Offshore Update No. 2 2010

Key Aspects of an Effective U.S. Offshore Safety Regime

Barents Sea rescue operations

offshore update

Environmental risks offshore North Norway

News from DNV to the offshore industry

No 02 2010

Risk Management after Deepwater Horizon

contents

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Key Aspects of an Effective U.S. Offshore Safety Regime ››

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Escape, evacuation and rescue operations in the Barents Sea ››

Modelling environmental risks offshore North Norway ››

Front cover: Aerial of the Helix Q4000 taken shortly before “Static Kill” procedure began at MC 252 site in Gulf of Mexico, on 03 August 2010. ©BP p.l.c.

Photos: p3 ©BP p.l.c., p13 ©BP, p16 ©DNV/Magne A. Røe, p17 ©Luth, p18 ©DNV and Prof. S. Løseth, NTNU, p19-20 ©DNV/Svetlana Bogdanova, p22 Masterfile/ Scanpix, p26 Svein Tangen, p29 ©StatoilHydro, p34 ©Oddfjell Drilling

Risk Management after Deepwater Horizon......................................... 4

offshore update We welcome your thoughts!

An effective US offshore safety regime............ 6

Offshore Update is a newsletter published by Det Norske Veritas. It is distributed to DNV customers and stations worldwide.

Key Aspects of an Effective U.S. Offshore Safety Regime................. 7

© Det Norske Veritas AS

Carbon Capture and Storage................................14 Barents 2020.....................................................................16 Escape, evacuation and rescue operations in the Barents Sea........................................................18 BARENTS 2020 – latest update..................................21 Gassco................................................................................22 Viking lady.......................................................................24 Sesam Floating Structures....................................28 Modelling environmental risks offshore North Norway...............................................................30 Joint Industry Project on the structural integrity of drilling and well systems..........34 2 | offshore update

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Please direct any enquiries to your nearest DNV station or Offshore Update e-mail: Lisbeth.Aamodt@dnv.com Editorial committee: Kåre Kristoffersen, Customer Service Manager Editor: Magne A. Røe Production: Lisbeth Aamodt Design and layout: Coor Design 1008-001 Printing: Grøset, 15000/08-2010 Online edition of Offshore Update: www.dnv.com/offshoreupdate DNV (Det Norske Veritas AS) NO-1322 Høvik, Norway Tel: +47 67 57 99 00 Fax: +47 67 57 99 11 An updated list of all regional offices can be seen on DNV’s website: www.dnv.com

editorial

We are pleased to welcome you to a new edition of Offshore Update

Knut Ørbeck-Nilssen Chief Operating Officer Knut.Orbeck-Nilssen@dnv.com

ONS is this year’s leading energy meeting place.

DNV will have a strong presence here, with senior staff present at two exhibition stands to welcome customers, share DNV news and discuss issues that are important for the industry.

During the past few months, we have been witness to a tragic accident in the Gulf of Mexico, an accident that has shaken the entire offshore industry and demonstrated the vulnerability of this industry and the importance of risk management in a broad sense.

DNV has assisted BP

after the accident in assessing the risk and the technical solutions for stopping the blowout.

We have addressed the risk management issue in this update as well as presenting a position paper concerning key aspects of an effective US offshore safety regime.

The paper is meant as a contribution to the on-going discussion on how to improve safety and environmental protection during offshore oil and gas exploration, development and production operations.

Carbon Capture and Storage (CCS) is another

area where DNV has made a strong contribution by leading the work of developing the world’s most comprehensive guideline for the safe and sustainable geological storage of CO2.

DNV’s objective is to safeguard life, property and the environment. Offshore developments in the Barents Sea and environmentally sensitive areas, such as Lofoten in Norway, are subject to a lot of attention from the public and politicians. Through the Barents 2020 initiative, DNV has helped to develop a guideline for safe offshore operations in the

Barents Sea. We have also conducted environmental risk studies regarding the use of Lofoten and Vesterålen as an important basis for this area’s future management plan.

In this update, you will find more details about the above issues as well as other interesting articles about important projects and technology developments.

I hope you will enjoy reading it. Please contact us if you wish to let us know your views on issues that are important to you as well as to share news during this year’s fantastic ONS event.

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“Static Kill” manifold onboard the Q4000 during the “Static Kill” in the Gulf of Mexico at the MC 252 site, on 03 August 2010.

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Risk Management after Deepwater Horizon

Risk Management after Deepwater Horizon The offshore industry invests considerably in safety and these investments have resulted in a steady improvement in safety performance. Despite this – accidents still happen. Why is this and what can we do to improve even further? For the sake of good order – the following is a general discussion and not based on any specific information from the Deepwater Horizon accident. And the experiences referred to are from a range of companies, including operators and suppliers to the offshore industry.

Text: Magne Tørhaug

In brief terms, the purpose of risk management is to take the right actions to handle the right risks. Do we know all the safety risks involved in offshore fields?

In broad terms, yes of course. All operator organisations have in-depth, detailed knowledge about risks and make great efforts to ensure the risk picture is kept up-to-date. However, there is still room for some improvement. Two areas in particular can be mentioned: the first is risks due to the extrapolation of design principles.

These typically occur when engineers alter the dimensions of their designs to a level where physical behaviour changes drastically. For example, heavier BOPs now cause the Eigen frequency of a floating rig/riser/BOP/wellhead combination to be close to typical surface wave frequencies – potentially leading to wellhead fatigue challenges. The second group of difficult safety risks is larger: those due to the dynamics of change. An example of this is the handling of safety during complex operations like the drilling and completion of a well, where safety barriers change during the operations. Other examples are human interaction with systems and changing risks due to wear and tear. A major contributor to several large accidents

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has been ongoing repairs or unrepaired system failures, i.e. systems which were temporarily outside their intended design conditions.

Do we manage the safety risks we know in the right manner and, above all, do we deal with the right risks? Many operators have focused heavily on this area in the past few years. We observe many very good practices here, but also a great deal of variation between organisations – even within companies. In the worst cases, we see that it has taken years to deal with conditions or designs which for very good safety reasons are listed as having top priority for change. Priorities may not always be correct: Some companies intensely persue their employees and visitors for not holding on to stair handrail. The lack of ability to deal with important issues is partly blamed on a lack of resources – each operating organisation is sized to handle exactly a “normal day”. Anything out of the ordinary requires special work processes and additional resources. Also there are typically long lists of things which need changing and these need be handled in a co-ordinated manner. The top safety issues do not always survive these prioritisation processes. This is a well known challenge

in risk management – that of structuring risk governance to ensure good risk reporting, the escalation and allocation of important risks in the organisational hierarchy, and good routines for the transfer of risks between units. Finally – some decision makers have problems prioritising issues in order to handle the risk of rare accidents with major consequences. These risks tend to be undervalued because they are complex to both understand and deal with. It seems easier to prioritise handling the risk of more frequent accidents with smaller consequences. From a safety risk management point of view, this may not be optimal.

Looking beyond the immediate causes of accidents – what can we learn? The development of new technology and new organisational practices have provided useful tools for optimising designs, work processes and organisations. The effects are highly valuable improvements in technology and operations. This has, however, also changed the conditions for successfully practising safety risk management.

In design and fabrication, there is much less room than before for failures and deviations from technical tolerances, i.e. a small deviation that was once harmless

Risk Management after Deepwater Horizon

could now cause a serious failure – and we see several examples of this in our failure investigations. A similar development applies to operational procedures and decision-making in operations. Disregarding the total effect of small and what seem to be individually insignificant deviations from safe practices may have grave consequences. The requirements of accuracy in decision-making and work execution are higher than before.

We think there is a need to upgrade safety risk management to better deal with these challenges. Some of the most important improvement areas are (in order of priority): n Bring higher quality into risk management leadership, including governance structure and the operational decision makers’ ability to assess and deal with risks in actual operational situations.

Risk escalation and the transfer of risks between units (and contractors) and over time are typical governance areas that can be improved. Other possible means are training to improve the understanding of risks due to rare/ large consequence accidents and how to prioritise these if they occur. Improved tools and more direct support could also be considered. n Dealing with the dynamics of handling the risk of changing conditions during operations. This is in part a question of improved attention to the details of risk assessment during such situations on site. In part, it is also a question of directing desktop risk analyses to assess such situations and of using the results when preparing operational decision makers. n Improve the accuracy of our risk assessments – in particular this means becoming much more technology-specific for important systems and functions.

DNV is working to contribute to these improvements through joint industry projects and internally funded developments. If you are interested, please contact us for further information.

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Magne Tørhaug, Director Market and Business Development.

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Key Aspects of an Effective U.S. Offshore Safety Regime

Elisabeth Tørstad, COO Division Americas and Sub-Saharan Africa

Eirik Andreassen, Director of Operations, International Affairs

Robin Pitblado, Service Director, SHE Risk Management

Peter Bjerager, Director of Operations, Energy Services Region North America

An effective US offshore safety regime As a consequence of the Deepwater Horizon blow-out accident in the Gulf of Mexico, DNV has prepared a position paper highlighting the key aspects of an effective US offshore safety regime. Major accidents tend to lead to a review and revision of current practices and regulations with the objective of avoiding other major accidents in the future. This also appears to be the case after the tragic Deepwater Horizon blow-out accident and subsequent oil spill. DNV´s views on key aspects of an effective offshore safety regime are presented in the position paper that has now been developed.

“The position paper is meant as input to the on-going discussion on how to improve safety and environmental protection during offshore oil and gas exploration, development and production,” says COO Elisabeth Tørstad, who has been in charge of the project.

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The white paper presented on the following pages has been prepared by Robin Pitblado and Peter Bjerager in Houston and Eirik Andreassen in Oslo with input and suggestions received by a number of experts and managers in DNV.

Key Aspects of an Effective U.S. Offshore Safety Regime

Key Aspects of an Effective U.S. Offshore Safety Regime Major accidents lead to a review and revision of current practices and regulations with the objective of avoiding similar or other major accidents in the future. This also appears to be the case after the tragic Deepwater Horizon blow-out accident and subsequent oil spill. This paper presents DNV´s view on key aspects of an effective offshore safety1 regime. The paper is meant as a contribution to the on-going discussion on how to improve safety and environmental protection during offshore oil and gas exploration, development and production. The paper supports and complements the recommendation for a more systematic approach to safety and environment in the U.S. Department of the Interior (DOI) report on “Increased Safety Measures for Energy Development on the Outer Continental Shelf” (May 27, 2010).

DNV believes that a step change can be achieved with respect to prevention and mitigation of major accidents through an effective and efficient safety regime for offshore energy exploration, development and production. Such a safety regime must be risk-informed, balancing the inherent risks with the benefits for society and must possess the following characteristics discussed in this paper n Performance-based supplemented by prescriptive regulation n Consideration of technology, organization and people n Clear roles and responsibilities n Enforced identification, reduction and control of risks n Shared performance monitoring n Practical and economic feasibility n Balance between risk, control and condition DNV has world wide experience within risk management in the offshore energy and maritime industries. DNV advises regulators on offshore safety regulation as well as executing key functions on behalf of authorities and industry in order to safeguard life, property and the environment. This paper does not present the many ways in which the key aspects could be implemented within law and regulation or how they are effectively institutionalized, or which roles are best managed by governmental agencies and which by independent or private organizations. The paper does, however, highlight issues and methodologies that DNV believe regulators should take into account when promulgating new legislation.

Objective of an offshore safety regime Oil and gas will constitute the major part of the U.S. energy 1

supply in the foreseeable future despite on-going and needed efforts in developing renewable and other alternative energy sources to meet our energy demand and limit carbon emissions.

In addition, deep water exploration and production of oil and gas will continue to be a vital part of our oil and gas supply. Because of this, additional focus on managing risk of deep water activities is needed to prevent consequences such as those from the Deepwater Horizon accident.

Following a major accident we have an obligation to review and revise as needed the offshore safety regime under which oil exploration and production takes place with the objective to n Ensure that exploration and production activity is done safely and in a sustainable manner, and n Assure all stakeholders – foremost the public – that activities that pose a threat to life, environment and property are properly controlled DNV believes that a safety regime for offshore energy exploration and production must ensure that n Life, environment and property are protected in an effective, consistent, transparent and predictable way; both for those directly affected and involved in offshore operations, but also for those otherwise affected by an accident, such as fisheries, recreation and the whole ecosystem n Risks are properly evaluated and all prevention and mitigation measures are identified n Control measures are implemented and maintained by all parties in accordance with mandatory risk assessments as well as what is prescribed by regulation

Safety in this paper often covers all aspects related to health, safety and the environment (HSE).

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Conditions of safeguards, facilities, procedures, personnel and organizations are continuously monitored throughout the lifetime for proper functioning and compliance with all regulatory requirements and to assure that risks do not increase n Technical innovation and efficiency improvements can be implemented safely and responsibly n

Performance-based supplemented by prescriptive regulation The safety regime must benefit from all learning of the past. This is the traditional way of developing safety regulations where previous events lead to new knowledge and additional regulation that prescribes a set of requirements for industry to follow. In most cases, however, regulators and industry do not regularly revise and upgrade procedures, rules and regulations, as the collective knowledge of how to operate safely increases (e.g. Baker Panel3 findings after Texas City). More often, a major disaster becomes the trigger to update regulations that have been proven to be insufficient.

Every major accident at sea has been followed by new regulation, from maritime oil spill accidents such as Exxon Valdez, Erika and Prestige to offshore oil and gas accidents such as Alexander Kielland, Piper Alpha and now Deepwater Horizon. The same is the case in the chemical process industry where accidents in Bhopal, Seveso, Pasadena Texas and Texas City led to new US and EU regulations. The potential weakness from such regulatory development is that issues of the moment rather than long term sound policy become dominant and that all focus is on the specific event and root causes with insufficient focus on other possible, future hazards.

An offshore safety regime based on prescriptive regulation has the advantage of being relatively easy and simple to implement and follow up but has the weakness that it may not prevent new types of accidents that may appear in the future and it often prevents innovation due to its specific, prescriptive rules and requirements. It may also limit operators’ dedication and understanding of responsibility as well as proactive initiatives to increase the safety level beyond compliance. This is particularly important in the deep water offshore arena where new technologies and techniques to improve production and safety and also reduce costs are being constantly developed, but by their nature may introduce potential new risks.

To be able to account for new types of events and to allow for needed innovation and new technology in the future, performance-based (also referred to as functional-based or goal-based) safety regimes have been introduced in several countries. In these, performance requirements and acceptance criteria are specified and industry must document that their specific solutions meet such requirements, e.g. in terms of acceptable risk levels. The advantage of performance-based regulation is that solutions for the problem at hand can be developed free of specific prescriptions. The regulation will include comprehensive safety – or HSE

– cases that document how all risks (including novel risks) for the specific facility, operational conditions and location will be prevented or mitigated. A challenge of a pure performance-based regulation is that it may require more analysis and documentation to be done in each individual case to verify that performance goals are met. It also requires a competent and active regulator.

The current safety regime for the U.S. Gulf of Mexico is largely a prescriptive regulation with no requirement for safety cases4 to be performed. The offshore safety regimes in the UK and Norway, for example, are of the performance-based type where safety cases (UK) or detailed risk assessments (Norway) must be presented to the authorities who review and accept - rather than approve these before implementation. Once accepted, operations not in conformance with the safety case is an offence.

DNV believes that an offshore safety regime based on a performance-based regulation requiring safety cases including risk assessments supplemented by required or recommended specific prescriptive regulation for selected areas is the most effective regime model. Areas that may be addressed by prescriptive regulation are typical facilities, components and situations where experience exists. The prescriptive regulation may include specific requirements supplemented e.g. by API standards and class societies such as DNV Offshore Codes.

The safety regime must ensure a safe operation of the offshore facility throughout its lifetime. The safety case performed at the design stage must be implemented in the actual operation of the offshore installation and not just end as a document on a bookshelf. Furthermore, the offshore installation may be modified, it will degrade over time, external loading conditions on structure or process system may change, and the operator and crew may change. Each such change of condition must be monitored and documented as a safety case update as part of the regulated process for ensuring a safe operation.

Consideration of technology, organization and people A complex system such as an offshore drilling or production platform performs safely and reliably only when 1. The technical facility is fit for purpose and works as intended 2. The people operating the facility are trained and competent, also as regards safety culture, and 3. The organization is defined so decisions are made and safe procedures are followed as planned

Within chemical process plants these aspects are often referred to as plant, process and people which all must be fit for purpose and performing accordingly for the process plant to perform safely.

When root causes are identified for major accidents, it generally turns out to be a combination of several factors that lead to

3 The Baker Panel was established to investigate safety management systems and safety culture after the Texas City disaster – they laid out many important concepts for enhanced major accident prevention. 4A Safety Case is a documented, facility specific, safety and environmental program that identifies all hazards, estimates risks and demonstrates how these are prevented or mitigated to a stringent target level of safety, merging both prescriptive and facility specific requirements. All safeguards are documented, their required performance defined, owners assigned, and means to keep functional at all times specified (e.g. maintenance, competence, etc), and providing a transparent means to verify the conditions.

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Key Aspects of an Effective U.S. Offshore Safety Regime

the accident – and often a combination of technical, human and organizational failures. Even when it at first appears that it was a technology failure, the root cause analysis may reveal that organizational or human failures e.g. during modifications or maintenance in reality lead to the failure.

Organizational and human factors are the dominant root cause factors and together often estimated to constitute up to 80% of the causes for major accidents.

In summary, it is critical that an offshore safety regime properly accounts for technological, organizational and human factor defenses – or barriers5 – in the prevention and mitigation of accidents throughout the lifetime of the offshore installation.

Clear roles and responsibilities An effective offshore safety regime must ensure that clear roles and responsibilities are established between all parties involved. In particular, the role and responsibility between authority and operator is important. The performance-based regime has been preferred by a number of authorities not least because of its very clear split of responsibilities, where authorities define performance goals and acceptance criteria and the operator has the responsibility to ensure that these performance goals are met. The aim is to force the operator and contractors to take an active role and not lean on authorities to ensure safety. In such a regime the authorities will normally not approve the operator’s plans but only review and accept them.

In a prescriptive regime the authorities define implicitly the performance by prescriptive requirements and will furthermore typically approve the operator’s plans, in some cases including detailed operations. Although the operator normally will be defined in the regulation to carry the liability for the operation, matters may become unclear if something goes wrong and the authorities have both given specific requirements for the facilities and operation plans as well as approved their implementation.

Also, the responsibilities between parties may also vary between different pieces of the regulation. The choice of the performancebased model is therefore natural when authorities want to minimize own risk and liability.

Enforced identification, reduction and control of risks DNV believes that risks such as those related to offshore drilling and operation can only be properly managed if the risks are known and understood by the operator (and subcontractors to operator) of the facility. Therefore, a key element in an offshore safety regime is that all parties are required to take an active role on undertaking holistic risk assessments for a specific installation through which preventive and mitigating means are identified and where all factors mentioned above are included in the safety and environmental models. Furthermore, the regime must ensure that

such risk management is maintained throughout the life of the installation and continuously kept up to date to prevent deterioration of barriers that prevent and mitigate risks.

DNV believes that the frequency of major accidents only can be significantly reduced by identifying the risks and the factors influencing these risks through quantified risk assessment where the effect of preventing and mitigation measures can be directly evaluated and compared. This is the means that have been introduced in other industries such as nuclear and aerospace and which have proven successful in reducing major accidents. As mentioned, the current offshore safety regime for the U.S. Gulf of Mexico does not require risk assessment and safety cases to be established.

IADC has, however, a recommended approach for a safety case for mobile drilling units. DNV believes that such requirements with extensions must be introduced in the future regulation so that all risks are evaluated throughout the lifetime of the offshore drilling and production activities, including design, construction, installation, operations, maintenance, adaptation of new technologies, modifications and decommissioning.

It should be noted that some operators in the US Gulf of Mexico already perform risk assessments due to their own corporate governance and based on experience from other safety regimes in the world. Furthermore, the challenge of handling an unlimited liability for operators can be met through a systematic risk management approach where active prevention and mitigation barriers are monitored and managed throughout the lifetime.

Shared performance monitoring DNV believes that performance monitoring of all factors influencing a safe operation should take place throughout the life time of the facility. The monitoring should include the actual risks updated regularly, the condition of the facility, people and organization as well as the condition of all barriers preventing and mitigating accidents. Such performance monitoring would be a continuous assessment of the total integrity of the operation and ensure that, for example, barriers do not deteriorate.

The performance monitoring should be shared – fully or partly – with all parties participating in the operations such as partners and subcontractors in order for all to benefit from the knowledge of the actual condition. Part of the performance monitoring could be reported as online information to authorities and regulators as part of their oversight function.

Practical and economic feasibility After a major accident there can be a tendency to establish a significant amount of new regulation where all elements may not have an equally good balance between investment and benefits to society. It is important that new regulation is practical and economically feasible in addition to ensuring sufficient safety

5 The term barriers is here used interchangeably with controls or safeguards, which are any technical, human or organizational feature interrupting an accident sequence – either stopping it or reducing its likelihood or consequence or both.

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and environmental protection. DNV recommends that the effectiveness of new regulation should be assessed on basis of a risk assessment where the reduction of risks (reduction of expected loss) due to the new or modified regulation is compared with the investment needed to implement the new or modified regulation.

As has been seen with the Deepwater Horizon accident it can be important that equipment from other parts of the world can be brought into the Gulf without any delay when needed. The regulation in the U.S. Gulf of Mexico should therefore be aligned with international regulation for offshore oil and gas exploration, development and production. Specific requirements needed for the local conditions such as risk of hurricanes should be established and met in addition.

A step change for major accidents DNV believes that a step change for major accidents can be achieved, i.e. that the risk can be reduced by a factor of 10 by use of risk management. The oil, gas and process industries have achieved significant improvements over the past 20 years in occupational safety and limited spills or pollution incidents because companies´ safety and environmental management have focused on and measured progress in these areas. However, major accidents in safety, structural failures, explosions and environmental pollution have been more resistant to improvement (e.g. major accidents onshore: Texas City6 and Longford Australia, and offshore: Piper Alpha and the Montara blowout).

After the Three Mile Island accident, the nuclear industry achieved a step change using better tools, namely formal Probabilistic Risk Analysis, new audit structures from the Institute of Nuclear Power Operations and stricter regulations. The Offshore industry in the UK and in Norway, following two major disasters with more than 100 fatalities each in the 1980’s, has also achieved an improvement by using safety cases and quantified risk assessments. Also the aviation sector has been successful in reducing major accidents.

There are important lessons to be learned from these achievements: n When seeking a step-change, a holistic approach to address technical, procedural, human and organizational and cultural aspects is essential n A detailed quantified safety and environmental model is necessary to underpin operational decision making to prevent major accidents Balance between risk, control and condition In the North Sea offshore industry and the commercial nuclear power industry, a detailed risk model is established and, from this model, all hazards are identified and managed to a level commensurate with the risks. In the offshore energy industry, all risks would include at least all safety and environmental risks from

topsides infrastructure, subsea arrangements and downhole. This approach has the benefit of being able to reduce risks as they become directly known and the approach therefore provide additional and higher levels of safety and environmental protection.

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Illustration of the elements Risk, Control and Condition in a risk-informed offshore safety regime

A risk management approach is characterized by three main elements 1. Risk: The risk model7 is the foundation of a safety case n The operator must identify of all risks ranging from high frequency, but small consequences to rare major events with significant consequences, ways and means to prevent these accidents and how to respond if prevention fails. The barrier model – mentioned further in the appendix – is an effective technique to understand prevention and mitigation systems, equipment and operating procedures. n The engineering and maritime design must meet current regulations and standards and the safety case must describe the basis for the design and operation. n The risk model must have a sound basis and detail. To achieve a step change it must in the design stage be quantified to cover safety and environment risks on the topsides, subsea and downhole. Subsequently, operations procedures may rely on, or require, more qualitative risk models. n The risk model is used to establish the required performance of all critical aspects (technical, human and procedural) and these performance standards would be used for verification.

2. Controls: Effective mechanisms for control must be implemented n Ensure that regulatory requirements and safety case commitments are achieved in practice, are documented and communicated to all offshore and onshore staff and contractors n Ensure that modern safety & environment management system and process safety and safe drilling operations culture programs are in place to institutionalize success and to prevent short term financial Key Performance Indicators from increasing longer term threats

6 Texas City refinery explosion 2005; Longford Australia gas processing facility fire 1998; Piper Alpha North Sea rig explosion and fire 1988, Montara oil well blowout off Northern Territory 2009 – particularly well documented and studied accidents amongst many. 7The concepts of a risk model are outlined further in the annex to this paper.

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n

Verification by an independent, competent party as a key control mechanism both during design and operations

3. Condition: The sound condition of all elements must be continuously monitored n Complex systems are subject to degradation or failure from the moment of entering service. Processes must be in place to maintain equipment and to ensure that systems meet the required performance standard throughout the life time n As well as the technical systems may degrade, this is also the case as regards working culture, organization and human competences which must be included in the condition monitoring processes n Changes in system, organization or people must be assessed, managed, controlled and documented before implementation, with effective processes for returning critical equipment to its current state after temporary changes It is important to have the right balance between the three elements risk, control and condition. A safety regime which has focus in only one or two of the elements will lead to ineffective risk management. A prescriptive regime focuses typically on control and condition but less on risk.

Conclusion DNV believes that an effective and robust safety regime for offshore energy exploration, development and production must be risk-informed and must possess the following characteristics n Performance-based supplemented by prescriptive regulation n Consideration of technology, organization and people n Clear roles and responsibilities n Enforced identification, reduction and control of risks n Shared performance monitoring n Practical and economic feasibility n Balance between risk, control and condition

DNV believes that the introduction of a risk management approach as basis for a new regulatory regime within U.S. waters will significantly improve the safety of offshore oil exploration and production. It will meet the public expectations for assessment of all risks as well as accommodate further development in offshore exploration and drilling safety and environmental protection.

DNV believes that it is critical to maintain and use a living quantifiable safety and environmental risk model to support decision making to prevent major accidents. A holistic model is needed that addresses all aspects affecting the safety, such as technical, procedural, human and organizational and cultural aspects.

This paper is intended to introduce the concept of a risk informed approach to safety and environmental regulations, and does not attempt to describe the concept comprehensively. DNV will be pleased to assist and contribute to the discussion and development of an improved offshore safety and environmental regime for the United States.

Appendix Risk models A risk model is a formal review of all threats to safety and the environment. Although complex in execution, the basic principles are simple and shown in the figure below. Because of its conceptual simplicity, however, the importance and complexity of asking the critical questions in the analysis of what can go wrong is often underestimated. This analysis needs to be undertaken both from a holistic perspective and from a detailed perspective on technology, people and organization. Therefore, the assessment requires a dedicated and tailor made approach and can not be undertaken by simple checklists or other standardized approaches.

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Illustration of the risk assessment and mitigation identification process

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Illustration of a holistic, quantitative risk model for offshore installation

Two risk models should be established, one for the Safety Case during the Planning Stage and one for the Operations Stage as briefly outlined in the following.

Planning Stage Risk Management The Planning Stage risk model includes quantified risk assessment (QRA) that uses detailed engineering studies and human performance models to identify all risks and demonstrate how they are prevented and, if an event occurs, mitigated. The figure above illustrates such a holistic, quantitative risk model. Within offshore facilities,

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there has traditionally been a focus on safety due to fire and explosion on the topside. A holistic model should also include e.g. environment and downhole related risk as illustrated in the figure.

A QRA is a risk model that quantifies key aspects of risk and – importantly – allows for the demonstration of risk reduction by the application of defined safeguards. In many ways, a QRA is similar to a Nuclear Probabilistic Risk Assessment (PRA), except that the numerical approach is a little different (discrete versus probabilistic) and the range of events examined is much broader for the offshore industry while the PRA focuses mostly on the single event of potential reactor meltdown.

Operations Stage Risk Management The Operations Stage risk model captures all the findings and requirements and translates these into easily understood terms and documents that can be effectively managed and driven into a positive process and safety culture during operations. The documentation will likely consist of a combination of a qualitative barrier diagram approach (often termed a “Bow Tie”, see figure below) for foreseen threats and an operational version of the QRA model described in the previous section to address unforeseen issues.

The nuclear industry uses also such an operational approach in utilizing the PRA model.

Verification and improvements through audits, reviews and inspections Regular audits during operations of the risk management system are vital. Important areas that need to be addressed are the management system, the process safety and organizational culture, seamless processes across company staff, contractors and sub-contractors, offshore and onshore as well as the status of all barriers.

Also the readiness of prevention barriers must be included, such as emergency and mitigation measures e.g. for containment of oil flow from a well and reduction of oil spill in the ocean.

Management and staff reviews must in the same way be executed regularly in order to improve continuously. Finally, regular and in-depth technical inspection and verification of physical facilities are needed to ensure robust integrity.

Effective communication and decision making Modern information and communication technology can be an effective support in sharing performance monitoring of risks and barriers as well as for making team-based decisions for critical situations in an integrated operations environment as illustrated in the figures below.

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Bow Tie barrier model showing critical barriers (controls). Prevention barriers are on the left and mitigation barriers on the right. Each barrier should have a responsible person - only some of these are illustrated.

Most accidents (e.g. Bhopal, Texas City) have been demonstrated to be due not to an unforeseen threat, but due to a known threat adequately addressed by regulations and company requirements, but where the safeguards have been allowed to degrade over time (technical, human or organizational). The Chemical Safety Board investigations have shown the same to be true in other serious U.S. accidents (e.g., recent explosion at Imperial Sugar, Georgia).

Thus, a vital output of the Operations Stage risk model is that it be maintained up-to-date to provide a clear understanding of the current status of all barriers and how they affect risks, when these have degraded what must be done to return the system to a safe state, and ensure that all company staff, contractors and regulators are aware of the barrier status at all times in daily operations.

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IT system can be used to communicate the current status on barriers and risk to allow everyone anywhere to access this information in real-time.

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Conference systems allow for “Decision Rooms” where offshore and onshore staff, contractors and regulators can meet in a common place for superior teambased decisions.

Key Aspects of an Effective U.S. Offshore Safety Regime

About DNV With the corporate objective of safeguarding life, property and the environment, DNV helps business and society to manage risks on basis of DNV´s independence and integrity. DNV serves a range of industries with special focus on the energy and maritime sectors.

Established in 1864, DNV has a global presence with a network of 300 offices in 100 countries, and is headquartered in Oslo, Norway. As a knowledge-based company, DNV’s prime assets are the creativity, knowledge and expertise of our 9,000 employees.

DNV is a global provider of services for managing risk, helping customers to safely and responsibly improve their business performance. As companies today are operating in an increasingly complex and demanding risk environment, DNV’s core competence is to identify, assess and advise on how to effectively manage risk, and to identify improvement opportunities. Our technology expertise and deep industry knowledge, combined with our risk management approach, have been used to manage the risks in high-profile projects around the world.

DNV in USA DNV opened its first office in USA in New York in 1898. Today DNV has 700 employees in USA with offices in Atlanta, Chicago, Columbus, Cincinnati, Detroit, Houston, Jacksonville, Long Beach, Boston, Miami, Norfolk, New Orleans, New York, Portland, Seattle, San Francisco and La Porte.

DNV’s main activities in USA are within the energy sector, both within oil & gas exploration, development and production as well as within wind energy. DNV is engaged in verification, classification and asset risk management offshore in the Gulf of Mexico and within risk management of onshore pipelines and refining. DNV has a Deepwater Technology Center in Houston and

a leading Corrosion and Materials Technology Center in Ohio focusing on management of degradable structures. The Technology Center in Ohio was a leader in the development of pipeline corrosion assessment standards referenced by US Federal Regulations. DNV is the largest independent consultancy within wind energy in USA. DNV helps the maritime industry to manage risk in all phases of a ship’s life through ship classification, statutory certification, fuel testing and a range of technical, business risk and competency-related services. DNV is among the top two classification societies for mobile offshore units. DNV is present in all maritime clusters in U.S. and our Global Cruise Center located in Miami supports our leading position in this sector.

DNV and Authorities DNV works for and on behalf of more than 130 authorities as an authorized, notified or accredited body within classification of offshore structures and ships, within certification of management systems and products and within validation and verification of climate change projects on behalf of United Nations.

DNV is authorized by the US Coast Guard as a classification society, approved by Department of Interior as a Certified Verification Agent, accredited by ANSI-AQS National Accreditation Board for certification services and approved by US Centers for Medicare and Medicaid Services to accredit hospitals.

DNV Offshore Codes The DNV Offshore Codes are a comprehensive set of documents in a 3-level hierarchy consisting of Offshore Service Specifications, Offshore Standards and Recommended Practices. The DNV Offshore Codes are referenced in a number of offshore safety regulations.

Published 22 July 2010 Det Norske Veritas USA Inc. 1400 Ravello Drive Katy, Texas 77449 USA Tel: +1-281-396-1000 Email: DNVHouston@dnv.com www.dnv.com Contacts Service Director, SHE Risk Management Robin Pitblado, robin.pitblado@dnv.com Director of Operations Peter Bjerager, peter.bjerager@dnv.com Director of External Affairs Blaine Collins, blaine.collins@dnv.com

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Carbon Capture and Storage

Breakthrough guideline to boost Carbon Capture and Storage DNV and the energy industry, with valuable contribution from government agencies, have developed the world’s most comprehensive guideline for safe and sustainable geological storage of CO2. This unified procedural framework is intended for global use, supporting both industry and regulators, and is a breakthrough that should speed up the large scale deployment of Carbon Capture and Storage (CCS).

Text: Svein Inge Leirgulen

››

A new unified procedural framework will accelerate the implementation of carbon capture and storage.

Deployment of CCS has been hampered by a lack of tailored regulatory frameworks and established industry practices. This was the key motivation for developing the CO2QUALSTORE Guideline for Selection, Characterisation and Qualification of Sites and Projects for Geological Storage of CO2.

The guideline provides a comprehensive and systematic process that covers the full lifecycle of a CO2 storage project, from screening and site selection to

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closure and transfer of responsibility from the operator back to the national state, taking into account the unique characteristics of each potential site. The aim is to accelerate the implementation of CCS by providing a common, predictable and transparent basis for decision-making between project developers, operators and regulators.

Project developers will benefit from a procedural framework to select and manage sites, delivering consistency and

efficiency based on best engineering practice and technology. Regulators can use the guideline to verify that sites have been selected and assessed as suitable for geological storage of CO2, following a standardized and globally recognised procedure.

Verified implementation of CCS projects in compliance with this guideline should also help provide assurance to the general public that a storage site is selected based on a recognized process, will be

Carbon Capture and Storage

The CO2QUALSTORE Joint Industry Partnership Members of the JIP are: Arup, BG Group, BP Alternative Energy, Det Norske Veritas (DNV), DONG Energy, Gassco, IEA GHG R&D Programme, Petrobras, RWE Dea, Schlumberger, Shell, Statoil, and Vattenfall.

The project was partially funded by the Research Council of Norway through the CLIMIT programme and was co-ordinated by DNV. A number of government agencies have also given valuable input to the development.

safely and responsibly managed according to recommended practices for sustainable CO2 storage, and is in compliance with regulations, codes and standards.

According to project manager, Jørg Aarnes at DNV: “The lack of tailored regulatory frameworks for CO2 geological storage has threatened to delay large scale adoption of CCS. In addition to providing increased predictability for operators, the guideline will help governments to implement internationally

harmonised regulatory frameworks for geological storage of CO2. We therefore believe the CO2QUALSTORE guideline is a real breakthrough moment for CCS and should provide a step-change in the pace of CCS deployment.”

Jørg Aarnes further emphasises that “while CCS alone will not solve the climate change challenge, it is a necessary part of the global mitigation strategy. The world’s energy demand cannot be met in the short term without continued use of fossil

fuels. CCS is the only mature technology that may provide significant reduction of CO2 emissions from combustion of fossil fuels, and is therefore a key bridging technology to a renewable energy future.”

Leading engineering, oil & gas companies and government bodies were brought together by DNV to develop the CO2QUALSTORE guideline 18 months ago. The procedural framework that was developed mirrors best practices within the oil & gas industry, reflects existing and emerging regulations, standards and directives relevant for geological storage of CO2, and draws on learnings from R&D and pilot CCS projects around the world.

With the world of CCS developing rapidly, the CO2QUALSTORE guideline will be updated periodically to keep pace of changes.

Full copies of the guideline are available from www.dnv.com/co2qualstore

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Barents 2020

Barents 2020 Assessment of International Standards for the Safe Exploration, Production and Transportation of Oil and Gas in the Barents Sea. Text: Erling SÌbø

The final report of this Russian-Norwegian cooperation project was approved by the project steering committee in March 2010. The report provides common, agreed recommendations for the use of international industry standards in Russian and Norwegian waters in connection with oil and gas operations in the Barents Sea. More than 100 experts from recognised Russian, Norwegian and international organisations have participated in seven expert working groups, focusing on safeguarding life, the environment

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and asset values and taking into account the additional cold climate challenges which face the oil and gas industry in these waters.

The report has been sent to industry, public and standardisation organisations in Norway, Russia and internationally. The report is offered as guidance for operators, contractors and manufacturers that will be involved in oil and gas activities in the Barents Sea, be it on the Russian or Norwegian side. It is further assumed that authorities may find the recommendations

useful in connection with their supervision activities, and finally that standardisation organisations will consider the proposed amendments to international standards in connection with their regular updating of such standards.

In total, 130 recognised industry standards have been assessed and, while half of them may be used in the Barents Sea as they are, amendments are recommended for the other half in order to maintain an acceptable safety level.

Barents 2020

›› From left to right: Nils Andreas Masvie, Regional Director, DNV Energy, Mrs Vlada Rusakova, member of Gazprom Management Committee, Mrs Marina Fokina, interpreter, Henrik O. Madsen, President and CEO of DNV. In the background: Mrs Tatjana Lobanova, Deputy head of Gazprom Department of strategic development.

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Escape, Evacuation and Rescue Operations in the Barents Sea

Escape, evacuation and rescue operations in

the Barents Sea Work Group 4 for the Barents2020 Project has identified a need for change in existing maritime and offshore oil and gas standards for escape, evacuation and rescue (EER) operations in the Barents Sea, and has proposed recommended changes in the standards.

Exerpt from the Barents 2020 Final Report

The Work Group has assessed a number of Norwegian, Russian and other international standards for maritime and offshore work typical for Barents Sea conditions. It has taken into account Russian and Norwegian experience with cold climate operations of ships in Arctic and sub-Arctic conditions, including the northern Caspian Sea and offshore Sakhalin Island. The assessment has included a review of a limited number of key recognised standards which currently contribute to the definition of the safety level for people, the environment and investments within the topics reviewed by the Work Group.

Risk Identification for the Barents Sea In the Barents Sea, as well as in other ice-covered regions of the world, a wide range of ice and weather conditions and structure-dependent factors can be seen

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at any particular point in time. Because of this, safe EER approaches must be capable of accommodating a full spectrum of ice or open water situations, which are often complicated by many other environmental and logistical factors.

The major EER risks which were identified by the Work Group include the following: n Traditional EER methods may not be appropriate for most of the year. n The full range of ice conditions, including icebergs and sea ice, combined with cold weather, wind and other weather conditions which may be encountered. n The logistics systems that may be available to support any required evacuation from the structure or vessel, including the presence of standby vessels. n The long distances from the potential emergency site to the support bases and other facilities.

The shortage of duly equipped support vessels that may be called on for assistance, with regards to their manoeuvring and station-keeping abilities in ice. n The accumulation of ice on external surfaces and its effect on equipment operation. n The limited amount of time that is available to react to a particular emergency situation. n The effect of cold temperatures on human physiology and psychology, equipment, materials and supplies. n The lack of experienced personnel and training facilities for the specific evacuation systems which have been proposed for the Barents Sea. n The effect of the polar night, with extended periods of darkness, on personnel activities in Arctic conditions. n

Escape, Evacuation and Rescue Operations in the Barents Sea

Difficulties caused by communication due to magnetic conditions and high latitude, lack of satellite coverage and language differences. n The possible lack of qualified medical help. n

The EER risks are closely related to the installation’s type, function, location in the Barents Sea and distance from rescue bases and resources. Hence the EER risks are, and should be, an integral part of the overall risk assessment for the installation itself.

Recommended Key HSE Standards The Work Group reviewed an extended list of applicable standards and concluded that no single standard (international, Russian or Norwegian) adequately addresses HSE concerns related to EER for the Barents Sea. The Work Group decided that a certain minimum number of key standards should be identified as the standards which should possibly be “upgraded” to Barents Sea standards for use in Norway and Russia. The remaining standards to be investigated should be treated as reference documents.

The process for selecting the standards to review was discussed. The following criteria were established: n Best international offshore practice n Relevance to Barents Sea conditions n Relevance to general Arctic/cold climate operations n High level in the standards hierarchy n High level of satisfying functional standards

The main Norwegian and Russian standards and other international or national standards were reviewed and these documents’ compliance with the above criteria was discussed in brief. Key standards were those which covered all main EER topics and satisfied most of the issues listed. Reference standards were largely to serve as support for recommendations for change.

It was concluded that the Draft International Standard (DIS) for ISO19906 should be used as a common basis for the Work Group’s comments or recommendations.

list of key standards Standard

Title

ISO/DIS19906

Petroleum and natural gas industries – Arctic offshore structures (Chapter 18, Escape evacuation and rescue, and Appendix A18)

ISO/15544

Petroleum and natural gas industries – Offshore production installations – Requirements and guidelines for emergency response

NORSOK Z-013

Risk and emergency preparedness analysis

NORSOK S-001

Technical safety

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Escape, Evacuation and Rescue Operations in the Barents Sea

The Work Group also recommended the Canadian Offshore Petroleum Installations Escape, Evacuation and Rescue Performance-Based Standards as a valuable reference document.

The Work Group recognised and agreed that the relevant sections (Chapter 18, Appendix A18) of ISO/DIS 19906 provide appropriate general and functional guidance for EER operations in Arctic conditions. However, the standard does not provide adequate EER recommendations for the Barents Sea. It was realised, therefore, that the best way to address the Group’s findings would be to propose a separate addendum or guidance document to ISO 19906 for the Barents Sea. General Comments, Findings and Priorities The EER provisions of ISO/ DIS19906 are based on applying a systems approach intended to promote the successful escape from the incident, subsequent evacuation from the installation (when the incident cannot be controlled) and ultimate rescue of installation personnel. It is clear that these EER provisions should be used as part of a continuous improvement process for managing risks and the safety of personnel working offshore in Arctic and cold region environments.

The EER provisions of the ISO standard are performance based, which means that verifiable attributes or benchmarks that provide qualitative levels or quantitative measures of performance are to be achieved. The key characteristic of a performance-based standard is its focus on what is to be achieved rather than on how this should be done. The performance target is to be the development of an EER system that incurs no additional casualties (i.e. a serious life-threatening injury or fatality resulting from an incident, including cases when emergency medical help cannot be provided) when prescribed EER methods and technical means are implemented. The performance target is developed in the context of a design health, safety and environment (HSE) case together with the relevant emergency preparedness plans. The provisions of a modified ISO/DIS19906 should

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be used by stakeholders, including designers and owners.

It is clearly recognised that the safe emergency evacuation of personnel from offshore structures and vessels is of critical importance in the event of a major onboard problem. In addition to the issue of specific evacuation systems and their capabilities, the question of safe evacuation also involves the procedures and training that are necessary for personnel to systematically respond in emergency situations, and a clear understanding of the range of environmental situations that may be encountered.

However, while progress is being made in HSE standards and guidelines, similar progress has not been made in the development of suitable evacuation methods and equipment in order to deal with different emergency situations in both ice and open water conditions. Although it is not commonly stated, most practitioners recognise that the majority of the evacuation systems developed to date do have some limitations, depending on the specific conditions encountered. This is particularly true for offshore structures operating in ice.

Due to Arctic conditions, special

attention should be paid to the development of amphibious vehicles that are able to perform evacuation and rescue operations in open water and a variety of ice conditions (see an example of such a prototype vehicle in the attached figure). No standards for such vehicles exist and this limits the development of these vehicles.

First of all, it is necessary to define operational Barents Sea conditions for new types of amphibious vehicles (including rescue operation conditions). It is also essential to clarify the requirements for stand-by and support vessels in order to verify their ability to pick up personnel from water, ice and rescue equipment.

For the most part, the existing infrastructure in the Barents Sea is not developed and does not allow adequate rescue operations. Therefore it is essential to develop technical means for supporting oil and gas activities in the Barents Sea, coastal infrastructure and mobile support bases. It is also important to establish cooperation between Russian and Norwegian authorities to develop regional standards and joint participation in EER efforts during emergency operations.

BARENTS 2020

BARENTS 2020 – latest update Providing guidance for safe offshore operations in the Barents Sea. The Barents 2020 project: “Harmonisation of Health, Safety and Environmental Protection Standards for the Barents Sea” started off as a Russian/Norwegian cooperation project in 2007, with substantial funding from the Barents 2020 programme which is administered by the Norwegian Government. The first phases of the project are now complete.

Text: Erling Sæbø

The phase 3 final report, issued in March 2010 and available on DNV’s website, gives specific recommendations regarding the use of existing industry standards in the Barents Sea. Some standards can be used as they are, while other standards need to be applied with caution. Some areas of concern are not sufficiently covered in existing standards, and phase 4 of the Barents 2020 project has now been launched to address these issues. Phase 4 will propose industry guidelines where such guidelines are most needed.

The current phase 4 has become an international joint industry project financed by Gazprom, Statoil, ENI, SDAG, Total, OGP, DNV and the Norwegian Government’s Barents 2020 programme. Phase 4 will have the following tasks during 2010 and 2011: n Provide guidance and recommendations on how to design stationary floating installations in the Barents Sea to withstand ice loads, in order to fill the gaps in the 2010 edition of the coming ISO 19906 Standard. n Ensure that best international practices relating to risk assessment and risk management are efficiently applied when planning and developing oil and gas fields in the Barents Sea. For this purpose, two risk assessment workshops will be organised to enable dialogue between the experts and executive authorities.

The topics proposed for the seminars

are: 1) the design of enclosed platforms in the Arctic, 2) a review of the Mexican Gulf oil spill accident in a Barents Sea perspective. n Apply the general system recommendations regarding Escape, Evacuation and Rescue given in the new standard ISO 19906 and provide more specific and practical guidance suitable for Barents Sea conditions, including high-level recommendations and functional specifications for an Arctic lifeboat design. n Provide industry guidance to ensure a safe working environment for personnel on board ships and offshore installations operating in the Barents Sea. The

NORSOK standard S-002 will be used as a starting point for this work. n Identify relevant parameters and define practical criteria for successful Ice Management Operations, in order to ensure that actual ice loads acting on offshore installations and vessels are kept within acceptable limits. In addition, establish operational procedures and propose updates of relevant standards, e.g. ISO 19906. n Specify and propose a regional standard for regular emissions and discharges from ships and offshore units in the Barents Sea, including applying the MARPOL Special Area (SA) requirements.

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Gassco

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gassco

transport system in good shape Norwegian gas wouldn’t reach Europe without pipelines, so it is reassuring to know that health checks of these 20 or so arteries have yielded positive results. text: gasscO

“we’re pleased to say that the overall findings of last year’s inspection programmes confirm that our pipelines are in good technical condition,” reports per atle strømme, vice president for the transport network at gassco. as operator, the company is responsible for about 8,000 kilometres of pipelines with an estimated value of nok 160 billion if the system had to be restored today. like the norwegian police security service (pst), Mr strømme uses the concept of ‘threat pictures’ when explaining condition management of the pipelines. “we use a risk-based methodology to understand which threat pictures we could face,” he explains. “that might be corrosion, for instance; trawl damage, or

collisions with anchors of the kind which damaged the kvitebjørn-kollsnes gas line.” programmes for both external and internal inspection have been established.

Remotely operated vehicles (Rovs) are used to inspect underwater pipelines. such work includes identifying free spans which are longer than the acceptance criteria. internal checks are conducted with the aid of pigs – instrument packages which detect corrosion and measure wall thickness. on land, cathodic protection and third-party activities such as excavation are among the targets for inspection work. “it’s also very important to monitor what goes into the pipelines, and control room staff play an important role in that

gassco is the operator for the integrated system for transporting gas from the Norwegian continental shelf to other European countries. this role confers overall responsibility for running the infrastructure on behalf of the owners. www.gassco.no

context,” says Mr strømme. “good control of hydrogen sulphide and dew point for water means that we don’t need to carry out internal inspection as often as before.” all information from the inspections is collected and summarised in the silverpipe computer tool, which also includes historical and design data for the various pipelines. “together with suppliers and research institutes, the industry has constantly improved its methods for design and condition management of pipelines,” observes Mr strømme. “i don’t know of anyone else worldwide who is better equipped to identify and reduce threat pictures for the technical integrity of this type of pipeline.”

sILVERPIPE is DNV software’s new generation software for pipeline integrity management, designed in close cooperation with DNV Energy. covering both offshore and onshore pipelines, it is a fully multi-user and webenabled system for pipeline data management, risk assessment, inspection management and aggregated management reporting.

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Viking Lady

Viking Lady shows the way Rising concerns over shipping’s role in climate change has put pressure on the industry to develop alternative power and fuel sources to reduce the environmental impact of the world fleet. As the first LNG-powered commercial ship equipped with a fuel cell adapted for marine use, the Viking Lady may be part of the solution.

Text: Alexander Wardwell

“The FellowSHIP project has demonstrated that LNG-powered fuel cell technology can be successfully applied to the marine environment and that these technologies are fully compatible with the normal commercial operation of the vessel.”

Tor E. Svensen, DNV President

By some estimates, eighty-five per cent of global trade is currently shipped by sea.

And while shipping remains the most environmentally safe way to transport goods over long distances, the industry produces about 1000 million tones of CO2 per year, representing about 3.5 percent of global greenhouse gasses. In addition, the heavy fuels used to power diesel electric engines produce a broad range of harmful substances, including nitrogen oxides (NOx), sulphur oxides (SOx) and toxic particles.

The industry has been criticized for not acting quickly enough to manage these issues, but rising public concerns and a surge in regulatory scrutiny has put pressure on shipowners and managers to reduce their impact on the environment.

In addition, the rising cost of fuel has en­couraged many shipowners to seek out ways to reduce consumption, and explore alternative energy resources.

According to a recent study produced

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by DNV (“Pathways to low carbon shipping: Abatement potential towards 2030”) the industry can reduce CO2 emissions 30 percent below the baseline in a cost-effective way by 2030. But according to Tor Svensen, COO DNV Maritime, there is no “silver bullet” technology capable of solving the issue overnight. “What we have here is a model that looks at the potential of a range of reduction measures, from more efficient voyage execution to speed reduction, onboard fuel cells to kite sails,” he says. “If the shipping industry starts acting now and applies the available cost-efficient technologies, emissions can be reduced considerably, without incurring costs.”

Indeed, the study identified no less than 25 emissions reducing measures, ranging from slow steaming to engine monitoring, from the installation of contra-rotating propellers to onboard solar and windpowered generators. Svensen estimates that if the industry utilized all identified

measures, it could cut carbon emissions by 60 percent. “The aggregated effect of all measures are significant and will ensure an industry that operates in a more energy efficient manner and also takes its share of the common responsibility of reducing carbon emissions,” he says.

However, while shipping companies may have the in-house expertise to manage operational changes, such as improved bunkering protocols, weather routing and trim optimization, many are reluctant to invest in unproven technologies. And as the industry cycles through a difficult period, the industry’s focus is largely confined to reducing fuel costs, not investing in new technologies to reduce carbon emissions. In short, to encourage the industry to embrace a more proactive approach to managing emissions to air will require tougher regulations and proven solutions which demonstrate a measurable commercial benefit.

Viking Lady

››

Viking Lady, the first CNG powered commercial vessel equipped with a fuel cell adapted for marine use.

Launched in 2003, FellowSHIP is a Joint Industry Project (JIP) supported by the Research Council of Norway, Innovation Norway, and the Eureka Network, including the German Federal Ministry of Economics and Technology. Partners include DNV, the engine manufacturer Wärtsilä, the Norwegian shipowner Eidsvik Offshore, and the German-based MTU Onsite Energy, a leading developer of fuel cell technology. The environmental group, The Bellona Foundation, also contributed.

The purpose of the JIP was to develop the industry’s first commercially viable fuel cell power pack capable of reducing CO2 emissions by up to 50 per cent and improve energy efficiency up to 30 per cent, compared to existing conventional power generators. If successful, the vessel would represent an industry first.

Fuel cell technology is not new, but until recently, it had never been successfully applied to commercial shipping. Fuel

cells convert fuels more efficiently than traditional combustion engines and therefore significantly reduce energy loss, harmful greenhouse gas emissions and local pollution.

A fuel cell converts the fuel’s chemically stored energy directly to electricity through a reaction with oxygen in the air. The process is similar to that of an ordinary battery – except that a fuel cell does not need to be recharged; it operates as long as it is supplied with a suitable fuel, such as hydrogen, LNG, methanol or biogas. Fuel cell technology also eliminates emissions of harmful substances, such as nitrogen oxides (NOx), sulphur oxides (SOx) and particles.

To succeed, FellowSHIP had to manage a number of technical challenges.

First, because fuel cell technologies can be somewhat sensitive, the team had to develop a robust, reliable system capable of operating safely in a crowded machinery

room while at sea, and in varying sea conditions. Second, the vessel would require class approval of the complete fuel cell system in order to operate safely at sea – an industry first.

Once manufactured, the system would be installed aboard the Viking Lady, an Offshore Supply Vessel, owned and operated

by Eidsvik Offshore. Phase I of the FellowSHIP project included a feasibility study, development of the fuel cell power package adapted for marine conditions, and integrated with new electronic systems, power electronics and control systems.

Since a gas-electric propulsion system provides a perfect test-bed for the fuel cell, the project team decided on Liquefied Natural Gas (LNG) as its primary fuel source. By using LNG instead of heavy fuels, shipowners can eliminate the emission of SOx and particles and reduce the emissions of NOx by almost 90 per cent and CO2 by some 20 per cent. At present,

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viKing laDy

VIKING LADY the Viking Lady was designed and built on the west coast of Norway by Vik sandvik (now wärtsilä ship Design) and west contractors. the Norwegian shipowner Eidesvik offshore took delivery of the Viking Lady on 29 april 2009. the ship is classed by DNV and is currently on charter operating in the North sea. specifications: Length: 92.2m width: 21m Depth: 7.6m gross tonnage: 6,100t Dead weight: 5,900t Berths: 25 persons imo no.: 9409675

›› the Viking Lady operational model at cop15 in copenhagen December last year.

lng is not an appropriate source of fuel for deep sea transportation, but for short sea shipping, or trades within a fixed geographical area, lng represents a promising alternative to heavy fuels. after years of development, the project team produced a 320kw lng fuel power plant, and in 2009, the new system was tested and verified on shore. later that year, the power plant was installed aboard the osv viking lady. testing followed to ensure the vessel was in compliance with the stringent requirements for marine power and sea-trails were a success. today, the viking lady is on charter to the french energy giant total, operating in the rough sea conditions of the north sea. preliminary testing has shown that compared to a similar vessel powered by a conventional power plant, the viking lady has reduced harmful nox emissions by 180

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tonnes — an amount equal to annual emissions from 22,000 automobiles. in addition, co2 emissions have been reduced by 20 percent. additional testing will continue until the spring this year, but already, the project has exceeded expectations. the viking lady is the first commercial ship ever with a fuel cell specially adapted for marine use, and among the few vessels fuelled by lng. the fuel cell reduces emissions to air and fuel consumption and operates very quietly – all significant for a ship with frequent stops in busy harbours located in populated areas. but svensen says that while the technical achievements of the project are notable, the viking lady should not be dismissed as an academic exercise in fuel cell technology. “what is important here is that the viking lady is meeting the commercial expectations of the owner and fulfilling

terms of its charter – all while significantly reducing harmful emissions,” he says. “the fellowsHip project has demonstrated that lng-powered fuel cell technology can be successfully applied to the marine environment and that these technologies are fully compatible with the normal commercial operation of the vessel.” svensen is quick to acknowledge that fuel cell technology and lng-fuelled vessels represent only part of the solution to the climate change challenge and that such solutions are not yet appropriate for all types of vessels or all trades. but he notes that there are a broad range of affordable measures now available to the industry to help manage climate change. “new regulations expected to come into force, combined with a rise in fuel costs will help make the case for action,” he says. “and with fuel cell technology now a proven solution, shipowners have another option.”

Meanwhile, data collected from the fellowsHip project will be a valuable resource to some shipowners serious about minimizing the environmental impact of their operations. “with the viking lady, fuel cell technology has gone from a good idea to a practical, proven solution, and as project evolves, we expect to see the technology developed further,” he says. “it is not the answer, but it is part of the solution.”

Viking Lady

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Sesam Floating Structures

Sesam Floating Structures from hydrostatics to fatigue analysis

Sesam Floating Structures is a complete toolkit for performing hydrostatic, hydrodynamic and structural strength analysis. This leads to enhanced quality, reduced software costs and reduced need for training.

Text: Ole Jan Nekstad

The lack of data integration between various software tools prevents efficient design iterations, as it is necessary to modify the various data models and perform re-analysis for each project revision. Furthermore, when different models are created, the design project is prone to quality problems – in particular when the project set-up is based on a globally distributed working environment.

Using concept technologies in computer-aided engineering has proven to be cost-efficient in all life cycle phases, as the same concept model can be used for different complexities. Typically, the same concept model can be used to create different analysis representations for hydrostatic/dynamic analysis, global strength analysis, local ULS analysis and detailed fatigue analysis. The use of concept modelling enables fast design iterations in Sesam, as modelling is carried out on the structure level – as compared to traditional modelling methods on a geometry or finite element level.

By modelling your experiences – or Best Engineering Practice – in a workflow modelling system, it is possible to share these as templates to the entire organisation. This leads to standardisation of work processes, reduced learning curve and the facilitation of distributed work, resulting in higher quality.

Perform your analyses with ease Sesam supports the life cycle approach of offshore structures. This means that analyses may be carried out for the different stages in a platform’s life. Common for all

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››

Sesam Floating Structures is the perfect tool for ballasting, hydrostatic and hydrodynamic analysis of large floating structures such as barges, ships of any type, semisubmersibles, tension leg platforms, floating production storage units or spar buoys, design of mooring lines and risers ranging from shallow to ultra-deep water depths.

analyses is that they are easy to carry out.

Either a rule-based approach (no integration with hydrodynamic analysis) or a direct analysis approach (hydrodynamic loads automatically included) is used.

There are no limitations to the analysis models in terms of model size or number of loadcases. The analyses are carried out using highly efficient and robust solvers, enabling the use of standard hardware for large problems.

A unique feature in Sesam is the possibility to perform equilibrium analyses and use the various floating positions without altering any model in the hydrostatic or hydrodynamic analysis. Of equal importance is the ability to perform nonlinear hydrodynamic analysis of offshore

structures to include typically pressure loading to the varying sea surface level and to load all wetted surfaces (green sea pressure).

Analysis types supported are typically global and local structural analysis, eigenvalue analysis, forced dynamic analysis and push-over analysis. Sesam has been known to support distributed and concurrent engineering by using the super-element technique. It is also very easy to perform local refined analysis based on a global analysis model without the need for reanalysis of the whole structure.

Closing the design loop Results assessment is a major part of the design process. This package facilitates an easy way to graphically or tabularly evaluate results whether they are deformations, forces, stresses or fatigue life. 3D highresolution pictures or tables for use in design reports may be created one by one or by use of scripting techniques. Offshore structures subjected to wave loads are normally analysed with a high number of loadcases. There are powerful features for combining and scanning results to find the worst conditions.

To document statutory compliance, Sesam includes the most recent code check standards for hydro-stability analysis and structural analysis.

Sesam Floating Structures contains three main packages; the topside package, the hull package, and the mooring and riser package. The packages build on each other – i.e. the functionality in one package may be used in the next package.

Sesam Floating Structures

“As the oil and gas fields get deeper, the installations of deepwater platforms become more challenging. The coupling effects between a floater and its moorings become more pronounced and more important. Sesam is an excellent tool for analysing the interaction between hull, moorings and risers.�

Andy Kyriakides, project manager, Modec International LLC.

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Modelling environmental risks offshore North Norway

Modelling environmental risks offshore North Norway The Norwegian government will soon decide whether or not to open up some of Norway’s most promising waters for offshore oil and gas activities.

Environmental risk studies involving oil drift models and consequence assessments regarding the marine life in Lofoten and Vesteraalen are being used as an important basis for this area’s future management plan.

Text: odd willy brude

This is the reason various stakeholder groups are debating heavily whether or not to open up for oil and gas exploration and possible development, and this is also causing political disagreements, even within the country’s government.

Just a few weeks ago, the Norwegian government issued a report compiled from research done by several institutes. The report is now being used as a basis for the ongoing round of consultations regarding the integrated management plan for the Lofoten – Barents Sea area. The Ministry of the Environment states that this plan Vulnerable area with oil will be a milestone in the work and gas reserves of establishing ecosystem-based Historically, Lofoten and Vestermanagement in all Norwegian sea aalen have been two of Norway’s areas. most important areas for both When concluded by the end tourism and fisheries. The Minof 2010, the management plan istry of the Environment states will describe the future oil and that: “The ecosystems are of ›› Figure showing prospects identified by the NPD in unopened areas outside gas development for the Lofoten very high environmental value Lofoten islands. Prospects in production licenses are not shown. area and the Barents Sea. It will and are rich in living natural set the overall framework for both resources that are the basis for existing and new activities in these waters Norway’s underwater rain forest. The fisha considerable level of economic activand facilitate the co-existence of different eries resources in the area are amongst the ity. The area also contains internationally industries, particularly the fisheries, mariworld’s richest. The challenge is to ensure important stocks of seabirds and sea mamtime transport and petroleum industries. that existing fisheries activities together mals, some of which are extremely vulnerwith increasing maritime transport and able. At the seafloor a diversity of habitats new petroleum activities do not constitute such as coral reefs and sponge aggregatoo great a pressure on the environment.” tions constitute what could be called

The area, which is located in the north of Norway, is expected to hold between1.3 and 3 billion barrels of oil equivalent, Norwegian Petroleum Directorate (NPD) and The Norwegian Oil Industry Association.

The NPD reserve estimate covers 50 prospects in the Nordland VI, Nordland VII and Troms II areas, stretching from south of the Lofoten islands to the Barents Sea border. Nordland VI is considered to be the most promising area.

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Modelling environmental risks offshore North Norway

Quantification of Environmental Risk An important basis for the management plan is the environmental risk analyses which quantify the possible consequences of accidental oil spills for fish, shoreline habitats, seabirds and marine mammals. In order to predict the environmental impact of an acute oil release, the potential spill scenarios must be identified. From an offshore installation, these could include riser and pipeline leakages, process and storage tank leakages, a blowout, uncontrolled discharges during drilling operations, releases due to loading and unloading of oil, FPSO accidents, etc. The table below illustrates identified and representative spill scenarios which were used for oil drift models and further used for quantifying the possible environmental impact.

The next step is to provide probabilities for these spill scenarios in order to enable quantification of the risk and not only the consequence. Frequency numbers are based on historical data from databases like the SINTEF Offshore Blowout Database. The table below gives the probabilities for the different spill scenarios identified for a future producing oil field with an Floating Production Storage and Offloading facility (FPSO) operating in the Lofoten area.

Oil drift modelling Based on the identified spill scenarios and type of oil, statistical oil drift modelling can be done using any combination of release rates and durations. In order to capture wind and ocean current variations, typically hundreds of simulations are performed each month using historical wind conditions (hind cast archive with wind every 6th hour for 10-20 years) and the monthly average current direction and speed. DNV uses the SINTEF developed OSCAR 3D modelling tool. For subsea blowouts, a premodelling of subsea discharge is conducted using PLUME3D before further modelling of the oil drift on the sea surface.

Each oil drift simulation for a given spill scenario reports parameters as maximum and average volumes of oil and emulsion

Title Scenario id

Spill rate (tons/day)

Spill duration

Spill volume (tons)

Representative scenario

1

500

2 hours

42

Well and process leakage

2

35

14 days

490

Riser leakage

3

1000

2 days

2000

4

4500

2 days

9000

Blow out, pipeline leakage, storage tanks & offloading

5

8500

2 days

17000

Ship accidents, & collisions

6

4500 1000 200

2 days 13 days 35 days

29000

Blow out (Diminishing spill rate)

7

4500

14 days

63000

8

4500

50 days

225000

9

15000

4 days

60000

Loss of ship *

››

Table showing representative oil spill rates and durations for various accidental scenarios related to offshore petroleum activity.

Title Scenario ID

A Blowout

1

B Well leakage

D Riser + internal pipelines

6,68E-04

2

5,92E-05

3

5,92E-05

4

3,61E-04

E Process

F Storage tanks

1,70E-03

9,98E-05

1,36E-02 1,36E-05

G Offloading

I Collision

9,91E-02

9,44E-05 9,44E-05

7,79E-04

9,98E-05

7,50E-05

8,40E-04

7,98E-04

7,98E-04

5

7,76E-04

6

5,92E-05

7

5,32E-05

8

5,32E-05

4,25E-05

5,25E-05

1,00E-05

3,15E-05

››

Table showing probabilities for different accidental oil spill scenarios calculated for a future oil field (FPSO development) outside Lofoten. The highest spill probabilities are associated with an offloading operation with a probability of 9,9 % per year (9,9x10-2) or 1 expected accident per 10 years. The expected spill volume of such a scenario is about 500 tons. The high volume scenarios typically have a probability of 10-4 to 10-5 or one incident per 10 000 or 100 000 years.

on sea, total hydrocarbon concentrations (THC) in the water column, oil drift times and mass balance (evaporation, downmixing, stranding). In addition, statistical results will show the probability of certain areas being exposed to oil and statistical values for the same parameters. The figure below shows an example of modelled statistical oil concentrations in the water column for four of the spill scenarios from the spill location in Nordland V. Environmental consequence In order to quantify the environmental consequence of a particular spill scenario,

the result obtained from the oil drift modelling must be combined with the presence of valued ecosystem components (VEC) like seabirds, marine mammals, shoreline habitats and fish eggs/larvae (the most sensitive stage for fish).

The VEC distribution is linked to the oil drift simulations in order to calculate the degree of exposure (computation cells encountered by oil slicks and related oil mass). For each oil drift simulation, the acute population reduction (mortality) is calculated as a function of oil mass and vulnerability (see an example for seabirds in the table below). For fish eggs and

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Modelling environmental risks offshore North Norway

larvae, a threshold level of 375 ppb total hydrocarbon concentration was used.

The acute reduction is calculated for each 10x10 km grid cell and summarized for all cells to give a population or habitat reduction. Since a lot of spill simulations are modelled for each spill scenario, probability distributions for different outcomes are generated. An example of the calculated environmental impact is given in the figure below.

A summary of all the spill scenarios and their possible consequences for all four spill locations is presented below for the periods with the highest consequence (spring and summer). The example results are shown for Norwegian spring spawning herring and reveal a lot of variation in

possible consequences both between the spill locations and (of course) between spill scenarios. Nordland V is the area with the possible greatest consequences for fish. Results are shown for a subsea spill as a surface spill will have much less of an effect on the water column. The opposite is true for seabirds and marine mammals (seals), which will be most affected by oil from surface spills.

From consequence to risk As environmental risk is defined by the probability of different consequences, the conditional probability, as shown in the figure above, must be multiplied by the probability (or frequency) of the different spill scenarios occurring (ref. table

above) in order to give the risk picture.

This would clearly change the overall expression of the consequence, as the high consequence scenarios usually have a low probability. In the case of a future oilfield with an FPSO, the overall environmental risk picture is presented below (risk for loss of year class recruitment of Norwegian spring spawning herring).

Overall conclusions The environmental impact analysis and risk calculations presented in this article are based on a vast amount of data regarding the presence and distribution of sensitive species and habitats, available due to the comprehensive mapping carried out by various Norwegian directorates and

Title Oil mass (tons) in 10 x 10 km grid cell

Effect key – acute mortality rate Individual vulnerability for VEC Seabird S1

S2

S3

1-100

5%

10 %

20 %

100-500

10 %

20 %

40 %

500-1000

20 %

40 %

60 %

≥1000

40 %

60 %

80 %

››

Table showing the linkage between oil volumes in 10x10 km grid cells and the corresponding expected mortality rate for seabirds within that area. For the most sensitive birds (S3; typically pelagic diving birds), an oil volume of between 500 and 1000 tons in a 100 km2 area will lead to a 60% mortality rate for birds in that area.

››

Figure showing the resulting oil concentrations in the water column after a 14-day simulation of 4,500 tons/day.

››

Figure showing the average distribution of herring eggs/larvae in the months May, June and July (data from year 1980-2004; Source data: Institute of Marine Research, Norway).

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››

Figure showing the results of statistical oil spill simulations for 4 different subsea spill scenarios in Nordland V (scenarios 4, 5, 7 and 8) as maximum oil concentrations (THC) in the water column.

Modelling environmental risks offshore North Norway

institutes over several decades. Combined with extensive modelling of different accidental oil spill scenarios and spill locations, the combined environmental risk analysis is able to highlight to stakeholders what the possible consequences of future petroleum activity in the Lofoten – Barents Sea area might be. Hence, the risk analysis will form a sound basis for further discussions on acceptable levels of possible consequences - and not only consequences, but also the probability of these consequences arising. In addition, the results show variance between different spill locations and this might provide further input for recommended areas of activity and possible restrictions. 

››

Figure showing probability of different losses of year class recruitment for Norwegian spring spawning herring calculated for spill scenario no. 7 (4500 tons/d for 14 days) in spill location Nordland VI. The figure indicates that in late June (day 170-180), there is about a 75% probability that the oil spill will have no impact on the herring recruitment, while at the other end there is about a 5% probability that the reduction in recruitment will be up to 2-5%.

››

Figure showing the environmental risk involved in a future oilfield (FPSO development). The risk is shown as frequency per year and the highest risk contribution comes from spill scenario no. 4 in Troms II with a probability of about 0.02% per year (2.0x10-4), or one spill every 5,000 years. Given such a spill, the most probable consequence would be a 0-1% reduction in the year class recruitment of herring. The high consequence scenario (no. 8) in Nordland V has a probability of about one magnitude less (0.002% per year) or one spill every 50,000 years.

››

Figure showing the overall summary of conditional probability (i.e. given that the spill has occurred) for different losses of the year class recruitment of herring from different spill scenarios (given by their ID) and spill locations. The results indicate that the worst consequences will occur from the spill location in Nordland V, with the worst case spill scenario being no. 8 (a 50-day blowout with 4,500 tons of oil per day). In this case there is even a small probability (8.3%) of a more than 50% reduction in the year class recruitment of herring.

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Joint Industry Project

Joint Industry Project on the structural integrity of drilling and well systems Nine oil companies and DNV kicked off a JIP on the structural integrity of drilling and well systems on Tuesday 22 June 2010 in Stavanger Norway. The JIP’s objective is to develop, together with industry partners, structural integrity management guidelines for well and drilling systems, including fatigue design and calculation methodology. Up to now, nine major oil operators have confirmed their participation, giving a total JIP budget of MNOK 10; these are Statoil, Total, Shell, Exxon, Talisman, Marathon, Lundin, Det Norske Veritas and ENI. Drilling contractors and equipment suppliers will be invited to contribute to the work and comment on proposals.

Text: lars tore haug

››

Photo shows the new 6th generation deepwater rig Deepsea Atlantic alongside the traditional-sized 3rd generation rig Deepsea Bergen.

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Joint Industry Project

Challenges facing the drilling industry There are some 800 subsurface wells in the North Sea. Although many of these are old (>20 years), there is commercial interest in re-entering them for completion and sidetracking. At the same time, the regulatory bodies are seeking ever more assurance that the well condition and integrity are being properly managed. This includes well fatigue in subsea wells, which has been identified as a challenge in the last few years.

Further, we are seeing that more complex well designs and operations, including multilateral and smart wells, increase the drilling time. The volume of intervention and work-over operations on subsea wells has also increased. The effects of the increased size and weight of BOPs (400t) and the fact that more drilling is done through horizontal XTs with a BOP on top are also significant.

Below are some of the challenges facing the offshore drilling industry which will be addressed in the JIP. n The drilling and subsea industry has recently faced challenges related to fatigue calculations for wellhead systems and XT connectors. Currently, the results vary significantly depending on the method used. n A number of design standards are available, but there are no uniform and systematic design philosophies, standards or norms for the structural integrity, condition monitoring and operation of drilling and well systems. n Components are mainly designed for pressure containment and static tension loads but not for the operational loading scenario or to meet a uniform set of reliability requirements. n The offshore industry must meet the strict requirements of regulatory bodies and society at large to prove there is a satisfactory margin that will prevent major accidents.

System engineering approach The objective of this JIP is to examine drilling and well system integrity as a

whole and to develop uniform design philosophy recommendations that address structural integrity, ranging from seabed sediments to cement, wellheads, BOPs, riser systems and rigs. The initial steps will be to document the current industry gaps and address the operational needs. Further steps will be to develop recommendations regarding the safety level and design calculation methodology, including fatigue and accident issues, and to recommend a corresponding integrity management system.

The JIP will cover the following planned activities: n State of the art review system benchmarking and gap identifications as well as specification of the industries’ needs and scope n Establish a uniform structural design philosophy across system interfaces n Further develop a method for calculating drilling loads and fatigue design n Define guidelines for an integrity management system

Propose guidelines for information handling and knowledge management systems n Take initial steps to define acceptance criteria and methods for determining the capacity of well system foundations n

Organisation of the JIP The oil operators have strongly recommended that this JIP should be directed by a steering committee that only includes oil operators. However drilling contractors and subsea suppliers will be invited to participate in work groups and to comment on developed guidelines.

This is a highly cross-disciplinary project run by the Well, Subsea and Pipeline Departments, DNV. Anders Husby, a group leader in the Subsea Section, is the project manager. He has previous experience of designing subsea systems at Vetco Gray and was in charge of developing the present Method Statement for calculating wellhead system fatigue for Statoil in 2009. 

››

Figure: Overview of drilling and well systems’ current standards. Date: 5 July 2010

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