure differential exists that may cause uncontrolled outflow from the borehead/wellhead to the external environment. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Furthermore, the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection 0 • • of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. 0 0 0 52 53 54 55 Relevant personnel from licensees and rig operators should meet face to face to agree on, and document, well control issues/arrangements prior to commencement of drilling operations. Well control should be regarded as a so-called SIMOP to signify its critical importance to both licensees and rig operators, and to ensure that they each take responsibility for achievement and maintenance of well control. Prior to commencement of drilling operations, senior representatives of the licensee and rig operator should exchange certificates to the effect that their respective key personnel and contractors have been informed in writing of agreed well control arrangements. Information relevant to well control must be captured and communicated within and between licensees and rig operators (and relevant third party contractors), in a manner which ensures it comes to the attention of relevant personnel. In particular, protocols should be developed to ensure that changes in shift and hitch do not operate as communication barriers. All communications between on -rig and onshore personnel relating to well control should be documented in a timely manner. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations. The Commonwealth also notes that operators already have well control and operating standards in place that are detailed in the WOMP and approved by the Regulator. The Commonwealth understands that the primary communication tools for service providers include the drilling operational programme and induction sessions, where information is provided to all personnel. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. • • 56 Logistics management of well control equipment should be conducted in such a way as to operate as a check against deficient well control practices, for example, use of serial numbers to track availability, testing, and deployment of well control equipment. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting this recommendation. The Commonwealth considers that the logistics management process of an organisation provides an important mechanism for ensuring that all appropriate documentation, certification, testing reports etc, that confirm that a particular piece of equipment being used for a well (or other activity) are fit for purpose, are easily accessible, traceable and clearly linked to the particular piece of equipment. However, the Commonwealth notes that the logistics management team is not the appropriate team to assess the adequacy of well management or well design. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. • • 0 57 Decision -making about well control issues should be professionalised. Industry participants must recognise that decision -makers owe independent duties to the public, not just their employer or principal, in relation to well control. Risk management in the context of well control needs to be understood as an ethical/ professional duty. Self -regulation contemplates self -regulation by the industry, not just by individual licensees and operators. 58 Existing well control training programs should be reviewed by the industry, regulators and training providers, with a focus on well control accidents that have occurred (in Australia and overseas). 59 A specific focus on well control training should be mandatory for key personnel involved in well control operations (including both on -rig personnel and onshore personnel in supervisory capacities). 60 Licensees and rig operators (and third party contractors involved in well control operations) should specifically assess, and document, the nature and extent of knowledge/skills of relevant personnel in relation to well control (including familiarity of personnel with agency -specific requirements and procedures). Training needs and opportunities should be identified. This process should take place on engagement and at appropriate intervals. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations. The Commonwealth also notes that operators already have well control and operating standards in place. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operators representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. 0 0 0 61 62 Licensees, rig operators, and relevant third party contractors should develop well control competency standards for their key personnel. Wherever possible, the competencies of key personnel should be benchmarked against their roles and responsibilities. Licensees, rig operators and relevant third party contractors should develop well control competency standards for key personnel in other entities involved in well control operations. Accepted. While this is primarily an industry operational matter, the Commonwealth considers that it would be appropriate for industry to carefully consider adopting these recommendations. The Commonwealth notes that operators already have well control and operating standards in place. Following the Montara and Gulf of Mexico incidents, the offshore petroleum industry has performed its own safety checks. A number of companies have implemented further actions including reviews of well plans, drilling processes, blow-out contingency plans, testing frequencies and training of personnel. Industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Operators are also working to clarify company operational practices and methods of communication onshore and offshore to prevent misunderstandings and miscommunications from occurring. In relation to occupational health and safety considerations, NOPSA has increased its focus on safety case assessments and through its inspection of drilling rigs, regarding: • Command and control arrangements: specifically including communication between the titleholder's and operator's representatives onboard drilling rigs. • Simultaneous operations: specifically including safety -related interface arrangements between titleholders and operators of separate facilities conducting co -located simultaneous operations. In addition NOPSA has increased its planned inspection frequency for manned drilling and production facilities from once to twice per year. A recruitment programme has been instigated to resource this higher frequency. 63 Achievement and maintenance of well control should be written into the job responsibilities of key personnel, at every level up to and including CEOs. That is, a functional line of accountability for well control must exist up to, and including, CEOs. 64 Supervision/oversight of well control operations (within licensees, rig operators and by regulators) must occur without assuming adherence to good oilfield practice. The opposite assumption should prevail: namely adherence to good oilfield practice may well be compromised by the pursuit of time and cost savings. 65 Licensees and rig operators should be astute in ensuring that corporate systems and culture encourage rather than discourage raising of well control issues. For instance, do performance bonuses or rewards actually encourage or discourage reporting of issues? Is there a system in place to enable anonymous reporting of well control concerns? What whistleblower protections are in place? Accepted. The achievement and maintenance of well control is fundamental to the petroleum industry maintaining its licence to operate. Noted. The Commonwealth notes the Commissioner's view. Accepted in principle. The Commonwealth notes the questions raised by the Commissioner, which are appropriate for industry to respond to. Chapter 4 of the Report — The Regulatory Regime considers the adequacy of the existing regulatory regime as it applies to offshore petroleum activities, including compliance and enforcement. The chapter contains 12 of 105 recommendations. • Chapter 4 — The Regulatory Regime: Well Integrity and Safety RECOMMENDATIONS 66 The Inquiry supports the objective (rather than prescriptive) approach to regulation now followed in Australia. However, the pendulum has swung too far away from prescriptive standards. In some areas relating to well integrity there needs to be minimum standards. Accepted in part. The Commonwealth supports the objective -based regime for the regulation of offshore petroleum activities and notes that this regime will be further enhanced by the establishment of a single national regulator for offshore petroleum, mineral and greenhouse gas storage activities. The Australian objective -based regime places the onus on the industry to ensure and demonstrate to regulators that the risks of an incident relating to oil and gas operations are reduced to 'as low as reasonably practicable'. The regime ensures flexibility in operational matters to meet the unique nature of differing projects, and avoids a 'lowest common denominator' approach to regulation that can be observed in a prescriptive regime. The objective -based regime is not self -regulation by industry, as industry must demonstrate to regulators — and regulators must assess and approve or not approve — that it has reduced the risks of an incident to as low as reasonably practicable in order to conduct operations. An important feature of objective -based regulation is that it encourages an improvement rather than a compliance mentality. It is essential that a regulatory system encourage the creator of the risk to move The Minister for Resources and Energy in his speech to the Parliament on 24 November 2010 reaffirmed the Commonwealth's commitment to the establishment of a national regulator for offshore petroleum activities by 1 January 2012. In addition, the Commonwealth has expanded the functions of NOPSA under the OPGGS Act to include the non -occupational health and safety (OHS) aspects of structural integrity for facilities, wells and well - related equipment in Commonwealth waters. This reform also applied an OHS duty of care to petroleum and greenhouse gas titleholders in relation to wells and well -related equipment, and improved NOPSA's inspection and investigation powers in relation to suspected breaches. The Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011 give affect to these amendments by providing NOPSA with regulatory responsibility for assessing WOMPs and associated well activities. From 2012, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) will have responsibility for regulating well operations and integrity; environmental plans and Oil Spill Contingency Plans; and occupational health and • • • beyond minimum standards in a continuous effort for improvement and not just accept the minimum standard. The risk of specific standards is that they can shift the burden of responsibility from the operator to the government and stifle innovation. The Australian objective -based regime seeks to maintain clarity that the operator is responsible for evaluating risk and achieving fit for purpose design that reduces risk to 'as low as reasonably practicable' Prescriptive -based regulation focuses on minimum compliance, requires frequent amendment and relies heavily on the ability of legislative drafters to understand and anticipate the risks and operational environment of the industry. safety in Commonwealth waters. AMSA will work with NOPSEMA to develop agreed arrangements to review Oil Spill Contingency Plans. The procedural framework supporting the agreed arrangements will be developed by RET and AMSA in consultation with DSEWPaC. Also, under this model, the States and Northern Territory will be able to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA for coastal waters (ie up to the three nautical mile limit). The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry in the areas of well operations, environment and integrity. The NLCF will be completed in the second half of 2011. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1972and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule of Specific • • .7 67 To better ensure that 'risks' are identified and managed in accordance with sound engineering principles and good oilfield practice, it is recommended that regulation 25(1)(a)(i) and (2)(a)(i) of the Management of Well Operations Regulations, be reworded as follows: 'A titleholder must not commence/continue a well activity if ... a well integrity hazard exists in relation to the well'. Accepted. The Commonwealth notes that there is already a requirement in the OPGGS Act for the operator to take all reasonable steps to identify well integrity hazards and control risks to 'as low as reasonably practicable'. Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. In addition, the industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed a Self -Audit Tool to guide companies in the management of well operations, and an agreed Australian industry position on Cap and Containment procedures. Part 5, Division 8 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 gives affect to this recommendation. • ,7 • 68 The definition of 'good oilfield practice' in the OPGGS Act is unduly narrow. The current definition is incapable of application except where things 'are generally accepted as good and safe: The definition should be amended such that 'good oilfield practice includes........ Accepted. The Commonwealth agrees that amendments to the definition of 'good oil field practice' are required. This amendment would be consistent with Australia's current non -prescriptive (objective -based) petroleum regulatory regime. Such a regime allows for the introduction of new and improved operator processes and procedures in response to technologies and other circumstances while adhering to the key legislative principles. As the Department with policy responsibility for the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (and its associated regulations), consideration of this recommendation will be led by DRET. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the SeoActs, the Navigation Act 1912and relevant international treaties. The Commonwealth will also consider if elements of the previously legislated Schedule of Specific Requirements as to Offshore Petroleum Exploration and Production should be incorporated into the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011. This process will also consider the definition of 'good oil field practice. This process will be completed during the second half of 2011, with any legislative amendments required introduced as soon as they can be accommodated within the legislative timetable. 0 • 69 Written (rather than verbal) approval from the DA (or new regulator) should be obtained before the commencement of well activities that lead to a physical change of a wellbore, other than in a true emergency situation (requiring amendment to regulation 17 of the Management of Well Operations Regulations). Accepted. The Commonwealth notes this recommendation is consistent with existing practices where written approval from the relevant Regulator is required for all permissioning documents including WOMPs, safety cases and environmental plans prior to the commencement of any offshore petroleum activity. Written approval from the Regulator is required prior to any well activity occurring. The granting of verbal approval in relation to well activities is not standard practice. The Commonwealth agrees that in an emergency situation where a well control issue needs to be resolved quickly, an operator cannot wait for a written response from the Regulator and that verbal approval would be appropriate in this circumstance. The Montara incident identified the need for more active emergency response engagement by Regulators and industry. Such engagement needs to be balanced to ensure both operator and Regulator independence is not compromised. In collaboration with DRET, the Northern Territory Department of Resources (NT DoR) has strengthened its approvals processes and clarified that all approvals must be made in writing. The Commonwealth is satisfied that the immediate deficiencies identified by the Commissioner have been adequately addressed. Specifically, the NT DoR has applied more rigour to the assessment of petroleum applications and has engaged an additional two petroleum engineers for the NT DoR Minerals and Energy Division. Further, all applications for approval and subsequent compliance data monitoring are being co -assessed by interstate regulatory staff (primarily from Western Australia). The system of co -assessment will continue pending a comprehensive skills and resourcing audit. The Commonwealth through DRET and Geoscience Australia will continue to work with the NT DoR until the establishment of a national offshore petroleum regulator in 2012. Furthermore the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. • `J • 70 The OPGGS Act should be amended to allow for a power to suspend a petroleum production licence (in addition to the current power to cancel a licence or suspend its conditions). Noted. The Commonwealth notes the Commissioner's view on this matter. The omission of a power to suspend a production licence was deliberate. The Commonwealth in preparing the legislation (Section 266 Suspension of rights — petroleum exploration permit or petroleum retention lease) determined this power to suspend should not apply to rights conferred under production licences, infrastructure licences or pipeline licences. The distinction was made on the basis of the higher capital investment and the smaller total areas of the seabed that operations under these licences involve. The Commonwealth notes that the OPGGS Act and its associated regulations provide a number of mechanisms that allow for the withdrawal of a production licensee's right to operate. These mechanisms include the withdrawal of approvals by the Regulator for Well Operations Management Plans; the Environment Plan; and Safety Case. An operator can only undertake an offshore petroleum activity if all approvals have been granted. 0 0 0 71 There should be a review to determine whether it is appropriate to introduce a rigorous civil penalty regime and/or substantially increase some or all of the penalties that can be imposed for breaches of legislative requirements relating to well integrity and safety. Accepted. The Commonwealth is considering amending the OPGGS Act to provide the power to impose a civil penalty regime. This process will also consider increasing some or all of the existing penalties. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. As part of this review, the Commonwealth will address the civil penalty regime for the offshore petroleum industry. • C. • 72 NOPSA's prohibition powers should be extended such that a prohibition notice can be issued where a NOPSA Occupational Health and Safety Inspector believes, on reasonable grounds, that an activity is occurring or may occur at a facility involving an immediate threat to the health or safety of a person. Accepted. The Commonwealth supports amendment to the prohibition notice powers under the OPGGS Act. This recommendation is consistent with existing practices. NOPSA's submission to the Montara Commission of Inquiry highlighted the need for the broadening of NOPSA's OHS inspector's powers in the event that an operator is not willing to comply, or if the circumstances are such that an inspector was prevented from issuing a notice due to the current narrowness of the prohibition powers. This amendment would enable inspectors to intervene and issue notices prohibiting entry to facilities where the inspector considers an immediate risk to the health or safety of a person is occurring or may occur at a facility. The Commonwealth further notes that the proposed amendment is consistent with other Commonwealth and State -based safety legislative frameworks. As the Department with policy responsibility for the OPGGS Act (and its associated regulations), consideration of this recommendation will be led by DRET. This process will be completed during the second half of 2011, with any legislative amendments required introduced as soon as they can be accommodated within the legislative timetable. 0 • 73 A single, independent regulatory body should be created, looking after safety as a primary objective, well integrity and environmental approvals. Industry policy and resource development and promotion activities should reside in government departments and not with the regulatory agency. The regulatory agency should be empowered (if that is necessary) to pass relevant petroleum information to government departments to assist them to perform the policy roles. Accepted. The Commonwealth supports reform of the current offshore petroleum regulatory arrangements. Noting the fundamental relationship between the integrity of facilities and the safety of people and operations, the Commonwealth supports the expansion of NOPSA's responsibilities beyond occupational health and safety issues to also include responsibility for the structural integrity of pipelines, wells and well -related equipment including the environmental aspects of petroleum development. The Commonwealth further supports the establishment of a single government department or agency to advise on title decisions and administration, and major questions of resource management and development. On 24 November 2010 in releasing the Report of the Montara Commission of Inquiry and the Commonwealth's draft response, the Minister for Resources and Energy also announced the Commonwealth's intention to implement the proposal of the Productivity Commission Review of Regulatory Burden on the Upstream Petroleum (Oil Et Gas) Sector (PC Review) to establish a national offshore petroleum regulator. This independent regulatory body will have responsibility for well integrity, safety and environmental regulation. On 11 April 2011, the Minister for Resources and Energy reaffirmed that the Commonwealth would be progressing the establishment of the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) in Commonwealth jurisdictions from 1 January 2012 by expanding the functions of NOPSA. NOPSEMA will become the regulator for all offshore petroleum activities in Commonwealth waters beyond three nautical miles from the territorial sea baseline. In addition to NOPSA's current regulatory functions, NOPSEMA will assume responsibility for environmental approvals, including Oil Spill Contingency Plans under the OPGGS Act. NOPSEMA will also regulate safety, integrity and environment plans for minerals extraction and greenhouse gas storage activities in Commonwealth waters. AMSA will work with NOPSEMA to develop agreed arrangements to review Oil Spill Contingency Plans. The procedural framework supporting the agreed arrangements will be developed by RET and AMSA in consultation with DSEWPaC. 0 0 0 A National Offshore Petroleum Titles Administrator (NOPTA) will be established within DRET to administer titles and data relating to offshore petroleum, minerals and greenhouse gas storage activities in Commonwealth waters. In addition, under this model, the States and Northern Territory will be able to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA and NOPTA for coastal waters (ie up to the three nautical mile limit). Legislative amendments to implement this institutional reform will be introduced into the Commonwealth Parliament during the Winter sitting period from May - June 2011. The reforms reflect extensive consultation with jurisdictions, industry and NOPSA and are supported by the offshore petroleum industry. In addition, the Commonwealth has expanded the functions of NOPSA under the OPGGS Act to include the non -OHS aspects of structural integrity for facilities, wells and well -related equipment in Commonwealth waters. This reform also applied an OHS duty of care to petroleum and greenhouse gas titleholders in relation to wells and well -related equipment, and improved NOPSA's inspection and investigation powers in relation to suspected breaches. The Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations2011 give affect to these amendments by providing NOPSA with regulatory responsibility for assessing WOMPs and associated well activities. 0 0 0 74 The proposal of the Productivity Commission's Research Report (Review of Regulatory Burden on the Upstream Petroleum (oil and Gas) Sector, April 2009) to establish a NOPR should be pursued at a minimum. Accepted. Refer recommendation 73. Refer recommendation 73. 75 Responsibility for well integrity should be moved Accepted. Refer recommendation 73. to NOPSA (as also proposed by the Productivity Refer recommendation 73. Commission). • • • 76 In the meantime, the Minister should: a. consider revoking the existing delegation to the Director of Energy, NT DoR providing the functions and powers of the DA under the OPGGS Act and Regulations specified in item 1 of the Schedule to that instrument (the Minister's DA powers and functions) and transferring this delegation to either NOPSA, the Commonwealth Department of Resources, Energy and Tourism (RET), or a DA from another state; b. enquire into whether the other DAs to whom he has delegated his functions and powers relating to well integrity are adequately fulfilling their roles; and c. consider amendments to the OPGGS Act to enable DAs to be given direction as to the performance of their regulatory roles. Accepted in part. a. Accepted in part Section 72(3) of the OPGGS Act provides for the ability to revoke an existing delegation of functions and powers of the Designated Authority for the Territory of Ashmore and Cartier Islands. The delegation of the Commonwealth's Designated Authority powers and functions to the Territory of Ashmore and Cartier Islands has historically been viewed as an extension to the principal Northern Territory offshore area. However the power to revoke a delegation under section 72(3) of the OPGGS Act does not extend to the functions and powers of the Northern Territory Designated Authority in relation to the Northern Territory offshore area, or any other Designated principal offshore area. The Commonwealth therefore considers that the withdrawal of the delegation for the Ashmore and Cartier Islands area would not address the full range of systemic issues identified by the Inquiry given the Northern Territory's ongoing responsibility as the Designated Authority for the Northern Territory principal offshore area. b. Accepted. The Commonwealth, through DRET, has requested all Designated Authorities (Tasmania, Western Australia, Northern Territory, Victoria, South Australia, New South Wales and Queensland) undertake a number of reviews to ensure the integrity of wells and their assessment, approvals and monitoring of offshore petroleum activities were in accord with the OPGGS Act. The Commonwealth is satisfied that the immediate deficiencies identified by the Commissioner have been adequately addressed. The Commonwealth, through DRET and Geoscience Australia, will continue to work with the NT DoR until the establishment of a national offshore petroleum regulator in 2012. All Designated Authorities have cooperated fully and provided assurances to the Commonwealth that rigorous regulatory practice are being implemented in relation to the approval and compliance monitoring of well operation activities. In addition the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011 c. Refer recommendation 73 c. Accepted Should the deficiencies identified by the Montara Commission of Inquiry not be satisfactorily addressed through the current offshore petroleum regulatory reform, consideration may be given to introducing amendments to the OPGGS Act to provide the responsible Commonwealth Minister with a new or extended 'general power of direction', as part of the Commonwealth's broader review of marine environment and petroleum legislation. The Commonwealth notes, however, that such an amendment may erode the 'co-operative' relationship model upon which the offshore petroleum regulatory regime is based and lead to other constitutional issues such as Commonwealth Minister directing a State Government agency which would erode State Government Ministerial accountability. C] 0 1�i 77 The recommendations of the Inquiry in relation to suitable ways of achieving well integrity contained in Chapter 3 be included in a guidance manual that is issued for the assistance of industry and regulators. Noted. The Commonwealth notes that the cause of the Montara incident was not a lack of industry -accepted procedures, standards and operating manuals, but failure to follow them. As such, an additional guidance manual is unnecessary. The Commonwealth notes that this recommendation is consistent with existing practice. The existing regime requires the written approval from the relevant Regulator for all permissioning documents including WOMPs, safety cases and environmental plans prior to the commencement of any offshore petroleum activity. These documents set out the processes, practices and actions that must be met by operators to ensure they meet their safety, integrity and environmental obligations. Furthermore, it is common industry practice to have a drilling operations manual covering all aspects of drilling, completion and well control operations on the rig. Chapter 5 of the Report - Arresting the Blowout considers the initial response to the incident at the Montara Wellhead Platform and the steps taken by the operator and responsible Government agencies in arresting the blowout. The chapter contains 8 of 105 recommendations. 0 0 0 Chapter 5 —Arresting the Blowout Recommendations 78 In the future, and in the interests of ensuring that all possible well control options are comprehensively pursued to exhaustion, decisions as to well control response options should be the result of collaboration between the regulator and the operator rather than leaving one party to make unilateral judgements as to the appropriateness of various well control operations. The regulator should provide transparent and contemporaneous explanations to the public of all well control options under consideration at any particular time. Noted. Refer recommendation 84. The Commonwealth notes that the Montara incident identified the need for more active emergency response engagement by Regulators and industry. Such engagement needs to be balanced to ensure both operator and Regulator independence is not compromised. In responding to the Montara incident, the Commonwealth did not rely only on the operator's decision regarding well control options. The Commonwealth received independent advice on all options for controlling the well from GA and NOPSA (who also sought advice from its international peers). Australia's offshore legislative and regulatory regime places legal obligations on operators for well control, including arresting a well blowout. The Commonwealth understands that it is accepted industry practice to report to and engage with the Regulator in the case of serious well control incidents, such as underground flow or loss of surface containment. Minor incidents not involving a breach of the well envelope are dealt with by the operator in compliance with its Well Control Manual, and reported to the Regulator in the daily drilling report. If significant deviation was required from approvals, the Regulator must be informed. The Commonwealth (through DRET and NOPSA) is progressing the Terms of Reference for the 2011 review of NOPSA's operations. The 2011 NOPSA Operational Review will focus on the legislated requirement to assess the effectiveness of NOPSA; NOPSA's engagement with operators; and NOPSA's role in responding to incidents involving the offshore petroleum industry. In addition the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The Commonwealth has also commissioned a consultancy to develop a National Legislative Compliance Framework (NLCF) to develop a consistent best practice approach to be used by regulators in their regulation of Australia's offshore petroleum industry. The NLCF will be completed in the second half of 2011. The development of an incident management and coordination framework for dealing with incidents involving the offshore petroleum industry will be led by DRET in conjunction with NOPSA and relevant stakeholders, and will be finalised by the end of 2011. • • • 79 The regulator, rather than the responsible Minister, should be given the power to direct an operator to use a particular rig for the purpose of well control operations, if appropriate in the circumstances, and the power should be used in the future if that rig is the best option available. This would necessarily involve the operator fully compensating for the use of the rig and any other associated costs. The Inquiry suggests that this power could be invoked and given effect as a condition of an operator's licence. The Commonwealth recognises the need for a more transparent communication strategy to inform stakeholders and the public and is developing an incident management and coordination framework based on proven frameworks such as the National Counter -Terrorism Plan. This framework will be coordinated by the central body to be established pursuant to recommendation 84 and will include a clearly defined, transparent communication strategy for incident response. Noted. The Commonwealth notes that the OPGGS Act provides the Designated Authorities, as the appropriate Regulator, with the power to issue directions (refer Part 6.2 OPGGS Act). In relation to the Montara incident, the Commonwealth Minister for Resources and Energy is the Designated Authority for the Territory of Ashmore Cartier Islands offshore area and was therefore the appropriate decision -maker. In respect of compensation and associated costs, the Commonwealth does not intervene in commercial negotiations between operators. The Commonwealth is seeking further advice on the utility of such directions powers for use in these circumstances. This advice will be taken into consideration in the development of the Commonwealth's broader incident management and coordination framework which will be completed by the end of 2011. In addition, the industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, is working to formalise assistance arrangements for the offshore petroleum industry and facilitate the sharing of resources and equipment through a memorandum of understanding around mutual aid. Industry has established a Drilling Steering Committee and an Emergency Management Steering Committee to identify and implement cross -industry learnings from the Montara and Gulf of Mexico incidents. • C] • 80 The regulatory regime should also impose an obligation on an operator to ascertain the availability, and provide details to the regulator, of any potential relief well rigs, prior to the commencement of drilling operations (including prior to each phase of a drilling operation where applicable). Noted. The identification of a relief well rig is an operational matter and one that the Commonwealth considers should form part of an operator's risk management strategy, which is part of the process for seeking approval to undertake an offshore petroleum activity. The Commonwealth considers that the risk management strategy should be identified and considered as part of the process for seeking approval to undertake an offshore petroleum activity. However, the Commonwealth does not consider that this requirement needs to be formalised in the regulatory regime. The offshore petroleum industry has performed its own safety checks and reviews of its processes and procedures including the consideration of well plans, drilling processes, blow-out contingency plans, testing frequencies, training regimes for personnel and emergency response capabilities. The petroleum industry through AMOSC has also reviewed its equipment stockpile and capacity to respond to an incident. In addition, the industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, is working to formalise assistance arrangements for the offshore petroleum industry and facilitate the sharing of resources and equipment through a memorandum of understanding around mutual aid. The Designated Authorities have been requested to provide clarification to all operators that the risk management strategy in force during an approved drilling program must include identification by the operator of suitable rigs within the area that could be utilised in the event of an emergency. • • • 81 NOPSA develop a policy of engagement with operators so as to enable experts (including safety experts) to canvas all available options for well control in the event of a blowout. Accepted. The Commonwealth notes that the Montara incident identified the need for more active emergency response engagement by Regulators and industry. Such engagement needs to be balanced to ensure both operator responsibility and Regulator independence is not compromised. The Commonwealth (through DRET and NOPSA) is progressing the Terms of Reference for the 2011 review of NOPSA's operations. The 2011 NOPSA Operational Review will focus on the legislated requirement to assess the effectiveness of NOPSA; NOPSA's engagement with operators; and NOPSA's role in responding to incidents involving the offshore petroleum industry. Furthermore, the Commonwealth has issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The development of an incident management and coordination framework for dealing with incidents involving the offshore petroleum industry will be led by DRET in conjunction with NOPSA and relevant stakeholders, and will be finalised by the end of 2011. • • • 82 The Inquiry also supports Bills and Agostini's recommendation: '...in relation to safety case development and compliance overall, that NOPSA revise its approach to interacting with operators prior to the safety case assessment process and subsequently direct more resources into its advisory functions. We further recommend that NOPSA develop and implement a formal plan for supporting and guiding each operator prior to safety case acceptance, as well as for ongoing compliance with that safety case, recognising the unique experience, capabilities and assessed risk of that operator. Each plan needs to include advice, education and liaison meetings with the operators. The plan needs to be continuously reviewed and reassessed based on the latest information, including the interaction with the operator'. Accepted. The Commonwealth considers that this recommendation is consistent with recommendation 3 of the Offshore Petroleum Safety Regulatory Inquiry (NOPSA Report). Consistent with the Commonwealth's response to recommendation 3 of the NOPSA Report, the Commonwealth notes that NOPSA has commenced work to address these issues and will continue to be responsible for improving interaction and consultation with stakeholders on this. The Commonwealth proposes that, as part of the 2011 NOPSA review, a review of policy matters around the safety case framework (including development, content requirements and implementation) be included. The Commonwealth (through DRET and NOPSA) is progressing the Terms of Reference for the 2011 review of NOPSA's operations. The 2011 NOPSA Operational Review will focus on the legislated requirement to assess the effectiveness of NOPSA; NOPSA's engagement with operators; and NOPSA's role in responding to incidents involving the offshore petroleum industry. Furthermore, the Commonwealth has issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The CEO of NOPSA will be responsible for improving the interaction between NOPSA and its stakeholders. The Commonwealth will work with the CEO to determine the process for the 2011 review and will consult with stakeholders to determine the most appropriate means of ensuring improvements in the development, implementation and compliance with the safety case requirement. • • 83 The regulator should pre -assess and review in a generic sense, and in conjunction with the offshore petroleum industry, available options for well control in the event of a blowout. Being 'match fit' in this sense will enable a quicker and more effective response in terms of safety assessment, and will ensure that expectations of both operator and regulator are more readily aligned. Accepted in principle. The Commonwealth agrees that the Montara incident identified the need for more active emergency response engagement by regulators and industry. Such engagement needs to be balanced to ensure both operator responsibility and regulator independence is not compromised. The Commonwealth (through DRET and NOPSA) is progressing the Terms of Reference for the 2011 review of NOPSA's operations. The 2011 NOPSA Operational Review will focus on the legislated requirement to assess the effectiveness of NOPSA; NOPSA's engagement with operators; and NOPSA's role in responding to incidents involving the offshore petroleum industry. Furthermore, the Commonwealth has issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912 and relevant international treaties. As part of this process, legal consideration will be given to the engagement between the regulator(s) and operator(s) in responding to a well control incident. • • • 84 In any future similar blowout or offshore emergency situation, the Minister appoint (through either a NOPR or the relevant Department) a senior public servant to establish and oversight a central coordinating body that will facilitate interaction between regulators, industry, AMSA and the owner/operator. Primary responsibility for stopping a blowout should remain with the owner/ operator but should be subject to direction from the central coordinating body in consultation with stakeholders (including the owner/operator). Accepted. Refer recommendation 94. The Commonwealth accepts the recommendation for the establishment of a central coordinating body in responding to a future offshore petroleum incident. This role will be fulfilled by DRET. The incident response will be supported by a framework for incident management and coordination. This framework will clearly define the responsibilities of each agency, including procedures and accountabilities for the management of future oil spill incidents. The Commonwealth notes that the purpose of the central coordinating body in responding to a future offshore petroleum incident will be to facilitate interaction and communication between stakeholders and with the public. This body will not assume any aspect of the Combat Agency role as designated under the National Plan. Australia's offshore legislative and regulatory regime places legal obligations on operators for well control, including arresting a well blowout. The Commonwealth (through DRET and NOPSA) is progressing the Terms of Reference for the 2011 review of NOPSA's operations. The 2011 NOPSA Operational Review will focus on the legislated requirement to assess the effectiveness of NOPSA; NOPSA's engagement with operators; and NOPSA's role in responding to incidents involving the offshore petroleum industry. Furthermore, the Commonwealth has issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The development of an incident management and coordination framework for dealing with incidents involving the offshore petroleum industry will be led by DRET in conjunction with NOPSA and relevant stakeholders, and will be finalised by the end of 2011. f�J • Is 85 The body established to undertake a central coordination and facilitation role in the event of any future blowout in Commonwealth waters should undertake to make all relevant information publically available from one, authoritative and easy to access source. Accepted. Refer recommendations 84 and 94. The Commonwealth agrees that the purpose of the central coordinating body will be to facilitate interaction and communication between stakeholders and with the public. This role will be fulfilled by DRET. In this regard, it will also have responsibility for communicating to the public on all elements of the incident. In fulfilling this function, DRET will be able to request, and have access to, specialised capability from other agencies to provide it with the necessary resources, such as satellite imagery, during the course of an incident response. This will also ensure that that adequate and relevant information is disseminated to the public throughout the course of the incident response. In advancing the incident management and coordination framework, which will be a key element of the operating platform for the central coordinating body, the Commonwealth will work to develop the capacity where gaps are identified in respect of specialised infrastructure or training. The development of an incident management and coordination framework for dealing with incidents involving the offshore petroleum industry will be led by DRET in conjunction with NOPSA and relevant stakeholders, and will be finalised by the end of 2011. Chapter 6 of the Report - Environmental Response considers the protection and management of the marine environment and remediation of the area both during and post the Montara incident. The chapter contains 15 of 105 recommendations. 0 9 0 Chapter 6 — Recommendations 86 Environmental Response The National Plan should be reviewed to clarify the arrangements to apply in Commonwealth waters regarding key roles and responsibilities, including in relation to the ESC, in the event of an oil spill. This should also address any necessary training required. Accepted. The Commonwealth agrees that the responsibilities of stakeholders under the National Plan need to be clarified, noting that the National Plan is not a legally enforceable instrument. The comprehensive assessment of the National Plan currently being conducted by AMSA in consultation with the National Plan stakeholders will define the roles and responsibilities specific to Commonwealth agencies within the National Plan. This will include having clearer arrangements for both operational and scientific monitoring. The Commonwealth is progressing the development of a response plan for the Commonwealth marine area as a subset of the National Plan. Such a plan would specify responsibilities of each Commonwealth department and agency in relation to the oil spill response and specifically address the matter of the ESC. There are currently arrangements in place with states and territories that provide for the utilisation of operational capability from these jurisdictions in responding to incidents in Commonwealth waters. All appropriate training in respect of the National Plan is and will continue be provided by AMSA and the relevant National Plan stakeholders. Training for offshore petroleum personnel is to be provided on a cost recovery basis. Consistent with arrangements under the National Plan, AMSA established an Incident Analysis Team (IAT) to review the response to the Montara Wellhead Platform. The purpose of the review was to provide strategic recommendations for improvements to the National Plan arrangements and identify lessons learned to improve future major incident responses. The March 2010 Report of the IAT identified eight recommendations which are being progressed. A comprehensive assessment of the National Plan is underway and will be finalised by the end of 2011. The purpose of this assessment is to determine if current arrangements are adequate to provide an effective response to marine casualties and pollution of the sea by oil and hazardous noxious substances and, where deficiencies are identified, make recommendations to rectify them. The assessment will provide analysis on any gaps in response preparedness and capabilities and provide recommendations for improvement to the current regime, and will also consider succession planning and training arrangements under the National Plan. 87 DEWHA should participate in training programs Accepted. The Commonwealth notes that, since the Montara and exercises relevant to an oil spill in the marine incident, in advance of a decision regarding environment. responsibilities under the National Plan, the Department of Sustainability, Environment, Water, Population and Communities (DSEWPaC) (formerly DEWHA) has undertaken to develop staff capability through appropriate training and participation in courses. Further implementation of this recommendation will be informed by the outcomes of the comprehensive assessment of the National Plan which is being coordinated by AMSA and the National Plan stakeholders and will be finalised by the end of 2011. • • 88 The National Plan should be revised to ensure that it fully comprehends environmental matters and that it recognises the importance of the prompt implementation of Scientific Monitoring to facilitate the assessment of the environmental impacts of an incident. Accepted. The Commonwealth is progressing National Contingency Plans as a part of the comprehensive assessment of the National Plan to Combat Pollution of the Sea by Oil and Other Noxious and Hazardous Substances that is being undertaken by AMSA in consultation with National Plan stakeholders. The assessment of National Contingency Plans will develop a clear plan and delivery mechanism for the provision of environmental advice, preparation and maintenance of Net Environmental Benefit Analysis, wildlife response and monitoring for a spill where the Commonwealth is the lead agency (refer recommendation 3 of the IAT Report). It will also include a clear statement on sourcing Commonwealth environmental and scientific advice. Industry and other stakeholders have an opportunity to provide input on the most appropriate mechanism for seeking expert advice through the National Contingency Plan assessment process. Consistent with arrangements under the National Plan, AMSA established an IAT to review the response to the Montara Wellhead Platform. The purpose of the review was to provide strategic recommendations for improvements to the National Plan arrangements and identify lessons learned to improve future major incident responses. The March 2010 Report of the IAT identified eight recommendations which are being progressed. The comprehensive assessment of the National Plan is underway and will be finalised by the end of 2011. The purpose of this assessment is to determine if current arrangements are adequate to provide an effective response to marine casualties and pollution of the sea by oil and hazardous noxious substances and, where deficiencies are identified, make recommendations to rectify them. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. The Commonwealth will also implement changes through appropriate legislative instruments to ensure the prompt implementation of Scientific Monitoring following an incident. • • • In addition, the industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed Oil Spill Preparedness and Response Improvement Strategies for the upstream petroleum industry which includes response monitoring (operational and scientific). • • • 89 Procedures for the approval of development projects should ensure that conditions of approval are comprehensive and clearly set out the obligations of their proponents in relation to environmental matters (including expected monitoring and remediation obligations). Accepted. The Commonwealth agrees that the requirements for Scientific Monitoring and environmental remediation in the event of an incident should be included as a condition of approval under the EPBC Act for future petroleum activities. Such a condition will reaffirm the 'polluter pays' principle in that the operator will be responsible for covering the costs of Scientific Monitoring and/or environmental remediation in the event of an incident. Mechanisms for requiring Scientific Monitoring and remediation under the OPGGS Act will also be investigated. The Commonwealth notes that Part 6.4 of the OPGGS Act (Restoration of the Environment) provides the Designated Authority with the authority to issue a direction to an operator in respect of environmental remediation. Under the EPBC Act, all new approved offshore production facilities will include requirements to obtain sufficient baseline information to enable an assessment of any impacts and implement an agreed monitoring program in the event of a spill. The Commonwealth will implement changes through appropriate legislative instruments to ensure the prompt implementation of Scientific Monitoring during an incident. The implementation of this recommendation as it applies to approvals under the OPGGS Act and the EPBC Act will be led by DRET and DSEWPaC respectively, on an ongoing basis. The Long Term Scientific Monitoring Programme, as agreed by PTTEP AA, will continue to be managed by DSEWPaC. Lessons learned from the implementation of this plan will inform the future development of "off the shelf' monitoring plans. In addition, the industry, through the Australian Petroleum Production and Exploration Association (APPEA), the peak industry body representing Australia's offshore oil and gas industry, has developed Oil Spill Preparedness and Response Improvement Strategies for the upstream petroleum industry which includes response monitoring (operational and scientific). Industry has established Emergency Management Steering Committee to identify and implement cross -industry learnings from the Montara and Gulf of Mexico incidents. • • • 90 DEWHA, in concert with AMSA and with expert input, should develop 'off the shelf monitoring programs that can be speedily implemented following incidents in Commonwealth waters. In this context, the utility of the current Scientific Monitoring program should be peer reviewed to inform future policy. Accepted. Refer recommendation 97. The Commonwealth agrees that a suite of "off the shelf' monitoring programs to cater for the different environments in which an oil spill could occur, for example, the Bass Strait or in proximity to sensitive marine environments such as the Ningaloo Reef or the Ashmore Reef and Cartier Islands area, is required and is developing such programs. A requirement to implement these monitoring programs in the event of a spill will be reflected in the conditions of approval for petroleum activity. The review of the PTTEP AA Long Term Scientific Monitoring Program will inform the development of the "off the shelf' monitoring programs. Under the EPBC Act, all new approved offshore production facilities will include requirements to obtain sufficient baseline information to enable an assessment of any impacts and implement an agreed monitoring program in the event of a spill resulting from offshore petroleum activity(ies). The development of the "off the shelf' monitoring programs will be led by the primary regulator of the operation of offshore production facilities, in consultation with DSEWPaC on matters of National Environmental Significance as defined under the EPBC Act. A review of the Montara Long Term Scientific Monitoring Program will be undertaken for the specific purpose of informing the development of "off the shelf' monitoring programs for use in future incidents. • 91 The funding arrangements that support the National Plan should be reviewed to ensure that the costs associated with both preparedness and response capability are equitably shared between the shipping and offshore petroleum industries. Accepted. The Commonwealth accepts that the Montara incident highlighted the need to address the funding arrangements supporting the National Plan. The Commonwealth supports the 'polluter pays' principle and in accepting this recommendation the Commonwealth will establish a framework that provides equitable cost -sharing arrangements between the shipping and the offshore petroleum industry as it relates to preparedness and response capability to a future offshore petroleum incident. As a part of its broader legislative review of the marine environment and petroleum legislation, the Commonwealth will identify and implement an ability to enforce the 'polluter pays' principle in the offshore petroleum industry. A discussion paper, Montara Commission ofInquiry - Equitable funding between the shipping and offshore petroleum industries, has been provided to key stakeholders. AMSA and DRET will meet with these stakeholders to further discuss and test the principle and assumptions identified in the discussion paper. This is an important element in identifying a preferred option for equitable cost -sharing arrangements between the offshore petroleum and shipping industries on oil spill preparedness and response capability under the National Plan. A comprehensive assessment of the National Plan is currently being undertaken by AMSA in consultation with the National Plan stakeholders. The assessment will be finalised by the end of 2011. The assessment will specifically consider the adequacy and appropriateness of funding mechanisms and the efficiency of cost recovery arrangements in the delivery of the required outcomes of the National Plan. The Commonwealth, in consultation with the offshore petroleum industry, is undertaking a detailed analysis of cost recovery arrangements in regards to oil spill preparedness and response capability. This will inform future changes to the funding arrangements under the National Plan, specifically for the offshore petroleum industry. • The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will identify the most appropriate mechanisms for enforcing the Commonwealth's 'polluter pays' principle and will ensure consistency and prevent duplication. It will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 7912 and relevant international treaties. • • 92 The National Plan should specify that the cost of responding to an oil spill, or other damage to the offshore marine environment, will be totally met by the owner/operator. This would be consistent with the Inquiry's recommendation for legislative changes to the regulatory framework concerning owner/operators meeting the cost of monitoring and remediation of environmental damage. Accepted. Refer recommendation 88. The Commonwealth supports the 'polluter pays' principle and in accepting this recommendation the Commonwealth will establish a framework that provides equitable cost -sharing arrangements between the shipping and the offshore petroleum industry as it relates to responding to a future offshore petroleum incident. The Commonwealth notes that currently there is no legislative requirement to recover costs incurred from an offshore petroleum activity incident response under the National Plan, but understands that the offshore petroleum industry currently contributes a proportion of the National Plan funding through LNG and crude tanker movements in addition to the direct funding of AMOSC. The Commonwealth also notes that the OPGGS Act contains requirements for petroleum titleholders to have adequate insurance cover (refer s571) to meet the costs of remediation of environmental damage. Further, Part 6.4 of the OPGGS Act provides the authority to give remediation directions to titleholders in relation to the restoration of the environment. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. It will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912 and relevant international treaties. This process will identify and implement an ability to legislatively enforce the 'polluter pays' principle for the offshore petroleum industry, including prompt implementation of Scientific Monitoring following an offshore petroleum incident, and will ensure consistency and prevent duplication. • 11 93 The National Plan should be reviewed: a. to ensure that it adequately addresses the risks associated with offshore oil and gas exploration; b. to revisit the underlying risk assessment undertaken to inform capacity and preparedness under the National Plan; c. to ensure that response operations can be coordinated effectively with state and territory arrangements where a response requires operations across Commonwealth and state or territory borders; and d. to explore the state of readiness of equipment and resources in the context of the future expansion of the petroleum industry. This should be undertaken by AMSA in consultation with AMOSC. Accepted. The Commonwealth is undertaking a comprehensive assessment of the National Plan. It will address items (a), (b), (c) and (d) and will define the roles and responsibilities specific to Commonwealth agencies within the National Plan. The Commonwealth agrees that contingency planning needs to be based on risk assessments that take into account probability and consequence. The Commonwealth notes that Australia has arrangements in place to obtain international assistance in the event of larger scale incidents than Montara. A risk assessment addressing issues such as the current level of risk of pollution of the sea, coastline and ports of EEZ and offshore territories by oil from ships, offshore installations (fixed and floating) and drilling rigs, with regard to the location, is being undertaken as part of the review of the National Plan. The risk assessment will inform future contingency planning in regard to the capacity both in the nine AMSA Tier two/three stockpiles around the Australian coastline and the AMOSC stockpile in Geelong. Resourcing implications arising from this risk assessment will be identified and addressed accordingly. This may also include a minimum requirement for response capacity and capability to be identified in contingency plans and implemented and resourced by the offshore petroleum industry in the event of an incident. A comprehensive Review of the National Plan has commenced and is being coordinated by AMSA in consultation with the National Plan stakeholders. The Review is to be finalised by the end of 2011. The purpose of the Review, amongst other matters, is to determine if current arrangements are adequate to provide an effective response to marine casualties and pollution of the sea by oil and hazardous noxious substances and, where deficiencies are identified, make recommendations to rectify them. The Review is considering the adequacy of the Inter - Governmental Agreements and the existing domestic legal, regulatory, governance and procedural regime that applies to the National Plan. It is also considering the effectiveness of current functions and resourcing levels to deliver on National Plan outputs and services, and the appropriateness of current hardware and equipment holdings and locations. C] 0 �J 94 Procedures and accountabilities should be established to ensure, in the event of a future incident, that: a. there is adequate monitoring of the volume of oil spilt and the spread of the oil (both surface and sub -surface dispersed oil); and b. information about the volume and spread of the oil is made available to the public through regular updates. Accepted. Refer recommendation 84. The Commonwealth is progressing the incident management and coordination that will provide clearly defined responsibilities for agencies, including procedures and accountabilities for the management of future oil spill incidents. In responding to a future offshore petroleum incident, the Commonwealth has identified DRET as the central coordinating body. In fulfilling this function, DRET should be able to request, and have access to, specialised capability from other agencies to provide it with the necessary resources, such as satellite imagery, during the course of the response. This will assist in ensuring there is adequate monitoring of and information dissemination about the oil spill. Where gaps are identified in respect of specialised infrastructure or training, the Commonwealth will work to develop this capacity. a. Accepted The provision of adequate sub -surface monitoring for oil spill response is specialised and requires infrastructure (including fluorometry and sampling equipment) and trained personnel in readiness for an incident. In respect of the Montara incident, there was never sufficient information to estimate the oil flow rate with a high degree of accuracy. This issue was also identified during the Gulf of Mexico incident where five different methodologies were being used at any one time, and it was impossible for the oil flow rate to be accurately determined. The development of the offshore petroleum incident management and coordination framework for dealing with incidents involving the offshore petroleum industry will be led DRET, in conjunction with NOPSA and relevant stakeholders, and will be finalised by the end of 2011. The framework will clearly define the role of the central coordinating body, in having responsibility for the management and communication of incident responses, and the role of the Combat Agency, as having operational responsibility under the National Plan for the incident response. The development of an improved sub -surface monitoring capability for oil spill responses will be coordinated by AMSA on an ongoing basis. The outcomes of the Review of the National Plan in relation to the adequacy and appropriateness of funding mechanisms and the efficiency of cost recovery arrangements in the delivery of the National Plan will be considered in the implementation of this recommendation. 0 0 9 b. Accepted Refer recommendation 84. The Commonwealth proposes that the purpose of the central coordinating body will be to facilitate interaction and communication between stakeholders and with the public. In this regard, it will have responsibility for informing the public about the volume and extent of an oil spill. • • • 95 The regulatory framework should provide that in respect of all activities in Commonwealth waters: a. there are powers to require companies involved in an incident causing significant environmental damage to undertake actions to remediate the damage to a standard determined by the regulatory authorities; b. the nature of the Scientific Monitoring and the remediation required should be determined by environmental regulatory agencies rather than the companies involved; c. the costs of all Scientific Monitoring and remediation should be fully borne by the companies involved, whether the remediation is undertaken by the companies or another party to the standard determined by the regulatory authorities; and d. penalties should be payable for pollution on a no fault basis. The EPBC Act should be amended to include the powers in a, b, c and d above. These powers should be applicable to both prospective and existing operations in Commonwealth waters. Accepted in principle. The Commonwealth supports the 'polluter pays' principle and will establish a framework that provides equitable cost -sharing arrangements between the shipping and the offshore petroleum industry as it relates to responding to a future offshore petroleum incident. Mechanisms for requiring companies to bear the cost of monitoring to identify environmental damage and subsequent remediation activities, as identified by the relevant regulatory agency, will be investigated through the legislative review being led by DRET. This review will identify the appropriate legislation and/or regulations which could most effectively take account of this recommendation. This review will include consideration of possible amendments to the EPBC Act. Under the OPGGS Act there are existing powers, including the authority in Part 6.4 of the OPGGS Act (Restoration of the Environment), which allows the Regulator give remedial directions to titleholders in relation to the restoration of the environment. The Commonwealth supports the need for overarching penalty provisions to be applied to the offshore petroleum industry. The Commonwealth's review of the legislative framework will consider the appropriate mechanisms for implementing these penalty provisions for the offshore marine environment, including a broader range of compliance tools such as the ability to impose a civil fine or prohibition notice as well as a general contravention offence following the causing of serious or material harm to a protected matter or a breach of approval conditions. Penalty provisions in respect of the OHS legislative regime for the offshore petroleum industry are also being considered. Since the Montara incident, the Commonwealth has included requirements for Scientific Monitoring and environmental remediation in the event of an incident as a condition of approval under the EPBC Act for petroleum activities. This condition reaffirms the 'polluter pays' principle in that the operator will be responsible for covering the costs of Scientific Monitoring and/or environmental remediation in the event of an incident. The Commonwealth is considering amending the OPGGS Act to provide the power to impose a civil penalty regime. This process will also consider increasing some or all of the existing penalties. This process will be completed during the second half of 2011, with any legislative amendments required introduced as soon as they can be accommodated within the legislative timetable. The implementation of this recommendation will be further informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. It will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. This process will identify and implement an ability to legislatively enforce the 'polluter pays' principle for all activities in Commonwealth waters, including prompt implementation of Scientific Monitoring following an offshore petroleum incident, and will ensure consistency and prevent duplication. • • is 96 The obligation of companies involved in an incident to meet the full costs of monitoring and remediation should be made a condition of approval of proposals under the EPBC Act and OPGGS Act. Suitable arrangements (insurance or otherwise) need to be in place to ensure that companies have this capacity. Accepted. Refer recommendation 89. The Commonwealth supports the 'polluter pays' principle and in accepting this recommendation the Commonwealth will establish a framework that provides equitable cost -sharing arrangements between the shipping and the offshore petroleum industry as it relates to responding to a future offshore petroleum incident. The Commonwealth agrees that conditions of approval should clearly set out the proponent's obligations in relation to environment matters. The legislative review will consider the most appropriate legislative mechanisms for addressing environmental matters, including incorporating the 'polluter pays' principle in Australia's legislative framework and requiring monitoring and remediation in the event of an incident. Mechanisms for requiring Scientific Monitoring and remediation will be investigated through the legislative review being led by DRET. The Commonwealth notes that Part 6.4 of the OPGGS Act (Restoration of the Environment) provides the Designated Authority with the authority to issue a direction to an operator in respect of environmental remediation. The Commonwealth also notes that insurance is a requirement under the OPGGS Act. Since the Montara incident, the Commonwealth has including requirements for Scientific Monitoring and environmental remediation as a condition of approval under the EPBC Act for petroleum activities; however the Commonwealth notes that not all petroleum activities are regulated by the EPBC Act. Since the Montara incident, the Commonwealth has included requirements for Scientific Monitoring and environmental remediation in the event of an incident as a condition of approval under the EPBC Act for petroleum activities. This condition reaffirms the 'polluter pays' principle in that the operator will be responsible for covering the costs of Scientific Monitoring and/or environmental remediation in the event of an incident. The implementation of this recommendation will be further informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. It will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912and relevant international treaties. This process will identify and implement an ability to legislatively enforce the 'polluter pays' principle for the offshore petroleum industry, including prompt implementation of Scientific Monitoring following an offshore petroleum incident, and will ensure consistency and prevent duplication. Furthermore, the Commonwealth, in conjunction with the offshore petroleum industry, will examine the legislative arrangements concerning insurance to ensure cost recovery arrangements following oil spills are effective. This review will recommend any necessary improvements. • C� C J 97 Environment plans and OSCPs should be made publicly available as a condition of approval of proposals under the OPGGS Act, and should clearly set out Scientific Monitoring requirements in the event of an oil spill. Accepted. Refer recommendation 90. The Commonwealth, in consultation with the offshore petroleum industry, is considering whether Oil Spill Contingency Plans can be provided to the public without commercial prejudice to the operator. The Commonwealth notes that environmental plans are very detailed. Under the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009, a summary of an operator's environmental plan is made publicly available. The Commonwealth agrees that an operator should be required to undertake Scientific Monitoring in the event of an incident and this will be considered as part of the legislative review being led by DRET. Any conditions on approval relating to Scientific Monitoring in the event of a spill will need to be informed by the existing level and type of monitoring that is undertaken by the offshore petroleum industry in the course of their petroleum operations. The requirement for scientific monitoring and environmental remediation in the event of an incident has been included in EPBC Act approval conditions for oil and gas developments since the Montara incident. Since the Montara incident, it has become a standard requirement for all proponents to publish all management and scientific plans required by EPBC Act approval conditions and to publish the reports of performance against those plans. In respect of the publication of Oil Spill Contingency Plans, the implementation of this recommendation will be led by DRET and will be completed within the second half of 2011. The imposition of conditions on petroleum activity will be coordinated by DRET on an ongoing basis. Furthermore, the establishment of National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), through the expansion of NOPSA, will result in NOPSEMA becoming the regulator for all offshore petroleum activities in Commonwealth waters beyond three nautical miles from the territorial sea baseline. Under this model, the States and Northern Territory will be able to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA for coastal waters (ie up to the three nautical mile limit). In addition to NOPSA's current regulatory functions, NOPSEMA will also assume responsibility for environmental approvals, including Oil Spill Contingency Plans under the OPGGS Act. NOPSEMA will regulate safety, integrity and environment plans, including Oil Spill Contingency Plans, for minerals 98 The Government should examine the scope for a single environment plan to meet the regulatory requirements of both the OPGGS Act and the EPBC Act. This could possibly be achieved by way of bilateral agreements and accreditation arrangements and/or legislative amendment. Accepted. The Commonwealth considers that this recommendation is consistent with the Independent Review of the Environment Protection and Biodiversity Conservation Act 1999, undertaken by Dr Allan Hawke AC in 2009 (the Hawke Review). extraction and greenhouse gas storage activities in Commonwealth waters. AMSA will work with NOPSEMA to develop agreed arrangements to review Oil Spill Contingency Plans. The procedural framework supporting the agreed arrangements will be developed by REf and AMSA in consultation with DSEWPaC. The Commonwealth has also issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The implementation of this recommendation will be determined by the Commonwealth's response to the Hawke Review. • • 99 OSCPs should be endorsed by AMSA prior to regulatory approval to ensure that they align with the National Plan. Once field operations commence, the capability of operators should be assessed against their plans, and exercises conducted to ensure the plans remain effective. Accepted. The Commonwealth agrees that an opportunity exists for AMSA to be consulted as part of the assessment of an environmental plan under the OPGGS Act. Through this process of consultation, AMSA will have regard to the adequacy of resources available to mitigate pollution and ensure consistency with the National Plan. The Commonwealth will strengthen current procedures for consultation in relation to approvals for offshore petroleum activity to ensure comprehensive consultation on Oil Spill Contingency Plans is being implemented between DRET, AMSA and DSEWPaC. The Commonwealth recognises that the establishment of a more comprehensive consultation and assessment process in relation to Oil Spill Contingency Plans may result in additional resourcing costs for Commonwealth agencies, and that such costs will need to be recovered from the offshore petroleum industry. The cost recovery arrangements will be considered as part of the Commonwealth's broader review of the marine environment and petroleum legislation. In relation to the assessment of operator capability, the Commonwealth notes that Australia's offshore petroleum legislative framework places obligations on operators to demonstrate to the regulator how they intend to effectively acquit their responsibilities under the OPGGS Act, which includes environmental requirements. The Commonwealth is working to strengthen the effectiveness of the compliance and monitoring framework through mechanisms such as the proposed penalty provisions identified in recommendation 95(d) On 11 April 2011, the Minister for Resources and Energy reaffirmed that the Commonwealth would be progressing the establishment of the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) from 1 January 2012 by expanding the functions of NOPTA. Upon establishment, NOPSEMA will become the regulator for all offshore petroleum activities in Commonwealth waters beyond three nautical miles from the territorial sea baseline. In addition to NOPSA's current regulatory functions, NOPSEMA will assume responsibility for environmental approvals, including Oil Spill Contingency Plans under the OPGGS Act. NOPSEMA will also regulate safety, integrity and environment plans for minerals extraction and greenhouse gas storage activities in Commonwealth waters. AMSA will work with NOPSEMA to develop agreed arrangements to review Oil Spill Contingency Plans. The procedural framework supporting the agreed arrangements will be developed by RET and AMSA in consultation with DSEWPaC. A National Offshore Petroleum Titles Administrator (NOPTA) will be established within DRET to administer titles and data relating to offshore petroleum, minerals and greenhouse gas storage activities in Commonwealth waters. Under this model, the States and Northern Territory will be able to confer powers for the regulation of offshore petroleum activities under their respective legislation to NOPSEMA and NOPTA for coastal waters (ie up to the three nautical mile limit). 0 0 0 and through the development of consistent and best practice approaches to the administration of offshore petroleum regulation. This framework will be further enhanced by the establishment of a single national regulator for offshore petroleum, mineral and greenhouse gas storage activities. The Commonwealth has announced its intention to have the single national regulator in place by January 2012. Legislative amendments to implement this institutional reform will be introduced into the Commonwealth Parliament during the Winter sitting period from May — June 2011. The reforms reflect extensive consultation with jurisdictions, industry and NOPSA and are supported by the offshore petroleum industry The Commonwealth has also issued a Statement of Expectations to NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. The implementation of this recommendation will be informed by a broader consideration of all Commonwealth legislation applicable to the marine environment and offshore petroleum legislation. It will address gaps or outstanding issues in the offshore petroleum legislative regime as identified through the Montara Commission of Inquiry and other relevant reports as appropriate. This process will also have regard to the OPGGS Act and associated regulations; the EPBC Act and associated Acts; the Protection of the Sea Acts, the Navigation Act 1912 and relevant international treaties. As part of the legislative review, the Commonwealth is developing guidelines for the petroleum industry regarding the requirements for Oil Spill Contingency Plans, and also around the information requirements for offshore drilling referrals under the EPBC Act. M Arrangements should be developed to minimise duplication between the EPBC Act and the OPGSS Act Environment Regulation. Accepted. The Commonwealth considers that this recommendation is consistent with the Hawke Review and the Productivity Commission Review of Regulatory Burden on the Upstream Petroleum (Oil and Gas) Sector (the PC Review), undertaken in 2009. The Hawke Review noted that streamlining should maximise regulatory efficiency while maintaining strong environmental safeguards. The PC Review noted the merit in retaining an independent decision maker Of last resort, particularly in relation to matters of potential national environmental significance. In May 2011, the Commonwealth released its response to the PC Review. The Commonwealth's response notes a number of initiatives progressed to date aimed at streamlining requirements between the EPBC Act and the OPGGS Act. This includes progressing strategic assessments under the EPBC Act and maintaining bilateral agreements with state and territory jurisdictions. Further implementation of this recommendation will be determined by the Commonwealth's response to the Hawke Review. Chapter 7 of the Report — Review of PTTEP AA's Permit and Licence at Montara and Other Matters considers the oil field practices of PTTEP AA, as the operator of the Montara Wellhead Platform, and provides views in respect of its interaction with the regulators and the Montara Commission of Inquiry. The chapter contains 5 of 105 recommendations. • Chapter 7 — Review Of PTTEP AA's Permit and Licence at Montara and Other Matters Recommendations in 102 The Minister should, as the JA for the offshore area of the Territory of Ashmore and Cartier Islands, undertake a review of PTTEP AA's permit and licence to operate at the Montara Oilfield. For the purposes of that review, the Minister should issue a 'show cause' notice to PTTEP AA under s 276 of the OPGGS Act. Accepted. Noted. The Commissioner noted (page 11 of his Report) that shortly prior to the finalisation of his Report, PTTEP AA provided him with the Montora Action Plan which was comprehensive and impressive, and effectively addressed the shortcomings in PTTEP AA's operations identified by the Commissioner. The Minister has moved to address the Commissioner's findings through ongoing interaction with PTTEP AA and by directing that an independent assessment of the Montara Action Plan be undertaken. The Independent Assessment will provide advice to the Minister on whether the Action Plan, once implemented, will ensure that PTTEP AA's operational and procedural measures meet industry best practice standards. It will also, identify whether PTTEP AA has the organisational culture and capability to properly implement the Action Plan. Evidence that PTTEP AA's Montara Action Plan is implementing industry best In September 2010, the Commonwealth commissioned an independent assessment through two separate, complementary, consultancies: an assessment of the technical adequacy of the Montara Action Plan as against industry/leading practice standards; and a governance review of PTTEP AA's organisational structures, policies and procedures to ensure the effective implementation of the MontaraAction Plan and continuous improvement by PTTEP AA in respect of operational and corporate functions. These consultancies also identified leading practice actions that will be shared with the offshore petroleum industry more generally. The Independent Review concluded that the Montara Action Plan effectively responds to the issues identified by the Montara Commission of Inquiry and sets PTTEP AA on the path to achieving industry best practice standards for both good oil field practice and good governance. In releasing the Independent Review report on 4 February 2011, the Minister for Resources and Energy announced that he would not be issuing a 'show cause' notice to the company that could lead to the cancellation of its petroleum titles. • practice and its ongoing commitment to operational improvement will be central to the consideration of whether a 'show cause' notice is issued, as it demonstrates measures to remove or prevent recurrence of the grounds for cancellation. The Independent Assessment of the Montara Action Plan does not prevent the Minister from taking further action. This decision was conditional on PTTEP and PTTEP AA entering into a binding Deed of Agreement with the Commonwealth in which it was agreed that the Montara Action Plan will be implemented in full in respect of all of PTTEP Australian's operations, and that this implementation will be subject to an 18 month monitoring program undertaken by independent experts appointed by DRET. The Deed of Agreement was signed on 22 February 2011. It formalises the implementation of the Montara Action Plan and the arrangements for the 18 month monitoring program, incorporating additional actions identified by the Independent Review of the Montara Action Plan. On 16 March 2011, Noetic Solutions Pty Ltd was engaged by DRET to monitor the implementation of the PTTEP Montara Action Plan. Should the Montara Action Plan not be fully completed and properly implemented, or should any other concerns arise that warrant it, the Minister is able to issue a 'show cause' notice to PTTEP AA at any time. PTTEP will also be subject to an additional set of conditions on the renewal or future granting of offshore petroleum title applications in Australia. These conditions will ensure that good oil field and governance practices are applied by the company across its Australian operations. • • • 103 In carrying out a review of PTTEP AA's permit and licence, the Minister should have regard to this Report, particularly (i) the adverse findings set out in this Chapter; and (ii) the extent to which PTTEP AA has implemented the Action Plan submitted to the Inquiry, or otherwise addressed the matters canvassed in this Report. 104 The Minister consider legislative amendments to the OPGGS Act which make clear that (i) the Minister can direct a titleholder to obtain an independent report into the circumstances and likely causes of a blowout; and (ii) the Minister can direct that such a report be provided to him (and such direction overrides any legal professional privilege which otherwise attaches to the report). Accepted. Refer to Recommendation 102 Noted. Refer recommendation 102. 0 • • 105 In view of the numerous well integrity problems in all of the Montara Oilfield wells, the Minister should commission a detailed audit of all the other offshore wells operated by PTTEP AA to determine whether they too may suffer from well integrity problems. Accepted. The Commonwealth agrees that an audit of the other suspended wells at the Montara Wellhead Platform was required to ascertain the integrity of the suspended wells. PTTEP AA has verified the integrity of the remaining wells at the Montara Wellhead Platform and these results have been confirmed by Geoscience Australia, providing the Commonwealth with confidence in the integrity of all wells at the Montara Wellhead Platform. In addition to work undertaken with the NT DoR, on 31 May 2010 the Commonwealth requested all other Designated Authorities to undertake a number of reviews to ensure the integrity of wells, in particular the status of all completed and suspended wells since 2005, and their assessment, approvals and monitoring of offshore petroleum activities were in accord with the OPGGS Act. All Designated Authorities have cooperated fully and provided assurances to the Commonwealth that that rigorous regulatory practice are being implemented in relation to the approval and compliance monitoring of well operation activities. In addition the Commonwealth has issued a Statement of Expectations to the Designated Authorities and NOPSA which sets out the Minister for Resources and Energy's expectations, as the responsible Commonwealth Minister, on matters relating to the exercise of their functions and powers under the OPGGS Act and associated regulations and principles of best practice regulatory administration. • U • The Department of Resources, Energy and Tourism commissioned an independent review of PTTEP Australasia's Montara Action Plan to determine whether all necessary measures have been taken to prevent any future incident like Montara. The Independent Review also identified a series of lessons arising from the Montara incident that are relevant to the oil and gas industry. The lessons address themes within the acquisition and integration of production assets; and governance and oversight. The following chapter contains the nine recommendations and the Commonwealth's response. Additional Recommendations for Industry - Review of PTTEP Australasia's Response to the Montara Blowout (Noetic Report) Recommendations DRET should work with industry and the Australian Noted. Petroleum Production Et Exploration Association (APPEA) to develop programs to ensure greater understanding of Major Accident Events (MAE) include causes, prevention and management. DRET should work with APPEA and other industry bodies to ensure senior executives in the industry clearly understand the distinction between auditing and performance monitoring. DRET should work with the industry to identify mechanisms to publish factual reports as soon as possible after an incident to assist others engaged in similar activities or using similar equipment to avoid an incident. DRET should work with industry and APPEA to develop mechanisms to share information on high potential incidents. DRET should work with industry and APPEA to enhance the training available to personnel involved in well operations. In addition to the recommendations made by Noetic Solutions Pty Ltd in the "Review of PTTEPAustralosia's Response to the Montara Blowout' (Review Report) that were specific to PTTEP Australasia (Ashmore Cartier) Pty Ltd, the Review Report identified a series of lessons arising from the Montara incident that may have relevance to the offshore petroleum industry. As stated by Noetic in the Review Report, there are "few, if any, completely new lessons" for industry arising from the Montara Commission of Inquiry. The lessons identified by Noetic reflect internationally recognised themes supporting good governance and best practices, and are to be continually considered and implemented through industry education and development by the industry, its representative bodies and governments. As the peak industry body for Australia's offshore petroleum industry, the Australian Petroleum Production and Exploration Association (APPEA) has the capacity to issue "high potential incident alerts" to industry stakeholders as a mechanism for highlighting learnings and strategies for industry to prevent major • DRET should consider working with APEPA to promote and educate industry on matters relating to good practice in undertaking due diligence around safety, health and environment. DRET should consider working with APPEA to promote and educate industry on matters relating to good practice in dealing with asset integration to ensure asset integrity following acquisition. DRET should work with APPEA to improve the ability of mid to small tier companies to incorporate HSE issues into corporate planning frameworks. DRET should work with APPEA to provide advice to industry on the use of advisory boards to enhance safety, health and environmental outcomes. incidents. As the national offshore safety regulator, NOPSA is continuing to examine options to share information and learnings on specific safety incidents with the industry. In addition, APPEA has established a "Montara Response Taskforce" This Taskforce has identified a number of key tasks in relation to well operations and containment; a mutual aid agreement; oil spill response and preparedness strategies and industry best practice. APPEA will be asked to ensure that the lessons identified by Noetic are incorporated as part of the Taskforce's activities. The Commonwealth notes that elements of the Noetic recommendations specifically relating to matters around acquisition, integration and governance will be considered as part of the high level International Offshore Petroleum Regulators and Operators Summit scheduled for 10-11 August 2011. In addition these matters will also be raised with industry as part of the 2011 APPEA Conference and Exhibition on 10-13 April 2011 and the APPEA Health and Safety Conference on 8-10 August 2011. The Commonwealth through DRET will work with APPEA in implementing the lessons identified across the offshore petroleum industry. The Implementation Plan identifies how the recommendations arising from the Report of the Montara Commission of Inquiry and the Review of PTTEPAustralosia's Response to the Montara Blowout have been; are being; or will be progressed. • Implementation Plan Implementation of the Government's response to the Report of the Mon tara Commission of Inquiry wiII provide operational direction for industry and will establish a regulatory framework for approval and compliance monitoring by regulators. Implementation will require significant and sustained efforts over several years by governments, industry and regulators. A significant number of recommendations are already being implemented by the Commonwealth, the Northern Territory Designated Authority and industry. It will be undertaken by different Government agencies, and will also involve the engagement of state/Northern Territory agencies. In addition to the Report of the Montara Commission oflnquirythe Government has undertaken to implement the lessons for the offshore petroleum industry as identified through the independent review of PTTEP Australasia's Montara Action Plan (the Review of PTTEPAustralosia's Response to the Montara Blowout). The Independent Review, undertaken by Noetic Solutions Pty Ltd, made nine recommendations covering the acquisition and integration of production assets, and governance and oversight (refer Appendix 2). The Minister for Resources and Energy, the Hon Martin Ferguson AM MP, tabled the Independent Review report in Parliament on 4 February 2011. This Implementation Plan identifies how the recommendations arising from the Report of the Montara Commission oflnquiryand the Independent Review of PTTEP Australasia's Montara Action Plan have been; are being; or will be progressed. Implementation of the Government's response includes a suite of initiatives that involve potential • amendments to legislation and improvements to strengthen and clarify the administrative and operating practices of the regulator and the offshore petroleum industry. Recommendations are addressed against the following key themes: 1. Regulatory Regime 2. Regulator Operating Practices 3. Response Arrangements 4. Environmental Management 5. Review of PTTEPAustralosio's Response to the Montara Blowout; and 6. Additional Recommendations. Key implementation activities, and timing, for these themes are addressed below. • 1. Regulatory Regime Recommendations:2; 23-26; 28; 44; 48; 66; 68; 71-72; 79; 83; 88-89; 91-92; and 95-97. The Government will: Review all Commonwealth legislation applicable to the marine and offshore petroleum environment to strengthen the marine and offshore petroleum legislative frameworks to ensure a comprehensive, consistent approach to the regulation of petroleum activities in Commonwealth waters. Develop and implement a model that ensures an appropriate cost sharing framework between shipping and marine industries relating to incident response and preparedness. Timing: To be completed by the end of June 2012. 2. Regulator Operating Practices Recommendations: 5-9; 14; 16-18; 19; 22-35; 39-44; 48-51; 69; 81-83; and 89-90. The Government will: • Clarify and strengthen the robustness of the current regulatory regime through the actions of regulators for offshore petroleum activities, in discharging their regulatory obligations by: • Strengthening the framework for engagement between regulators and the offshore petroleum industry in responding to a future offshore petroleum incident. Timing: To be completed by June 2012 • • Developing a National Legislative Compliance Framework that will clarify and strengthen the role of the regulator for offshore petroleum activities through the development of a consistent and best practice approach in discharging their regulatory responsibilities. Timing: To be completed by December 2011 Continuing with the establishment of a national offshore petroleum regulator for Commonwealth waters (beyond the three nautical miles from the territorial sea baseline) - the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA). NOPSEMA will assume responsibility for environmental approvals, including oil spill contingency plans under the Offshore Petroleum and Greenhouse Gas Storage Act2006. NOPSEMA will also regulate safety, integrity and environment plans for minerals extraction and greenhouse gas storage activities in Commonwealth waters: • The states/Northern Territory will have an ability to confer power, under their respective legislation, to NOPSEMA for the regulation of offshore petroleum activities in coastal waters. Continuing with the establishment of a separate titles administrator, the National Offshore Petroleum Titles Administrator (NOPTA) within the Department of Resources, Energy and Tourism. It will administer titles and data relating to offshore petroleum, minerals and greenhouse gas storage activities in Commonwealth waters. • The states/Northern Territory will have an ability to confer power, under their respective legislation, to NOPTA to undertake titles administration for offshore petroleum titles in • coastal waters. Timing: To be competed by January 2012 3. Response Arrangements • Recommendations: 81; 84-86; and 94 The Government will: Establish an incident management and coordination framework that is specific to an offshore petroleum incident in Commonwealth waters and that provides a transparent communication strategy, including communication with the public. Timing: To be completed by April 2012 • Clarify the roles and responsibilities in responding to an offshore petroleum incident under Australia's National Plan to Combat Pollution of the Sea by Oil and Other Noxious and Hazardous Substance (the National Plan). • Review Australia's National Plan to ensure appropriate risk management and emergency response strategies are in place and that equipment is appropriately placed. Timing: The Review of Australia's National Plan is to be completed by the end of 2011. 4. Environmental Management Recommendations: 86-93 and 95-100 The Government will: • Strengthen the environmental protection regime for Commonwealth waters, through the legislative regime and the review of the National Plan: • This will also take into consideration other regulatory obligations, such as those required under the Environmental Protection and Biodiversity Conservation Act 1999. Clarify the cost of responding to an oil spill, or other damages to the offshore and broader environment will be totally met by the owner/operator responsible for the offshore petroleum activity through the 'polluter pays' principle. Timing: To be completed by the end of June 2012 • Establish "off the shelf' scientific environmental monitoring programs that can be speedily implemented during a response to an offshore petroleum incident. Timing: To be completed by the end 2012. 5. Review of PTTEP Australasia's Response to the Montara Blowout In addition to the findings and recommendations made by Noetic Solutions Pty Ltd in the Review of PTTEPAustralasio's Response to the Montara Blowout (Review Report) that were specific to PTTEP Australasia (Ashmore -Cartier) Pty Ltd, the Review Report identified a series of lessons arising from the Montara incident that potentially have relevance to the offshore petroleum industry. The lessons and corresponding recommendation address themes within the acquisition and integration of production assets; and governance and oversight. The Review Report specifically tasks the Department of Resources, Energy and Tourism (DRET) with taking forward the nine recommendations with industry participation through the Australian Petroleum Production and Exploration Association (APPEA). Timing: August2011 and ongoing: The Department of Resources, Energy and Tourism will consider the elements of these recommendations specifically relating to matters around acquisition, integration 40 and governance, as part of the high level International Offshore Petroleum Regulators and Operators Summit scheduled for 10-11 August 2011. 6. Additional Recommendations There are a number of recommendations that are specific to the offshore petroleum industry; that have been completed that the Government has agreed to "Note" or are "Not accepted") Offshore Petroleum Industry Recommendations:4; 11-13; 15; 21; 36-37; 45- 47; 52-63; and 65 It is appropriate that the offshore petroleum industry carefully consider adopting those recommendations, which are not already addressed of accepted industry practice, that relate to operating matters specific to the industry. Completed Actions Recommendations: 1; 67; 73-76; 101; 103; and 105 A number of Recommendations has been identified as having been addressed by the Government or are currently being implemented through the Government's upstream petroleum regulatory reform agenda. . Noted Recommendations Recommendations: 3; 10; 64; 70; 77-80; 102; and 104 These recommendations have been noted by the Government as not requiring further action or implementation as they relate to actions or information that are already required by the existing regulatory regime, or are considered to be primarily operational matters for industry. Not Accepted Recommendations Recommendations:8; 20; and 38 The three recommendations not accepted are considered technically inappropriate, may potentially compromise safety, or are factually incorrect. Provides a summary of stakeholder submissions on the Commonwealth's draft response to the Report of the Montura Commission of Inquiry Appendix 1 to the Final Commonwealth • Government Response Stakeholder Consultation Summary of stakeholder submissions on the Commonwealth's draft response to the Report of the Montgro Commission of Inquiry Seventeen submissions, three of which were confidential and one which was considered as not relevant, were received from a range of stakeholders including governments, industry, environmental representatives and the community. The remaining thirteen non -confidential submissions that made substantive comments on the draft response are available at www.ret.gov.au/montarainquiryresponse. The comments received from stakeholders have been considered carefully in the development of the Commonwealth's final response to the Report of the Montoro Commission of Inquiry. 1. Mr Wayne Needoba, Managing Director, Labrador Holdings WA Pty Ltd Community 2. ExxonMobil Australia Industry 3. WWF-Australia Environmental 4. Australian Marine Oil Spill Centre Pty Ltd (AMOSC) Industry 5. Plexus Ocean Systems (Malaysia) Sdn Bhd Industry 6. Australian Institute of Marine Science (AIMS) Government 7. Northern Territory Government Government 8. Australian Network of Environmental Defender's Offices (ANEDO) Environmental 9. Australian Petroleum Production and Exploration Association Ltd (APPEA) Industry Body 10. Western Australian Department of Mines and Petroleum (WA DMP) Government 11. Environs Kimberley Environmental 12. Chevron Australia Industry 13. West Timor Care Foundation Environmental 0 Chapter The Circumstances and Likely Causes of the Blowout • The submissions presented by government indicated support for a minimum of two or more barriers being adopted and noted that the removal or installation of barriers was assessed on a case -by -case basis. The Northern Territory Department of Resources (NT DoR) provided a whole of NT Government response outlining the actions undertaken by the Commonwealth and the NT (as already publicly noted) and reiterating its position that at "all material times there was no formal arrangement stipulating the manner in which the position of Director of Energy was to account to the Commonwealth in relation to the performance of the functions as the Commonwealth's delegate': The Western Australian Department of Mines and Petroleum (WA DMP) made several comments relating to the National Offshore Petroleum Safety Authority (NOPSA)'s approval or compliance checking of the safety case, expressing some criticism that these matters were not considered by the Montara Commission of Inquiry. WA DMP did not support Recommendation 37 relating to contractor liability, and suggested that minimum standards in relation to drilling operations be identified and adhered to by all parties. Submissions received from industry demonstrated broad support for the Commonwealth's draft response and outlined detailed information regarding industry operating practices in a number of areas including clearly articulated "Management of Change" processes and procedures; well barrier design and operations management; and accepted industry procedures, practices and commitment to the application of best practice. Industry however sought further clarification regarding the Commonwealth's position on Well • Operations Management Plans, well integrity hazards and 'worst -case' scenario planning, and recommended that the Commonwealth amend its draft response to not accept Recommendations 2,3,4,16,17,18,25,26,28,37,40 and 56. Industry noted that the licensee (not the rig operator or contractor) is responsible for the well design, including installation of barriers, and there are many practical examples where barriers are installed or removed offline. Submissions also indicated that the logistics team is not the appropriate party to assess the adequacy of well management (or well design) as suggested by the Commissioner in Recommendation 56. Industry also reiterated that any change brought forward in the definition of 'good oil field practice' should not diminish from the objective - based regulatory regime. In its submission, the Australian Petroleum Production and Exploration Association (APPEA), as the peak industry body representing Australia's offshore oil and gas industry, noted that through the APPEA Montara Response Taskforce, the industry has developed: • A Self -Audit Tool for Management of Well Operations; • A draft Memorandum of Understanding around Mutual Aid; • An agreed position for Australian Industry on Cap and Containment; and • Oil Spill Preparedness and Response Improvement Strategies. APPEA also noted that the offshore petroleum industry acknowledges that it must be able to demonstrate its leadership and commitment to achieving the highest standards if it is to retain its social license to operate and achieve strong public confidence in its operations. • The environmental representatives while supporting the objective -based regulatory regime recommended that it be supported with minimum standards for well operations and barriers (set in legislation), including reiterating a minimum two barrier well control configuration, cementing standards, drilling standards, and well trained and qualified industry and government personnel to implement more robust auditing and compliance/integrity testing. Furthermore, WWF in its submission . recommended that the Commonwealth should review and approve industry training programs and establish well control competency standards. Communitystakeholders provided an opinion on the causes of the spill, and suggested that industry could fund the modelling of geological complexities and their impact on barrier quality in regards to well control, matters which the Commonwealth considers are appropriate for the offshore petroleum industry to consider. Chapter 4 The Regulatory Regime: Well Integrity and Safety The submissions presented by government varied. The NT DoR indicated support for the establishment of a single national regulator. However, the WA DMP did not support Recommendations 73,74,75 and 76(c) and suggested that the establishment of a national offshore petroleum regulator contradicts the evidence presented by the Report. WA DMP did not support Recommendation 69, noting that initial verbal approval is sufficient for the regulator to be satisfied that the changes to the well bore will occur without incident, followed up with a written request as soon as reasonably practicable (usually within 6-8 hours). WA DMP notes that NOPSA should be the regulator for all well integrity matters, and does not support any amendment of the Offshore Petroleum and Greenhouse GasStorogeAct2006 (OPGGS Act) to enable Designated Authorities to be given direction by the Commonwealth Minister as to their regulatory performance. Submissions received from industry indicated support for the objective -based regulatory regime, noting that this approach encourages continuous improvement by industry. Submissions provided information • on agreed industry practice relating to situations where collaboration with the regulator was required. APPEA noted that the regulator should be accountable through a governance board, and that a change/ management transition plan developed jointly by industry and government would assist in smoothing the transition to the new regulatory arrangements under the National Offshore Petroleum Safety and Environmental Management Authority. Industry recommended the draft response be amended to not accept Recommendation 67 to reflect that in some circumstances, the whole purpose of a well activity is to address a well integrity hazard. The environmental representatives expressed support for the objective -based regulatory regime. However, Environs Kimberley recommended that a combination of both prescriptive and objective - based regulation be implemented, which is supported by a clear definition of 'sensible oil field practice' and consistent application of the term 'good oil field practice' to recognise that the regulatory framework is only as effective as the compliance regime. Environs Kimberley expressed support for the establishment of a national offshore petroleum regulator that is empowered to enforce a clearly defined regulatory framework and is adequately resourced to do so, and supported the Commonwealth's commitment to consider improving the penalty regime for pollution of Commonwealth waters. Chapter 5 Arresting the Blowout In respect of the submissions received by government, the WA DMP made comments regarding Recommendations 78 and 83, suggesting that these recommendations should not be supported as the consideration of options for arresting the blowout should be the responsibility of the operator, and that NOPSA, "not the regulator", should pre -assess available options for well control. Submissions received from industry indicated support for the need for clarity in respect of incident response management and co-ordination when responding to an offshore petroleum incident. Industry also emphasised the importance of an integrated industry/government response team supported by sufficient resources for response personnel. Submissions noted that the offshore petroleum industry is • committed to contributing to Tier 2 regional spill clean-up response capability and maintaining a Tier 3 oil spill clean-up equipment stockpile under the management of the industry -funded Australian Marine Oil Spill Centre (AMOSC). Industry recommended the Commonwealth's draft response be amended to not accept Recommendations 78 and 82, which in the view of industry have recommended a change in the accountability and roles of regulators versus operators. The environmental representatives noted the parallels between the Montara and Deepwa ter Horizon incidents and recommended that an appropriate penalty regime be established. Chapter 6 Environmental Response The submissions presented by government agreed to the Commissioner's recommendation to make environment plans publicly available in full, provided issues around commercial confidentiality were addressed. The NIT DoR promoted an environmental security bond or the establishment of a contingency fund as possible mechanisms to address costs associated with preparedness and responsible capabilities. Submissions noted that specific responsibilities for key roles in oil spill response should be documented in Australia's National Plan to Combat Pollution of the Sea by Oil and Other Noxious and Hazardous Substances (National Plan), and take into consideration the mobile nature of oil slicks in that they often involve multiple jurisdictions. The WA DMP in its submission noted that, as Western Australia has the highest level of offshore oil and gas activity in Australia, equipment stockpile locations in WA should form part of the 2011 Review of the National Plan being undertaken by the Australian Maritime Safety Authority to ensure • that equipment and resources are strategically placed and are readily accessible where most needed. WA DMP did not support Recommendations 98 and 99 which in the view of WA DMP add regulatory burden and duplication to the approvals process. Submissions received from industry indicated in principle support for the equitable cost -sharing proposal and support for a risk -based approach to determining the appropriate level of contribution. Submissions noted that the responsibility for meeting costs incurred in the clean-up of an offshore petroleum incident rests with the facility operator, and requested clarification of the legislative position around this and associated insurance and liability issues as well as the scope and application of the 'polluter pays' principle. APPEA in its submission noted the work of the industry in establishing an Oil Spill Preparedness and Response Focus Team to advise the APPEA Board on industry's response to the Montara and Macondo incidents. The Focus Team is also liaising with the International Oil and Gas Producers Forum on international developments in this area. Some of APPEA members are also working on the development of a Scientific Monitoring Program for the Prelude floating liquefied natural gas project. The Australian Marine Oil Spill Centre (AMOSC) noted that the oil and gas industry supports a minimum requirement for response capacity and capability to be identified in contingency plans, and implemented and resourced by the industry in the event of an incident. AMOSC also noted that the oil industry has well established mutual aid arrangements with other oil spill response organisations around the world that have been operationalised so mutual aid can be provided at short notice, with pre -agreed arrangements to manage liabilities and costs. AMOSC also pointed to the training programs provided by industry to maintain personnel competency in oil spill response. The environmental representatives requested that the Commonwealth in its final response acknowledge the current Marine Bioregional Planning process and support the establishment of a network of "highly" protected marine parks. Submissions also recommended that a comprehensive risk assessment of the offshore petroleum industry be undertaken to indicate any high conservation areas and values as • a matter of priority, and suggested that requirements for sufficient baseline information be extended to include exploratory drilling activities near sensitive marine environments. Submissions also suggested that the distinction between operational and scientific monitoring be removed in the National Plan to give equal status to both types of monitoring. WWF Australia throughout the submission expressed concern that some of the recommendations and the draft response appear to rely too heavily on industry -led programs where industry "... is handed the reins to write their own rules': The submission from the West Timor Care Foundation (WTCF) focused specifically on Recommendation 86 and included unverified new data concerning the impact on West Timor which it stated has been independently collected by the WTCF, but was not available in its original submission to the Montara Commission of Inquiry. The WTCF noted concerns that the implementation identified in the draft response does not address "marine casualties and pollution by oil and hazardous noxious substances" beyond Commonwealth waters, and noted several additional areas that were not addressed in the draft response, including evidence of oil and dispersants in Indonesian waters resulting from the Montara incident that occurred in Australian waters; the decision to use Corexit 9500 in addition to other dispersants and its impact on environment, health and economic livelihoods of people; and Australia's obligations under the United Nations Convention on the Law of the Sea. The Australian Institute of Marine Science (AIMS) made specific comments in relation to Recommendations 88-93, and suggested that further discussion between the linkages of the "off the shelf' monitoring plans and baseline data should be undertaken. AIMS recommended that baseline • assessments and scientific monitoring be developed in tandem, and that the distinction between operational and scientific monitoring should be removed from the National Plan to give both types of monitoring equal status. AMOSC made specific comments in relation to Recommendations 86-100. AMOSC supported the need for clear guidelines for the exercise of powers and responsibilities for managing and coordinating a response to an offshore petroleum incident, as well as incident preparedness and monitoring, and noted the need for clarity of the legislative position around clean-up costs, insurance and no-fault liability. AMOSC supported a minimum Tier 1 standard for equipment requirements at each operational facility that reflect the appropriate risk factors, and noted that the oil industry is committed to contributing to Tier 2 regional spill clean-up response capability and maintaining a Tier 3 oil spill clean-up equipment stockpile under AMOSC management. AMOSC expects that industry mutual aid agreements (including international agreements) will be activated in the event of an incident. AMOSC also emphasised the importance of appropriate competency -based training. Community stokeholders noted that the draft response addresses the numerous issues raised in submissions made to the Montara Commission of Inquiry, and suggested that further discussion between the linkages of the "off the shelf' monitoring plans and baseline data needs to be undertaken so that both baseline assessments and scientific monitoring can be developed in tandem. 17J Chapter 7 Review of PTTEPAA's Permit and Licence at Montara and Other Matters • APPEA's submission on behalf of industry noted that any attempt to diminish legal professional privilege in relation to reporting into the causes of well blowouts should be resisted as decision makers in the offshore petroleum industry need the benefit of professional legal assistance free from the apprehension of disclosure. Industry recommended a change in the draft response to not accept Recommendation 104 and resist any attempt to diminish legal professional privilege. The Australian Network of Environmental Defender's Offices (ANEDO) submission on behalf of environmental representatives raised concerns with the decision of the Minister for Resources and Energy not to issue a 'show cause' notice to PTTEP Australasia (Ashmore Cartier) Pty Ltd (PTTEP AA), and suggested that the Minister should cancel the company's Montara production licence or suspend the licence until the requisite remedial action has been taken. ANEDO also suggested cancelling all other production licences held by PTTEP AA to send a message to other oil field operators. • • • • 0 • • Australian Government 40 Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More Air France crash and the psychology of well control June 1, 2011 by offshoreenergy "It would seem to me, reading between the lines, that the cockpit crew weren't confident of the information that was being presented to them on the data displays. Maybe — and it's only a maybe — they took some action that led to the stall warning, and the plane stalling and then being unable to correct it. " The above quote from a new article on the Air France crash should sound familiar to BOE readers. At both Montara and Macondo, the evidence of hydrocarbon influxes was clear, but personnel misinterpreted or ignored that information. Was this wishful thinking on their part? Was their training flawed? Lack of sleep? Overstressed? Distracted? These issues need to be carefully studied. Improving well control preparedness is not simply a matter of modifying stack design. • The thought processes and human response tendencies that contribute to well control incidents and other accidents must be fully considered. Monitoring systems must provide timely, accurate, and understandable information, and training programs must teach workers not to rationalize negative signals, but to respond with caution pending further assessment. Trainers must remind students about past disasters and how they could have been prevented. Nearly 20 years after it was written, Paul Sonnemann's excellent paper on the Psychology hology of Well Control (excerpt below) is even more relevant today. We need to build upon and apply the lessons. In Conclusion, strictly analytic, technical and ever more sophisticated approaches to well control are unlikely to succeed as long as human needs, fears, and perceptual or cognitive limitations arc permitted to dominate behavior in actual well control sltuationr. As concerned professionals, we need to increase our awareness of and efforts to understand these "human" factors. And they must he kept firmly in mind while developing policy, procedures, rig systems. and training activities. I was in the audience almost 18 years ago when Paul Sonnemann made an outstanding presentation on the thought processes and human response tendencies that contribute to well control incidents and other accidents. These tendencies may have been significant contributing factors at both Montara and Macondo. With Paul's permission I have attached a copy of his 1992 paper. I strongly suggest that you read it. 0 hgp•//budsoffshoreenergy.files.wordpress.com/2010/06/psych-of-wc-paper-1992.pdf • While considering new regulations, standards, and procedures, the industry and government need to look closely at the issues identified in Paul's paper. • 40 i IADC The Psychology of Well Control -- P. Sonnemann 1 The Psychology of Well Control Y gY Paul Sonneman Sedco Forex 1992 IADC Well Control Conference of the Americas This paper was prepared for presentation at the 1st annual IADC Well Control Conference of the Americas held in Houston, Texas 18-19 November 1992 at the Marriot West Hotel. ABSTRACT Serious well control problems in the field are more often the result of inappropriate human behavior than of any other single cause. This behavior is as much a function of psychological factors as of equipment, technique or knowledge. Management decisions that include consideration of psychological factors relating to perception and motivation offer opportunities for eliminating the human mistakes that too often result in dangerous and expensive well control incidents. • TEXT I am grateful for the chance to share some observations with such a wide range of people who have expertise and responsibilities touching on well control. Perhaps my conclusions will seem obvious to some. But consideration of the effect of psychological factors on well control behavior is certainly not a standard or well documented topic. So I hope it will provide at least some food for thought. Let me give you an idea of where my thoughts come from. I became involved in well control training for Sedco Forex while working in the North Sea in the early Eighties. But with with an academic background encompassing both engineering and Psychology, I found myself making observations on the topic of field application of well control practices with an appreciation for technique, but also a pre -disposition to focus on human behavior. And this is what interests me most today -- human behavior in well control situations. Although I have taken the liberty of describing my topic as the "Psychology of Well Control" , I don't mean to introduce obscure • theory derived from studies of rats running in mazes. Nor do I want to consider interpretation of dreams. Instead, I want to focus on IADC The Psychology of Well Control -- P. Sonnemann 2 • some straightforward observations about things that affect human behavior -- that is, what people do when confronted with well control related situations. Psychological concepts relating to perception and motivation, in particular, are as applicable in well control situations as in any other area of human activity. But let's avoid an esoteric discussion of psychological concepts in favor of a sample examination of a relatively simple field example that will, I hope, illustrate the importance of these factors in field practice. Let's consider a situation in which we have a driller whose mud pit volume alarm sounds, indicating an increase in mud volume in the active pits. In a normal drilling situation, routine well control practice calls for the driller to recognize this as a classic indication of a potential kick in the well. Since the danger and difficulty of handling a kick generally increases in proportion to kick volume, drillers are often trained to respond by stopping to do a flow -check in a circumstance such as this. If mud continues to flow from the well when the pumps are turned off, a kick is indicated and the well would normally be shut in with the BOP's in accordance with company policy. • I think most would agree that most drillers in the field today would be able to describe this sequence of events with little difficulty. And, given a reasonable approximation of familiar rig equipment, virtually all experienced field hands could demonstrate an ability to enact this sequence. Yet, year after year, we hear of well control situations resulting from, or complicated by, a dramatic failure of trained rig personnel to perform this simple sequence of behaviors in a timely fashion. What are some possible reasons for these failures? Lack of knowledge of principles? of policy? of technique? of training? Let's consider how some "psychological" factors might provide some explanation here. I'll start with "Perception". Perception is the process of becoming aware of of physical reality. Since we are bombarded continually during our lives by incredible amounts of sensory data, it can be argued that a major mental activity is that of screening sensory input, allowing perception of only a small subset of available data that the brain considers relevant at a given moment. When the brain is confronted with input that fails to support a concept of reality, it can quite actively prevent that data from being objectively processed. • What this means, of course, is that it is quite possible for things to occur within our sensory range without our becoming aware of IADC The Psychology of Well Control -- P. Sonnemann 3 • them. That is why alarms on gauges located within our range of peripheral vision are essential to direct our attention to information that might be routinely screened from our stream of consciousness. But it also explains why it may be surprisingly hard to correct a faulty perception or belief once it has been formed. Now when our imaginary driller hears his PVT alarm going off, it may well be his first opportunity to perceive a trend that is occurring on his gauges literally before his very eyes. Depending on the sophistication of the instrumentation, the driller may be able to confirm this newly perceived piece of information on a separate gauge or even review recently recorded data that can inform him of the rate of change. But his ability to do any of these useful things is too often limited in practice by the sensory overload of a 100 decibel alarm horn located three feet from his ear. Only after dealing with the alarm (instead of the well), is he likely to stop to consider how to react. Now in well control training, it is perhaps simple for him to immediately begin to perform the above mentioned procedure. The student will often start with the (correct) perception that the alarm • indicates a well kick. But in a real world situation, he may be confronted with at least two possibilities: 1) the well is kicking 2) someone in the mud pits has done something to affect the pit volume Without advance knowledge that a kick was likely, the data from the alarm may be ambiguous, equally supporting either of these conclusions. In situations in which ambiguity exists, it is a human characteristic of many people (consider optimists) to consistently accept (and act on a belief in) the less unpleasant or undesirable alternative explanation. (Consider, as another example, an optimist suffering mild heart attack symptoms who convinces himself it's probably just indigestion.) In cases like this, it is a common observation that drillers are more likely to pick up the phone to call someone in the mud pits to confirm the instrument reading than they are to immediately flow - check as prescribed by doctrine. Does it matter? Yes it does, since not only is time wasted which, during which in an actual kick, the situation would be deteriorating, but also an opportunity is created • for acceptance of plausible, but false alternative explanations for the observed phenomenon. And once this possible false explanation is IADC The Psychology of Well Control -- P. Sonnemann 4 • accepted, the driller's brain will unconsciously operate to cling to this explanation in spite of further sensory input. In other words, a pit watcher who speculates to the inquiring driller that it was perhaps an adjustment to mud cleaning equipment that was responsible for the observed pit level change may be contributing to the driller's acceptance of the "innocent" explanation for the alarm. This may cause a driller to forego the check required by prudent policy, perhaps resulting in a prolonged failure to perceive reality correctly -- that is, that the well may be flowing as well. This behavior of "explaining away" undesirable observations shows up with remarkable regularity in case histories of well control incidents and can surely be labelled the root cause of a number of well known industrial catastrophes (including the likes of the Three Mile Island and Chernobyl nuclear incidents). It is worth stressing that the problem here has nothing to do with knowledge, skill, brainpower, or company loyalty, but is a result of well-meaning individuals acting in normal and predictable human ways. In short, people often perceive (and believe) what they want or are prepared to perceive (or believe), rather than what is real. • But what, you may wonder, would have been the result of having a natural (or trained) pessimist on the brake who always assumes the worst? Such a driller might well suspect the worst ("the well is kicking and I'm the unlucky sap who has to interrupt an important or costly drilling operation to handle it"). As he flow checks to confirm his worst fears (while the optimist would still have been on the phone to the pits), what might his further thoughts be? Might he be thinking about the consequences of the next step?: - "If I close the well in, we'll probably end up with stuck pipe and there will be hell to pay." - "If I close the well in and it turns out that the flow is due to U-tubing of unbalanced mud, or "just" some trip gas, or just the well "giving back some mud" when excessive overbalance is reduced, there will be hell to pay." - "If I' close the well in and we damage or prematurely wear out our BOP elements, we'll have down -time and there will be hell to pay." - "If I close in the well, I'll have to wake the Boss, who doesn't like me nearly as much as he likes his sleep, and there will be hell to pay." • - "If I close in the well and report a pit gain of 7 barrels, no one will believe that there is a kick since this is less than the IADC The Psychology of Well Control -- P. Sonnemann 5 • normal flowback that occurs when I stop the pumps. I'll be considered a wimp or a nutcase. I'd better make sure there really is a problem before I "risk" closing in." Thoughts of this nature (and those who have been in the driller's shoes in the middle of the night on a tricky well should be able to relate to this) are common in the field. They all tend to prevent the driller from making the decision that would render well control much simpler -- to close in the well with a minimal influx. In fact, case histories again suggest that the decision to close in a well is often delayed until long after all ambiguity has ceased to exist. Sometimes, the only indicator that seems to overcome field personnels' reluctance to make the decision to shut in the well is mud actually spewing through the rotary table. When the situation has been allowed to progress to this point, it is little surprise that the well kill is substantially more difficult. We could continue to imagine our driller as he confronts one decision after another, hesitating at each step until events overwhelm him and gut reaction often prevails ("close the well in anyway you can regardless of training to do a "soft" shut in, concern for operating or well pressures, string position, etc.). But the point • should by now be clear that the driller's natural, human tendency to inaccurately perceive the situation and his concern for consequences of his decision can dominate his well control behavior at this early, but critical stage. This is in spite of his technical competence and field skills. So, what can be done to increase the chances that a driller will act in accordance with what he has been trained to do? First, company policies should unambiguously emphasize desired behavior -- regardless of consequences of that behavior. Such policies must be backed by a credible management commitment to support and stand behind those who comply. This can help remove conflicting motivation in emergency situations. If, for example, our driller didn't have to even imagine being blamed for stuck pipe or loss of productivity if he closed in the well, he would be more likely to perform as trained. Second, essential procedures should be kept as simple as possible. Every small step or decision in a sequence that can be eliminated increases the likelihood of the procedure being followed as per policy. This concept is relevant to the debate as to the relative merits of hard versus soft shut-in methods; a hard shut-in with the • annular preventer has an undeniable and, I believe, major advantage in its simplicity. It is unwise to underestimate the importance of IADC The Psychology of Well Control -- P. Sonnemann 6 • keeping steps simple if they must be performed without fail in moments of stress or confusion. Third, rig instrumentation should be designed to inform, not intimidate. Systems that can integrate sensors and perform some selective processing or interpretation of information can at least partially relieve the driller of the stress of being solely responsible for rapid decisions in moments of potential confusion. Complex instrumentation layouts that consist of a hodge-podge of unrelated instruments vying equally for the driller's attention are a hindrance to efficient action. A key design consideration should be simplicity of operation and minimization of less relevant data. Fourth, rig personnel actually handling well control situations should not be expected or required to perform theoretical calculations that contribute less to safe handling of the situation than they add to procedural complexity. Where such calculations are needed, it is often sufficient to substitute pre -kick data for calculations typically emphasized as necessary for well control. The greatest proportion of information on a typical kill sheet, for example, can be routinely kept adequately current by having it updated once or twice a day. Changes to most values (such as change • in open hole volume after drilling 10% more open hole) are generally less important to concentrate on than are other kill considerations such as equipment lineup, influx disposal, etc. Computer programs designed to assist the rig crew in calculation and analysis of well behavior during kicks hold promise so long as manipulation of the programs is not permitted to supercede control of the well as a goal. Fifth, communication at the rig and the office should be routine and thorough enough to help prepare drill crews to rapidly respond by helping to maintain an air of expectation of the potential for the development of well control situations. Once someone states that a well problem is unlikely, it is far less likely that a driller will correctly identify early signs of problems than would be the case if he were encouraged to keep his guard up. Actions such as a decision to not hire a mud logging service for a development well should not be allowed to imply that a kick can't occur; kicks on development wells are anything but unusual in the industry today. And finally, training activities must focus more attention on teaching students to act rather than simply understand. Knowledge of principles, equipment and technique is certainly important. But it is important to make a conscious effort to include consideration of • thoughts, emotions and psychological tendencies that will certainly affect behavior in high -stress, non -routine well control situations. IADC The Psychology of Well Control -- P. Sonnemann 7 CONCLUSION In conclusion, strictly analytic, technical and ever more sophisticated approaches to well control are unlikely to succeed as long as human needs, fears, and perceptual or cognitive limitations are permitted to dominate behavior in actual well control situations. As concerned professionals, we need to increase our awareness of and efforts to understand these "human" factors. And they must be kept firmly in mind while developing policy, procedures, rig systems, and training activities. Thank you for your attention. • C. 10 Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More PSA releases summary of Deepwater Horizon review June 11, 2011 by offshoreenercy P E T R 0 L E U M S T I L S Y N E T PETROTEUM SAFETY AUTHORITY NORWAY From the standpoint of post-Macondo safety and regulatory issues, this concise summary is the most comprehensive and useful report that I have read since the blowout. I have pasted (below) comments about information management — one of the many • important topics considered in the report — and hope you take time to read the entire summary. It is only 12 pages. http://www.ptil.no/ eg tf le.php/PDF/DwH PSA summary.pdf Conducting a critical review of the information used to manage major accident risk is one of the measures relevant for the companies. This work could include an assessment Of • the relevance, reliability and modernity of the indicators used to follow up risk trends • inappropriate use of indicators, incentives and reward systems • the need for better indicators and other information about the business which can be used to secure an early warning about a weakening in safety -critical barrier elements. The PSA is of the opinion that the quality of information applied in managing major accident risk is also a question of what overview the players have of their own business, and thereby a question of the players' own control. The PSA assumes that managing major accident risk cannot be outsourced. In light of the DwH accident, it could be relevant for the companies to review the processes intended to provide the necessary information about the business, assess in part how these processes support a culture of accountability and how various management and audit functions, third party verifications and so forth contribute in this connection. • PETROLEUM SAFETY AUTHORITY N O R W A Y The Deepwater Horizon accident - assessments and recommendations for the Norwegian petroleum industy SUMMARY 0 • Summary A blowout, explosion and fire occurred on the Deepwater Horizon (DwH) mobile unit on the Macondo field in the Gulf of Mexico (GoM) on 20 April 2010. Eleven people were killed, a number suffered serious injuries and the unit sank after two days. The uncontrolled oil flow totalled more than four million barrels by the time the blowout was halted 87 days later. Only eight months earlier, on 21 August 2009, a blowout occurred on the Montara field in the Timor Sea about 250 kilometres off the north-western coast of Australia. This blowout lasted for about 10 weeks and was halted with the aid of a relief well. The Petroleum Safety Authority Norway (PSA) established an internal multidisciplinary project team in May 2010 to follow up the work being done in the wake of the DwH accident and to develop the best possible basis for the authority's supervision and other measures which could improve health, safety and the environment (HSE) on the Norwegian continental shelf (NCS). The PSA's report builds on the investigation reports published so far, as well as a number of assessments of the accident by various professional bodies and various national and international processes. This report falls into two parts: • Part 1 presents the lessons learnt from the DwH accident which are significant for safety and emergency preparedness related to drilling and well operations on the NCS. • Part 2 presents the lessons which are significant for preventing major accidents in general, and which are considered relevant for Norway's petroleum industry as a whole. • Investigations of the DwH accident published so far have not identified new underlying causal mechanisms or causes. A number of underlying causes are the same as those identified for the Montara blowout, and also reflect conclusions reached by investigations of serious incidents in the Norwegian petroleum industry. The DwH accident cannot be confined to considerations which relate only to BP, Transocean and Halliburton, deepwater drilling, blowouts, the GoM and so forth. This incident raises issues which concern a whole industry, national regulation and international processes, and which are relevant for the prevention of major accidents in general. It must lead to improvements in Norway's petroleum activities as well. This accident has demonstrated the need to assess a number of measures which can contribute to better management of the risk of major accidents, and many relevant measures are pointed out. Where prevention of major accidents is concerned, the report from the US "National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling" (the presidential commission) assigns accountability to everyone who participates in and influences the petroleum industry. It addresses the accountability of the authorities by pointing to the need to assess regulatory requirements, official regulation/supervision, government organisation, collaboration between government agencies and operating parameters for these agencies so that they can meet all these expectations. At the same time, it is quite clear that improvements at the government level will be far from enough to prevent major accidents in the petroleum sector, and that in addition a very different level of industry involvement is required — both to improve safety and to restore the necessary confidence in the sector. The consequences of the DwH accident extend far beyond the possibility that drilling operations in the GoM could become 10-15 per cent more expensive. Based on extensive information about and analyses of the accident, the companies, the industry, the authorities and so forth over a long period (back to the 1970s), the presidential commission has concluded that the errors in managing major accident risk which underlie the DwH accident are representative of what is possible in the rest of the industry and symptomatic of the prevailing safety culture throughout it. The PSA is of the opinion that the DwH accident must be seen as a wake-up call to the Norwegian petroleum sector, that it must lead to a big improvement in managing major accident risk, and that the conclusion that the safety culture needs developing throughout the industry must also be considered relevant for Norway's petroleum activity. The DwH accident demonstrates the need for improved risk management and processes which lead to more robust solutions. These are ones which have built-in safety margins — a degree of slack — and which equip the industry to tackle human and technical error, operational non -conformities, unexpected conditions, the pressure of events and so forth. Robust solutions also contribute to the effective identification and management of hazardous conditions, and to ensuring that sufficient time is available to bring such conditions under control. The need for robust solutions applies to technology, capacity, expertise, organisation and management in every phase. The Macondo blowout happened in deep water, while the Montara incident occurred in shallow water and with other challenges determined by its location. Norway's petroleum industry is diverse, and factors influencing risk can vary a great deal from area to area. That demonstrates the importance of a risk -based approach to the activity, so that safety and emergency preparedness measures can be adapted to the specific risk factors which apply in each case. The GoM blowout underlines the need for 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 further development by the companies of performance standards for the • various barrier elements. That relates to the level of ambition for these standards when establishing, testing, maintenance and monitoring barriers. The accident also underlines the importance of temporary plugging and abandonment of wells. About a third of the wells temporarily plugged and abandoned off Norway have well integrity problems of one form or another. The DwH incident confirms that the industry must continue to give high priority to and intensify efforts to improve the integrity of temporarily abandoned wells. No need has so far been identified for major changes to the requirements set for well barriers in Norwegian regulations. However, a requirement exists for high priority to be given to a thorough updating of the Norsok standards related to methods, technology and work processes for drilling and well operations, well design, the equipment and media used for barrier elements, well control and so forth to ensure that they reflect developments in technology, knowledge and best practice. It is also important that routines are established for regular updating of these standards. An event like the DwH accident underlines the importance of being prepared for the unexpected and of detecting it when it occurs. Robust and appropriate equipment is one important factor, while the ability to handle safety -critical conditions is another. About 40 minutes elapsed on DwH from the initial indications that a well kick was coming until people reacted. Lack of information via screen diagrams, sensors and instruments, and inadequate use of existing data and equipment have been identified as contributory factors in this context. Norwegian regulations require that personnel must be capable of handling hazards and accidents, and that provision must be made so that personnel with control and monitoring functions are able to acquire and respond to information efficiently at all times. In light of the DwH accident, it is considered • natural that the industry collaborates to further develop, qualify and adopt technology and visual tools which permit real-time monitoring of well barrier condition and the maintenance of well control. For use in its supervisory activities, the PSA has developed a method for systematic follow-up of • barriers. This approach is also intended to help improve processes for systematic follow-up of barriers and well control both among managers and by the individual employee involved in drilling and well operations. The DwH accident confirms the importance of the PSA's continued development and clarification of the conditions for utilising this approach to supervision. It is also considered relevant to continue conveying this approach to industry, since it is also relevant for the companies' own evaluations, audits, training and exercises. Norway requires well control equipment to be designed and activated in such a way that it takes care of both barrier integrity and well control. Although a failure of the blowout preventer (BOP) was not a direct cause of the DwH accident, it was an important contributory factor to the catastrophic outcome. Investigations and analyses of the BOP were still under way when the PSA's report was being finalised. The PSA has not drawn any conclusions about the standards to which BOPS should be designed and manufactured. However, questions can be posed about BOPS intended for the Norwegian petroleum industry. The PSA takes the view that the lessons drawn from DwH must not be limited to the well control system which was in use on that unit, but must apply to all types of such systems. The PSA takes it for granted that modern barrier philosophy is applied to the continued development of standards, guidelines and requirements for following up and maintaining BOPS with their control system. A relevant consideration for the PSA will be to assess a clarification of regulatory requirements for blowout prevention, including intervention and seabed BOPS. Today's requirements stipulate a risk analysis for the control system of a drilling BOP, with specified minimum requirements for its safety integrity level (SIL). As a result of the DwH incident and of the fact that blowouts are not confined to drilling operations, the question is whether such an analysis, with a specified minimum SIL level, should also apply to all types of BOPS, including well -intervention models. In addition, consideration should be given in this context to whether other control and management systems related to well integrity/control exist which should be subject to such requirements. The DwH accident has demonstrated the need for the industry to develop efficient solutions as quickly as possible for halting and/or diverting the wellstream in the event of a blowout. This requirement also applies to the NCS, and high priority must be given to designing effective resources. A number of company groups and players in several parts of the world are developing arrangements for joint use of resources which can halt and/or divert the wellstream at source in the event of a blowout. Norway's regulations do not stand in the way of such joint resource use. It is important to have efficient plans for sealing wells and halting blowouts should this become necessary. Equipment, resources, procedures, plans, collaboration agreements and so forth must in place wherever a blowout is possible. Moreover, it is important that the resources are tailored to the relevant conditions expected in each case (reservoir conditions, regional factors and so forth). Every technical solution and activity which involves halting and/or diverting the wellstream at source in the event of a blowout with the aid of a system connected in some way or another to the well falls within the concept of petroleum activity, and accordingly comes under the PSA's regulatory authority. It could therefore be relevant for the PSA to assess the need to clarify regulatory requirements for such aspects as applications for consent, emergency preparedness and well control. When the kick in the Macondo well developed into a blowout, it led to large volumes of gas on the unit. That resulted in two explosion because the fire and gas detection system failed to prevent ignition. The PSA will continue to emphasise that solutions chosen on offshore facilities are designed with as much robustness and inherent safety as possible. DwH and other accidents have shown that this could be crucial • for preventing or limiting the scale of a major accident. A review of applicable regulations, standards and industry practice on fixed installations and units is recommended, together with an assessment of the extent to which these set adequate requirements for ignition source control, positioning and adequate separation of air intakes in power generators, • emergency shutdown of drilling systems, dimensioning fire and explosion loads, and the use of probabilistic methods in relation to a specified minimum level of barrier performance. For its part, the industry should verify that mobile units have defined dimensioning fire and explosion loads, that these can be documented and that these are reflected in the design of physical partitions, review the shutdown philosophy on all mobile units, develop best practice for disconnecting drilling systems in an emergency on fixed installations and mobile units, and verify that the facilities have a system for maintaining an overview of cutouts/overbridgings/inhibitions. It is considered relevant for the PSA to assess the need to amend prevailing regulations, standards and so forth in such areas as ignition source control, air intakes in power generators, shutdown of drilling systems, dimensioning fire and explosion loads, and so forth. It is also regarded as relevant for the industry to carry out such actions as verifying that facilities are tailored to dimensioning fire and explosion loads, that the shutdown philosophy includes ensuring an appropriate division between manual and automated action by the fire and gas detection system, and that a system exists for maintaining an overview of cutouts/overbridgings/inhibitions. Further development of best practice for emergency disconnection of drilling systems is also considered relevant on both fixed installations and mobile units. Emergency preparedness in Norway's petroleum industry builds on the principle that it must be possible to pursue operations in an acceptable manner on the basis of both individual and collective assessments of all HSE-related factors which are significant for planning and executing these activities. Key personnel on DwH were not trained in handling an incident on the scale of the blowout, nor did they act in accordance with applicable procedures for notification and response. The way training and exercises at training centres and on facilities are followed up on the NCS today does not reflect to any extent the necessary integration of emergency response organisations and combinations of possible incidents, since the practice is simply to train and exercise on "defined hazards and accidents" which are dimensioning for the activity. Consideration should be given to placing greater emphasis on training and exercises for • personnel whose jobs give them key decision -making roles and whose errors could have major consequences. Weaknesses have been exposed in the lifeboats used on DwH. The PSA has initiated the work required to amend the regulations so that all types of lifeboats are assessed after 1 January 2015 against the safety level corresponding to DNV-OS-E406 and Norsok R-002. In the PSA's opinion, this work will take account of the post-DwH findings on weaknesses in the evacuation equipment. The sinking of DwH was one in a series of incidents in which semi -submersible units have either sunk or experienced serious float stability problems. The PSA considers it relevant to conduct a detailed assessment of the need to make the regulations more specific in this area and to give greater emphasis to certain subjects in its supervision. Maintenance deficiencies were a contributory cause of the DwH accident. These related primarily to the BOP (maintenance, testing, faults and so forth), but the unit's general maintenance status is also mentioned to some extent in the various investigation reports. A number of the critical components required to operate the BOP had not been maintained at the intervals recommended by the manufacturer. The control system which operated the BOP on the seabed had been modified, and non - original equipment components with specifications which differed from those of the original parts had been used. No need has been identified so far to amend the requirements for maintenance management in the Norwegian regulations. The DwH accident confirms the importance of maintenance for ensuring that safety -critical equipment can function when required. It thereby also confirms the need to continue giving high priority to processes related to improving maintenance in the Norwegian petroleum industry. • The DwH accident also points to a number of challenges related to operational management functions on facilities and in the support organisation on land. These include challenges related to compliance with procedures and approved practice, risk understanding and assessments in general and in connection with changes to procedures and plans, communication, collaboration and involvement of the workforce. It has also been noted that the companies had good results from managing personal safety but devoted insufficient attention to major accident risk. The effect of lessons from earlier incidents between • facilities, companies, continental shelves and sectors was weak. Over time, it was also seen that a number of decisions favoured considerations of time and money, and disfavoured safety considerations. The investigation reports refer to substantial challenges posed by the safety culture on DwH, management handling of operational and mandatory changes, and striking the balance between efficiency requirements and safety considerations. The PSA considers it necessary that the government and players in the petroleum industry focus continuously on creating and maintaining a good safety culture in general, and a management culture where safety has a high priority. The PSA considers it important that the industry continues to give priority to improving the way changes which might threaten the organisation's capacity and expertise are addressed and subject to impact assessments, and to whether risk analysis tools need further development in this context. Moreover, it is considered relevant for the companies to evaluate how operational management functions on the facilities and in the support organisation on land help to prevent major accidents and thereby contribute to important reflections for management and the rest of the organisation. Apart from lesson which are significant for safety and emergency preparedness related to drilling and well operations on the NCS, experience from the DwH incident is also considered — as mentioned above — to be significant for major accidents in general and is regarded as relevant for all Norwegian petroleum activity. The DwH accident confirms that major accidents must be regarded as the result of a system error — in other words, a failure over time in a system of interconnected, to some extent mutually players and processes. •interdependent, A system perspective prompts serious questions about why clear and repeated signals concerning the decay of system -critical barrier elements were not picked up by the company's own follow-up, the official regulators or other stakeholders. A perspective of this kind is also important because it prompts a search for measures which can mobilise and make accountable many players both in and around the companies. That also helps to focus attention on such participants as the board and executive management, contractors, equipment suppliers, service providers, licensees, standardisation bodies, industry organisations, unions, insurance companies and so forth. This is a perspective which makes people conscious of the relationship between industry and society, and conveys in a better way that the companies must regard their safety performance and the confidence society has in them as a condition for securing access to business opportunities and as a competitive factor. Another important message which follows from a system perspective of this kind is that complex systems fail in complex ways. Major accidents cannot be explained by simple models and cannot be prevented by simple solutions. While it is important to simplify reality in order to deal with it in practice, it is also important to be able to deal with complexity. This is a fundamental requirement for developing the necessary respect for the uncertainty which underlies most decision, and thereby for being better positioned to choose robust solutions. The fact that a number of the causes of the DwH accident have features in common with earlier major accidents demonstrates a continued need for reflection on the issue of learning from accidents. A number of improvement initiatives have already been launched after the DwH incident, and great willingness exists in a number of quarters to demonstrate a decisive response. It is also important to take • time for reflection, not least on the lessons learnt after major accidents. Relevant questions in this context are: • why is learning apparently inadequate? • what does learning involve? • what can be learnt and what cannot? • • who has something to learn? • who learns what? • do we learn what we already know? • do we learn to improve the same types of problems? • do we learn to ignore the same types of problems? • do we learn to fail again? The DwH accident is not so far considered to have challenged the most overarching principles in the Norwegian regulations, such as the division of responsibility for regulatory compliance and the demand for systematic and risk -based compliance with functional requirements. Nor is the DwH incident considered to have challenged the need for a risk -based regulatory supervision. However, it raises serious questions about the integrity, modernity and efficiency of government regulation, monitoring and influence. That confirms the need for the PSA, on a continuous basis, to continue evaluating and improving the way it seeks to influence safety in the petroleum industry, and the effect of such an influence. The 2011 report from the presidential commission proposes the creation of an industry -operated self-regulating organisation (on the model of such bodies as the Institute of Nuclear Power Operations - Inpo) which can contribute to the development and implementation of high safety standards as well as providing evaluation of and advice on company operations, management, performance and behaviour. This type of solution functioned well in the nuclear power industry, but is perhaps not entirely suited for the petroleum industry and Norwegian conditions. However, Inpo has a good deal of positive experience which could also be useful for further development of government regulation and the petroleum industry in Norway. • These include: • the importance of giving weight to risk management and safety rather than regulatory compliance, in order to avoid a tick -box mentality • the importance of benchmarking safety performance across the players • the significance of establishing the frameworks needed to involve company managements in assessing safety performance and culture development • the significance of building up a good reputation over time with regard to professional integrity and purposefulness in order to influence improved risk management • the significance of influence and a recognition that this is exerted through both positive (trust - based processes, dialogue, motivation and rewards) and negative instruments (punishment, exclusion). • It is also relevant for the PSA to make a more detailed assessment whether some requirements need to be made clearer at the level of regulations, guidelines or interpretations. That could include • requirements for managing major accident risk, so that differences in such risk management emerge more clearly • requirements for managing major accident risk which are clearly more consistent with the safety concept, so that they take account of people, the environment and material assets • requirements for integrated assessment of a number of factors and for handling conflicting goals • requirements which clarify various areas of responsibility, including o the responsibility for systematic compliance borne by each player within their area of responsibility, and what that involves for suppliers of goods and services o responsibility of management functions in general and corporate management in particular • o responsibility for audit functions o licensee responsibility requirements related to the customer -contractor relationship • requirements for players to demonstrate that technology, operations, organisation and so forth are tailored to such considerations as regional factors affecting risk, including activities in deep water or in Arctic areas • requirements for equipment which are intended to avoid circumstances in which a player can deny the authorities or an investigation team access to internal requirements and documents. The PSA regards the involvement of the companies in standardisation work as a specific way for them to demonstrate their collective responsibility for a high level of safety, and to work actively to incorporate established best practice and to support the national standardisation strategy. The available investigation reports confirm that the companies still need to give high priority to standardisation work, and to allocate the necessary resources in that context. The PSA has plans to conduct a review in 2011 of standards used as recognised norms in the guidelines to the regulations, in order to eliminate possible outdated references and to assess the scope of the references which the authorities can acceptably qualify with their available resources. A project has been pursued for several years under the auspices of the Research Council of Norway to evaluate existing regulations as well as to reflect broadly on what characterises robust regulation in Norway's petroleum industry and which factors are important for achieving a robust set of regulations. The project has drawn on expertise and experience from a number of quarters, parties and countries. Findings include the importance of a tripartite collaboration between companies, unions and government, how conditions determining the robustness of the regulations develop over time, and unavoidable dilemmas between different considerations. Priority still needs to be given to R&D activities related to robust regulations in order to continue developing the necessary understanding of what characterises a robust set of regulations, what can be • expected of robust regulations and their limitations, and to challenge the robustness of the regulations in the light of advances in knowledge, social developments, changes in the industry, experience from other countries and so forth. In this context, it could be relevant to consider establishing the extent to which the conditions for functional regulations are present in the Norwegian petroleum industry, so that the PSA acquires a good basis for regulatory development and can otherwise adopt the necessary measures. In this report, the PSA has presented a number of good national and international initiatives for collaboration between government agencies following the DwH accident. These could influence the regulations, standardisation, government supervision, and government duties and resource use in more general terms. In order to be able to respond to so many initiatives in an acceptable manner, it will be important to maintain the existing principles and, for example, to • ensure that changes to Norwegian regulations and control systems in the wake of the DwH accident are assessed on the basis of their potential impact (positive and negative) on safety and with regard to the context in which they are meant to function • undertake a risk -based prioritisation of what the PSA chooses to become involved with — in other words, take account of its resource position and experience with the way resource -intensive collaboration between government bodies can be organised in order to dimension and shape its involvement in a good way • ensure that it benefits from and secures consistency with development activities in which the PSA is already involved, such as the work on management plans and the Barents 2020 project • retain earlier experience of how important it is to ensure that this type of work is not dominated too strongly by commercial interests, but is rooted in the authorities, industry organisations, unions, key university and R&D teams, and standardisation organisations. • The presidential commission recommends an international governmental collaboration to establish a robust foundation for managing Arctic regions. Both R&D activities and standardisation work are proposed in this context. It is important that the Norwegian safety authorities participate in this work, in part to benefit from and ensure consistency with the development efforts being devoted to the management plans and Barents 2020. • The DwH accident has weakened trust in the industry, which naturally leads to critical questioning about whether the government has adequate and appropriate sanctions, whether the companies suffer sufficiently serious consequences when they fail to operate acceptably, and whether the prospect of sanctions and consequences in the event of an accident are likely to have a preventive effect. However, it is not the case that more regulation, more government supervision, more orders, more punishment and so forth will benefit safety by definition and in all circumstances. Nor is it the case that regulations and government supervision are the only drivers for company work on safety and for regulatory compliance. It is also relevant to assess and take account of the companies' own incentives for preventing major accidents (concern for their own goals and strategies, financial reporting, business continuity, reputation, business opportunities, access to acreage and so forth). It is also relevant to search for government -controlled incentives which can influence/motivate the companies to price the accident risk better, invest more in safety and safety -promoting R&D, and so forth. An economic logic to safety work can be advantageously combined with a more traditional approach to safety, and to a more active involvement by forces which benefit from better safety. The report from the presidential commissions shows that the level of safety in the petroleum industry must also be seen in relation to national operating parameters which are set for safety considerations and by the safety authorities. It also notes that viewing the development of regulatory duties and allocated resources in an overall context is safety critical. Due to the developments / activity level in the petroleum industry the PSA has proposed to the Ministry of Labour a need for increased resources. As mentioned above, the PSA is of the opinion that the need to enhance the safety culture . throughout the industry must also be seen as relevant for the Norwegian petroleum sector. Development of a good safety culture calls for broad involvement and commitment by the companies (operators, drilling contractors, licensees and so forth), the unions, the government and so on. A good safety culture is characterised in part by the acceptance of a collective responsibility by the companies for pursuing improvements in safety -critical areas in a concrete way through such activities as a visible and ambitious commitment in the industry organisations (the Norwegian Oil Industry Association (OLF), the Norwegian Shipowners Association (NR) and the like), in standardisation work (Norsok, Barents 2020, Working Together for Safety and so forth), in work on developing the regulations (the Regulatory Forum), and in R&D (Petromaks, Demo2000 and so forth). An important condition for developing a safety culture and improving frame conditions for managing major accident risk is the development of a management culture which gives weight to safety considerations and where the commitment of the board and the executive management, for instance, to safety issues becomes clearer and more visible within the company, in various industry fora and in the public arena in general. The PSA believes that the issue of better protection for whistleblowers raised by the presidential commission must also be viewed in connection with ambitions related to improving the safety culture in the industry. In the PSA's view, important conditions for a good safety culture include the development of a culture of accountability, where everybody accepts responsibility for safety at their own level, and a culture of openness, which welcomes the raising of safety -related challenges and everyone accepting responsibility for safety. Given the importance of tripartite collaboration in the Norwegian model, it is considered relevant that the unions also consider their contribution to the improvement processes regarded as necessary for managing major accident risk. It is regarded as relevant in this context to look at the way concern for • major accident risk can be balanced with concern for the working environment and welfare. The DwH accident confirms the need for the PSA and the industry to continue to give high priority to improving the management of major accident risk. A big improvement in this context calls for a broad commitment. A number of relevant measures have been identified, related to risk analysis tools, data, • information on risk in the industry, understanding of the context, expertise, communication in and between companies, safety culture, management, benchmarking of safety performance and so forth. As mentioned above, this is also a matter of mobilising companies, government agencies and a number of other stakeholders. Conducting a critical review of the information used to manage major accident risk is one of the measures relevant for the companies. This work could include an assessment of the relevance, reliability and modernity of the indicators used to follow up risk trends inappropriate use of indicators, incentives and reward systems the need for better indicators and other information about the business which can be used to secure an early warning about a weakening in safety -critical barrier elements. The PSA is of the opinion that the quality of information applied in managing major accident risk is also a question of what overview the players have of their own business, and thereby a question of the players' own control. The PSA assumes that managing major accident risk cannot be outsourced. In light of the DwH accident, it could be relevant for the companies to review the processes intended to provide the necessary information about the business, assess in part how these processes support a culture of accountability and how various management and audit functions, third -party verifications and so forth contribute in this connection. The DwH accident thereby confirms the need for the PSA and the industry to continue giving high priority to the work of improving barrier management, and ensuring that this commitment covers all types of barrier elements. The PSA also relates work on improving barrier management with the need to improve the maintenance of safety -critical equipment identified in the Norwegian petroleum industry and • the development of the level of risk in this activity. It is accordingly considered relevant that the industry (through the OLF and the NR, for instance) assesses a mobilisation or the establishment of suitable fora to develop better practice for qualifying and maintaining safety -critical equipment and self -assessment of maintenance efficiency in relation to major accident risk. It is natural that a commitment of this kind at industry level addresses the breadth of opportunities and challenges on the NCS, including paying particular attention to the maintenance requirements which follow from a cold climate and aging of facilities as well as the limitations imposed by established organisational boundaries and traditional contractual terms. Experience from DwH concerning communication between the customer and the suppliers of equipment and services is also important for major accident risk in the Norwegian petroleum industry, where many contractors both contribute to risk and are exposed to it. The PSA will consider defining requirements more precisely in order to clarify different areas of responsibility, including the responsibility for systematic compliance with requirements which rests on each player within their area of responsibility, and what this involves for the supplier of products and services. It could also be relevant for the industry to review established practice related to the type, content and structure of contracts, as well as contractual relations and incentives, in order to assess whether management of major accident risk is taken sufficiently into account. Implementing an ambitious programme of studies and development related to tools for managing major accident risk could also be assessed. The main purpose could be to develop/identify appropriate decision -support tools in order to manage varying types of risk in various phases, for different conditions and types of decisions, at different levels, for different purposes and so forth. Initiating a process for identifying and prioritising the industry's need for better analysis tools could be considered in order to create ownership of such tool development. 40 Given recommendations made in the wake of the DwH accident, this work should include risk analysis processes and tools related to • the well planning phase (well design and drilling plan) 10 • the need for better handling of changes to the drilling plan during the operational phase. • Consideration must be given to monitoring the development work on risk analysis tools in these areas which is currently under way internationally in the wake of the DwH and Montara accidents, so that the best tools are implemented on the NCS. In this context, the best tools mean decision -support tools which can promote a good understanding of uncertainty in each business, identify relevant safety -critical priority areas, and prompt robust solutions. As mentioned above, the need has been identified for a greater diversity of risk analysis tools tailored for a number of requirements. It is important that consideration is also given to developing analysis tools which are better able to pick up changes in risk, as well as tools which can address non- technical barrier elements from a number of accident perspectives. An R&D commitment of this kind assumes that the industry itself takes the lead in initiating, financing and executing such work and seeks, to the greatest possible extent, to include more and preferably different discipline teams at Norwegian universities and research institutes. The government should be included as a key policy contributor, and users at various levels must contribute actively. This proposal should be discussed in greater detail with research institutes and the industry. The PSA believes that the DwH accident confirms the need for a continued commitment to a substantial improvement in barrier management by the Norwegian petroleum industry, with continued emphasis on work processes for barrier management from a life cycle perspective and a commitment by everyone concerned — including contractors and vessel owners. The DwH accident also confirms that improvements to barrier management should cover all types of barriers and all accident perspectives. The presidential commission gets across well that the route to improved management of major • accident risk in the petroleum industry goes through strong and competent players. Measures which could be relevant include government assessment of the financial capacity of the companies as a safety factor in player qualification and licence award processes government contributions, including through player qualification and licence award processes, to making company safety performance an important condition for securing access to business opportunities industry reviews of processes and criteria for qualifying suppliers of goods and services in light of experience from the DwH incident and earlier major accidents in order to assess whether management of major accident risk is taken sufficiently into account. The presidential commission's recommendations also confirm how important it is that the PSA continues to give priority to work on the RNNP and safety performance. The PSA is participating in an initiative by the International Regulators' Forum (IRF) aimed at harmonising some accident data internationally. The PSA may also consider whether the proportion of benchmarking in existing RNNP and safety performance work should be increased, and assess measures for ensuring that this work is utilised by more stakeholders. The route to improving the management of major accident risk in the Norwegian petroleum industry also goes through better administration of accident risk by the authorities. Relevant measures which affect the regulations, supervisory work, and monitoring risk trends and safety performance in the petroleum sector have already been mentioned. The need has also been identified to give continued priority to current work on developing risk analysis tools which are tailored to the government's role and • requirements, and which can help ensure that safety aspects are given greater weight in the competition between environmental and value creation considerations, and that major challenges related to regional factors which influence risk are addressed in a better way at an industry level. That includes a need for the PSA to give priority to 11 • continued methodological developments for describing accident risk in an area -based, long-term and social perspective • continued methodological developments for describing the social consequences of major accidents in the petroleum industry • a review of industry practice with regard to cost -benefit assessments used in practice in connection with risk -reduction decisions, including assessments of prevailing perspectives on the benefit of investing in safety measures and the need to adjust established practice. The PSA's report also notes that the financial consequences of the DwH accident have exceeded the costs of all previous accidents in the petroleum industry, and incentive structures and an unfortunate balance between safety and financial goals/cost-cutting appear to have been key underlying causes of the accident. This confirms that it will be relevant for the PSA and the industry to assess the measures listed above, and which affect, among other factors • the understanding of the way different (financial) incentives influence safety management • the quality of the information base which is intended to express the status of major accident risk and give early warning of dangerous developments • the perspective on and tools to express the benefit of investing in safety measures and achieving a more accurate pricing of risk • the safety aspect of decisions taken at company level • company self -assessments in general, and the involvement of audit functions in particular. The PSA highlights the fact that it is also important for Norway to secure good operating parameters for safety -related R&D, both in general and in connection with future petroleum operations in the country's far northern waters in particular. To achieve the government's goal of being a world leader in • HSE, consideration should be given to identifying the extent to which operating parameters for research in relevant areas are adequate, and whether these parameters make an adequate contribution to overcoming major challenges, achieving the big boosts or accomplishing the major technological leaps. In the PSA's opinion, research which is too fragmented and which lacks predictability and long-term operating parameters could be an obstacle to reaching the goal. The PSA has also registered that qualifying and implementing apparently good solutions often present a challenge. Consideration should accordingly be given to whether it would be possible, through the operating parameters provided for R&D, to make the route from idea to implementation and application of good solutions in the industry easier and shorter than it is today. It is considered relevant to propose a review of R&D by the Research Council of Norway to assess in part whether • concern for preventing major accidents and harm related to the working environment is an important driver for research (in connection with the qualification of technology development through Petromaks and Demo2000, for instance), or whether it has more the character of an "accidental" spin-off from other R&D • R&D related to major accident risk and the working environment is adequately prioritised and integrated • the balance between major accident risk and the working environment is appropriate • the balance between preventive and impact -reducing measures/solutions is appropriate. Studies could also be conducted into which instruments might promote safety -related R&D in the petroleum industry, and which might help to avoid new technology increasing the accident risk. 12 0 Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More Transocean Releases Macondo Investigation Report June 22, 2011 by offshoreenergy Summary Press Release: http://phx.corporate-ir.net/phoenix.zhtml?c=113031&p=irol- newsArticle&ID=1576865&highlight= Full Report: In 2 parts, 74 MB and 195 MB http://www.deepwater.com/fw/main/Public-Report-1076.htmi Animation of Transocean's BOP analysis is Transocean's BOP Defense: Forensic evidence from independent post -incident testing by Det Norske Veritas (DNV) and evaluation by the Transocean investigation team confirm that the Deepwater Horizon BOP was properly maintained and did operate as designed. However, it was overcome by conditions created by the extreme dynamic flow, the force of which pushed the drill pipe upward, washed or eroded the drill pipe and other rubber and metal elements, and forced the drill pipe to bow within the BOP. This prevented the BOP from completely shearing the drill pipe and sealing the well. In other words, Transocean contends that properly maintained BOPE was not up to the task of shutting -in and securing a high -rate well. If true, this finding has significant implications for the offshore industry. I'm looking forward to reading the government's findings on the BOP failure when the Joint Investigation Team report is issued next month. 0 Transocean :: Public Report Page 1 of 1 •OUR COMPANi Response Home Info News • C7 Internal Investigation Public Report BOP Video AMF Video Debris Retrieval Contact G... ma— / Contact Info / Site Map / Search Transocean Internal Investigation 4 Public Report Macondo Well Incident: Transocean Internal Investigation ® Report Files (PDF) - Macondo Well Incident: Transocean Investigation Report, Vol. I (Full Version.74 M6 • Macondo Well Incident Transocean Investigation Report, Vol. 11 .(Full Version 195 M8) Adobe PDF files require Acmbel Reader to view. Click hereto download QVideo Summaries • Blow- OutPreventer(BOP) • Automatic Mode Function (AMF) Inlerrwl Investigation Report by QupYr. Executive Summary Chapter 1. The Macondo Prospect and the Deepwater Horizon Chapter 2: Incident Chronology_ and Overview Chapter 3. Incident Analysis 3.1 Well Design and Production Ca Cement 3.2 Temporary Abandonment 3.3 Drill Floor Activities 3.4 Blow Out Preventer (BOP) 3.5 Gas Dispersion and Ignition 3.6 Muster and Evacuation Chapter 4:_ Key Findings ApperMkes: Appendix A_ Abbreviations and. Atxomym_ s Appendix BMacondo Casing. Calculations Appendix C: Testing of Cement Float Appendix D6. Centralization Plan at Macondo Appendix E Review of Macondo #1 7" x 9-7/8" Production Casing Cementation Appendix F. Lock -Down Sleeve Decision Appendix G Hydraulic Analysis of Macondo #252YJeI1 Prior to Incident of April 20 2010 Appendix H-. BOP Modifications Appendix I. BOP Maintenance History Appendix J: BOP Testing Appendix K. BOP Leaks Appendix L. Dnll Pipe in the BOP Appendix M. Structural Analysis of the Macondo #252 Wortt�t_ring Appendix N. AMF Testing Appendix O: Analysis of Solenoid 103 Appendix P: Deepwater Horizon InvestigIabon_t;3s Dispersion tudies Appendix Q. Possible _Ignition Sources References: Transocean Internal Investigation News Release Transocean's Response to the U.S. Coast Guard Draft Report Copyright O 2011 Transocean Ltd. http://www.deepwater.com/fw/main/Public-Report-1076.html 6/30/2011 Transocean Ltd.:: News Release Page 1 of 3 � I Transocean News Release Transocean Ltd. Announces Release of Internal Investigation Report on Causes of Macondo Well Incident ZUG, SWITZERLAND, Jun 22, 2011 (MARKETWIRE via COMTEX) -- Transocean Ltd. (NYSE: RIG) (SIX: RIGN) today announced the release of an internal investigation report on the causes of the April 20, 2010, Macondo well incident in the Gulf of Mexico. Following the incident, Transocean commissioned an internal investigation team comprised of experts from relevant technical fields and specialists in accident investigation to gather, review, and analyze the facts and information surrounding the incident to determine its causes. The report concludes that 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 likelihood of its failure. The decisions, many made by the operator, BP, in the two weeks leading up to the incident, were driven by BP's knowledge that the geological window for safe drilling was becoming increasingly narrow. Specifically, BP was concerned that downhole pressure -- whether exerted by heavy drilling mud used to maintain well control or by pumping cement to seal the well -- would exceed the fracture gradient and result in fluid losses to the formation, thus costing money and jeopardizing future production of oil. The Transocean investigation team traced the causes of the Macondo incident to four overarching issues: -- Risk Management and Communication: Evidence indicates that BP failed to properly assess, manage and communicate risk to its contractors. For example, it did not properly communicate to the drill crew the • absence of adequate testing on the cement or the uncertainty surrounding critical tests and procedures used to confirm the integrity of the barriers intended to inhibit the flow of hydrocarbons into the well. It is the view of the investigation team that the actions of the drill crew on April 20, 2010, reflected the crew's understanding that the well had been properly cemented and successfully tested. -- Well Design and Construction: The precipitating cause of the Macondo incident was the failure of the downhole cement to isolate the reservoir, which allowed hydrocarbons to enter the wellbore. Without the failure of the cement barrier, hydrocarbons would not have entered the well or reached the rig. While drilling the Macondo well, BP experienced both lost circulation events and kicks and stopped short of the well's planned total depth because of an increasingly narrow window for safe drilling, specifically a limited margin between the pore pressure and fracture gradients. In the context of these delicate conditions, cementing a long -string casing would increase the risk of exceeding the margin for safe drilling. But rather than adjusting the production casing design to avoid this risk, BP adopted a technically complex nitrogen foam cement program that allowed it to retain its original casing design. The resulting cement program was of minimal quantity, left little margin for error, and was not tested adequately before or after the cementing operation. Further, the integrity of the cement may have been compromised by contamination, instability and an inadequate number of devices used to center the casing in the wellbore. -- Risk Assessment and Process Safety: Based on the evidence, the investigation team determined that BP failed to properly require or • confirm critical cement tests or conduct adequate risk assessments during various operations at Macondo. Halliburton and BP did not adequately test the cement slurry program, despite the inherent complexity, difficulties and risks associated with the design and implementation of the program and some test data showing that the http://phx.corporate-ir.net/phoenix.zhtml?c=l 13031&p=irol-newsArticle_print&ID=15768... 6/30/2 011 Transocean Ltd.:: News Release Page 2 of 3 cement would not be stable. BP also failed to assess the risk of the temporary abandonment procedure used at Macondo, generating at least • five different temporary abandonment plans for the Macondo well between April 12, 2010 and April 20, 2010. After this series of last-minute alterations, BP proceeded with a temporary abandonment plan that created unnecessary risk and did not have the required approval by the MMS. Most significantly, the final plan called for underbalancing the well before conducting a negative pressure test to verify the integrity of the downhole cement or setting a cement plug to act as an additional barrier to flow. It does not appear that BP used risk assessment procedures or prepared Management of Change documents for these decisions or otherwise addressed these risks and the potential adverse effects on personnel and process safety. -- Operations: -- Negative Pressure Test: The results of the critical negative pressure test were misinterpreted. Post -incident investigation determined that the negative test was inadequately set up because of displacement calculation errors, a lack of adequate fluid volume monitoring, and a lack of management of change discipline when the well monitoring arrangements were switched during the test. It is now apparent that the negative pressure test results should not have been approved, but no one involved in the negative pressure test recognized the errors. BP approved the negative pressure test results and decided to move forward with temporary abandonment. The well became underbalanced during the final displacement, and hydrocarbons began entering the wellbore through the faulty cement barrier and a float collar that likely failed to convert. None of the individuals monitoring the well, including the Transocean drill crew, initially detected the influx. • -- Well Control: With the benefit of hindsight and a thorough analysis of the data available to the investigation team, several indications of an influx during final displacement operations can be identified. Given the death of the members of the drill crew and the loss of the rig and its monitoring systems, it is not known which information the drill crew was monitoring or why the drill crew did not detect a pressure anomaly until approximately 9:30 p.m. on April 20, 2010. At 9:30 p.m., the drill crew acted to evaluate an anomaly. Upon detecting an influx of hydrocarbon by use of the trip tank, the drill crew undertook well -control activities that were consistent with their training including the activation of various components of the BOP. By the time actions were taken, hydrocarbons had risen above the blowout preventer and into the riser, resulting in a massive release of gas and other fluids that overwhelmed the mud gas separator system and released high volumes of gas onto the aft deck of the rig. The resulting ignition of this gas cloud was inevitable. -- Blowout Preventer (BOP): Forensic evidence from independent post -incident testing by Det Norske Veritas (DNV) and evaluation by the Transocean investigation team confirm that the Deepwater Horizon BOP was properly maintained and operated. However, it was overcome by the extreme dynamic flow, the force of which pushed the drill pipe upward, washed or eroded the drill pipe and other rubber and metal elements, and forced the drill pipe to bow within the BOP. This prevented the BOP from completely shearing the drill pipe and sealing the well. -- Alarms, Muster, and Evacuation: In the explosions and fire, the general alarm was activated, and appropriate emergency actions • were taken by the Deepwater Horizon marine crew. The 115 personnel who survived the initial blast mustered and evacuated the rig to the offshore supply vessel Damon B. Bankston. http://phx.corporate-ir.net/phoenix.zhtml?c=113031&p=irol-newsArticle_print&ID=15768... 6/30/2011 Transocean Ltd.:: News Release Page 3 of 3 • • The Transocean internal investigation team began its work in the days immediately following the incident. Through an extensive investigation, the team interviewed witnesses, reviewed available information regarding well design and execution, examined well monitoring data that had been transmitted real-time from the rig to BP, consulted industry and technical experts, and evaluated available physical evidence and third -party testing reports. The loss of evidence with the rig and the unavailability of certain witnesses limited the investigation and analysis in some areas. The team used its cumulative years of experience but did not speculate in the absence of evidence. The report of the team does not represent the legal position of Transocean, nor does it attempt to assign legal responsibility or fault. The investigation report and supporting documents are available on the homepage of the Company's website at www.deepwater.com. About Transocean Transocean is the world's largest offshore drilling contractor and the leading provider of drilling management services worldwide. With a fleet of 138 mobile offshore drilling units as well as three high -specification jackups under construction, Transocean's fleet is considered one of the most modern and versatile in the world due to its emphasis on technically demanding segments of the offshore drilling business. Transocean owns or operates a contract drilling fleet of 47 High -Specification Floaters (Ultra-Deepwater, Deepwater and Harsh -Environment semisubmersibles and drillships), 25 Midwater Floaters, nine High -Specification Jackups, 53 Standard Jackups and other assets utilized in the support of offshore drilling activities worldwide. For more information about Transocean, please visit our website at www.deepwater.com. SOURCE: Transocean Ltd. http://phx.corporate-ir.net/phoenix.zhtml?c=113031&p=irol-newsArticle print&ID=15768... 6/30/2011 Bud's Offshore Energy (BOE) Energy Production, Safety, Pollution Prevention, and More SINTEF Deepwater Horizon Report — Executive Summary http://budsoffshoreeneru.wordpress.com/2011/06/29/sintef-deepwater-horizon- repo rt-executive-summary/ June 29, 2011 by offshoreenergy SINTEF has provided a copy of the Executive Summary (English) of their Deepwater Horizon report. I suggest that you take a few minutes and read this excellent eleven page document. The full report (Norwegian) can be found here. http://www. sintef.no/upload/Konsem/Media/Deepwater%20Horizon%20- %20SINTEF 23.06.11.pdf Comprehensive experience from previous accidents has taught us that two events are never identical. It is therefore somewhat futile to question whether the same course of events that took place on Deepwater Horizon could have happened in the Norwegian petroleum activity. We can, however, conclude that our own offshore industry generally faces the same challenges and the same hazards, and we therefore need to maximize lessons learned from the DWH accident in order to avoid similar accidents in the Norwegian petroleum activity. Well said! 0 • SINTEF on avoiding disasters June 29, 2011 by offshoreenergy (5)) SINTEF SINTEF researchers have studied the Macondo findings and issued a news release (link provided by BOE's Cheryl Anderson). http://www. sintef.no/home/Press-Room/Research-News/New-skills-needed-to-avoid- major-disasters/ I thought this quote from safety researcher Ranveig Kviseth Tinmannsvik was interesting in light of our ongoing discussion on low frequency, high consequence events: "From now on, the challenge will be to develop resilient organisations in which everyone has a good understanding of risk. At the same time, people need to have sufficient insight to enable them to handle unexpected situations and improvise safely and effectively in critical situations. Or, to put it in other words; we need to develop the ability to deal with unexpected situations that are not captured by risk analyses. Although current risk analysis methods provide a good basis for decision -making in the design phase, we still • lack methods that offer us good support for making safety -critical decisions during operations. " 0 0 (N S I NTEF Rapport Deepwater Horizon-ulykken: O Arsaker, laerepunkter og forbedrings- tiltak for norsk sokkel The Deepwater Horizon accident: Causes, learning points and recommendations for the Norwegian continental shelf . Executive summary • Tinmannsvik, R.K., Aibrechtsen, E., Bratveit, M. (UiB), Carisen, I.M., Fylling, I. (MARINTEK), Hauge, S., Haugen, S. (NTNU), Hynne, H., Lundteigen, M.A. (NTNU), Moen, B.E. (UiB), Okstad, E., Onshus, T. (NTNU), Sandvik, P.C. (MARINTEK) og Bien, K. Kilde: Getty Images SINTEF Mai 2011 N SINTEF Executive summary Background and objective On April 20, 2010, an uncontrolled blowout of oil and gas occurred on the Deepwater Horizon drilling rig, in the Gulf of Mexico off the Louisiana coast. The accident caused the loss of 11 lives and the resulting environmental oil spill has been estimated to almost 5 million barrels. As a response to the Deepwater Horizon accident, hereafter referred to as the DWH accident, a number of investigations and studies have been carried out, some of them still ongoing. The Petroleum Safety Authority (PSA) Norway appointed a separate group for follow-up of the accident. The present report has been prepared by SINTEF as part of this work. Our mandate has been to "review and systematise information from Deepwater Horizon investigation reports and from other major accidents in the petroleum industry. The main purpose has been to contribute towards 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. Lessons learned and recommendations • Lessons learned - Norwegian petroleum industry When experiencing accidents like Deepwater Horizon, an obvious question is how could so much go wrong at the same time? Or said in another way; how could so many safety barriers possibly fail simultaneously? Answering this question is not straightforward, but two important aspects which are closely related are; how to maintain control of the barriers and how to manage an increasing degree of complexity. Drilling and well operations differ from many other offshore operations by the dynamic nature of the safety challenges and the large number of different operations throughout the various phases of the well's lifecycle. It is therefore challenging to maintain overview and control with all the barriers throughout the various lifecycle phases, including modifications and other changes. A number of control questions should therefore be asked. Are the specific barriers related to drilling and well operations generally adequate? Are our safety management systems appropriate to ensure control of the barriers through the entire lifetime of the well? Do the barriers fulfil the regulatory requirement concerning functional independence? And what about the performance requirements - are they strict enough? When studying why barriers related to drilling and well operations fail, increasing degree of complexity is often found to be a common characteristic. This can be exemplified by; a large number of involved actors must interact, frequent reorganisations and new work processes, rapid technological advances in terms of deeper wells and more complex reservoirs. Hence, it is no wonder that offshore drilling into complex reservoirs is often referred to as a continuous process of problem -solving where new and unexpected situations arise and must be managed on the spot. This increasing complexity results in new demands on how we think about safety and it has been questioned whether safety research has failed to keep pace with the otherwise rapid technological development. It is therefore our opinion that a joint effort is required to initiate new advances within the safety research discipline. Furthermore, we need innovative thinking concerning how to cope with the unexpected - i.e. situations that can occur, but has not been considered or planned for. Hence, we need to improve our capabilities to interact and make decisions in an environment of increasing isdegree of complexity and uncertainty. SINTEF A19148, Mai 2011 OO SINTEF • Operational decisions that are critical to maintain well integrity are often subject to challenging framework conditions and decision makers are frequently faced with conflicting interests between production and safety. Time pressure may be another disturbing factor, e.g. due to heavy workload, last minute changes of plans, or situations where operation is suspended until a decision is made. The investigation reports further reveal that the competence of the decision makers is a crucial aspect in order to maintain well integrity, not only related to individual skills, but also the ability of the decision maker to mobilise competent personnel when making critical decisions. Recommendations for the industry Based on the investigation reports from the DWH accident and other relevant accidents and incidents, SINTEF recommends to implement the following measures in the Norwegian petroleum activity (not in prioritised order): 1. Update NORSOK D-010 "Well integrity in drilling and well operations" with respect to the cement as a primary barrier, and the use of new technology. • Why: Failure of the cement barrier and the lack of adequate qualification was an important direct cause of the DWH accident and Montara accident. Shortcomings in relation to application of new technology (such as "managed pressure drilling") were a contributing cause to the Gullfaks C incident. • How: NORSOK D-010 should be updated in terms of improved procedures for planning, mixing, pumping and qualification of cement as a primary barrier. The method of placement and qualification of cement as a primary barrier should be better described. Moreover, the standard should be updated based on existing new technologies. • Objective: An improved best practice will increase understanding of the criticality of cement • as the primary barrier and increase the likelihood of successful cementing. Description of best practices regarding new technologies will increase the likelihood of safe applications. • 2. Improve the understanding of a comprehensive strategy for barrier control, including the application of the principle of two independent and tested well barriers, and the monitoring of these. • Why: The likelihood of effectively aptivating the secondary barrier is time critical. It is therefore important to detect warnings of an abnormal situation as soon as possible. Inadequate monitoring was a key factor leading up to the DWH accident, as well as the Snorre A and Gullfaks C incidents. • How: Adopt or develop operational tools (e.g. well barrier schematics) that can provide the different actors with simple visual aids, including descriptions of monitoring methods for each defined barrier element. • Objective: To enable activation of the secondary barrier as early as possible following a failure in the primary barrier. 3. By considering drilling operations on an individual basis, evaluate whether the present blowout preventers (BOP) design with single blind shear ram (BSR), is acceptable. • Why: The present BOP design impose some operational limitations such as lack of ability to cut through tool joints. It is not clear how the industry evaluate these limitations with respect to the criticality of individual operation. • How: Evaluate the criticality of drilling and well operations taking into consideration aspects such as water depth, location of BOP, complexity of reservoir, vulnerability of area, etc. • Objective: Increased reliability of BOP and reduced risk related to critical drilling and well operations. SINTEF Al9148, Mai 2011 OO 51 NTEF • 4. Consider the need for new requirements and guidelines on design and operation of the diverter system in order to minimise the likelihood of mal-operation. • Why: In case of BOP failure and a topside blowout, the diverter system appears as the "last line of defence" with respect to reducing the amount of flammable hydrocarbons on the rig. The possibility of mal-operating the system therefore needs to be minimised. • How: Review today's systems and update relevant standards to reflect best available technology (BAT). In general, when activating the diverter system it should only be possible to route the flow overboard. • Objective: Reduce the likelihood of igniting a topside blowout. 5. Review safety instructions to ensure water tightening, as well as instructions for testing of doors and other passages through deck and bulkheads that are assumed to be watertight. • Why: Unintentional flooding of compartments is the main cause for disasters due to stability loss. • How: Establish company routines that insure integrity, including e.g. monthly control and reporting. • Objective: Reduce risk of stability loss. 6. Follow-up on a regular basis the drilling contractors' progression in managing the maintenance backlog. • Why: On Deepwater Horizon the operating company had to follow-up the drilling contractor's management of the maintenance backlog actively and systematically in order to reduce the backlog. This demonstrates the importance of active involvement by the operating company. • • How: Regular (for instance weekly) meetings between the operating company and the drilling contractor to review status and plans for managing the maintenance backlog. • Objective: Control of the extent of maintenance backlog, particularly on safety critical equipment. Consider developing improved methods for managing different types of blowouts. • Why: The DWH accident illustrates that upon BOP failure there are not many alternatives to drilling of a relief well, which is a very time-consuming endeavour. The industry should consider developing other possible solutions before a new accident occurs. Such a development should not only take place as trial and error during an accident. • How: Learn from, and contribute to the development that has taken place during and after the DWH accident, including development of equipment such as a well -capping device. The work should include methods, equipment, competence, training and exercises. • Objective: Faster control of a blowout. 8. Improve organisational and individual awareness and abilities to detect early warnings on lack of control. • Why: Monitoring and interpretation of danger signals are important means to detect lack of control and thus make it possible to handle situations before serious incidents occur. Both monitoring and interpretation of danger signals was inadequate in the period before the first explosion on the Deepwater Horizon. • How: R&D -activities based on the following general recommendations: create awareness of risky situations in normal operations; encourage scepticism and the ability to ask critical questions; and evaluate technological solutions that make faster detection of danger signals and errors possible. • Objective: Improved awareness and ability to detect and react to early warnings on lack of control. SINTEF Al9148, Mai 2011 OO SINTEF is9. Facilitate improved competency and a better working situation for personnel who make safety critical decisions in drilling and well operations. • Why: Different accident investigations have identified needs for structured competency building and improvement of the working situation for personnel who make safety critical decisions in drilling and well operations. Inadequate competency and a demanding working situation contributed to a series of failures and misjudgements at the DWH accident. • How: Develop requirements for training and education for personnel who make safety critical decisions in drilling and well operations. Review the working situation for this group of personnel, including the organisational structure for today's drilling and well operations. • Objective: Ensure that personnel in safety critical functions have adequate competency and a working situation that enables them to perform their functions in a safe manner. 10. Improve the flow of information and the collaboration between different actors; secure support from onshore experts in safety critical decisions and operational tasks. • Why: Breakdown in the flow of information is a contributing factor to most major accidents, including blowouts at Deepwater Horizon, Montara, Snorre A and Gullfaks C. • How: Ensure that offshore personnel maintain adequate communication with the correct onshore teams and are aware of their own information needs; develop and implement tools for validation of flow of information and secure adequate interpretation of information; R&D -activities to generate knowledge on how new ICT-based working processes influence major accident risk. • Objective: Ensure adequate decision support during safety critical situations by flow of information and collaboration between actors. • 11. Develop new methods and tools for risk evaluation, which, in a better manner than today, can support operational personnel in everyday decisions. • Why: Today's methods are too static, too comprehensive or do not focus sufficiently on the risk for major accidents. The individual need for decision support in a complex and dynamic working -day environment should to a larger degree govern the development of future methods. • How: R&D -initiative to develop user friendly methods for risk evaluation and decision making support. The methods should among other things, focus on increased awareness related to the state of the safety barriers, dependencies and connections between the barriers, and the effect of changes during drilling and well operations. • Objective: Develop simple and user friendly methods that support operational personnel in terms of better insight and understanding of the consequences from various decisions. 12. Develop safety management strategies that both ensure compliance to requirements, as well as resilient abilities to adapt to changes, to both handle anticipated and unanticipated situations. • Why: In drilling and well operations a wide range of demanding situations can occur. Different strategies are required to deal with this variability. One approach constitutes development, implementation and compliance to requirements. However, there is also a need to make organisations resilient so that they can adapt to different situations quickly and thus bounce back and normalise the situation. How: R&D -activities to identify which critical elements (actions, processes and resources) that must be in place to adapt to changes in assumptions and situations in drilling and well operations, including unexpected situations that may occur during operation. Objective: Identify actions and processes that create resilient drilling and well operations, including management strategies for such operations (e.g. training; communication, risk management and monitoring). 4 SINTEF Al9148, Mai 2011 OO SINTEF 13. Facilitate the systematic exchange of experience and learning from incidents in various industries (globally). • Why: Investigations of accidents and incidents often show repeating underlying causes, and the industry is being criticized for lack of experience transfer and learning from incidents. • How: The industry should establish a "learning unit" - internally or externally - with responsibility for reviewing accidents and incidents, and for dissemination of lessons learned to the industry and authorities. In addition to learning from what went wrong, it is important to learn from the successful recovery of situations that were about to get out of control. One can take advantage of experiences from a similar initiative in the French nuclear industry. • Objective: Improve the industry's ability to apply knowledge about the causes of adverse events and successful recovery, in order to implement effective measures in their own organisation ("learning to learn"). Recommendations for the authorities SINTEF considers the following recommendations as being most important for the Norwegian authorities (not in prioritised order): 1. For critical operations, consider to require increased redundancy of BOPS, as for example double blind shear ram (BSR) or single BSR that works in all conceivable scenarios. • Why: Today's design has operational limitations e.g. related to cutting of tool joints. • How: Depending on the type of operation (topside or subsea BOP, complexity of reservoir, vulnerability of area, etc.) consider the need for stricter BOP requirements through regulations. • • Objective: Reduce the risk related to critical drilling and well operations. 2. Ensure and follow-up that the companies have implemented performance requirements (including reliability requirements) for critical safety functions related to drilling and well operations, and verify that these requirements are followed -up during operation. • Why: Regulations already state that performance requirements for safety critical equipment shall be stipulated and followed -up during operation, but this is not consequently implemented by the companies. • • How: Through supervision verify that the companies (1) stipulate performance requirements and (2) follow-up these requirements. In particular, consider systems for kick detection, diverter system, mud treatment system and BOP. • Objective: Ensure required integrity of barriers during drilling and well operations. Revise the Stability Code, to ensure integrity of water tight compartments. • Why: System errors and operational errors are main causes for incidents of stability loss. • How: Requirements to internal log documentation when watertight doors etc. need to remain open longer than a defined maximum duration. Requirements to periodical control and reporting. • Objective: Reduce risk of stability loss. Maintain continuous focus on maintenance management through audits and dialogue with the industry. • Why: Inadequate maintenance is a recurring contributing cause of major accidents. Many installations on the Norwegian Continental Shelf extend their lifetime after a period of controlled phase out and reduced maintenance. As a result, they have built up a substantial amount of backlog. SINTEF Al9148, Mai 2011 N SINTEF • • How: Auditing the companies' maintenance management, including management of maintenance backlog. Contribute in further development of maintenance management on the Norwegian Continental Shelf, through dialogue with the industry. • Objective: Improved maintenance management in general, and justifiable (risk based) amount of backlog in particular. 5. Provide for necessary competence regarding well control methods, to enable the authorities to follow-up the decision processes in the companies on well control accidents of national significance. • Why: During the DWH accident the authorities were criticized for not contributing actively in controlling the runaway well. Some of the well control attempts could have made the situation worse, and required approval by the authorities. A competent authority is a prerequisite for such approvals. • How: By the exchange of experience on well control measures attempted during the DWH accident, and by stimulating research and development in this field. • Objective: Fast and proper control of a blowout. Basis For recommendations What happened on Deepwater Horizon? On April 20, 2010, the Deepwater Horizon drilling rig was about to complete its work on the Macondo exploratory oil well - 79 kilometre off the Louisiana coast in the Gulf of Mexico. Around 9 pm the well however started to get out of control, and some 45 minutes later large amounts of drilling mud, oil and gas was sprayed onto the drill floor. This was later described by one of the survivors: "as a freight train coming • through my bedroom and then there was a thumping sound that consecutively got much faster and with each thump, I felt the rig actually shake". A few minutes later the first explosion occurred, then another huge explosion, followed by fires and more explosions. Of the 126 people onboard Deepwater Horizon, eleven crew members died. The rig burned for one and a half day before sinking, and for another 87 days oil blew out from the well at the seabed some 1.500 meter below sea level. The largest oil spill in U.S. history was a fact — about 20 times larger than the oil spill from Exxon Valdez when it ran aground off the coast of Alaska in 1989. Blowout response On the rig an inferno of heat, smoke and flames developed, and the surviving crew members soon abandoned any efforts to control the event. They evacuated using lifeboats, a life raft and by jumping overboard, and were taken onboard the supply vessel Damon B. Bankston, which was located alongside Deepwater Horizon. The U.S. Coast Guard entered the scene fairly quickly and various vessels and aircrafts were mobilised to search for missing personnel and to reduce the consequences of the fire. As the seriousness and extent of the event became apparent to the American people, the accident became breaking news in the weeks to follow. The U.S. Government and President Obama engaged themselves in stopping the blowout and collecting the oil. In particular, Secretary of Interior Ken Salazar and Secretary of Energy Steven Chu got directly involved. On the seabed the well blew out through the blowout preventer (BOP) which was installed to stop a blowout, but failed to do so. In such a situation there are no quick -fixes to shut in the well and stop the flow. The only "proven" method is to drill a relief well, which for deep wells can take several months. Meanwhile a number of innovative solutions were attempted, developed more or less on the spot. Finally, one succeeded to stop the well flow by using a purpose made "BOP capping stack" on top of the ordinary BOP. 87 days had then • elapsed since the blowout started and almost 5 millions barrels of oil had gushed into the Gulf of Mexico. SINTEF Al9148, Mai 2011 N SINTEF • In mid -September, when the first relief well intercepted the Macondo well, BP was able to pump in cement and permanently seal the reservoir. On September 19, 152 days after the blowout, Admiral Allen could announce that the well was effectively dead. Why did the accident on Deepwater Horizon occur? Deep wells and operations in ultra-deepwater areas (> 1.500 m) require extensive planning and preparations. Further, the complex operations require that the various actors interact effectively. However, there were no conditions at Macondo, related to the underground, water -depth or the environment that were too exceptional to manage. Well qualified and internationally leading companies were involved and had previous experience from similar prospects. Therefore, the drilling and well operations should have been carried out safely. However, BPs safety reputation had become somewhat frayed as a result of accidents such as the Texas City refinery explosion in 2005 and the Prudhoe Bay pipeline leak in 2006. The DWH accident did not happen as a result of one crucial misstep or a single technical failure, but as a result of a series of events, decisions, misjudgements and omissions that reveal a systemic breakdown. Important direct causes Important direct causes of the DWH accident: 1. The cement outside the production casing and at the bottom of the well (at the "shoe track") did not prevent influx from the reservoir 2. The crew misinterpreted the result of the negative pressure test and considered the well as being properly sealed 3. The crew did not respond to the influx of oil and gas before hydrocarbons had entered the riser • 4. The crew routed the hydrocarbons to the mud gas separator instead of diverting it overboard 5. The fire and gas system did not prevent ignition 6. The BOP did not isolate the wellbore and the emergency methods available for operating the BOP also failed In order to avoid collapse of the wellbore and prevent uncontrolled influx of oil and gas, the wellbore is reinforced with pipes of steel — casing — which are anchored with cement on the outside. Cement is also used at the bottom of the well to avoid influx of oil and gas from below. However, the cement outside the production casing and at the bottom of the well (at the "shoe track') did not prevent influx from the reservoir. Oil and gas escaped through the cement and up through the casing. In order to test the integrity of the well including the bottom -hole cement, a "negative pressure test" was conducted by displacing drilling mud, thereby creating under pressure — negative pressure — in the well. Influx of hydrocarbons would then be an indication of something wrong. However, the crew misinterpreted the result of the negative pressure test. The test indicated influx of oil and gas (i.e. a "kick") but the crew considered the well as being properly sealed. Oil and gas had started flowing into the well, but the crew did not respond to the influx before hydrocarbons were already above the subsea BOP and expanding up through the drilling riser towards the rig. Indications of influx were detectable some 45 minutes before the crew responded. When finally doing so, they attempted to close the BOP and then routed the hydrocarbons to the mud gas separator instead of diverting it overboard. However, the mud gas separator had insufficient capacity to handle the large flow from the well, and the gas quickly overwhelmed the separator and escaped through gas vent lines, discharging onto the rig. Here, it encountered a number of potential ignition sources, first on the drill floor and subsequently in the engine rooms. The fire and gas system did not prevent ignition of the flammable gas cloud, partly due to the size of the gas cloud, but also since equipment were bypassed and/or defective. Manual action in terms of closing • ventilation inlets to the main engine rooms were not taken, neither from the driller's control panel nor the bridge. The BOP did not isolate the well and the blowout continued. After the explosion the emergency SINTEF Al9148, Mai 2011 OO SINTEF • methods available for operating the BOP also failed. The cause of BOP failure is not finally concluded, but a main theory is that the drill pipe was elastically buckled within the wellbore and was partly outside the shearing blade surfaces of the blind shear ram. Important underlying causes Important underlying causes of the accident: 1. Ineffective leadership 2. Compartmentalisation of information and deficient communication 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/instrumentation 7. Failure to appropriately analyse and appreciate risk 8. Focus on time and costs rather than control of major accident risks Most of the events and missteps related to the Deepwater Horizon disaster can, according to the President Commission, be traced back to an overarching failure of management and communication. As an example the BP's onshore team was aware of the cementing -related risks, but did not emphasise them to the individuals conducting the negative pressure test. Correspondingly, BP's drilling supervisor did not contact onshore experts regarding the dubious results from the negative pressure test. The report from the Chief Council further identifies a number of managerial deficiencies including failure to provide timely procedures and poor training and supervision of contractors. As an example neither BP nor • Transocean had any internal, formal procedures on how to carry out and interpret the results from the negative pressure test, and they did not provide any formal training on how to properly conduct and interpret a negative pressure test. The report further points to ineffective management and oversight of contractors; Although BP was aware of uncertainties related to how Halliburton conducted their cement tests, they did not sufficiently compensate these weaknesses. Inadequate use of technology/instrumentation was also identified. Well monitoring equipment on the Deepwater Horizon was inadequate, and neither did BP nor the other companies utilise the information from available data displays and monitoring equipment adequately. This contributed towards the crew's failure to timely detect the kick. Failure to appropriately analyse and appreciate risk is clearly expressed when the President Commission concludes that "the immediate causes of the Macondo well blowout can be traced to a series of identifiable mistakes made by BP, Halliburton, and Transocean that reveal such systematic failures in risk management that they place in doubt the safety culture of the entire industry". BP's management system required separate risk analyses to be conducted during the planning phase of the well, but not during the execution phase. Critical decisions were therefore made during the execution phase without any formal risk evaluations. At the same time the crew was working with a mindset that they were aware of all the hazards, whereas in fact they were probably not capable of keeping oversight of the hazards, i.e. they had an inadequate risk perception. BP focused on time and costs rather than control of major accident risks. BP made a number of decisions with the priority of time and cost savings over safety. By the time of the blowout the operation was 38 days delayed and an estimated $58 million above budget. This may explain the lack of focus on assuring well integrity. On the day of the accident the crew on Deepwater Horizon was congratulated by representatives • from BP management for achieving seven years of drilling without any "lost time incidents". The SINTEF A19148, Mai 2011 N SINTEF isinvestigation of the Texas City explosion in 2005 revealed that BP has had a strong focus on personal safety, put less attention to process safety. Could this have happened in the Norwegian petroleum activity? Every accident is unique, as is also the case for the Macondo blowout. However, many of the causal factors have similarities to previous accidents and incidents. This applies for the Montara accident in Australia in 2009, the Snorre A incident in 2004 and the Gullfaks C incident in 2010. The two latter events are of particular interest since they exemplify that things can go wrong also on the Norwegian sector, and only narrow margins saved us from major blowouts. The direct causes of accidents often differ, but many of the underlying causes are identified as recurring problems. Examples of such problems are inadequate verification of the well barriers, failure to perform risk evaluation during changes and modifications, and lack of involvement and follow-up by management. The oil industry is global, and various actors and facilities move between countries, adapting to national regulations if required. However, the design standards very often have a common basis, e.g. represented by the American API -standards. There are however a number of differences, related to for example type of regulatory regime (balance between prescriptive requirements and functional requirements) and regulations. There are also differences between standards since the Norwegian petroleum industry has developed their own NORSOK standards. Furthermore, there are differences with respect to operational practice and safety culture. Comprehensive experience from previous accidents has taught us that two events are never identical. It is therefore somewhat futile to question whether the same course of events that took place on Deepwater Horizon could have happened in the Norwegian petroleum activity. We can, however, conclude that our own isoffshore industry generally faces the same challenges and the same hazards, and we there ore need to maximise lessons learned from the DWH accident in order to avoid similar accidents in the Norwegian petroleum activity. Major safety improvements are required The President Commission identifies the need for major changes both with respect to how the petroleum industry is being regulated by authorities, as well as changes within the industry itself. Concerning the authorities, the President Commission claims that fundamental reforms are necessary, both concerning the structure of the bodies that are responsible for regulating the industry, as well as internal decision making processes within these bodies themselves. According to the Commission this is necessary to assure the independence and technical expertise of government institutions, and to receive full attention on environmental concerns from these institutions. As examples the President Commission here mentions Norway and U.K. Concerning the petroleum industry itself, the President Commission challenges the industry to find measures and make decisions to increase the safety level dramatically. This includes the implementation of self - policing mechanisms that supplement governmental enforcement. In Norway we must — by any means — avoid taking a defensive position by claiming that everything is much better here. Rather we should seize this opportunity to learn from the DWH accident. If we do, this may initiate a major effort for improving safety also in the Norwegian petroleum activity. SINTEF's assignment The DWH accident involved some major, global actors (BP, Transocean and Halliburton) and the media attention and coverage have been massive. As a result, the accident is likely to affect both the global and the Norwegian petroleum industry. In Norway, this is reflected by the increased attention given to operations in • the northern areas, increased focus on accidents and incidents in the Norwegian petroleum activity and the demands for a more stringent safety regime also in the Norwegian petroleum sector. SINTEF A19148, Mai 2011 0 N SINTEF The Petroleum Safety Authority (PSA) Norway appointed a separate group for follow-up of the DWH accident, and assigned SINTEF to conduct a systematic review of literature and investigation reports from this accident and other major accidents in the petroleum industry. The objective has been to provide a better knowledge base, to give a foundation for understanding major accidents in general, and to broaden the perspective on the DWH accident. The PSA wanted an overall consideration of causal factors and potential areas of improvement and particularly requested an evaluation of human and organisational factors. This work shall contribute towards lessons learned and improvements in order to prevent similar accidents in the Norwegian petroleum industry. The work has been limited to analysing investigation reports and other available documentation from blowouts, well incidents and incidents involving loss of stability. Hence, SINTEF has not performed a separate investigation and data collection. The DWH accident is the fundament of this project and constitutes approximately 80 % of the documen- tation reviewed. In addition, SINTEF has made comparisons with some other important accidents and incidents in the petroleum industry, including the Montara blowout off the coast of Australia in August 2009, the Snorre A blowout in November 2004 and the Gullfaks C well incident in May 2010. The project is limited by areas being under PSA's regulatory responsibility. Lessons learned and recommendations related to the clean-up phase, being under the responsibility of the Climate and Pollution Agency and The Norwegian Coastal Administration, are not a part of this project. Conclusions in this report are based on the content of the investigation reports and other information • available as of April 20, 2011. Hence, the report has been finalised without the results from the BOEMRE/U.S. Coast Guard joint investigation report (expected by July 2011), and the report from the Chemical Safety Board (CSB) (expected by June 2012). • SINTEF has reviewed and categorised a total of 134 recommendations from Deepwater Horizon investi- gation reports. In addition, recommendations from the Montara blowout, the Snorre A blowout and the well incident at Gullfaks C have been considered. A majority of the recommendations are related to management and organisation, as well as drilling and well technology. These recommendations, together with input from the Project Reference Group, PSA personnel, other experts and the project group's general knowledge about the industry, constitute the basis for the recommendations to the Norwegian petroleum activity. Within the discipline of management and organisation, different perspectives on major accidents and resilient organisations have also been applied in recommending improvements. 10 SINTEF A19148, Mai 2011 Bud's Offshore Enemy (BOE) Energy Production, Safety, Pollution Prevention, and More http://onlinepubs.trb.ort!/onlinepubs/sr/srSEMSlnterimReport.pdf Interim Report on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations June 30, 2011 by offshoreenergy This National Academies Marine Board Report was commissioned and initiated prior to the Macondo, but the task statement (Appendix Q was revised after the blowout. The final report with recommendations is due in the fall. • 0 0 Interim Report Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations C7 Transportation Research Board of The National Academies 2011 • WRA1131 TRANSPORTATION RESEARCH BOARD OF THE NATIONAL ACADEMIES June 24, 2011 Mr. Douglas Slitor Acting Chief, Office of Offshore Regulatory Programs Bureau of Ocean Energy Management, Regulation, and Enforcement 381 Elden Street Herndon, VA 20170 Subject: Interim Report on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations Dear Mr. Slitor: In response to a request of the Minerals Management Service (MMS)—now the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE)--the . Marine Board, under the auspices of the Transportation Research Board of the National Academies, formed a committee that is examining methods for assessing the effectiveness of an operator's Safety and Environmental Management Systems (SEMS) program on any given offshore drilling or production facility. The committee membership includes National Academy of Engineering (NAE) members and practitioners and academicians who bring a broad spectrum of expertise that includes the areas of safety management, human factors, risk assessment, organizational management and management systems, offshore engineering, offshore platform design and construction, offshore operations, and policy as well as the areas of safety regulations and inspections in related industries (see Appendices A and B). This letter constitutes the interim letter report required in the committee's revised statement of task, dated January 31, 2011 (see Appendix Q. This letter report presents nine methods for evaluating the effectiveness of an operator's (i.e., lessee's) SEMS program, presents the benefits and disadvantages of each method, identifies entities that could perform the audits, specifies the range of potential roles and qualifications of the auditors and of the BOEMRE inspectors who will conduct or oversee the SEMS audits, or both, and presents various methods that could be employed to conduct the audits. • THE NATIONAL ACADEMIES wa hingtonfFifth eDC 20001 Fax: 202 334 2003 Advisers to the Notion on Science, Engineering, and Medicine www.TRB.org • BACKGROUND BOEMRE has broad regulatory authority over energy operations on the U.S. Outer Continental Shelf (OCS), including oversight responsibility with respect to the offshore platforms involved in drilling and production of oil and natural gas. Included in BOEMRE's oversight authority is the responsibility to conduct safety audits of each platform at least annually as well as periodic unannounced "spot" audits, the intent of which is to make offshore facilities safer. The hope is that the audit process will encourage owners and operators to develop a healthy and viable safety culture on offshore facilities and that, if there are potential problems, they will be identified during the audit process and subsequently addressed, thereby reducing the likelihood of a major incident. In 1990, the Marine Board reviewed the MMS inspection program and made several recommendations for improvement. At that time, the inspection program mostly focused on facilities and whether they met certain standards. At each visit, inspectors worked through a potential incidents of noncompliance (PINC) checklist. Among other things, the 1990 Marine • Board committee found the following: 1. The emphasis on compliance with hardware -oriented PINCs fostered an attitude of "compliance equals safety" that can actually "diminish the operator's recognition of his primary responsibility for safety."' 2. The "majority of accident events occurring on the OCS in a representative year (1982) were related to operational and maintenance procedures or human error that are not addressed directly by the hardware -oriented PINC list."2 3. "Third -party inspection by private sector contractors (alternative 4) would not diminish and would probably increase the tendency of operators to abdicate safety responsibility to the inspecting organization. ,3 1 National Research Council, Alternatives forInspecting Outer Continental Shelf Operations, National Academy Press, Washington, D.C., 1990, p. 80. Z National Research Council, Alternatives for Inspecting Outer Continental Shelf Operations, p. 81. 3 National Research Council, Alternatives for Inspecting Otter Continental Shelf Operations, p. 81. 2 • 4. "Self inspection (alternative 5), while it would pinpoint the operator's responsibility, would be unsuitable because the MMS oversight function would be too tenuous."4 The report recommended that inspections instead focus on a sample of PINCs and devote greater resources to unannounced inspections as well as increased analysis of incidents and accidents and data collected by inspectors. MMS should "place its primary emphasis on detection of potential accident -producing situations —particularly those involving human factors, operational procedures, and modifications of equipment and facilities ...."5 For the latter to become more useful, the committee recommended that the quality and quantity of inspection data be considerably enhanced to allow MMS to take more of a risk assessment approach to inspections. Ultimately, the committee hoped that MMS would collect sufficient information about each platform to allow for development of risk indices that MMS could use to allocate more of its resources to platforms at higher risk. In the main, however, the committee stressed that the private operator was the primary responsible agent for ensuring safe operations and that MMS should structure its program to reinforce that awareness among operators. MMS adopted some of the recommendations made in the 1990 report and spurred the industry to develop American Petroleum Institute (API) Recommended Practice (RP) 75, Development of a Safety and Environmental Management Program for Offshore Operations and Facilities. Industry was encouraged to voluntarily adopt safety and environmental management programs (SEMPs). In mid-2009, MMS proposed a rule that would have required offshore operators to adopt four of the 12 elements of API RP 75. In April 2009, MMS again approached the Marine Board to request that the current study be conducted to review the MMS inspection program for offshore facilities to assess its effectiveness in protecting human safety and the environment. The Committee on Offshore Oil and Gas Facilities Inspection Program of the MMS was tasked with 4 National Research Council, Alternatives for Inspecting Outer Continental Shelf Operations, p. 82. . 5 National Research Council, Alternatives for Inspecting Outer Continental Shelf Operations, p. 83. 3 0 ■ Examining changes in the inspection program and process since the 1990 study by the Marine Board; ■ Reviewing available trend data on inspections, safety, and environmental damage; ■ Examining analogous safety inspection programs in other regulatory agencies and other nations for lessons that could be applied to MMS inspections; ■ Considering changes in industry's safety management practices since the 1990 Marine Board report and the implications of these changes for MMS inspection practices; ■ Considering the effects of the current inspection program on offshore safety and environmental protection; and ■ Recommending changes, as appropriate, to the inspection program to enhance effectiveness. The committee was appointed in November 2009 and held its first meeting the following month. In March 2010, a subgroup of the committee made site visits to the MMS Pacific OCS Region and to the California State Lands Commission. The committee also scheduled a site visit in May of that same year to the MMS Gulf of Mexico Region. This visit, however, was overtaken by the unfolding events of the Deepwater Horizon explosion, blowout, and oil spill. In the aftermath of the Deepwater Horizon event, the Department of the Interior conducted a reorganization of MMS, which was renamed BOEMRE. During this process, BOEMRE officials asked that this project be put on hold while the agency reevaluated its approach to safety.6 6 The agency is still undergoing major structural changes. The reorganization will transform BOEMRE into three separate bureaus: the Bureau of Ocean Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE), and the Office of Natural Resources Revenue (ONRR). The royalty and revenue management functions of MMS including, but not limited to, royalty and revenue collection, distribution, auditing and compliance, investigation and enforcement, and asset management for both onshore and offshore activities [has been]... transferred to ONRR. `BOEM will exercise the conventional (e.g., oil and gas) and renewable energy -related management functions of MMS not otherwise transferred pursuant to Secretary Salazar's Order 3299 including, but not limited to, activities involving resource evaluation, planning, and leasing. BSEE will oversee the safety and environmental enforcement functions of MMS including, but not limited to, the authority to inspect, investigate, summon witnesses and produce evidence, levy 4 • Then, in October 2010, BOEMRE issued a final rule requiring adoption of API RP 75 with minor revisions as defined in the rule and retitled Safety and Environmental Management Systems (SEMS). SEMS lays out multiple requirements for safe and environmental operations, including requiring specific written plans for operating practices, hazards analysis, management of change (MOC), safe work practices, training, mechanical integrity, emergency response, and incident reporting. RP 75 recommends that practices be audited by a qualified party, which could include individuals employed by the same company, on a regular schedule. In contrast, the final SEMS rule requires that these audits be conducted by an independent third party (I3P). In the proposed rule, BOEMRE recognized that its inspection program was too focused on mechanical integrity and that mechanical failures represent a small minority of incidents. With issuance of the final rule, BOEMRE's approach to safety and environmental protection shifted from reliance solely on inspections of hardware -oriented PINC items to also requiring operators to specify how they will manage safety holistically to avoid injury and spills. There is a proposed rule to assure effective implementation of these programs • through third -party audits. Accordingly, BOEMRE's request for a revised scope of this study reflects its interest in seeking guidance on how SEMS programs should be evaluated and their effectiveness assured. STUDY OBJECTIVE AND CHARGE After MMS was restructured, BOEMRE requested that the scope of this study be changed from a review of the agency's offshore platform safety and environmental inspection program to provision of guidance on how the agency should evaluate and ensure the effectiveness of the new SEMS practices that will be required of offshore operators effective November 15, 2011. Thus, this project was refocused and restarted in late January 2011. Under the new agreement with BOEMRE, the committee (renamed the Committee on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations) was tasked with preparing this interim report to identify penalties, cancel or suspend activities, and oversee safety, response, and removal preparedness" (http•//www boemre gov/ooc/newweb/frequentlyaskedguestions/freguentlyaskedquestions.htm). 5 0 potential methods for assessing the effectiveness of a company's SEMS program and to describe the pros and cons of each method as they are known to this point. This interim report was developed through open- and closed -session meetings, discussions, and subsequent correspondence. The report then went through independent peer review following standard National Research Council (NRC) procedures. (See Appendix D for a brief description of the review process and the list of reviewers.) The final report, to be completed later this year, will present the committee's assessment of different methods for auditing an offshore drilling and production SEMS program and will recommend what it considers to be the best method. The report will not be released until after the release of the report of the NAE—NRC Committee for the Analysis of Causes of the Deepwater Horizon Explosion, Fire, and Oil Spill to Identify Measures to Prevent Similar Accidents in the Future, so that the findings and recommendations of that committee's work on drilling operations can be taken into account. GOAL OF SEMS • As previously noted, the BOEMRE requirement that lessees and operators of oil drilling and production operations on the OCS have a SEMS program is based on the previously voluntary guidelines established by API. The goal of these new requirements is to reduce human and organizational errors that cause work -related accidents and offshore oil spills by improving the overall safety of operations with better procedures and training. A successful program should address both occupational and process safety. Minimizing the risks of slips, trips, and falls (e.g., lost -time accidents) is important, but it is BOEMRE's opinion that a SEMS program should also help reduce the likelihood and consequences of major organizational and system failures that could result in other accidents similar to the Deepwater Horizon event. A platform that has managed to maintain multiple years of operations free of occupational injuries may still be susceptible to the development of high -consequence events.8 Briefing by Douglas Slitor, Acting Chief, Office of Offshore Regulatory Programs, BOEMRE at the committee meeting on March 3, 2011. 40 8 J. Reason, Achieving a Safe Culture: Theory and Practice. Work & Stress, Vol. 12, No. 3., 1998, pp. 293-306. 6 • According to BOEMRE,9 to be effective, operators' implementation of SEMS needs to be evaluated and tracked through an auditing mechanism. The auditing approach adopted by BOEMRE will have a direct effect on the short- and long-term success of the SEMS program. Auditing programs vary across multiple dimensions, such as the quantification of goals, the frequency and type of audits, the size and severity of any reward or penalty assessment, and the collection of data to determine program effectiveness. The audit approach should help foster SEMS programs that are adopted throughout all levels of management. An operator that is merely trying to avoid penalties by going through the motions will not be effective in controlling on -platform risks. SEMS should be much more than a paperwork drill, and the auditing process should encourage this broader perspective. SEMS and a Culture of Safety The management of safety within an organization is ultimately a reflection of its safety culture. It is hoped that effective implementation of SEMS will have a positive impact • on the safety culture of companies operating on the U.S. OCS; however, this will not be known until trend data are available and analyzed. Although a safe culture is a goal of organizations and attempts are made to measure it, people often find it difficult to describe a safe culture in concrete terms. According to James Reason, "Uttal's (1983) definition of safety culture captures most of its essentials: `Shared values (what is important) and beliefs (how things work) that interact with an organization's structures and control systems to produce behavioural norms (the way we do things around here).""0 Safety management should be integrated into a company's organizational systems and management practices to achieve a positive culture of safety. Safety management systems are more than a set of policies and procedures; they also include how policies and procedures are implemented through work practices and the commitment of resources and support in the workplace that can truly make an impact on safety culture. 9 Briefing by Douglas Slitor, Acting Chief, Office of Offshore Regulatory Programs, BOEMRE at the committee meeting on March 3, 2011. 10 J. Reason, Achieving a Safe Culture: Theory and Practice, p. 294. See also B. Uttal, The Corporate Culture is Vultures, Fortune Magazine, October 17, 1983. 7 • For a culture of safety to exist and grow, there should be reciprocity between corporate and (individual) employee values, beliefs, and perceptions. SEMS can create the backbone of the safety culture upon which organizations build these internal reciprocal relationships that lead to a better culture of safety. In other words, a culture of safety requires commitment, engagement, and execution from all levels of the organization. It is this ownership and engagement that reshapes safety culture into a continuing, long-term commitment to improve. A common problem for some companies is the tension between organizational mandates regarding safety and messages for efficiency in terms of time and money. Companies are continually making decisions that trade off safety against other objectives (e.g., time and cost). Without a framework that keeps safety concerns elevated to an appropriate level, suboptimal decisions can be made. This can happen when the conflict of responsibility and accountability with respect to many different organizational goals (e.g., safety, time, and production) ensures that the target with the most forceful message from top management will prevail. Building trust that top management will support decisions to • override other priorities with safety is the only way to achieve a culture of safety; however, SEMS alone cannot achieve this. With its audit program, the Bureau of Safety and Environmental Enforcement (BSEE) will be in a unique position to influence how SEMS is implemented and integrated in an organization. To achieve reliably safe operations, more than a well-defined SEMS is needed —people in the organization must actually use SEMS and improve it on a continuing basis. Thus, auditing has to extend beyond the existence of a SEMS—and the existence of documentation that supports its use —to assuring that what is described in the SEMS is actually the way people work. An effective audit program would extend assurance beyond paper verifying records to how the SEMS is used to guide what individuals in the organization do to ensure safe and environmentally responsible operations. Perhaps one useful way to explain the interaction of process and culture is the organization —individual — able -to —want -to matrix (Figure 1). 0 LJ • 3 Organization Individual Figure 1. Interaction of process and culture. Source: J. Ford Brett, committee member, and adapted by the committee. This matrix illustrates the requirements for an action to reliably occur in a real organization. For something to reliably occur, the organization as a whole, and each individual in the organization, needs to be able to and needs to want to accomplish the action. As a brief overview, the organization —able -to quadrant of the matrix describes the mechanism an organization would use to operate safely and is basically the SEMS plan and supporting documentation. For example, without an effective SEMS plan and appropriate documentation, an organization could not operate safely; however, great plans, and even great documentation, do not mean the organization will be safe. The individual —able -to quadrant of the matrix is competency and describes how people as individuals are capable of executing the requirements of safe operations. There may be great plans, but without competent individuals, they cannot be carried out. The individual —want -to quadrant is motivation and describes those factors in the actual organization that would cause a totally selfish person to want to work safely. For example, if people really are totally unmotivated to report incidents (e.g., because bonuses are lost or because the paperwork is just too much of a hassle) then more training on how to spot incidents will not address the issue. Finally, the organization —want -to quadrant is the culture or behavioral norms that cause people to act properly, even when no one is looking and when it is not in their immediate best interest. E • Culture causes people to accurately report events, even when they are at fault, because the norm is telling the truth. Very briefly, if one of these elements is missing, there will be a bottleneck in the organization's ability to work safely and with environmental responsibility, and more emphasis of the other elements will not address the problem. If motivation or culture is missing, training or the detailed process will not be the root cause of an incident. This type of analysis can be helpful in creating ways to assure that SEMS is more than a paper exercise. Guiding Questions for Evaluation or Audit Any audit process has multiple opportunities for checking the strength and effectiveness of each platform's instantiation of SEMS. A sequence of guiding questions provides a preliminary structure for the audit (as shown in Figure 2): 1. Is a SEMS plan in place? Is the plan complete? Is there a document to read? Has the • owner or operator structured a plan that covers all the necessary personnel, equipment, and situations? 2. Is the plan feasible and effective? Given that a plan is in place, how good is the plan in reducing risks? If the steps outlined in the plan are followed, will they be successful in meeting program safety goals? Are sufficient resources available to comply with the plan? How does the plan compare with plans that have been developed for other similar platforms and have been shown to be effective? 3. Do personnel know about the plan? A well -written and carefully thought-out program will not succeed if the personnel required to follow it are not aware of it. Is there a way to track components of SEMS with the necessary personnel? As personnel are replaced, is there a process by which new personnel are introduced to their responsibilities? Is the plan pervasive throughout the organization? 4. Can and do personnel effectively carry out the plan? That personnel are aware of the program does not mean that they can follow it effectively. Is a training program in place? Are there periodic tests and drills with which personnel can demonstrate their • familiarity and expertise with details of the plan? 10 • 5. Is the plan affecting safety? The goals of SEMS programs are to improve both occupational and process safety. Are metrics that permit verification of the SEMS plan being recorded and tracked? Is the plan being used to instill and encourage a healthy safety culture? Long-term effectiveness can only be assessed through the comparison of tracked measures with baseline data. Are occupational and process safety near -miss events being recorded and evaluated? A careful definition of performance metrics would allow for comparisons across platforms, rigs, operations, lessees —operators, and regions. It would also facilitate international comparisons. Each question requires a different audit approach; a different data collection requirement; a different audit schedule; and, potentially, a different type of trained auditor. Strengths and weaknesses of alternatives for these options are discussed in the following sections. METHODS FOR ASSESSING EFFECTIVENESS • To date, the committee has identified nine methods for assessing the effectiveness of • an operator's SEMS program: audits, compliance inspections, peer reviews —assists, key performance indicators, whistleblower programs, periodic lessee reports, tabletop exercises or drills, SEMS monitoring sensors, and calculating the risk with SEMS in place. Some of these methods can be further subdivided. These nine methods, however, are not mutually exclusive and elements of each could be combined to develop the most effective evaluation program. A general description of each method is provided below. Table 1 summarizes each method, in no particular preferred order, including the pros and cons of each as well as notes for clarification. Audits This is the classic audit consisting of a comprehensive systematic collection and review of information to ensure the SEMS program is being maintained and operated as 11 • Resources to Develop SEMS • RP 75 • Process Safety Management (PSM) • Safety Case Operators Develop SEMS 1 Operators Implement SEMS 1 Outcome of SEMS Implementation Methods to Evaluate Effectiveness of Operators' SEMS Methods to Evaluate Effectiveness of Operators' Implementation of SEMS Is SEMS Achieving Its Intended Vision, Mission, Goals, and Objectives? 1. What are the metrics for each? 2. How are they measured? By whom? When? 3. What are the scales of absolute or comparative effectiveness evaluations? Figure 2. Scope of SEMS study. 12 • intended. Where possible, the audit should verify objective evidence showing conformance to the SEMS program. The audit is typically performed by an independent organization. There may be (a) periodic, (b) surprise or random, or (c) event -driven audits. Compliance Inspection This is one of the simplest forms of SEMS verification. The intent is to verify with little time and minimal inspector training that at least portions of the SEMS program are operating. It is not meant to be a comprehensive audit such as that described in the previous section; rather, it provides a general indication of the state of the SEMS program by verifying specific components. Compliance inspections take place on the offshore facility and may involve the use of checklists, interviews, witnessing, and the like. For example, the inspector may use a brief checklist to verify that SEMS items such as operating procedures, training (certificates), and emergency response plans are in place and the staff are familiar with their • use. The inspections can be performed by company personnel as well as government inspectors. Having an operator from one platform conduct a compliance inspection on another platform can be instructive for both operations. Peer Review —Assist This is also often called the peer assist method. Respected industry peers from outside the organization, including other operators, review the company's compliance performance and SEMS implementation and then suggest helpful ideas for improvement. There may or may not be formal documentation. Peer assists are a common intra- and intercompany activity for technical and economic issues and have been found to work well in the offshore as well as other industries. There are different protocols for this method (e.g., different levels of required response to peer recommendations) that may vary from an informal process with no formal recommendations and no written record, to a formal process with formal recommendations and written responses to recommendations, to some variant in between. One goal of the peer review —assist method is to have an independent set of eyes focusing on • a company's operations with the sole purpose of helping that company improve. This method 13 • is based on the premise of promoting a "don't -blame -let's -improve" culture. The aviation industry is one example where this approach is employed." Key Performance Indicators Key performance indicators (KPIs) are commonly used to evaluate a program's success or the success of a particular activity, in this case SEMS. KPIs work well when there are clear objective metrics that can be quantified, such as are often used in operations (e.g., barrels of oil produced or lost -time incidents). The difficulty for SEMS is to determine the specific metrics that will measure the effectiveness of the SEMS program. Whistleblower Programs This method involves an internal or external person (or organization) bringing to attention that some components of the SEMS program or the complete program are not being implemented correctly or are being falsified. In order to be most effective, such a program • would have to protect the identity of the informant as well as guarantee no repercussions (e.g., an employee losing his or her job). These types of programs often involve an I3P that handles the comments, perhaps as part of a comprehensive compliance system, to ensure the comments are confidential, properly vetted, and appropriately acted on. This program is used in numerous other industries, so there are plenty of examples for SEMS programs to refer to. Periodic Lessee SEMS Report This is a periodic self -generated report by the lessee describing the effectiveness of its SEMS program. Although produced by the lessee and perhaps open to questions about accuracy, the report does force the lessee to take an active approach to SEMS implementation and monitoring. The contents of the report can range from an open format defined by the lessee to a specific format and content required by the regulator. • " See, for example, http://www.iiasa.gov/offices/oce/appel/ask/issues/40/40i peer assist.html. 14 • Tabletop Exercises or Drills This involves special drills and tests of an operator's SEMS program and can be performed on a planned or surprise basis. Similar drills are already performed on offshore facilities related to life, safety, and environmental releases. This includes the use of computer -based virtual reality (VR) models to realistically assess operator skills and reactions to special situations. The use of VR models minimizes the impact on field operations and, if planned correctly, can also incorporate some of the other methods described here, such as SEMS monitoring sensors. Because this type of SEMS drill is not commonplace, this approach would require considerable preplanning by both the operator and the regulator to make the drill specific to testing the effectiveness of a SEMS program. SEMS Monitoring Sensors This approach uses mechanical sensors that monitor items such as pressures, temperatures, and flow rates to develop metrics that can be used to determine SEMS • effectiveness; however, the specific monitors, their relationship to SEMS, and how such a system would work have yet to be determined. Some of these monitors may be in place already as part of normal production operations, while other new monitoring devices may • need to be developed specific to SEMS metrics. Ideally, these systems would be able to send information directly back to shore for real-time SEMS monitoring. Calculation of Risk with SEMS in Place This involves a formal quantitative risk assessment (QRA) for the platform based on SEMS-specific data. The change in the QRA risk level with modification or updates to the SEMS program can be used to monitor the program's effectiveness, although this is a computed theoretical effectiveness. One advantage of this method is that the owner can use the QRA risk level to determine the effectiveness of alternative SEMS-related modifications and upgrades to assist in determining the best approach (from a SEMS perspective). 15 Table 1. Methods for Assessing the Effectiveness of SEMS Method Description Pros Cons Notes Audit Periodic audit Surprise or random audit Event -driven audit Review of the implementation and quality of SEMS at both corporate and platform level Platform level may be all platforms or a sampling Scope (e.g., comprehensive or selected components) and details (time interval, auditing protocols) can be varied Planned in advance on a regular basis, typically 2- to 3-year intervals Unannounced; a combination of randomly selected SEMS across all owners Triggered by events such as injury or death, pollution, a near miss, and noncompliance • Proven method • Established auditing protocols available for process safety management (e.g., API, American Institute of Chemical Engineers) • Scope and details can vary • Can be scheduled to meet BSEE requirements • Can be a comprehensive audit • Instantaneous assessment of state of SEMS implementation • Immediately corrects SEMS issues, if applicable 16 • Can only provide a reasonable assurance that the system is effective • Specific protocols need to be developed for defined scope • Auditor required to be expert at SEMS • Several auditors may be required in order to look at all SEMS areas • Cost and time • Need to develop specific protocols for SEMS audit • May disrupt normal activities (e.g., drilling or testing) • May not be comprehensive • Reactive, lagging assessment • May not reflect processes in place prior to incident Guidelines for meeting BSEE audit requirements "Surprise" means several days' notice, not instantaneous May be required in any case by regulations Method Compliance inspection Checklist Interviews, witnessing, etc. Peer review —assist Description Onboard SEMS check by the day-to-day BSEE inspectors; regional inspectors can also perform SEMS check Checklist to ensure SEMS is in place on platform Checklist scope and details may vary Interviews or other communication with platform personnel to determine whether they understand the SEMS program, including possible test drills May be concurrent with administering checklists Assessment of SEMS implementation by a team composed of peers from the industry Pros • Simple to implement with minimal training • May quickly identify deficiencies with SEMS program and implementation • Can provide information to assess whether personnel on platform are knowledgeable and use SEMS • Qualified and experienced in SEMS • Nonthreatening identification of catastrophic weaknesses and opportunities to improve • Good potential to learn from each others' SEMS 17 Cons • Scope of SEMS check limited because of responsibilities for inspections of all other mandatory requirements • May only assess compliance with paperwork or system; limited assessment of SEMS program's effectiveness • Platform specific; not a corporate -wide check • Content and quality can vary extensively • Must develop checklists • Can be subjective • Reliant on interviewer skills • Additional SEMS training required, perhaps substantial • Time consuming • Independence may be questioned • Potential conflicts of interest and confidentiality • Potential legal liability issues related to discoverability of recommendations and recommendations given in good faith that have poor outcomes Notes California State Lands Commission program is an example 0 • • Method Description Pros Cons Notes Key performance Use metrics from corporate- • Quantitative • Unclear as to how current BSEE can establish specific indicators or platform -specific data to • Easy to implement metrics relate to SEMS SEMS INCs assess SEMS effectiveness . Can be automated and effectiveness reported to BSEE regularly • New metrics may need to Metrics can be currently (quarterly) be developed reported ones [e.g., incidents • Could be used to identify • If metrics do not accurately of noncompliance (INCs), specific problem platforms reflect safe conditions, they spills, accidents, near misses] a BSEE databases available could create complacency or expressly developed new for analysis ones [e.g., number of changes (MOC), SEMS INCs] Whistleblower program Policy and programs by • Proactive for identifying • Lagging indicator of May be available in other owner for anonymous corrective actions problems already in place industries (e.g., nuclear, reporting of events or . Evidence of management's • Disgruntled persons can aviation) situations by employees or commitment to SEMS report false information other persons to complement • Engages staff day to day • Dependent on culture normal reporting and . Easy to implement • Requires fast and communication channels that transparent follow-up would lead to better SEMS program by owner implementation 18 0 0 0 Method Periodic lessee SEMS report Tabletop exercise or drill SEMS monitoring sensors Description Quarterly, biannual, or yearly specific report from the lessee on the status and effectiveness of its SEMS program Scope and details of these voluntary reports can vary Planned or surprise drill with specific actions to test SEMS; similar to spill drills Can vary from simple to complex exercises depending on the scope of SEMS tested Tracking onboard sensors to establish specific metrics for SEMS purposes Pros • Keeps SEMS relevant and recent in terms of operator's processes • As voluntary submissions, these may be useful when performing mandatory SEMS audits • Can become a subset of existing drills • True reflection of SEMS in action • Quantitative SEMS measure • Possible future development of SEMS- specific sensors • Can send data back to shore for evaluation 19 Cons • Accuracy of self -report can be questioned • Can be onerous on operator • Scope and detail are not defined and may need to be developed • Cannot test all SEMS— would have to be a selection • Would require much preplanning by owner and BSEE • Can only be applied to a limited number of facilities • Time consuming • May require dedicated BSEE personnel and skill set • Need to identify how these sensors may reflect SEMS issues Notes Report context and content are current and relevant; may be corporate level rather than platform specific • Method Description Pros Cons Notes Calculation of risk with SEMS in place (QRA) Specific quantitative methods that use owner's SEMS program as well as statistics from platform operations to determine effectiveness of SEMS over time • Measurable • Can see changes in performance over time 20 • Quantitative, results can vary between QRA approaches • Need data over time to see trends • Need baseline data for statistical analysis • Output depends on model assumptions and details • WHO PERFORMS THE AUDIT In the previous section, various methods for measuring the effectiveness of SEMS were identified. No matter which method is selected, BSEE will have to verify that operators have a comprehensive SEMS program in place and that it is operating effectively. That is, BSEE will need to have some mechanism in place to be able to conduct, participate in, or review SEMS audits that are conducted. In this section, various alternatives to accomplish this goal are discussed. Operator Reports Audit Results SEMS requires operators (i.e., lessees) to audit their SEMS program within 2 years of the effective date of the SEMS final rule, which is November 15, 2011, and then every 3 years thereafter. The audit is to consist of the company's overall SEMS program and 15% of the platforms operated by the lessee. The current requirement is that the audits can be . performed by qualified in-house staff or by I3P contractors. Under the operator -reports -results method, operators would be required to submit periodic [quarterly, annual, or event -based (incident -based)] reports of the status of their SEMS program and the results of the audits. BSEE would review these submittals at the regional level. On the basis of incidents, the reports received, suspicions that the audits are incomplete, or input from the compliance inspectors, BSEE might then elect to conduct its own audit as already allowed under SEMS. This process is similar to the one now in effect under the Occupational Safety and Health Administration (OSHA). Benefits: This method puts the burden for SEMS implementation and actual performance totally on the operator. One of the purposes of SEMS is to make a positive impact on the culture of safety of operators. SEMS elements have been identified as critical to, but not sufficient for, creating a culture of safety. For a culture of safety to exist, there must be a mind set of focusing on safety throughout the organization. The more the operator owns the process, the less the tendency for the operator to equate safety with compliance with prescriptive regulations. • 21 • Disadvantages: This method relies on operators to perform in good faith. There is a public perception that the industry has a tendency to sacrifice safety for profit and must be forced by threat of penalties to operate in a safe manner. In addition, BSEE would have to issue and police the qualifications required for both in-house auditors and ON. Independent Third Party Performs Audit Benefits: This introduces a required third party to work with the industry, and it should provide better assurance that qualified individuals perform the audit. Disadvantages: On the one hand, the operator would pick and pay for the I3P. Therefore, an operator who had not fully bought into the idea that SEMS would positively affect safety might pick the most lenient and least expensive I3P. An operator interested in doing the minimum required for compliance might not be so conscientious in its choice of an I3P. The operator might believe that the auditor has some level of responsibility for safety and making sure that the SEMS program is operating correctly, splitting the responsibility for • creating a safety culture between the operator and auditor in the operator's mind. In this case, there might be little or no improvement in safety culture over the current method. On the other hand, those committed to SEMS would be forced to hire an I3P rather than perform the audit themselves. This might reduce the operator's ownership of the process, with perhaps a slightly negative effect on safety culture. Additionally, the issue of who audits the auditor would come into play. Operator and BSEE Perform Required Audits Jointly as a Team In this method, the required audits would be performed by a combined team of BSEE and operator personnel. BSEE would still retain the right to do an audit by itself on the basis of incidents or observations of compliance inspectors. Benefits: Being a member of the audit team would make BSEE part of the team creating the safety culture and would enable BSEE to develop a much better idea of the safety culture of the operator and the platforms audited. Disadvantages: This method would require more BSEE staff than are needed when 0 the operator reports the results of the audit. 22 • BSEE Performs Required Audits 0 Under this method, BSEE would take on direct responsibility for performing the required periodic audits and any other audits based on periodic reports, incidents, or observations of compliance inspectors. This is similar to the way that the California State Lands Commission has conducted audits for the past 15 years of SEMP compliance on platforms in California state waters. The California State Lands Commission has required operators to comply with API RP 75 (SEMP) since the 1990s. Benefits: From the standpoint of public perception, this is perhaps the best alternative, as it would put BSEE directly in the role of assessing the effectiveness of the SEMS program. Disadvantages: Of the methods discussed, this one would make the most intensive use of BSEE staff. This method also would do the least to create a culture of safety, as passing the BSEE audit might become simply a paperwork compliance issue (i.e., What do I need to do to pass the audit?). Industry Safety Committee Performs Required Safety Audits This method would be similar to that employed in the nuclear industry. Operators would contribute personnel to an independent agency for a specified period of time. These people would perform the required safety audits. After their terms were completed, they would return to their original companies. Benefits: This method might result in the most informed audit teams, as companies would be encouraged to provide individuals with hands-on experience in practical aspects of operations and associated problems. It also would result in a spreading of best practices, as individuals would return to their companies, and could perhaps result in creating an industry- wide culture of safety. Disadvantages: In contrast to the nuclear industry, which has about 12 operating companies and 100 installations to audit, the offshore U.S. industry has more than 150 operating companies and more than 3,000 installations to audit. It might be difficult to find operating companies who would dedicate for periods of 2 to 3 years the number of staff required for such an undertaking. 23 • This method would also have the same drawbacks to creating a culture of safety that were discussed above, in that it would take the responsibility of auditing out of the hands of the operators. In addition, when auditing rigs, competitors' personnel would be exposed to company confidential materials that could prove useful in the competition for leases. Independent Third Party Performs Required Safety Audits The SEMS final rule includes a requirement for operators to use I31's to audit their systems; however, the rule does not define what constitutes an I3P. This section of the report explores the skills and qualifications that an I3P might need to possess. I3Ps: There are at least three potential options available for determining the competence of 1. BOEMRE could determine the attributes required of an I3P and perform an assessment of each company that wished to perform this service. BOEMRE • would need to maintain a register of these companies and establish a monitoring program to ensure they maintained competence. • 2. The I31's could be self-regulating. To give an example, the classification societies formed the International Association of Classification Societies, which sets standards in the form of a quality system certification scheme with which all member societies must comply. In other words, the companies who wished to offer the I3P service would form an association that would be able to demonstrate to BOEMRE that its members would satisfy all the criteria required of an I3P. 3. An independent body such as the American National Accreditation Board could develop criteria that the I31's would need to meet, and this independent board would award accreditation as appropriate and would then be responsible for assessing the system by monitoring and auditing the accredited companies. 24 • ROLE OF INSPECTORS IN SEMS AUDITS The role of inspectors cannot be exactly defined until the audit process, the role of BSEE, and other issues are defined in more detail. Therefore, this section is limited to a brief description of the role of the compliance and regional inspectors. The concept of having both prescriptive regulations and performance standards means that inspectors will be required to fulfill two distinct roles. Prescriptive regulations require inspection —audit processes similar in intent to those of the heritage MMS, namely, to ensure that lessees are following regulations. This means finding and reporting instances when regulations are broken. The envisioned audit of prescriptive standards could follow improved and more reliable processes, have more reliable tools and reporting methods, and so forth, but the basic idea would be the same: inspect operations, compare with regulations, and report on deviations. The compliance inspector's role will be primarily focused on prescriptive regulations. Properly auditing a safety management system is not only about finding and reporting . deviations, but also about assessing the current state of how safety is assured and finding specific opportunities for improvement (i.e., identifying weaknesses in the system). An audit of performance standards should have the purpose not just of identifying uncontrolled or inadequately controlled hazards, but also of finding the strengths and weaknesses of the safety management system itself. The regional inspector's primarily role will be focused on these performance standards as embodied in the operator's SEMS. A proper audit of a SEMS program should always find areas that can be improved. Indeed, an indication of a poor SEMS audit would be finding that everything is perfect. The determination of the degree to which a management system is in place and is encouraging a culture of safety is somewhat subjective. This is not the case for a compliance audit, in which an objective standard is used to determine whether there is compliance with a specific checklist item. Compliance Inspector In addition to focusing on the prescriptive regulations, the compliance inspector will 0 focus on those aspects of the performance standards and the SEMS program that can be 25 • objectively audited. At this time, this inspector's role can be summarized briefly as follows: ■ Observe operations (both on the rig and on shore) to compare the state of affairs with prescriptive regulations (mandatory laws and regulations) and the requirements of company SEMS plans (i.e., is there a written plan, and does it cover the elements specifically required by SEMS?); ■ Follow a defined audit process to spot-check key elements of prescriptive regulations; ■ Use BSEE audit tools (e.g., PINC checklist) to ensure a reliable audit process; ■ Create audit reports that summarize audit process findings; and ■ Create a separate report that focuses on potential opportunities for improvement over and above formal audit findings. Regional Inspector 0 The role of the regional inspector will focus more on implementation of SEMS across an entire organization. At this time, this inspector's role can be summarized briefly as follows: ■ Review compliance inspector audit(s) of an operator; ■ Review SEMS, as defined by the operator; ■ Review SEMS documentation and compare with SEMS definition; ■ Interview key operational and engineering personnel, as well as line workers, on how SEMS works in reality (use both formal and informal interview tools); ■ Create an audit report that summarizes audit process findings (e.g., differences between the SEMS program as defined and as implemented); and ■ Create an audit report that summarizes the strengths and weaknesses of the SEMS program and identifies specific improvement possibilities in the program as defined by the operator. 0 26 • AUDITOR QUALIFICATIONS • SEMS audits span a wide range of disciplines; thus, the auditors should be suitably qualified and trained in the audit function. The auditing organizations should be competent as well as independent. Consideration should be given to the various tasks associated with the audit function as well as to the qualifications of the individuals authorized to perform those tasks against two levels of competence: training and certification. Training Training programs allow individuals to become familiar with audit requirements. These programs may be structured around the elements of SEMS so that qualifications could be restricted to specific elements and individuals could be authorized to perform those particular functions. In this way, a team that carries out a SEMS audit could be composed of several individuals with different levels of competence and authorization. Training could be performed either in house or externally. Training courses, whether performed internally or externally, may need to be developed, tested, approved, and certified. Such training courses could also be attended by BSEE inspectors so that they could include aspects of SEMS audits as part of their routine inspections. They would also be qualified to perform audits when incidents occur (i.e., when an audit falls outside the routine triennial periodicity). Certification Two levels of certification could be required: 1. A high-level certification to demonstrate that the organization that will be doing the audits is accredited and approved to perform the audits and 2. Certification of the individual auditors to demonstrate that they have received the right level of training and are therefore competent in the audit role. 27 • PERFORMING AN AUDIT As discussed previously, there may be a need to manage safety following management principles of planning, organizing, implementing, and evaluating. Table 2 shows how the various elements of SEMS address each of these principles. Table 2. Management Principles and Elements of SEMS Management Principle SEMS Element Planning Employee participation Process safety information Process hazards analysis Pre —start-up safety review Emergency planning and response Organizing Operating procedures Safety work practices Training Implementing Contractor safety • Mechanical integrity Management of change 0 Evaluating Incident investigation Compliance audits As mentioned earlier, there are the two types of events that SEMS attempts to minimize by creating a framework upon which the operator can build a culture of safety: 1. Personnel safety event: Relatively low -consequence events such as slips, trips, and falls; small spills with only localized and short-lived pollution and fires; and even those events that may lead to one or two fatalities and 2. High -impact event: High -consequence events that are extremely low in probability but relatively much higher in consequence in terms of loss of life, such as the Piper Alpha event, or that cause widespread or long-lived environmental damage, such as the Deepwater Horizon event. 28 • As discussed previously, traditional measures of safety performance can be used to monitor progress toward improving personnel safety events. These measures can include fatalities, lost -time incidents, spills, incidents of noncompliance (INCs), and so forth. Indeed, tracking such statistics can lead to a reasonably high level of confidence in predicting which installations might be at higher risk for a personnel safety incident in the future and which will be at a lower risk for such incidents. No combination of these measures has been proven to be a good indicator of the future risk of a high -impact event, however. The year before the Deepwater Horizon incident, Transocean, the drilling contractor for the Macondo well, had received an award from MMS for being the safest drilling contractor in the Gulf of Mexico on the basis of these same measures. In addition, BP, the operator (lessee) for the Macondo well was one of the three finalists for the 2009 award as safest large operator in the Gulf of Mexico. The award was to be given out at the Offshore Technology Conference the first week in May 2010; however, the announcement of the winner was cancelled after the Deepwater Horizon disaster on April 20, 2010. It might be possible to analyze data on accidents and near misses that, for the • purposes of this report, can be defined as incidents of loss of containment of hydrocarbons. Unfortunately, unless there is a loss of life, lost -time incident, fire, explosion, or spill, loss - • of -containment data are not normally captured. It is known from the many risk assessments that have been performed on offshore drilling and production systems that, even if the barriers that prevent loss of containment are breached, mitigation barriers are in place that often prevent loss of containment from becoming either a personnel safety or a high -impact event.' 2 Thus, it is extremely difficult, if not impossible, to measure the degree to which a culture of safety exists within a specific organization from readily obtainable objective data. It could be possible to identify process -specific near -miss indicators (analogous to occupational safety near -miss events). This may be a fruitful longer -term source of possible 12 One example is Shell's bowtie model, which incorporates both prevention strategies (including barriers) to reduce the likelihood of a hazard release (referred to as a "top event") and mitigation strategies (recovery measures) to minimize the consequences of such an event. See http://www.shell.com/static/environment society/downloads/safety/process safety in shell Ir.pdf as well as http://www.leger.ca/GRIS/BowTie.htmi for a description of the bowtie model. 29 • improvement, but it will take time to develop relevant metrics and collect data to ensure they • are effective. Because SEMS is necessary for a culture of safety, all an audit can do is measure, if somewhat subjectively, the degree to which the elements of SEMS are understood and applied at all levels of the organization. This can be done by first making sure the appropriate documentation is in place and available to all and, more importantly, interviewing operating staff in the field at all levels of operations to determine the degree of awareness of and compliance with this documentation. No one can ever be expected to have a perfect score in this type of analysis. All that can be hoped for is that the specific operation being audited has a reasonable score that weaknesses are recognized, and that, over time, there is continuous improvement. That is, an audit system cannot just rely on yes or no answers to a series of questions in a PINC list. Several organizations have addressed this problem, including the California State Lands Commission, OSHA, the Mine Safety and Health Administration (MSHA), and the United Kingdom (UK) Health and Safety Executive (HSE). The committee has met with the California State Lands Commission but has yet to meet with the others. California State Lands Commission The California State Lands Commission requires operators to comply with what it calls Safety Assessment of Management Systems (SAMS). This is based on a joint industry project (JIP) performed in the 1990s by Paragon Engineering Services with help from the University of California, Berkeley, and sponsored by MMS, the California State Lands Commission, HSE, the National Energy Board of Canada, the American Bureau of Shipping (ABS), Chevron, and Texaco. The California State Lands Commission has been auditing SAMS performance for more than 15 years using a technique originally developed by the JIP and modified slightly with experience and has reviewed some installations three times over the years. It reports steady improvement from audit to audit, which it attributes to working with the operators to increase their compliance rather than punishing them with fines and shut-ins for areas that may need improvement. 30 • Occupational Safety and Health Administration OSHA requires operators of hazardous plants to maintain a Process Safety Management (PSM) program, which contains the same basic elements of managing safety that are listed in SEMS. It evaluates the plant's PSM system after a major incident. The committee has yet to meet with OSHA to better understand how the agency audits for effective implementation of the PSM program. Mine Safety and Health Administration MSHA was created in 1977. Among its responsibilities is the enforcement of safety and health rules in all mines and mineral -processing operations in the United States. Legislation provides that MSHA inspectors shall inspect each surface mine at least two times a year and each underground mine at least four times a year (seasonal or intermittent operations are inspected less frequently) to determine whether there is compliance with health and safety standards or with any citation, order, or decision issued under the Mine • Act and whether an imminent danger exists. MSHA pursues several activities that support its mission, such as ■ Educating and training mine inspectors, mine officials, and miners; ■ Testing, approving, and certifying certain mining products for use in mines; and ■ Providing technical assistance to the states and small mine operators. These are accomplished through specific mechanisms such as ■ The National Mine Health and Safety Academy, ■ The Approval and Certification Center, • The Pittsburgh Safety and Health Technology Center, and ■ The Directorate of Educational Policy and Development. Equally important is MSHA's work with industry and states to develop health and is safety programs. For example, its State Grants Program for miner training programs and 31 • training resource materials is used by the states and trainers to conduct health and safety training. Recently, MSHA has been in the process of making rules for a "safety and health management program in the mines." In late 2010, MSHA held three information -gathering meetings, and proposed rules are expected in 2011. The proposed rules may be similar to those of OSHA's proposed Injury and Illness Prevention Programs. The aim is to develop a culture of safety in mines. In all likelihood, the current mandatory inspections by MSHA inspectors and MSHA penalty provisions will continue. UK Health and Safety Executive The UK HSE requires operators of offshore installations to develop and maintain a safety case that makes the argument that the individual risk rate for someone working on the installation is as low as reasonably practicable (ALARP). An adequately written safety case must address how the operator plans to manage safety, which will include, from a practical • standpoint, most if not all the elements of SEMS, although they may be defined in slightly different terms. The committee has yet to confer with HSE to better understand how they • audit for effective implementation of the safety case. The committee's current understanding is that UK duty holders (operators) are required to employ verification bodies whose main responsibility is to ensure that the duty holder is performing its work and maintaining its safety -critical elements (SCEs) in accordance with its safety case and written scheme of verification. The duties typically performed by the verification company include ■ Witnessing activities associated with testing and measuring of SCEs; ■ Reviewing documentary evidence to substantiate the satisfactory demonstration of the continuing achievement of performance standards for SCEs; ■ Periodically reviewing the verification process to ensure compliance with the duty holder's written scheme; ■ Monitoring trends of availability and reliability of SCEs; 32 • ■ Witnessing, reviewing, and document auditing of activities associated with vendor -supplied equipment where applicable to SCEs; ■ Monitoring and reviewing the duty holder's modification activities where interfaces with existing or potential SCEs exist; ■ Completing all documentation and reports as required in the duty holder's written scheme of verification and well examination scheme; ■ Periodically reviewing the duty holder's procedures for complying with lifting legislation; ■ Performing audits to verify compliance with procedures and legislation; ■ Participating in failure investigations; ■ Developing procedures for lifting operations and lifting equipment inspection; ■ Reviewing crane maintenance inspection and testing records and issuing annual crane approvals; and ■ Reviewing annual safety and engineering cases for the deferral of removal for internal examination of crane slew ring bearings and provision of such a • certificate. To fulfill these obligations, the verification company makes regular visits to the offshore installations pertaining to the contract of work. The skills and competence of the surveyors are aligned to the type of work being undertaken. In other words, one platform visit might be tailored toward instrumentation, and another visit might concentrate on pressure systems, and the surveyor in each case would be trained and competent in the appropriate discipline. An offshore visit will generally last several days (and nights) and will include such things as witnessing function tests and reviewing records that will demonstrate that the duty holder is assuring the suitability of the SCEs. Note that the duty holder places a contract with the verification company. Annual summary reports are issued as well as individual discipline reports. When HSE engineers carry out their offshore visits, one of the first things they ask to see is the verification report. HSE also carries out offshore and onshore inspections and audits. A typical offshore visit involves a focal point plus up to four specialist HSE engineers and typically lasts • between 5 and 7 days (and nights —note that the duty holder is responsible for transporting 33 • the HSE engineers to the installation and for providing messing facilities. This is not considered to be a conflict of interest issue, as all operators have to comply). The aim is to visit each installation annually. Note that in this example, an installation will be a platform that was designed to produce 80,000 to 200,000 barrels of oil per day (although current production is likely to be much less than this). The HSE inspectors will be highly qualified discipline engineers (degree or equivalent) and will be chartered engineers, the UK equivalent of the professional engineer. During the offshore visits, they perform tasks such as witnessing function tests, fire pump tests, and electrostatic discharge tests. They also carry out general visual inspections and audit offshore records. HSE also carries out onshore audits of the duty holder's office. These audits focus on a review of the duty holder's records, how it is managing and maintaining the SCEs and, if there is a backlog of work, what plans are in place to address that backlog. In recent years, HSE has instigated key programmes (KPs) to try to determine how the duty holders are addressing the management of the SCEs. This year, KP4 is addressing Ageing Assets and Life Extension Programmes.13 • Note that, although there is a legal requirement for a duty holder to employ a verification body, there is no communication link between HSE and the verification companies. That is, all communication is via the duty holder, so if HSE wishes to see the verification reports, the reports are requested from the duty holder and not the verification company. COMPLETING THE COMMITTEE'S STUDY In carrying out the remainder of its study, the committee will continue to gather information to evaluate the auditing methods, the entities that could perform the audits, and the roles and qualifications of the auditors and inspectors presented in this report. The committee will also examine new regulations that are being discussed (e.g., SEMS Rule II) and other initiatives (of both governmental and private organizations) that are being developed to respond to the SEMS final rule for U.S. OCS oil and gas operations. All of • 13 See HSE, http://www.hse.2ov.uk/offshore/ageingjkp4-12rolzramme.htm. 34 • these activities are intended to inform the committee's deliberations for its final report, due • • later in 2011 following release of the final report of the NAE/NRC Committee for the Analysis of Causes of the Deepwater Horizon Explosion, Fire, and Oil Spill to Identify Measures to Prevent Similar Accidents in the Future. The committee's report will recommend a method for assessing the effectiveness of an operator's SEMS program for any given offshore drilling or production facility, taking into account the findings and recommendations of the NAE/NRC committee. Sincerely, Kenneth Arnold Chair, Committee on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations 35 • Appendix A Committee on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations COMMITTEE Kenneth E. Arnold, WorleyParsons, Inc., Houston, Chair J. Ford Brett, PetroSkills, Tulsa, Oklahoma Paul S. Fischbeck, Carnegie Mellon University, Pittsburgh, Pennsylvania Stuart Jones, Lloyd's Register EMEA, Aberdeen, Scotland, United Kingdom Thomas Kitsos, Consultant, Bethesda, Maryland Frank J. Puskar, Energo Engineering, Houston, Texas Darin W. Qualkenbush, United States Coast Guard, Morgan City, Louisiana Raja V. Ramani, Pennsylvania State University, State College, Pennsylvania (emeritus) Vikki Sanders, Atkins Global, Houston, Texas • TRB STAFF Beverly Huey, Study Director Stephen Godwin, Director, Studies and Special Programs Claudia Sauls, Senior Program Assistant C] 36 • MARINE BOARD U Michael S. Bruno, Stevens Institute of Technology, Hoboken, New Jersey, Chair Thomas M. Leschine, University of Washington, Seattle, Vice Chair Steven R. Barnum, Hydrographic Consultation Services, Suffolk, Virginia Jerry A. Bridges, Virginia Port Authority, Norfolk Mary R. Brooks, Dalhousie University, Halifax, Nova Scotia, Canada James C. Card, Maritime Consultant, The Woodlands, Texas Stephen M. Carmel, Maersk Line Limited, Norfolk, Virginia Edward N. Comstock, Raytheon Company, Sudbury, Massachusetts Stephan Toni Grilli, University of Rhode Island, Narragansett Douglas J. Grubbs, Crescent River Port Pilots Association, Metairie, Louisiana Frederick J. Harris, General Dynamics, San Diego, California Judith Hill Harris, City of Portland, Maine John R. Headland, Moffatt & Nichol Engineers, New York, New York John M. Holmes, Port of Los Angeles, San Pedro, California Ali Mosleh, University of Maryland, College Park George Berryman Newton, QinetiQ North America, Marstons Mills, Massachusetts Patrick Ernest O'Connor, BP America, Inc., Houston, Texas Robert W. Portiss, Tulsa Port of Catoosa, Oklahoma Peter K. Velez, Shell International Exploration and Production, Inc., Houston, Texas John William Waggoner, HMS Global Maritime, New Albany, Indiana TRANSPORTATION RESEARCH BOARD 2011 EXECUTIVE COMMITTEE OFFICERS Neil J. Pedersen, Administrator, Maryland State Highway Administration, Baltimore, Chair Sandra Rosenbloom, Professor of Planning, University of Arizona, Tucson, Vice Chair C. Michael Walton, Ernest H. Cockrell Centennial Chair in Engineering, University of Texas, Austin (Past Chair, 1991), Division Chair for NRC Oversight Robert E. Skinner, Jr., Transportation Research Board, Executive Director 37 • Appendix B Biographical Information on the Committee on the Effectiveness of Safety and Environmental Management Systems for Outer Continental Shelf Oil and Gas Operations Kenneth E. Arnold, National Academy of Engineering, Chair, is an independent consultant with more than 45 years of experience in projects, facilities, and construction related to upstream oil and gas development. He spent 16 years at Shell in engineering and engineering and research management prior to forming Paragon Engineering Services, a project management and offshore engineering company, in 1980; it had a staff of 600 when it was sold to AMEC in 2005. Mr. Arnold is the author, coauthor, or editor of several textbooks and numerous technical articles on the design and project management of production facilities. He taught production facility design at the University of Houston and has been active in the Society of Petroleum Engineers (SPE) and other technical societies. He was named Houston's 2003 Engineer of the Year by the Texas Society of Professional Engineers, and is the recipient of the SPE Public Service Award and the DeGolyer Distinguished Service Medal. He was elected to the National Academy of Engineering in 2005, primarily for the work he has done in promoting offshore safety. Mr. Arnold has served on two Marine Board committees, including the 1990 Committee on Alternatives for Offshore Inspection, and was a member of the Marine Board for 6 years. He currently works as a senior technical • advisor for WorleyParsons and as an independent consultant for the American Bureau of Shipping (ABS), oil and gas companies, and contractors on an as -needed basis. J. Ford Brett is Managing Director of PetroSkills and Chief Executive Officer of Oil and Gas Consultants International (OGCI), the world's largest petroleum training organization. Mr. Brett has consulted in more than 25 countries worldwide in the area of petroleum project and process management. Prior to joining OGCI, he was with Amoco Production Company, where he worked on drilling projects in the Bering Sea, the North Slope of Alaska, the Gulf of Mexico, offshore Trinidad, and Wyoming. In 2000, the American Society for Competitiveness awarded him the Crosby Medallion for Global Competitiveness for work in "global competitiveness through quality in knowledge management, best practices transfer, and operations improvement." He currently serves on the Society of Petroleum Engineers (SPE) Board as Technical Director for Drilling and Completion. For his work on improved drilling techniques, he was also honored in 1996 with a nomination for the National Medal of Technology, the U.S. government's highest technology award. Mr. Brett has been granted more than 25 U.S. and international patents and has authored or coauthored more than 25 technical publications. He holds a BS degree in mechanical engineering and physics from Duke University, an MSE from Stanford University, and an MBA from Oklahoma State University. Paul S. Fischbeck is Professor in the Department of Engineering and Public Policy and the Department of Social and Decision Sciences at Carnegie Mellon University. He is also Director of Carnegie Mellon's Center for the Study and Improvement of Regulation (CSIR), • where he coordinates a diverse research group exploring all aspects of regulation, from historical case studies to transmission -line siting to emissions -trading programs. Widely 9T • published, Dr. Fischbeck has served on a number of national research committees and review panels, including the National Research Council (NRC)—Transportation Research Board (TRB) Committee on School Transportation Safety; the National Science Foundation's Decision, Risk, and Management Sciences Proposal Review Committee and Small Business Innovative Research Proposal Review Committee; the NRC—TRB Committee on Evaluating Double Hull Tanker Design Alternatives; and the NRC—TRB Committee on Risk Assessment and Management of Marine Systems. His research involves normative and descriptive risk analysis, including development of a risk index to prioritize inspections of offshore oil production platforms; an engineering and economic policy analysis of air pollution from international shipping; a large-scale probabilistic risk assessment of the space shuttle's tile protection system; and a series of expert elicitations involving a variety of topics, including environmental policy selection, travel risks, and food safety. He is cofounder of the Brownfields Center at Carnegie Mellon, an interdisciplinary research group investigating ways to improve industrial site reuse. He is involved with a number of professional research organizations, including the American Society for Engineering Education, the Institute for Operations Research and Management Sciences, the Military Operations Research Society, and the Society of Risk Analysis. He has chaired a National Science Foundation panel on Urban Interactions and currently serves on the Environmental Protection Agency's Science Advisory Board. He holds a BS in architecture from the University of Virginia, an MS in operations research and management science from the Naval Postgraduate School, and a PhD in industrial engineering and engineering management from Stanford University. • Stuart Jones is a project manager with Lloyd's Register EMEA, Aberdeen, Scotland, United Kingdom, where he is responsible for several integrity management contracts for clients operating oil and gas installations in the North Sea. He started offshore work in the oil and gas industry in 1983, when he joined Conoco in Aberdeen as its maintenance coordinator for corrosion, responsible for fabric maintenance, inspection, and corrosion monitoring on the Murchison and Hutton tension leg platforms. He was Corrosion and Inspection Engineer for the British Gas Rough Field operation between 1990 and 1995, when he left to follow a career more aligned with risk -based inspection. He has performed risk -based inspection studies on oil and gas installations and their associated pipelines both on shore and off shore. In 2000 he joined Lloyd's Register, and since then has performed a number of roles, including senior corrosion engineer, team leader, project manager, and now project controls manager. In 2009, at the initiation of this committee study, he was on a long-term international assignment with Lloyd's Register Capstone, initially as head of their Upstream Operations Team and later as head of their project controls group. He returned to work in the United Kingdom in October 2010. Mr. Jones has published a number of papers and made numerous presentations on corrosion and risk -based inspection, and from 2008 to 2010 he served on the SPE's Gulf Coast Section, Projects, Facilities, and Construction Study Group. Mr. Jones earned a second-class honours degree in metallurgy from the University College of Swansea, Wales, United Kingdom, in 1974. He is a professional member of the Institute of Corrosion and of the Institute of Materials, Minerals, and Mining and is a chartered engineer. Thomas Kitsos served as Executive Director of the U.S. Commission on Ocean Policy (USCOP) from 2001 to 2004. In 2005, Dr. Kitsos retired from the National Oceanic and • Atmospheric Administration, U.S. Department of Commerce, as Associate Deputy Assistant 39 • Administrator for Ocean Services. He is currently a private consultant on national ocean policy, advising the Joint Ocean Commission Initiative, the follow-up, foundation -supported organization composed of the members of USCOP and the privately funded Pew Ocean Commission and dedicated to promoting ocean policy reform proposals recommended by the two commissions. His earlier experience included 6 years at the Department of the Interior (DOI), where his primary responsibilities were in the area of energy development on the Outer Continental Shelf. He also served as Special Assistant to the Assistant Secretary, Land and Minerals Management, and as DOI's Acting Director of the Minerals Management Service, among other positions. Prior to his tenure at DOI, Dr. Kitsos spent 20 years on Capitol Hill on the staff of the U.S. House of Representatives' Committee on Merchant Marine and Fisheries. His final position with the committee was as chief counsel, advising the chairman on national ocean and coastal issues, offshore energy development, and environmental and other marine management legislation, including amendments to the Outer Continental Shelf Lands Act and the Coastal Zone Management Act. He holds BS degrees in education and social science from the Eastern Illinois University, and an MA and PhD in political science from the University of Illinois. Frank J. Puskar is Managing Director of Energo Engineering in Houston, Texas. Energo specializes in advanced structural engineering and structural integrity management (SIM) of existing offshore structures. Mr. Puskar has more than 28 years of experience in the offshore industry and is a recognized leader in SIM technology. He has been involved in the planning of above -water and below -water inspections and structural assessments for more than 250 • fixed and floating platforms located worldwide. He has served on committees or task groups of the American Petroleum Institute (API), International Standards Organization (ISO), and American Society of Civil Engineers and on the Offshore Operators Committee and was Chairman of the API Task Group that developed API Bulletin 2HINS, Guidance for Post - hurricane Structural Inspection of Offshore Structures, published in May 2009. In 2007, he was awarded the Minerals Management Service Corporate Leadership Award for his industry efforts, including improving codes and standards related to the damage and destruction of platforms in the Gulf of Mexico from Hurricanes Ivan, Katrina, and Rita. He earned a master of engineering degree in ocean engineering from the University of California, Berkeley, and a BS in civil engineering from the State University of New York at Buffalo. He is a registered professional engineer in California, Louisiana, and Texas. Darin W. Qualkenbush has served in the U.S. Coast Guard (USCG) for 22 years and is currently serving in the National Technical Advisor office of the Outer Continental Shelf National Center of Expertise in Morgan City, Louisiana. This office is responsible for revitalizing the technical competency and expertise within the USCG marine safety program to keep pace with the growth and complexity of the offshore maritime industry. Additional duties include directing the generation of regulations, policy, and doctrine for marine safety and offshore operations, as well as being a repository for USCG expertise and best practices for the offshore oil and gas industry. LT Qualkenbush's previous assignment was as Chief, Outer Continental Shelf Inspections, at the Marine Safety Unit, Morgan City, where he was responsible for all regulatory and compliance issues for exploration, exploitation, and production of oil and natural gas within USCG's approximately 69,000-square-mile offshore • area of responsibility. He is a subject matter expert on lifesaving and firefighting equipment 40 • and deployment and on USCG regulatory compliance and International Maritime Organization Convention compliance on offshore oil and gas production platforms, offshore drilling units, and oil field support vessels of all types. Raja V. Ramani, National Academy of Engineering, is emeritus George H., Jr., and Anne B. Deike Chair of Mining Engineering and Professor Emeritus of Mining and Geo- environmental Engineering at The Pennsylvania State University. Dr. Ramani holds MS and PhD degrees in mining engineering from Penn State, where he has been on the faculty since 1970. He is a certified first-class mine manager under the Indian Mines Act of 1952 and has been a registered professional engineer in the Commonwealth of Pennsylvania since 1971. Dr. Ramani's research activities include mine health, safety, productivity, environment, and management; flow mechanisms of air, gas, and dust in mining environs; and innovative mining methods. Dr. Ramani has been a consultant to the United Nations, World Bank, National Safety Council, mining companies, and governmental agencies. He has published extensively on health, safety and environmental planning, and management issues and has received numerous awards from academia and technical and professional societies. He was the 1995 president of the Society for Mining, Metallurgy, and Exploration (SME). Dr. Ramani has served on the U.S. Department of Health and Human Services' Mine Health Research Advisory Committee (1991 to 1998). He was the chair of the National Research Council (NRC) Committee on Post Disaster Survival and Rescue (1979 to 1981) and a member of the Health Research Panel of the NRC Committee on the Research Programs of the U.S. Bureau of Mines (1994). He was a member of the Department of the Interior's • Advisory Board to the Director of the U.S. Bureau of Mines (1995) and a member of the Secretary of Labor's Advisory Committee on the Elimination of Coal Worker's Pneumoconiosis (1995 to 1996). More recently, he was a member of the NRC Panel on Technologies for the Mining Industries (2000 to 2001), the NRC Committee on Coal Waste Impoundment Failures and Breakthroughs (2001 to 2002), the NRC Committee to Inform Coal Policy (2005 to 2007), and the NRC Committee to Develop the Framework for the Evaluation of NIOSH [National Institute of Occupational Safety and Health] Research Programs (2005 to 2009) and was chair of the National Academy of Sciences Committee to Evaluate the NIOSH Mining Health and Safety Research Program (2005 to 2007). In 2002, he chaired the Pennsylvania Governor's Commission on Abandoned Mine Voids and Mine Safety that was set up immediately after the Quecreek Mine inundation incident and rescue. Dr. Ramani is a distinguished member of SME (class of 1988) and an honorary member of the American Institute of Mining, Metallurgical, and Petroleum Engineers (class of 2010). Vikki Sanders is a human factors consultant for Atkins Global in Houston, Texas, and works on a variety of oil and gas projects, providing human factors assessments of control rooms and other equipment for offshore platforms. She also provides input to the safety management system integration toolkit for the marine industry. Previous clients include BP, Shell, Hess, and the American Bureau of Shipping (ABS). Ms. Sanders graduated in psychology with honors in 1995 from the University of Humberside, United Kingdom, and earned a master's degree in organizational psychology from the University of Nottingham, United Kingdom, in 2002. After receiving her master's degree, she began working in organizational development at the Aston Centre for Effective Organisations, Birmingham, • United Kingdom, focusing on leadership, teamwork, and employee satisfaction, before 41 • working in safety management and human factors at the Health and Safety Laboratory, an agency of the Health and Safety Executive (HSE), the regulatory body in the United Kingdom. She provided technical assistance to HSE inspectors, focusing on assessment of workforce tasks in multiple industries in the United Kingdom. • • 42 • Appendix C Statement of Task This project will recommend a method for assessing the effectiveness of an operator's Safety and Environmental Management System (SEMS) on any given offshore drilling or production facility. In addition, the committee will prepare a brief interim report in April 2011 that will provide a listing of potential methods for assessing effectiveness along with the pros and cons of each method as they are known to that point. The committee will address methods to maximize the implementation effectiveness of individual SEMS rather than the adequacy of the Final Rule of October 2010 requiring SEMS to mitigate safety and environmental risk of offshore platform operations. The committee's assessment of effective methods will focus on the safety and environmental risks of offshore production until after the release of the report of the NAE/NRC Committee for the Analysis of Causes of the Deepwater Horizon Explosion, Fire, and Oil Spill to Identify Measures to Prevent Similar Accidents in the Future, which is expected in June 2011. The committee's assessment of effective methods for safety and environmental risks of exploration drilling will take into account the findings and recommendations of the NAE/NRC committee. The project is sponsored by the Bureau of Ocean Energy Management, Regulation, and . Enforcement (formerly the Minerals Management Service) of the U.S. Department of the Interior. is 43 Appendix D Review of the Document This report has been reviewed in draft form by individuals chosen for their diverse perspectives and technical expertise, in accordance with procedures approved by the National Research Council's (NRC) Report Review Committee. The purpose of this independent review is to provide candid and critical comments that assist the authors and NRC in making the published report as sound as possible and to ensure that the report meets institutional standards for objectivity, evidence, and responsiveness to the study charge. The contents of the review comments and draft manuscript remain confidential to protect the integrity of the deliberative process. The following individuals participated in the review of this report: Baruch Fischhoff, Carnegie Mellon University, Pittsburgh, Pennsylvania; David A. Hofinann, University of North Carolina, Chapel Hill; Morgan L. Jones, PetroSkills, Tulsa, Oklahoma; Paul L. Kelly, Energy and Ocean Policy Consultant, Houston, Texas; Joshua D. Reynolds, U.S. Coast Guard, Washington, D.C.; and Stanley C. Suboleski, Virginia Polytechnic Institute and State University (retired), Blacksburg. Although the reviewers listed above provided many constructive comments and suggestions, they were not asked to endorse the committee's conclusions or recommendations, nor did they see the final draft of the report before its release. The review of this report was overseen by Hyla S. Napadensky, Napadensky Energetics, Inc. (retired), Grand Marais, Minnesota; and C. Michael Walton, University of Texas, Austin. Appointed by NRC, they were responsible for making certain that an independent examination of the report was carried out in accordance with institutional procedures and that all review comments were carefully considered. • Responsibility for the final content of this report rests entirely with the authoring committee and the institution. • 44 • Appendix E Acronym List ABS American Bureau of Shipping ALARP as low as reasonably practicable API American Petroleum Institute BOEM Bureau of Ocean Energy Management BOEMRE Bureau of Ocean Energy Management, Regulation, and Enforcement BSEE Bureau of Safety and Environmental Enforcement CSIR Center for the Study and Improvement of Regulation DOI Department of the Interior HSE Health and Safety Executive I3P independent third party INC incident of noncompliance • ISO International Standards Organization JIP joint industry project KP key programme KPI key performance indicators MMS Minerals Management Service MOC management of change MSHA Mine Safety and Health Administration NAE National Academy of Engineering NRC National Research Council OCS Outer Continental Shelf OGCI Oil and Gas Consultants International ONRR Office of Natural Resources Revenue OSHA Occupational Safety and Health Administration PINC potential incident of noncompliance PSM process safety management • QRA quantitative risk assessment 45 • RP recommended practice SAMS Safety Assessment of Management Systems SCE safety -critical element SEMP Safety and Environmental Management Program SEMS Safety and Environmental Management Systems SIM structural integrity management SME Society for Mining, Metallurgy, and Exploration SPE Society of Petroleum Engineers TRB Transportation Research Board UK United Kingdom USCG United States Coast Guard USCOP U.S. Commission on Ocean Policy VR virtual reality • is 46
