Oil & Gas Update 2-2013 by DNV GL (old account)

Eu: preventing major offshore accidents in Europe

Collaboration speeds up innovation

oil & gas update oFFshore saFety

technology leadership

Helping offshore assets age gracefully

NEWs FROM dNV tO tHE Oil & gas iNdustRY

Mobile oFFshore units

custoMer insights

rules & regulations

tHE NEEd FOR VigilaNCE â&#x20AC;&#x201C; and the continual improvement of offshore safety

No 02 2013

liFe extension

contents

oil & gas update Front cover The Piper Alpha memorial sculpture in the Rose Garden of Hazlehead Park in Aberdeen. ©DNV/Nina E. Rangøy

News

Offshore Safety

Technology Leadership

FT Global Shale Energy Summit .................................................................... 4 Emergency preparedness analysis for Statoil’s Johan Castberg field............ 4 DNV to class a semisubmersible unit for US-based Diamond Offshore....... 4 Standard for offshore service modules re-launched...................................... 5 Serving major projects in the UAE.................................................................. 5 Independent risk review work for PetroSA in South Africa.......................... 5 The need for vigilance..................................................................................... 6 EU: Preventing major offshore accidents in Europe..................................... 8 Elected Safety Representatives’ development training is key to improving safety culture................................................................................. 12 Application of safety case for offshore operations in Brazil........................ 16 Collaboration speeds up innovation............................................................. 18 DNV students propose new subsea solution for the Gulf of Mexico.......... 21 Innovation powerhouse in Asia Paciﬁc......................................................... 22 New industry guidance on CO2 risk management....................................... 23 New dynamic Veriﬁcation Scheme Dashboard developed.......................... 24

Mobile offshore units

Increased FPSO activity on the horizon........................................................ 26

Customer insights

Maersk Oil UK: Building on investment – persistence pays off.................. 28 Asgaard conﬁdently enters the Brazilian offshore support market............ 32

Rules & Regulations

New simpliﬁed rules for local content certiﬁcation in Brazil...................... 33

Life extension

Helping offshore assets age gracefully.......................................................... 34

Published by DNV Maritime and Oil & Gas Communications Editorial committee: Cathrine Torp, Svein Inge Leirgulen, Kristian N. Lindøe and Bert Droy Joyce Dalgarno, Editor

Design and layout: Coor Media 1307-001

Please direct any enquiries to DNVUpdates@dnv.com Online publications: www.dnv.com/industry/ oil_gas/publications

DNV (Det Norske Veritas AS) NO-1322 Høvik, Norway Tel: +47 67 57 99 00 © Det Norske Veritas AS www.dnv.com

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editorial

Reflect and improve

Remi Eriksen CEO, DNV Maritime and Oil & Gas Remi.Eriksen@dnv.com

Tremendous developments have taken place in the oil and gas industry since the first submerged oil wells were drilled from platforms built on piles in the fresh waters of the Grand Lake St. Marys in Ohio, US, in 1891. Ever since, there has been a strong drive to find, develop and produce large amounts of hydrocarbons in a safe, effective and responsible manner to meet the needs of society. New technical solutions have been developed and operating practices have been tested and refined to unlock a wide variety of oil and gas resources within increasingly advanced regulatory frameworks. Despite these achievements, accidents and near-accidents continue to happen. Marking the 25th anniversary of the Piper Alpha tragedy, we take time to reflect on some of the innovations in offshore safety and environmental protection in this issue of the Oil & Gas Update. Since the disaster, the industry has learned valuable lessons about how to enhance safety performance and gained extensive operational experience, but still more needs to be done in the pursuit of continual improvement. What’s encouraging is that we see a continued drive to improve safety across the industry by legislatures and regulators. In June this year, the EU Council of Ministers adopted a new EU Offshore Safety Directive. The new directive requires operators to demonstrate their ability to cover potential liabilities and to submit major hazard reports, supported by independent verification, before operations start. This should result in standards being raised across the EU to the high levels already present in the North Sea. We were privileged to gain insight into the new directive from Mr Eero Ailio, Deputy Head of the Directorate-General for Energy, European Commission. Read the interview with him in full on pages 8-11. Increasing workforce involvement in the management of Major Accident Hazards is recognised as one way of reducing releases and improving safety culture. DNV

has recently become the only OPITO (Offshore Petroleum Industry Training Organisation) accredited provider of a new major hazards training programme for Elected Safety Representatives which is already driving positive change within the industry. As the offshore industry moves rapidly into its next exciting chapter - deeper waters, deeper and more complex reservoirs and more challenging operating environments - new technologies and operating practices enable those challenges to be solved. At DNV, we always focus on improving our own knowledge and expertise in order to develop new recommended practices, guidelines and standards for the industry. We have a long tradition of developing these in close cooperation with industry partners; often through Joint Industry Projects (JIPs). On page 20, we highlight more than 30 JIPs that we have initiated and are ongoing. Every year, we are delighted with the outcome of our Summer Student project and this year is no exception. DNV’s 2013 summer students presented SPSO Cobia, an all-electric subsea processing and storage facility which seeks to extend oil production in ultra-deepwater fields in a safe and sustainable manner – a concept true to the DNV spirit of meeting the demands of tomorrow with creative technical solutions. The interview with Mr Martin Rune Pedersen of Maersk Oil UK shows that he too is looking to the future as this company grows its business through a diverse portfolio based on sustainability. Mr Pedersen shares his insights into the industry’s potential and some current challenges. The global oil and gas industry will continue to provide many opportunities and challenges for us all. Whilst we seize the opportunities and solve the challenges, let us reflect on key learnings from the past and use our experience to allow us to continually improve as we move forward.

Oil & gas update no. 2 2013 |

news

Ft global shale energy suMMit

The FT Global Shale Energy Summit, to be held in London on 21 October, will bring together the energy companies behind the shale revolution, their supporters and detractors and government, academic and civil society experts to examine the broader implications of the shale revolution for the future of the global energy industry. The US shale transformation could now go global as energy companies apply the same techniques that unlocked America’s vast shale potential to other basins around

the world. The implications for energy and LNG trade, for the balance of power in global energy markets, and for the world’s efforts to curb emissions and affect a transition to a low-carbon future are profound. CEO of DNV Maritime and Oil & Gas, Remi Eriksen, will address more than 200 delegates when he gives the introductory presentation to the panel debate “Will the Shale Revolution Go Global?” The key challenge is not technical, but one of reputation. This industry lacks public acceptance, which can only be gained by implementing operational best practices and documenting that the activities can be executed in a safe and responsible manner. By working towards a global standard for shale gas risk management, DNV brings the systematics to handle a complex picture, quality assurance based on risk management principles and an objective third-party view. www.ft.live.com/shalesummit www.dnv.com/shalegas

dnv to class a seMisubMersible unit For us-based diaMond oFFshore Diamond Offshore Drilling, Inc. has announced an agreement with Hyundai Heavy Industries Co., Ltd. to build a new Moss CS60E design harsh-environment semisubmersible drilling rig. The 10,000’ dynamically positioned rig is expected to be delivered after November 2015. The projected capital cost of the unit including spares, commissioning and shipyard supervision is approximately USD 755 million. The rig will be classed by DNV. The design will be similar to that of the Fred Olsen Energy semisub currently under construction in HHI. The Moss CS60E type unit will be built at HHI in Korea. The contract between HHI and DNV is currently being finalised, but the

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notations are expected to be: 1A1 Column Stabilised Drilling Unit DRILL, ISDS, DYNPOS-AUTRO, DYNPOS-ER, EO, HELDKSH, CRANE, BIS and POSMOOR-ATA. DNV’s credibility, based on its experience and ability to meet project delivery deadlines, was a key factor in the decision to class with DNV. A three-year drilling contract has been entered into with a subsidiary of BP plc (NYSE: BP) to utilise the rig for initial operations off the coast of South Australia. The operating day rate under the drilling contract starts at USD 585,000 per day and is subject to upward adjustment for certain increased operating costs and equipment modifications.

eMergency preparedness analysis For statoil’s johan castberg Field In preparation for the potential development and landing of oil from the new Johan Castberg field in Norway, DNV is to prepare an environmental risk and emergency preparedness analysis for Statoil. The work will be carried out by DNV’s new Oil Spill Preparedness Department in Harstad together with the Environmental Department in Oslo. It will be completed by October 2013. “We are very pleased to win this contract and consider the work as important in relation to the ongoing development in the Barents Sea. The study will among other things include a detailed and highresolution flow model to simulate oil operations. We have worked on similar projects on the Norwegian continental shelf over the past 25 years, and this work will involve many interesting elements related to activities in coastal areas with important environmental resources,” says Stein Thorbjørnsen, director for DNV’s department in Harstad.

›› stein thorbjørnsen, director for dNV’s department in Harstad.

news

DNV has completely re-written the standard for Offshore Service Modules certification, commonly referred to as DNV 2.7-2, which was first published in 1995. The revised version is now available for download. DNV in Aberdeen has reviewed the standard and collected the views of the global network of DNV personnel as well as of operators, manufacturers and contractors. DNV 2.7-2 is a single document which brings together the key safety requirements of multiple existing standards to enable users to effectively apply it to transportable and temporary equipment. Though widely recognised as a safety standard for pressurised modules for temporary workspaces, it has now been extended to cover all types of temporary equipment, from diesel engines and compressors to well test production equipment. The overall aim of the revision is to provide a standard to which modules may be certified, making them compliant with global offshore installation regulations.

Serving major projects in the UAE A number of greenfield offshore projects are currently under development, driven by the operators belonging to the national oil company in the UAE: ADMA-OPCO and ZADCO. DNV has been selected to be engaged in some of these projects. ADMA-OPCO’s main offshore developments include the Umm Lulu Al Nasr early production development, Umm Lulu full field development, Al Nasr full field development and SARB development, whilst ZADCO has the Upper Zakum 750k development project. All except for the Al Nasr full field development project have entered the detailed engineering and construction phase and DNV has been retained on each of these projects as either an independent verification and design certification body or an HSE independent advisor and technical safety consultant. “These projects have varying complexities and include building artificial islands, significant tonnage in topsides and process facilities, a number of pipelines, extended reach drilling, etc. DNV being chosen by ADMA-OPCO and ZADCO to be engaged on these projects shows that our customers

trust DNV when it comes to their most important and challenging projects,” says Prajeev Rasiah, Area Manager of DNV’s Oil & Gas Services in the Middle East.

›› Prajeev Rasiah, Area Manager of DNV’s Oil & Gas Services in the Middle East.

Standard for offshore service modules re-launched

For more about DNV’s rules and s tandards, go to: www.dnv.com/resources/rules_standards/

›› Download the Standard for Certification No 2.7-2.

Independent risk review work for PetroSA in South Africa PetroSA in South Africa chose DNV to carry out an independent risk review of Project Ikhwezi. Won in stiff competition with local and international companies, the deciding factor was DNV’s expertise and track record. The scope was to review and provide input to the risk assessment work that had been performed in-house as well as to examine PetroSA’s own enterprise risk and project risk management methodologies. Particular attention was paid to those risks that could grow during the remaining months of the project, in which the final

platform modifications, commissioning of the subsea pipeline and drilling and tieback of the first producer were occurring simultaneously. DNV drew on competence from South Africa, the UK, the USA and Norway to deliver the project. Project Ikhwezi is set to play an instrumental role in sustaining the life of PetroSA’s gas-to-liquids refinery in Mossel Bay. It involves tapping into gas reserves in Petro SA’s F-O field, a subsea development located 40km south-east of PetroSA’s F-A production platform off the south coast of South Africa.

oil & gas update NO. 2 2013 |

Offshore Safety

The need for vigilance The Piper Alpha tragedy in 1988 cost the lives of 167 men and is the world’s worst ever offshore disaster. A quarter of a century on, the global industry continues to remember and learn from this devastating event. DNV reflects on how far this catastrophe was the catalyst for change and what more needs to be done to be better prepared. Text: Peter Boyle, DNV

Despite the 25 years that have elapsed since the Piper Alpha disaster, serious offshore accidents continue to occur globally; the Montara blowout offshore Australia (2009), the loss of the Kolskaya rig on the east coast of Russia (2011) and the fire and explosion on the Endeavour rig offshore Nigeria (2012) are key examples. Increasing public awareness and scrutiny and a continued drive for change from regulators to operators have shown there is no room for complacency and that lessons must be learnt and acted upon to alleviate any further potential risks and incidents. RADICAL TRANSFORMATION FROM SIMPLE CHANGES From standardised alarms being raised through to recovery to a clearly identified place of safety, for example, the most simple and common sense approaches have made the biggest difference. New escape-to-sea regulations and major improvements in the wholesale provision of emergency response and recovery vessels have radically changed emergency response from being reactive to being proactive in minimising risk. Taken in isolation, hardware enhancements are not enough to overhaul the current system, and amendments to associated processes and a step-change in workforce attitudes and behaviours have been addressed as a direct result of the disaster. The obvious system change was the adoption of the safety case approach, built largely around a goal setting, rather than prescriptive, approach. The segregation of regulator roles to the Department of

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Energy and Climate Change (DECC) and the Health and Safety Executive (HSE), as the dedicated safety regulator, is also an important part of the overall process that now governs the UK industry. Most significantly, enhanced, more encompassing, tested and refined emergency response plans have been developed. These illustrate the improved link between major accident hazard events requiring emergency response and the actual response plans for both offshore and onshore operations. They represent key areas of wholesale improvement across the industry. It is these and a host of other process improvements which shape and influence the design, testing and maintenance of emergency response technologies and provide the performance required. IMPROVING KNOWLEDGE AND AWARENESS ACROSS THE WORKFORCE A striking consequence of Piper Alpha was how high the casualty rate was for people not fully familiar with the platform. Basic offshore survival training, its certification and exemption levels have all been improved to ensure the entire workforce, at all levels, knows the essentials; and the coupling of Minimum Industry Safety Training (MIST) further enhanced this. Drill repetition, the diversity of scenarios and exercise instruction, combined with improved Offshore Installation Manager (OIM) and emergency team training, were rightly seen as paramount to the success of emergency response procedures. This has created a culture that allows people to adapt better to any given situation, which

in short can be the fine line between a high potential event and a disaster. Although the industry has made huge leaps forward since Piper Alpha, recent events have highlighted that the mission to mitigate all risks is by no means complete. THE ONGOING STRUGGLE TO IMPROVE SAFETY It is regrettable that incidents of varying degrees and consequences continue to blight the industry when so much is being done to improve equipment, processes, procedures and the awareness and education of the workforce. Caution is also required when looking for transferable lessons from previous incidents, as the introduction of FPSOs, deepwater drillships and well intervention vessels combined with E&P activity in deeper and harsher environments demands the more specific and stringent application of existing regulations and procedures. Possible challenges relating to response times, increased evacuation risks, and an improved means of ensuring a good prospect of survival are pushing the industry into new realms of emergency response. In the US, operators were accused of adopting a “cookie cutter” approach to emergency (and environmental) response plans in light of Macondo. Industryinduced assessments were heavily criticised as being idealised and lacking robustness to how deviations from anticipated events could be handled. Whilst the UKCS is unlikely to be exposed to the same accusation, there is merit in investigating if

Offshore Safety

Piper Alpha was a North Sea oil production platform operated by Occidental Petroleum (Caledonia) Ltd. The platform began production in 1976, first as an oil platform and then later converted to gas production. An explosion and the resulting oil and gas fires destroyed it on 6 July 1988, killing 167 men, with only 61 survivors. The death toll includes two crewmen of a rescue vessel. Total insured loss was about £1.7 billion (US$3.4 billion). At the time of the disaster, the platform accounted for approximately ten percent of North Sea oil and gas production, and was the worst offshore oil disaster in terms of lives lost and industry impact.

››

Piper Alpha Memorial statue in Aberdeen.

the spectrum of activity – from raising the alarm to the recovery of people to a place of safety – is completely covered. The HSE recognised this and in the early 1990s developed its EER HAZOP – Escape, evacuation and rescue hazard and operability study – to test plans in a desktop manner in order to anticipate foreseeable deviations. LESSONS LEARNT ARE PROBLEMS SOLVED Hydrocarbon leaks still occur, but maintaining a diverse testing and drill portfolio creates an adaptive and responsive culture, allowing a smooth response to anticipated conventional accidents and a better reaction to unanticipated outcomes.

The UK industry’s response to the recommendations and lessons stemming from Lord Cullen’s report has been significant. However, the ageing offshore infrastructure, rise and arrival of newer technologies, human resourcing challenges and even the changing physical size of the workforce means that the industry must rise to this challenge and overcome new pressures. The footage and images taken from helicopters and vessels involved in the rescue operation at Piper Alpha will forever be etched on the minds of those who watched and prayed. They continue to haunt those working in the industry at the time and serve as a sober reminder of the importance of safety offshore to the next

generation. No emergency response is ever textbook, it is by nature variable and novel; we humans make it so and all events afford an opportunity to learn. There can never be a full stop to safety improvements, they involve lifelong learning and vigilance to ensure that history is not repeated. 

Contact

Peter Boyle peter.boyle@dnv.com

oil & gas update NO. 2 2013 |

Offshore Safety

Since the tragic Deepwater Horizon accident, offshore safety has been high on the agenda of the European Union. After intensive negotiations lasting more than a year, the EU has published new legislation on the safety of offshore oil and gas operations. “Our aim is to reduce the risk of major accidents and their environmental consequences throughout the entire lifecycle of offshore exploration and production,” says Eero Ailio, Deputy Head of Unit Retail Markets, Coal and Oil at the European Commission. He has been instrumental in the process towards the new directive. Text: Svein Inge Leirgulen, DNV

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Preventing major offshore accidents in Europe

Offshore Safety

The Deepwater Horizon explosion in 2010 was a wakeup call for the industry, the regulators and society at large on the mismatch between the reality and ambitions of the offshore industry (perhaps also of some regulators) on the one hand and the state of preparedness, risk awareness and management on the other. Statistics from the UK and Norway showed a plateauing of risk reductions relating to major hazards, and both the UK Health & Safety Executive and the Norwegian Petroleum Safety Authority reported that industry was not meeting its safety targets. Meanwhile smaller companies were and are taking over mature assets and new exploration in the traditional regions. The majors are heading increasingly for frontier areas, be it in the northern Atlantic or the Mediterranean, where there is little cumulative operational experience, including for emergency response to a major accident. At the same time, societal tolerance for environmental damage reached an all-time low. The need for a coherent EU-wide legal framework based on global best practices was the result of an impact assessment complemented by public consultation and hearings with a large number of stakeholders. In the EU, offshore activities are framed by highly divergent national solutions of varying levels of stringency based on an EU drilling safety directive from 1991 applying to all minerals and applying on- and offshore. In addition, the directive (92/91/EEC) does not reflect current best regulatory practices for major accident prevention, nor does it address environmental consequences of a major accident. The Seveso Directive, which does integrate safety and environmental consequences, is directed at onshore sites holding threshold quantities of dangerous substances. This patchwork approach is no longer considered adequate to manage risks of cross-border pollution in a globally mobile industry.

ÂŠ DNV/Marianne Wennesland

Why did the EU find the need for a new directive on offshore safety?

Member States need to transpose into national law by 19 July 2015, while industry needs to adapt to the new standards by July 2016 for planned operations and July 2018 for existing operations. What was the process towards the final directive? Following the consultations and impact assessments led by the Commission, a proposal for a Regulation was adopted in October 2011. As a regulation, it would apply consistently and equally to all Member States and directly upon the industry. This proposal then fell subject to the ordinary EU legislative procedure whereby the Council of the Member States and the European Parliament act as co-legislators. The Council debated the proposal and the Cypriot Presidency drafted a directive form of the legislation. The work was completed under the Irish Presidency. The Parliament worked through its Committees, with the lead given to the Industry Transport and Energy Committee. The Parliament and Council came together to negotiate the final stages in December

2012. Following formal adoption in both Parliament and Council, it was signed in Strasbourg on 12 June 2013. Directive 2013/30/EU entered into force on 18 July 2013. Why was this made as a directive and not as a regulation? What does this mean in practice for the individual Member State? The key Member States and the European Parliament committees preferred to turn the proposal from a directly applicable Regulation into a Directive. In practice, this transfers the burden to the Member State to table national legislation or other adequate legal measures to implement the EU law. In particular, the directive only applies to Member States â&#x20AC;&#x201C; it has no bearing on industry until transposed into national law by the Member State. It also changes the administrative burden

oil & gas update NO. 2 2013 |

Offshore Safety

between individual Member States. This means that land-locked Member States such as Austria will have to transpose into national legislation, measures in the directive that apply to overseas operators that are or may in the future be domiciled in their jurisdictions. This also applies to non-active coastal Member States such as Sweden, as well as requiring such Member States to transpose duties to cooperate with offshore-active neighbours in emergency response planning.

What is the implementation timeframe? Member States need to transpose into national law by 19 July 2015, while industry needs to adapt to the new standards by July 2016 for planned operations and July 2018 for existing operations. To what extent has the new directive been built on existing regulations from other major O&G countries? The approach has been to level up standards to industry and regulators’ global best practices for the prevention of major offshore accidents. There is no intention to experiment with new, untested approaches. The directive advocates the goal setting regulatory philosophy adopted first by the North Sea countries. As regards the contents, they build on existing best practices at times improved by the latest recommendations supported by a general stakeholder consensus. Often these derive from the North Sea practices; however, there are elements from other countries such as Italy. How has the directive been received in the EU? Apart from changing the legal form to a directive, the substance of the original proposal was largely unchanged by the negotiations between the co-legislators, and the changes have been mostly to clarify or strengthen the original drafting. The need for the EU to act and the substance of the law has been well received by the Member

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››

Since 2000, Mr Ailio works at the European Commission in Belgium and is currently Deputy Head of Unit Retail Markets Coal and Oil at the Directorate-General Energy. The unit leads offshore oil and gas safety policy in the EC, smart grid and metering initiatives, horizontal coal and oil issues and various retail market issues. Mr Ailio represents the Commission in various international cooperation activities including the G-20 Global Marine Environment Protection (GMEP) initiative.

States and most stakeholders, including from the global trade associations. The main industry associations focussed their energy on legal issues during negotiations in 2012, notably for a directive. In contrast, individual O&G companies and the IADC have supported us e.g. in promoting the goal setting approach (via the safety case) and promoting greater transparency of industry performance. During the process, the trade unions became more positively engaged on issues such as workforce consultation, while the NGOs were perhaps the most ambitious in terms of their expectations from the proposal. For experienced O&G countries such as the UK and Denmark; how will this impact their existing regulation? The foundations will remain (risk based, goal setting philosophy) but there are changes in the small print. For instance, the ‘safety case’ in the UK and Denmark (the formal demonstration that all major accident risks for a particular installation

are adequately controlled) will need to address containing a blow out on an evacuated installation, such as on Elgin last year. Also, both countries need to establish a single competent authority for safety and the environment protected from conflicts of interests that could arise if its staff were to engage both in safety and in licensing or economic promotion of offshore oil and gas activities. In the Netherlands, the regulator will have to formally ‘accept’ the safety case (in the directive referred to as a report on major hazards (RoMH). A further change (to all Member States) is the adoption of a common accident reporting format to allow comparing data between the Member States. This has been an unrequited ambition of both the North Sea Offshore Authorities Forum and International Regulators Forum, which are prominent but informal groups of offshore safety regulators. Norwegian authorities have stated the directive does not affect them. What is the Commission’s view on this?

Offshore Safety

The EU has adopted this directive as being EEA relevant. This issue will be discussed and hopefully a solution found in the EEA governing bodies in due course. The approach in the directive has a lot in common at least with its Norwegian counterpart. This is perhaps not surprising since Norway has participated in the process from its early days.

formats (in effect adding details to the provisions in the directive); the state of ‘best practice’ by Member States following transposition of the directive into national law; and the means for making sufficient technical capacity available to Member States for carrying out their functions under the directive. It is too early to say what will be the deliverables – if any - on these topics.

The directive requires the application of independent verification. How will the Commission ensure that verifiers are both sufficiently competent and independent of design and operations?

Could you expand upon the definition of a non-production facility as outlined in the directive? Which types of units are covered by this definition?

The directive does indeed foresee independent verification as a necessary assurance system for the operator. The responsibility for ensuring the independence lies with the operator, whose actions are overseen by national regulators. As a goalsetting instrument, the directive lays out the necessary tests of independence and the fundamental features of the schemes for verification of safety and environmentally critical elements and for well design. There will be no statutory lists of verifiers that, provided they meet the independence criteria, could be 2nd or 3rd party entities. The question of what is the most suitable verification scheme needs to be tackled installation by installation.

This will be addressed by Member States during transposition. However, it could probably be said that they are installations that do not produce (‘win and save’) hydrocarbons. Member States could, in their national law, take the approach of the most robust regulators such as Norway and the UK. One could envisage such facilities being interpreted as those stationed for the purposes of conducting well operations, providing accommodation, and so on. Member States could also want to give early clarity to such things as ‘connected infrastructure’ (defined in the directive) when looking at multi-installation complexes, where accommodation and production functions are on separate installations.

The Commission has been increasingly involved in offshore safety. After the launch of the directive, what other initiatives will the Commission carry out to assist or enhance safety in industry?

How will operators demonstrate they have sufficient financial capacity to cover any potential remediation?

The directive foresees a number of areas for further work and for reporting back to Member States and Parliament at various times during the next two years. These include the effectiveness of existing civil liability mechanisms and whether they can be broadened or enhanced; the availability of financial security instruments and compensation schemes; whether to make certain breaches of duty relating to environmental damage a criminal offence; the development of common reporting

There is no standard reply to these questions since the individual cases vary widely. The Deepwater Horizon disaster demonstrated that few companies could cover the ultimate losses of an extreme major accident, and that the market does not provide such levels of cover. In addition, the directive is consistently a goal-setting instrument and the financial capacity aspects need to be assessed in the light of the risks of the project under consideration. What the directive does is to ensure that the matter is dealt with robustly at the licensing stages, that the full cost of

emergency response and environmental remediation is considered, and that sufficient capacity is available throughout the lifecycle of the operations. Member States are also asked to facilitate the deployment of sustainable financial instruments in their jurisdictions and to promptly handle compensation claims for economic losses. As said above, the Commission is being asked to report back to the EU with some further thinking on the financial liability and security aspects. The directive places expectations on operators to apply the MAPP requirements to their operations outside Europe. How will this be monitored? The Major Accident Prevention Policy is indeed a pre-condition for operations in an EU Member State. The provision of a MAPP allows Member States to scrutinise the operator’s commitment to apply a single standard to all its operations worldwide. In the EU, this will be monitored by the competent authority in each Member State, the ones who meet each other in the recently established EU Offshore Authorities Group. Outside the EU, these regulations will, as a minimum, be based on self-regulation and the watchful eye of the civil society. However, it is to be expected that operators and rig owners will take this transparent statement of their global policy extremely seriously. Where it might be claimed that some aspects of the policy cannot be applied in some non-EU jurisdictions, the directive requires this to be made clear in the policy statement. 

Contact

Graham Bennett Graham.Bennett@dnv.com

oil & gas update NO. 2 2013 |

Offshore Safety

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Offshore Safety

Elected Safety Representatives’ development training is key to improving safety culture Oil and gas safety performance has improved since the Piper Alpha disaster 25 years ago. However, still gas releases occur each year. One way to reduce releases and improve the safety culture is by increasing workforce involvement in the management of Major Accident Hazards (MAHs). DNV has recently become the only accredited provider of a new training programme for Elected Safety Representatives (ESRs), which is already having impactful change within the industry.

TEXT: FIONA FITZGERALD, DNV

››

Alistair Stewart, Elected Safety Representative on Shell’s Shearwater rig, arrives home via CHC Helicopter after putting what he learned from DNV’s ESR Development Training into practice.

oil & gas update NO. 2 2013 |

Offshore Safety

POWERS OF ESRs UK legislation gives offshore ESRs the right to: participate in the preparation and review of safety cases; participate in the investigation of hazards, dangerous occurrences and accidents; conduct independent inspections on the installation; and make representations to the installation management regarding health and safety matters. The Cullen Enquiry report following the Piper Alpha disaster recognised that: “It is essential that the whole workforce is committed to and involved in safe operations… Possibly the most visible instrument for the involvement of the workforce in safety is a safety committee system”.

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Subsequent to the report, it has been recognised that most ESRs are not sufficiently equipped to perform the full range of their functions and, therefore, wholly achieve the vision that Lord Cullen created for workforce involvement. Indeed, in his 2011 review of the UK regulatory regime following the Macondo Blowout, Professor Geoffrey Maitland of Imperial College, London commented: “ESRs will be more effective if they have a good understanding of the major process hazards in an organisation’s activities and how the risks are managed. Training in this respect would impart the ability, knowledge and understanding necessary to make them more competent in this area. Included in this must be the ability

to communicate effectively with workforce and managers alike.” This is precisely what the ESR Development Training addresses. A taskforce comprising ESRs, trade unions and industry bodies worked together to produce a standard for ESR Development Training which was then adopted by OPITO – the global oil and gas industry training organisation. Earlier this year, DNV held a series of successful pilot courses and is now the only accredited provider of Elected Safety Representative Development Training. It will make the courses available to more than 2,000 ESRs working across the industry.

Offshore Safety

The training comprises four 2-day modules which may be completed as any combination of the following: 1. Understanding and identifying MAHs; 2. Understanding risk analysis to get involved in preparing/revising safety cases; 3. Investigating incidents and applying root cause analysis; 4. Conducting independent inspections and audits and presenting findings effectively.

ESRs – often from different backgrounds, installations and companies and with varying experiences. Delegates are actively encouraged to work collaboratively and this diversity has led to the excellent sharing of practical solutions to common challenges. THE FUTURE During Oil & Gas UKs recent Piper 25 Conference in Aberdeen, a series of workshops introduced this training to

“Since the training, I’ve looked at the safety case in a new light. It has given me renewed confidence to go on and challenge myself and others. The training was most useful and I would recommend others to take part in it.” Alistair Stewart, Stork Technical Services

The focus of the training is firmly on the understanding, interpretation and review of safety cases. The training aims to demystify the safety case, debunk some of the terminology and shift the emphasis towards high-consequence, low-probability events. AHA MOMENTS The training is interactive, with most of the time spent on activity-based learning. This helps delegates to retain more of the new knowledge and confidently apply it to effect change on installations. Activitybased learning recognises the varying strengths and combinations of individuals’ preferred learning styles. Consequently, the training incorporates music, problem solving, imagery, photos, spoken and written language and interactive activities that combine to create “aha” moments of personal discovery. Crucially, the training is delivered by subject-matter experts who are leading practitioners in their field and have hundreds of years of accumulated experience. This, combined with small class sizes and low trainer/delegate ratios, means that classes address specific issues that arise. Classes are a maximum of 12

the industry. The programme has been established for 2013/14, giving ESRs the opportunity to learn more about safety cases and strengthen their network. Initial delegates have already reported stories of opening their installation safety case for the first time and reading it meaningfully. One delegate has committed to auditing one Major Accident Hazard and associated Safety Critical Elements on each trip. Other ESRs on his installation are now attending the training to support his efforts. Several Duty Holders have put all four modules in their training matrix as mandatory for all ESRs. This feedback shows that the training is effective in equipping ESRs to provide impactful change. Perhaps the last word should go to a safety representative, Alistair Stewart, Stork Technical Services, who said: “Since the training, I’ve looked at the safety case in a new light. It has given me the confidence to go on and challenge myself and others. The training was most useful and I would recommend others to take part in it.” Courses can be booked via ESRtraining@dnv.com 

OPITO is unique as it is an industry owned organisation built on a self-sustaining, solid business plan. The company is a not for profit organisation and reinvests any additional funds to further meet skills shortages and potential further demands. OPITO’s focus is to deliver initiatives and activities which ensure a competent and safe workforce supply for industry both now and in the future. Its primary aim is to ensure people go to work and come home safely. With over 30 years of experience, OPITO supports the oil and gas industry around the world with offices in Aberdeen, Dubai, Kuala Lumpur and Houston. The core focus of the OPITO business remains the management, development and assurance of the industry training and safety standards. It continues to work with industry to establish the content, purpose and learning outcomes of required training standards, as well as analyse, review and audit existing standards to ensure they remain fitfor-purpose and relevant. The OPITO Skills Strategy extends across four key strands of delivery: Education; Careers and Attraction; Informing and Influencing; and Workforce Development. As part of this, OPITO delivers a broad range of successful educational and training initiatives and programmes, aimed at addressing the industry skills agenda.

Contact

Fiona FitzGerald Fiona.FitzGerald@dnv.com

oil & gas update NO. 2 2013 |

Offshore Safety

››

Christ the Redeemer Statue, Rio,

Application of safety case for offshore operations in Brazil As companies increasingly focus on extending their drilling and production operations in Brazil’s offshore waters, Brazilian legislative requirements concerning health, safety and the environment pose an additional challenge in achieving this objective. TEXT: MARIANA BARDY, DNV

16 | oil & gas update NO. 2 2013

Offshore Safety

in order to protect human life and the environment. This system includes 17 management practices related to leadership, personnel and management; installations and technology; and operational procedures. Management Practice #12, related to the identification and analysis of risk, aims to establish requirements for the identification and analysis of hazards that may result in incidents and to guarantee that the identified risks will be analysed, either qualitatively or quantitatively, as applicable, in order to recommend actions to control and reduce incidents that compromise operational security. ANP also periodically inspects the operating platforms to make sure they are following good safety practices. The Safety Case is a formal document that includes a description of the facility, a detailed risk analysis and a summary of the main aspects of the safety management system. It also contains any additional information and data that help the company to identify risks and support the company’s various controls and effective management.

As an example, the International Association of Drilling Contractors (IADC) has issued the IADC HSE Case Guideline that stipulates the minimum requirements for the development of a safety case. IADC recommends dividing the HSE case structure into six parts: an introduction in part 1, a description of the drilling contractor’s management system in part 2, the MODU/ rig description and supporting information in part 3, risk management provisions in part 4, and emergency response and performance monitoring requirements in parts 5 and 6 respectively. Although the development of a safety case is not mandatory according to Brazilian legislation, operators and drilling contractors in Brazil are increasingly doing so – by either introducing their own head office practices or implementing good practices from the oil and gas offshore community. DNV is at the forefront in safety case development in Brazil, helping several companies to create the document and implement its recommendations when operating installations. Indeed, a safety case has been shown to be a valuable tool for ensuring compliance with ANP requirements for operations in Brazilian offshore fields, specifically regarding risk identification/control and the management of safety critical elements – since as indicated previously other requirements from different regulators also apply. Additionally, the use of a safety case demonstrates the company’s commitment to managing its risks and is a good practice that should be adopted by companies operating in Brazil. 

Contact

©DNV/Magnus Dorati

Brazil has several regulators, such as the Ministry of Labour, the Brazilian Health Surveillance Agency (ANVISA), the Marine Authority (DPC), the Brazilian Institute of Environment and Renewable Natural Resources (IBAMA) and, currently the most important of all, the National Agency of Petroleum, Natural Gas and Biofuels (ANP). Some of ANP’s duties are to ensure compliance with best practices relating to the conservation of petroleum and natural gas and their products and of biofuels, the rational utilisation of those items and the conservation of the environment; (Wording of Law no. 11.097, 2005). Thus, ANP aims to promote the regulation, contracting and monitoring of economic activities in the petroleum industry in accordance with the legislation, the guidelines issued by the National Energy Policy Council and the interests of the country. Through Resolution No. 43, which established an operation safety management system (SGSO) for vessels used for the drilling and production of oil and natural gas, ANP aims to ensure adequate safety levels in offshore facilities

Marina Bardy Marina.Bardy@dnv.com

oil & gas update NO. 2 2013 |

Technology Leadership

Collaboration speeds up innovation When the oil and gas sector is facing challenges, the best way of solving these is to cooperate through Joint Industry Projects (JIPs). This increases the speed of innovation and the end-products become the world’s best practices and standards. “DNV has for many years taken on the role of initiating and running a large number of such JIP initiatives,” says Etienne Romsom, Oil & Gas Business Development Director at DNV.

TEXT: Svein Inge Leirgulen, DNV

››

Etienne Romsom, Oil & Gas Business Development Director at DNV.

Complex projects and a growing demand for energy imply a constant need for innovation. “At DNV, we always focus on renewing our own knowledge and setting new standards for the industry. Actually, DNV issued its first principles for offshore drilling platforms back in 1970, and has since issued a large number of new and revised codes. Approximately 5% of our company’s revenue is invested in technology development and innovation,” explains Mr Romsom. “Our simple idea is that if we combine our own development resources with those of the industry, we can achieve so much more. Therefore, we are continuously inviting partners to join us in the pursuit of new achievements. As a JIP partner, you will have first-hand access to the results of these efforts, providing you with a competitive edge,” he points out. Setting the standards According to Mr Romsom, it is important to DNV that the results of the development projects can be effectively applied in the industry. “We do this by either launching new services or codifying the knowledge in the form of new rules, standards and recommended practices. These incorporate knowledge and experience acquired over time, providing a consistent set of

18 | oil & gas update NO. 2 2013

standards designed to ensure fail-safe design and redundancy. Of course the rules and supporting documents are subject to regular updating to reflect operational experience and advances in technology,” he says. The documents used within the oil and gas industry consist of a three-level hierarchy: ■■ Offshore Service Specifications (OSS) state DNV’s principles and procedures for classification, certification, verification and consultancy services within the offshore industry. ■■ Offshore Standards (OS) provide technical provisions and acceptance criteria for general use as well as the technical basis for DNV offshore services. ■■ Recommended Practices (RP) provide sound engineering practice and recommendations/guidance. 

Contact

Evelin Garnaas evelin.garnaas@dnv.com

Technology Leadership

DNV 27 Cutting Edge projects 2012

Cutting EdgE viEw

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In our Cutting Edge View brochure, we have selected 27 projects within the Maritime & Class and Oil & Gas categories that propose solutions to key industry challenges. The brochure can be downloaded here: www.dnv.com/cuttingedge

Ensuring a licence to operate Changes in the oil and gas industry are taking place at an increasingly rapid pace, while the period between exploration and first production – the maturation cycle – has traditionally been a long one in new projects. Within only a few years, the shale revolution has changed and will continue to change the world’s energy supply and demand profiles. Projects today will need to be robust against the changing requirements of tomorrow. This is exemplified by projects in the Arctic, seen as the last frontier for the industry. At the same time, the global oil and gas infrastructure continues to expand, often around existing hubs, thereby further extending field life often well beyond the initial design life of assets. The continued safe operation of mature assets at a verified level of integrity is going to be critical, particularly for offshore assets and for wells where lifecycle integrity is more difficult to measure. With the growing number of oil and gas producing assets, the networks of onshore and offshore

pipelines will also continue to expand. Pipeline corrosion is a common loss of containment threat offshore, requiring increased corrosion monitoring. Onshore pipelines will also be subject to increased oversight regulation, for which new pipeline system verification criteria need to be adopted.

Ongoing JIPs within these segments: MOU • Offshore structures • Regulatory expertise and services • Post-Macondo initiatives • Operational safety and human factors

Against this background, the oil and gas industry is tasked to continue to reduce the risk of major accidents occurring. For companies, this is now intrinsic to the licence to operate.

Upstream Oil & Gas • Underwater transport systems • Subsea systems and equipment • Drilling and wells • Ageing and life extension • Arctic

“Currently, DNV’s contribution to this is our ongoing 31 JIP initiation projects, which will result in new services and codes in coming years,” says Evelin Garnaas, Senior Innovation and Communication Officer. “We’re excited about our new ideas and the prospect of developing them together with the industry. So please don’t hesitate to contact us if you are interested in learning more or in working together with us.”

Gas Value Chain • Shale gas service development • Onshore and offshore LNG units • LNG carriers • Gas transport pipelines • LNG as fuel

oil & gas update NO. 2 2013 |

Technology Leadership

DNV's ongoing JIP initiation projects Project

Project manager

Vortex induced vibration for free-spanning pipelines on dynamic sandy seabeds

Olav Fyrileiv

Collapse assessment of offshore pipelines

Ana Paula França de Souza

Specific ISRS protocols 2013

Cho Hing Lee

Building LNG-fuelled VLCC in China – key documents development

Ling Deng

Safety studies for the first FLNG with spherical tanks

Trond Elvehøy

Leak failure data collection and analysis for LNG plants and terminals

Chiara Felcini

Small GTL

Selim Stahl

Shale gas

Stuart Greenfield

Beyond FUI

Graeme Ripley

Continuous maintenance on BOPs

Gjermund Våge

System and software test strategies for advanced ships and MOUs

Thierry Coq

ISDS pilot for offshore units in operation

Kristian Aaslund

Verification of blind shear ram design for deepwater drilling

Brandon Cochran Rollins

Offshore mooring chain cable grade R5S/R6

Isak Andersen

Industry guidance on marine access to offshore facilities (JIP seed funding)

Hamish Holt

Development of specific process safety and integrity standards for developing and operating sour gas

Senthil Dhanasekaran

Cutting edge MPD (Managed Pressure Drilling) JIP

Francisco V. Chávez

Vortex induced vibration study for deep draft column stabilized floaters

Robert Gordon

Vortex induced vibration assessment of rigid 3D (Complex) jumper systems

Aravind Nair

Oil spill response readiness verification

Ole Øystein Aspholm

Design, analysis and testing of umbilical (JIP initiation)

Mayuresh Dhaigude

A new DNV recommended practice for pipe-in-pipe concept

Ali Sisan

Subsea integrity management phase 2 Initiation

Cathrine Tonhaugen Sletta

Integrity assessment of steel wire ropes for subsea lifting application

Inger-Lise Tangen

Design guideline for HIPPS for flowlines and risers

Partha Sharma

Risk assessment of pipeline protection (Update on the existing RP-F107)

Anders Johansson

RP for extending the use of flexible pipe in sour service

Jose Rafael Vera

Methodology for risk assessment of dropped and dragged anchors to subsea pipelines

Luiz Fernando Oliveira

Dynamic positioning – Industry standard for quantifying position keeping ability

Jan van Tiggelen

NMVOC (Non-Methane Volatile Organic Compounds)

Gerd Petra Haugom

LNG fuelled multihulls – tank location

Rodney Humphrey

20 | oil & gas update NO. 2 2013

Technology Leadership

DNV students propose new subsea solution for the Gulf of Mexico Tasked by DNV with developing new ideas for oil recovery at 2,500 metres depth in the Gulf of Mexico, a group of 20 international graduating master’s students have proposed a subsea concept involving a submerged tension leg processing platform midwater to evade the difficult conditions on the seabed. Additionally, storage tanks at 200 metres depth avoid the use of an FPSO and the complications of bad weather risks while still being accessible for shuttle tankers and intervention. TEXT: SVEIN INGE LEIRGULEN, DNV

the ideas and solution, citing the students’ familiarity with other projects and existing technology as additional strengths. DNV’s CEO Henrik O. Madsen says the ideas and reasoning behind them were impressive and worth further research, as the concept struck him as feasible, adding that “fresh knowledge from students is giving DNV different perspectives and the summer project is a unique way to add new impulses to our organisation.” Download the concept presentation and brochure here: www.dnv.com/summerproject2013 

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Overview of the SPSO Cobia subsea concept.

Taking a nuanced approach to what can be done where, the students propose combining existing technology in new ways and new places. By finding an optimal depth for the different processes, it will also be easier to standardise the equipment. This concept, called SPSO (Subsea Processing, Storage and Offloading) Cobia, would be able to operate 300 km from shore. The proposed processing facility at a depth of 1,000 metres will have a robotic arm that can reach all platform elements for intervention and component replacement tasks, supplemented by a connected ROV to carry out intervention on the platform, seabed and crude storage tanks. The entire SPSO Cobia would be powered electrically directly from shore using

a long distance low frequency power cable coupled with high voltage motors. Technically and economically feasible Based on initial assessments, the students argue that the concept is technically feasible and may become profitable at oil prices as low as USD 66 per barrel and have an internal return rate of nearly 14%. CAPEX is calculated to be NOK 22 billion (USD 4 billion) and OPEX NOK 750 million annually. Well received by the industry Representatives of DNV and the industry who saw the students’ presentation and documentation have expressed interest in

About DNV’s annual summer project • A group of graduating master’s students from all over the world is chosen in an application process. • The students solve relevant and challenging R&D tasks during seven summer weeks, with coaching from DNV experts. • The solution is presented to the company and industry players at the end of the project. • Twenty students were accepted for the project in 2013. • Half of the students involved in 2012 were offered a job at the end of the project.

Contact

Kristina Dahlberg Kristina.Dahlberg@dnv.com

oil & gas update NO. 2 2013 |

Technology Leadership

Innovation powerhouse in Asia Paciﬁc DNV’s Deepwater Technology Centre (DTC) was only launched in Singapore in January of last year and is already firmly established as a centre of expertise in Asia Pacific, creating an important link between Singapore’s research institutes and the oil and gas industry. TEXT: RIKARD TÖRNQVIST, DNV

FROM SEA SURFACE TO RESERVOIR “The Deepwater Technology Centre covers the entire value chain from the sea surface to the reservoir and has three core sectors,” says Alex Imperial, Managing Director of DTC. “The first of these sectors looks at subsea equipment, umbilicals, risers, flow lines and pipelines. The second sector focuses on floating systems, including production and drilling and, finally, the third sector works within the fields of drilling and wells. The deepwater oil and gas market in the Asia-Pacific region is rapidly expanding, with various field developments in both the planning and development phases. The region is expected to see massive investments and continuous growth and, combined with deeper waters and higher pressures and temperatures, the industry will experience several technical challenges in the years to come,” continues Mr Imperial. EXTENSIVE COLLABORATION Through workshops and seminars, DTC has initiated extensive collaboration with

22 | oil & gas update NO. 2 2013

Boasting a long history in Singapore, recognised expertise in the deepwater oil and gas industry and a unique position in developing R&D and industry-acclaimed technical standards, DNV’s ambition is to make DTC a central and leading partner for both the industry and academia. This is a perfect fit with Singapore’s strategy of becoming a hub for deepwater expertise in Asia.

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Alex Imperial, Managing Director of DTC.

Singapore’s universities and governmental R&D agencies, with initiatives related, for example, to FLNG side-by-side offloading, weld strength mismatch and composite structures. Furthermore, DTC is highly involved in DNV’s internal R&D projects, such as the Technology Leadership and Extraordinary Innovation programmes, where SliPIPE is one example project. The vision behind DTC is ambitious and requires the brightest talents in the region to be on board. DTC currently consists of 47 highly qualified engineers and consultants, and 20 additional professionals will be hired in the next few years to make sure that DTC remains a strong and sustainable innovation powerhouse in the region. 

Example DTC project: SliPIPE – a new pipeline expansion concept Transporting oil and gas from high-pressure and high-temperature reservoirs through pipelines is a major challenge. To deal with pipeline expansion, DNV has developed a new concept – SliPIPE, which consists of an outer pipe connected alongside a pressure chamber and an inner pipe that can slide inside it. SliPIPE has been developed by a global team of experienced engineers from DNV Singapore, Oslo, Perth and Groningen, combining youth and experience and headed by DNV in Singapore. The team has also taken into account comments received from the offshore pipeline industry. Besides a university professor, the personnel consulted are from two major installation contractors and a seal company.

Contact

Rikard Törnqvist Rikard.Tornqvist@dnv.com

Technology Leadership

New industry guidance on CO2 risk management DNV has released new industry guidance on managing major accident risks associated with handling large quantities of CO2. Although this guidance was developed for the emerging Carbon Capture and Storage (CCS) industry, it is also very relevant for the maritime and oil & gas industries. TEXT: SVEIN INGE LEIRGULEN, DNV

ADEQUATE UNDERSTANDING OF CO2 HAZARDS REQUIRED “There is little experience of handling very large quantities of CO2 outside the US, where CO2 is used to enhance oil production. With the introduction of CCS, and the possibilities of CO2 enhanced oil recovery (EOR), this will change. Engineers, project management, system operators, hazard management specialists and others who have a key role in delivering a safe operation need to have adequate understanding of the potential CO2 hazards so that they can effectively manage the associated risks,” explains Mr Holt. “The captured CO2 stream will likely be transported under pressure in its liquid or supercritical phases and this can lead to pressure containment issues due to low temperature embrittlement, damage to elastomers, lubricant breakdown and rapid internal corrosion if water is present,” says Mr Holt. “A confined space release, for

"The guidance, developed within the CO2RISKMAN joint industry project (JIP), provides a comprehensive reference source aimed at helping to raise understanding of the issues, challenges and major accident potential of handling large quantities of CO2,” says Hamish Holt, CO2RISKMAN project manager and principal consultant at DNV. “The guidance also provides details of measures that should be considered within the risk management process to reduce the likelihood and/or consequences of a CO2 release,” he adds.

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Experimental release of high pressure CO2 within a confined space.

example a release within a compressor house, can pose a significant hazard, both from the toxic effects and also from the very low temperatures.” SUPPORT FROM INDUSTRY The new guidance was developed over 15 months with support from 16 industry and regulator organisations including Shell, Chevron, Maersk Oil, E.On, National

Grid and the UK and Norwegian HSE regulators. It provides valuable knowledge and information for projects, operations and regulators across the world that are involved in CO2 handling. The main focus of the guidance is to support the emerging CCS industry but it is equally very relevant for existing industries looking to reduce their CO2 emissions through the inclusion of CO2 capture technologies, or enhance hydrocarbon production through use of the captured CO2. Recognising that the guidance needs to be readily assessable to a wide range of people with different backgrounds and requirements, the guidance has been structured into four levels. Level 1 provides a concise executive summary whereas Level 4 is a 300 page, in-depth, knowledge source that is sub-divided to address each stage of the CO2 handling process. Since the launch of the guidance earlier this year, it has been downloaded by over 260 people in more than 30 countries worldwide and is well on its way to becoming a global reference source for anyone involved in large-scale CO2 handling – be it at a power station, gas processing facility or an EOR field.  Contact

Download the guidance document here

Hamish Holt Hamish.Holt@dnv.com

oil & gas update NO. 2 2013 |

Technology Leadership

New dynamic Veriﬁcation Scheme Dashboard developed DNV has developed a highly graphical, web-database-driven Verification Scheme Dashboard (VSD) to clearly show the offshore risks revealed by verification findings and ultimately to reduce major accident risks.

Whilst a verification scheme is a mandatory requirement for all offshore oil and gas installations operating, or to be operated, in the UK continental shelf area under the Offshore Installations (Safety Case) Regulations 2005, it can also be used worldwide as a means of verifying and demonstrating the safe operation of any offshore fixed or floating installation. The overall objective of the verification scheme is to establish a system of independent and competent scrutiny of safety-critical elements throughout the lifecycle of an installation, and to confirm that applicable performance standards are achieved and maintained. DNV acts as an Independent Verification Body (IVB) to undertake activities, both onshore and offshore, as specified in a Written Scheme. The findings from the IVB’s verification activities are traditionally issued in a written report containing positive reporting of the activities completed and any findings that indicate some form of ‘failure’ to meet the Performance Standard. The latter type of findings requires action by nominated responsible persons in the Duty Holder, i.e. rig owner/operator organisation. NEED FOR IMPROVED VISUAL OVERVIEW Jack Downie, Head of Verification & Product Certification Services in the UK, highlights the need for an improved visual overview of verification findings and the benefits this can bring. “Current solutions for handling these findings within either a

24 | oil & gas update NO. 2 2013

Text: JEFF COOPER, DNV

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Jack Downie, Head of Verification & Product Certification Services in the UK.

Duty Holder’s own Action Tracking System or a bespoke DNV system typically do not make the findings highly visible or provide a useful overview of the findings. Further, it is not possible to provide a meaningful analysis so that the risk profile indicated by the cumulative findings can be reviewed by the Duty Holder. DNV’s high-level VSD gives a ‘live’ summary of all the findings where action is required of the Duty Holder. The dashboard shows a list of all Safety Critical Elements (SCEs) and the number of findings relating to each SCE. The SCEs are also grouped into barrier types to allow the cumulative risk from related findings to be visible.” Mr Downie continues, “Each finding associated with an SCE can be ‘mapped’ to a specific location on the installation, as shown on the relevant plot plan. This display allows the Duty Holder to see for the

first time the potential cumulative effect of these ‘degraded’ SCEs.” Detailed information relating to any of the findings, including customer information, eg, Performance Standards, Planned Maintenance Routines (PMRs), Piping & Instrumentation Diagrams (P&IDs), etc, can be viewed by clicking on the category icon on the plot plan or isometric graphic whether they reside in the customer’s Electronic Document Management System (EDMS), Computerised Maintenance Management System (CMMS) or other corporate/project systems. REDUCING MAJOR ACCIDENT RISKS Cumulative risk is a common phrase amongst operators who are aware that, with increased complexity of systems and interfaces, minor defects can combine together to create an unseen hazard which represents a higher level of risk. Mr Downie concludes, “DNV’s Verification Scheme Dashboard provides a platform on which to map verification findings and visualise the cumulative effect, with the aim of reducing major accident risks. DNV offers the VSD as part of its independent verification service.” 

Contact

Jeff Cooper Jeff.Cooper@dnv.com

technology leadership

sces

barriers

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top level dashboard

the verification scheme dashboard gives a comprehensive overview, allowing operational and onshore support personnel to visually see at a glance the status of sCEs, associated barriers for each installation and the verification findings that require action.

plot plan

verification details

Firewater ringmain isometric

verification activity report (var)

2 DNV Verification Engineer

carries out verification activities in accordance with written scheme

›› Duty Holder

Findings

Focal Point

verifi database

the verification scheme dashboard management process.

reviews findings in var & assigns actions to responsible persons, where required

dashboard

3 Duty Holder Responsible Persons carries out required actions & on completion updates action list plot plan

adds supporting objective evidence to findings in database

DNV Verification Engineer on notification of completion, if acceptable, closes out finding

closed-out finding retained in database but 'removed' from dashboard & action list

auto e-mail sent to dnv verification engineer

verification activity report (var)

auto e-mail sent to duty holder responsible person responsible person action list

Oil & gas updatE no. 2 2013 |

Mobile Offshore Units

Increased FPSO activity on the horizon The easy oil is gone by all accounts, with operators now moving to more difficult environments and deeper waters to unlock reserves. This lends itself to the use of FPSOs and this market is growing, with figures showing more than 40 vessels currently on order, adding to a global fleet of 165. DNV classes 34% of the global FPSO fleet. TEXT: BERT DROY, DNV

FPSOs are selected for use in deepwater above other practical options because they are a trusted technology and a known entity among operators. This market is likely to continue to expand and FPSOs are expected to increase in size and complexity. The ‘golden triangle’ regions – the Gulf of Mexico, West Africa and Brazil – are particularly driving this. An abundance of orders have been coming from Brazil. While still a very fluid market, Brazil is presently dominating demand on the FPSO front. There has also been a steady flow of FPSOs into West Africa and significant gas finds near Mozambique and Tanzania on the East African coast could result in this becoming a major FLNG market in the future. Post-Macondo, the subdued Gulf of Mexico appears to be re-emerging and a recently issued United States Coast Guard policy letter allows for the use of FPSOs should future deepwater activity, away from existing infrastructure in the region, ramp up. This could lead to doors opening for more FPSO selection. One significant advantage of this type of installation is that risks posed by potential hurricane damage can be mitigated by disconnecting and moving to more sheltered waters. FLNG is full steam ahead The burgeoning FLNG sector is expanding globally, with more than 20 prospects currently on the horizon. All eyes are on

26 | oil & gas update NO. 2 2013

the Eastern Mediterranean, where there are several players involved. Australia, however, is the main centre of FLNG activity at the moment, with several gas finds now progressing into projects. Over the next decade, we expect to see this market flourish even more. The same basic principles apply to both FLNG vessels and FPSOs and DNV has written an offshore technical guidance note for FLNG ships. This compiles more than 30 years of DNV research activity and provides guidelines for the design and classification of these vessels. The UK North Sea focus FPSOs are still very much in focus in the North Sea, with new circular construction units becoming more popular with operators. These units are considered to be well suited to the harsh sea conditions since their design is intended to offer more favourable motion characteristics than traditional ship-shaped FPSOs. Chevron’s new build FPSO for the Rosebank Field will face harsh conditions as it will operate in the deep waters of the North Atlantic. Similar new builds are also being considered for EnQuest’s Kraken Field and Premier’s Catcher Field. DNV has a 65% market share in the UK and is the classification society of choice for FPSOs operating in harsh environments. The FPSO upgrade and conversion market is also buoyant at present. Several units

are currently being converted or upgraded for service in the North Sea. This includes tankers being converted into FPSOs and existing FPSOs working in other locations being relocated and refurbished to work in the North Sea. Operators looking at development solutions will examine a number of potential options. New builds and conversions will be considered depending on the economics and design of the field, among other factors. Flagging up class FPSOs are built to class and generally flagged. However, when they become a fixed installation some operators choose to drop this status and aim only to meet the minimum coastal state legislation. This could become a pertinent issue in the event of an incident or if an FPSO needs to come off station for maintenance. Without class and flag certification, operators could run into difficulty getting into port or relocating to a yard with people on board. The wave of new build FPSOs therefore poses some concerns. DNV urges operators to retain class and flag and avoid a situation in which the vessel is unable to enter port without unwelcome or unnecessary delay. These potential difficulties can be overcome by maintaining class and flag, which is seldom any more taxing than meeting the requirements of coastal state legislation.

Mobile Offshore Units

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Teekay’s Petrojarl Cidade de Rio das Ostras was converted into a floating production storage and offloading (FPSO) vessel in 2007. This former tanker is now capable of processing up to 25,000 barrels a day. Currently, it is producing oil from the Aruana field off the Brazilian coast.

The value of offshore class DNV’s offshore classification establishes basic rule requirements based on theory and experience of Mobile Offshore Units, and verifies that the required safety and reliability standards are complied with throughout the entire lifecycle of the unit. Continuation of the Class concept during the operational phase has the advantage that an independent party with extensive maritime experience will evaluate status at agreed milestones. DNV’s enhanced class rules to be launched later in the year will in addition include a comprehensive description of interpretations.

Another potential major barrier is multi-geographical challenges faced by projects. An FPSO may be engineered in Houston, built in Korea and verified in London before being stationed in the North Sea. There is a danger of a duplication of effort during verification for UK compliance and what is required for class and flag, since no one set of guidelines acts as the common denominator. To unite all parties, DNV is drafting an

Offshore Class activities typically include: • Setting rules based on the latest developments • Early engagement with designer, yard and owner to ensure that safety standards are met • Identification of safety-critical aspects • Certification of safety-critical components and systems, both for marine and industrial use on-board • Construction survey throughout the entire fabrication period • Inspections and tests during commissioning • Regular surveys during operation

additional class notation, PROD (UK), to ease these issues and unify the approach. As the FPSO market continues to expand and change in terms of new regions and technologies, there will be many novel challenges to tackle for this familiar friend of the oil and gas operator. As a leading expert in this area, DNV continues to support the sector with its wealth of experience and innovative new thinking. 

Benefits By choosing DNV Offshore Classification we ensure: • Access to DNV’s competence on marine structures • Application of modern safety principles and latest advances in design and dimensioning principles • Acknowledged and recognised third-party review of plans and drawings • Certification of safety critical components and systems • Access to DNV’s worldwide network of surveyors

Contact

Bert Droy Bert.Droy@dnv.com

oil & gas update NO. 2 2013 |

custoMer insights

Growth and the beneﬁt of partnerships in the oil and gas sector Maersk Oil uK’s Managing director, Martin Rune pedersen, is confident that the oil and gas industry will continue to provide many opportunities. “there is a strong appetite for investment,” says Mr pedersen. “at Maersk, we are growing the uK business through a diverse portfolio with the long-term sustainability of the business in mind.” Mr pedersen shares his insights on the industry’s potential and some recent and current challenges as he talks with dNV. TExT: VICKy FloreNCe

28 | Oil & gas updatE no. 2 2013

Customer insights

Can you give a current overview of Maersk Oil on a global scale? We operate production of around 600,000 barrels of oil equivalent per day. Our key operations are in Denmark, the UK, Qatar, Kazakhstan and Algeria. We have some non-operated assets in Brazil and are active in global exploration.

There is a significant exploration programme in Angola with the Chissonga development, which is going to be our first deepwater development. We are mainly a non-operated partner in the Gulf of Mexico, but have a considerable number of licensing blocks. We are establishing a production base in Norway, to which the Johan Sverdrup field is key. We are also active in Kurdistan and Greenland. What are your views on the North Sea market and plans in the region? I think there are still substantial opportunities to be had in the North Sea and there is a strong appetite for investment. It is a core area for our business globally and, with the 27th licensing roundâ&#x20AC;&#x2122;s applications at a high, there is sizeable potential around existing acreage and infrastructure, where we invest quite heavily, as well as in exploration prospects. Recent tax allowances were encouraging to see. It is in the interests of UK plc to ensure that we explore and move developments forward. We are growing the UK business through a diverse portfolio. Delivering this from exploration through to maturation and execution is absolutely vital for us to build real long-term sustainability for the business.

Golden Eagle is in the execute phase, with on stream production planned for 2014. We have Flyndre-Cawdor, which is a tie-back opportunity to Clyde. We are just completing the final development considerations on that, so we expect it to move to the field development plan (FDP) this year. Culzean, which is currently in the select stage, is a major HPHT project for us and we are looking at various concepts to move this forward. Jackdaw is another HPHT project where we have significant equity. How does technology play a part in achieving your ambitions? We are moving into more challenging areas and complex developments. Technology is the key for making more marginal fields attractive, as well as to explore new finds. Our heritage in Maersk Oil means we thrive on technical challenges and have a detailed technical approach. Seismic has a major impact on our existing assets: for example, in some of our assets we are mapping small injectite features of sand that are just tens of feet wide in order to intersect with wells. So itâ&#x20AC;&#x2122;s all about 3D modelling and having the confidence that the volumes are there as we go into smaller targets.

ÂŠ Simon Price

Danish-born Martin Rune Pedersen joined Maersk Oil in 1997 as a well site engineer in the drilling department. In 1998, he was posted to Maersk Oil, Qatar, working with drilling activities offshore and onshore. In 1999, he transferred to the petroleum engineering department in Denmark where he worked as a reservoir engineer, team leader and, finally, head of the Tyra gas assets until 2005. He then assumed responsibility for the reservoir management and development of the Dan, Halfdan, Kraka and Regnar fields. Mr Pedersen transferred to Aberdeen in 2007 as director of petroleum engineering and development and took over as managing director in September 2010. Mr Pedersen holds an MSc in Engineering from Aalborg University, Denmark and a diploma degree from Copenhagen Business School in Management Accounting and Process Management.

oil & gas update NO. 2 2013 |

Customer insights

What are the key challenges you face in the North Sea? As hydrocarbons become harder to find and exploit, Maersk Oil has demonstrated that we can put in the investment and effort to handle issues as assets mature. However, this does not mean we underestimate the challenge. Clearly, as time goes by the reliability and predictability of maturing assets and infrastructure grow harder to manage and this is something we face every day. What is important is ensuring that we have the right systems, processes, procedures and tools available to us at any given moment. Safety is an important focus for us and there is a huge drive to improve this across the UK industry. Our core aim is to ensure that the engine room, our operations, run safely and efficiently. This means we focus on process safety, including our maintenance systems, our integrity management and our management systems, as well as occupational safety. That is very much about mindsets, so we have the incidentfree philosophy that every incident can be prevented. Staffing is a common challenge for oil and gas firms. We have doubled our staff numbers over the last few years and seek to develop our people and enable progression. We focus on staff retention to preserve the knowledge and experience of our skilled teams. We are still looking for the right people with the right skills and the right aptitude to join the company as part of our growth. What were the key challenges with the Gryphon Area Redevelopment Project? The Gryphon incident was an unwelcome event so of course the initial focus has been on the safe reinstatement of this key asset. There were challenges with moving into yards at short notice, and we had to set up systems so that all contractors were on the same page with our safety mindset. We also saw this as an opportunity to undertake a number of life extension scopes. Quite a lot of the subsea

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infrastructure has been changed out and that also gave some opportunities to create a slightly smarter design and layout. There would normally be a couple of years of planning and detail design for a project like this. The reinstatement, field development and modification work being unplanned meant that scoping, procurement, design and execution in principle ran in parallel to building up the project team. Inherent to this type of project, there were surprises, such as helicopter issues and other aspects you canâ&#x20AC;&#x2122;t predict, like the weather. Looking backwards, and with hindsight in mind, I would have liked to have managed our expectations a little better and added in more contingency. Of course, with any project you want it completed as quickly as possible but then, as one starts to understand the full scope and complexity of the job at hand, you also need to be adaptable and accept that some things take longer than expected. However, to complete a project of this scale in less than two and a half years is a huge achievement that we are all proud of and means we can now focus on the growth aspect of the business. DNV has played an absolutely critical part in the project and our collaboration has been very positive and constructive - we have worked together to deliver success. What was the final outcome of the project? We are pleased to have Gryphon back in operation as it is an important asset and there is extensive potential in the area. It is also beneficial to have completed the life extension scopes in the time Gryphon has been off station. Gryphon is now back on stream and we had a safe start up, which is really critical for us. We put substantial effort into operational readiness. So far, it is performing above expectations, which is very positive. ď&#x201A;Ł

Customer insights

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©Maersk Oil

The Gryphon FPSO, located 175 miles north east of Aberdeen, sustained damage in a storm on 4 February 2011 when four anchor chains broke and the vessel moved off station. This caused considerable damage to the subsea architecture, requiring the Gryphon FPSO to be towed and dry docked in Damen Shipyard in Rotterdam for repairs and upgrades. “Gryphon is now back on stream and we had a safe start up, which is really critical for us. We put substantial effort into operational readiness. So far, it is performing above expectations, which is very positive,” says Mr Pedersen.

oil & gas update NO. 2 2013 |

Customer insights

Asgaard conﬁdently enters the Brazilian offshore support market ASGAARD NAVIGATION SA is a new and ambitious Brazilian offshore support vessel (OSV) company that will operate and charter a fleet of modern offshore vessels. In addition to currently acquiring four ships, the company is now ordering a total of 10 oil spill response vessels (OSRV) to be built on speculation. TEXT: KRISTIAN LINDØE, DNV

Strong demand for OSVs in Brazil The oil and gas industry in Brazil is growing rapidly, albeit not as rapidly as many had hoped. Limitations on yard capacity are contributing to a strong demand for more OSVs. Asgaard is therefore confident about building advanced OSVs partly on speculation. “As a Brazilian company, one of Asgaard’s objectives is to develop and grow the maritime industry in Brazil. To do so, Asgaard and the Brazilian government are committed to encouraging national content in offshore contracts,” comments Patrícia Coelho, the CEO of Asgaard and a business lawyer with many years’ experience in finance and investments,

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particularly within the maritime industry. However, the company’s ambitions go beyond Brazil: “Asgaard’s goal is not only to perform and expand in the Brazilian market. We also participate in international tenders to carry our name and Brazilian industry abroad,” states Patrícia Coelho. “Asgaard chose DNV because of its extraordinary reputation and expertise in the OSV industry. Moreover, DNV draws on a high-quality team of professionals, including the team in Brazil,” she says. DNV is also contracted to verify that all

of Asgaard’s operations comply with the ISM (International Safety Management) Code. 

Contact

Jonas Mattos Jonas.Mattos@dnv.com

The Shipyard Alliance joint venture in Brazil is building two of the OSRVs (Rolls Royce UT 535E with MTU engines), with delivery scheduled for 2015. Both of these will be built to DNV class. Another two of the OSRVs are scheduled to be built in 2013. In addition to the newbuilding programme, the newcomer is also planning to charter vessels for operations in Brazil. Of the four midsize platform supply vessels (PSV) currently being acquired in Brazil, two of them are Brazilian-flagged. Asgaard will also provide anchor handling towing supply vessels, remotely operated vessels (ROVs) and support vessels for ROVs in the future.

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Commitment to the Brazilian market All of Asgaard’s vessels will have the names of great Brazilian women. The first vessel, pictured here, is called the ASGAARD Cora C, a tribute to Cora Coralina, a Brazilian writer and poet. In addition, the vessels will take the colours blue and yellow, representing the Brazilian flag.

Rules & Regulations

New simpliﬁed rules for local content certiﬁcation in Brazil The Brazilian government, through the National Petroleum Agency (ANP), has now issued a new resolution to simplify the local content certification process and make it easier to understand and apply the methodology. DNV has issued more than 1,000 certificates, the majority to large international companies, and shares some thoughts on this below. TEXT: Stefânia Carvalho, DNV

“How quickly a company implements a good local content strategy into its business is part of how quickly that company succeeds in Brazil,” says Robertha Marques, who leads DNV’s work in this field. “Having issued more than 1,000 certificates, the majority to large international companies working in Brazil, we see that our main contribution as a third-party certification body is to help companies to comply with the local content certification requirements determined by ANP. DNV has had a presence in Brazil since the development of local content strategy was established in the country, and this is its great advantage,” says Márcio Monteiro, head of DNV’s Verification and Inspection Services in Brazil.

Correct treatment of intellectual property The treatment of intellectual property is an important consideration. The local content requirements demand many treasure troves of technology to be opened up. Knowing that this is treated in line with legal and commercial agreements is vital. “You need to be able to trust the certification body that oversees this process,” says Robertha Marques. She also takes the opportunity to address a common misunderstanding: “Many people seem to believe that if you buy equipment in Brazil, you have 100% local content right there, when in fact this has to be assessed properly to determine the local content percentage.” DNV expects an overall further increase of local content in Brazil’s oil and gas industry, despite many voices in the industry who are concerned about the effect of

these requirements. The requirements are designed to ensure that international oil companies operating in Brazil contribute to the development of local expertise, technology and equipment. “We believe these requirements are here to stay and that, with increased activity in Brazil, there will be more and more local content developed throughout the supply chain. Only in the long term, maybe in 20 years, will the maturity of the oil service industry meet the ANP’s objectives,” says Robertha Marques. Since 1999, when local content requirements were first introduced, DNV has worked with both the local and the international oil and gas industry in Brazil to meet these requirements. The formal certification scheme was in place in 2007 and DNV was among the first certification bodies to be accredited. 

Contact Robertha Marques Robertha Marques@dnv.com Márcio Monteiro Márcio.Monteiro@dnv.com Stefânia Carvalho Stefânia.Carvalho@dnv.com

oil & gas update NO. 2 2013 |

LIFE EXTENSION

Helping offshore assets age gracefully Many offshore fields developed during the offshore boom years in the 1970s and 1980s are still actively producing today, made possible through advances in oil and gas recovery methods. Operating ageing assets and infrastructure past their design lives to maintain production volumes poses certain challenges, but is possible with a rigorous approach to assessing the integrity and remaining lives of the assets and careful consideration of the risks involved. With this in mind, DNV has developed a unified methodology to extend the life of key facilities on fixed offshore platforms. TEXT: ANUPAM GHOSAL, DNV

More and more offshore assets in many geographical areas are reaching or going beyond their design life-spans. For example, hundreds of Fixed Offshore Installations (FOIs) in the Middle East are approaching or have exceeded their design life. North Sea offshore production facilities, built in the 1970s and 1980s, have a design life of 25 years and are over 30 years old. The average age of Norway’s offshore installations is nearly 25 years, past the intended productive lifespan. A similar situation exists in the US, Brazil and South-East Asia. Coupled with the positive oil and gas price outlook for the foreseeable future and factors like technological advances, the lack of viable alternative energy sources, production costs, this is driving the need to extend the life of ageing offshore assets. The decision to extend service life, however, needs an assurance that the safety of these assets will not be compromised during their extended lives. COMPREHENSIVE REMAINING LIFE ASSESSMENT METHODOLOGY Current methodologies for assessing a life extension of fixed offshore facilities are varied and focused on only specific asset types, and not one addresses a fixed offshore asset holistically. Driven by the need to capture the life extension requirements of all important facilities under

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one umbrella, DNV took current life extension assessment techniques and created a Remaining Life Assessment (RLA) methodology covering all an FOI’s critical facilities, such as the topside equipment, structure, pipeline and well. The aim is to provide techno-economical assessments upon which decisions may be made for the safe life extension of fixed offshore platform facilities (FOIs) beyond their original design life. The comprehensive RLA methodology includes analysis of the status of the installation and its associated facilities and the investment needed to ensure that the extension period is economically efficient. DNV’S APPROACH The first phase of the life extension process is to evaluate the available information (an as-is condition assessment of the facilities) and carry out a high-level risk-based technical condition assessment of all the major components to identify critical and focus areas for further detailed assessment. This stage is typically followed by a ‘Regulation Gap Analysis’ to identify current regulatory gaps and assess the risk taken when operating with gaps. The ‘Future Cost Analysis’ will include arriving at a cost breakdown structure (CBS) in order to find the baseline OPEX and CAPEX. The critical equipment and facilities identified

through the as-is condition assessment may need detailed evaluation to arrive at actions and recommendations for life extension. For topside facilities on fixed offshore structures, the methodology proposes appropriate analysis and assessment processes for the life extension of static equipment, rotating equipment and electrical and instrumentation components. The structures of fixed offshore platforms are constantly exposed to a hostile environment. The approach detailed in the RLA identifies the structural asset reliability, integrity, vulnerability and risks associated with safe operations that need to be managed before the fixed offshore installation is considered acceptable for operating beyond its design life. Methods for assessing the degradation mechanisms and state-of-the-art analyses to estimate the residual life are proposed. Offshore pipelines are expected to be operated safely and securely in a variety of hostile environments. The methodology addresses best practices for the life extension of pipelines by adopting rigorous analysis methods to demonstrate acceptable safety and reliability during the desired period of extended operation. These methods include both simple and complex fitness for purpose analyses as well as inservice maintenance assessment routines.

liFe extension

integrated well integrity management and risk-based inspection. The methodology presented captures the practices that DNV has adopted to help global operators maintain safe and efficient production from existing facilities for longer periods.

Following the Macondo accident, operators are placing greater focus on safe drilling and well operations. Traditionally, well integrity management has been conducted independently of the integrity management of other platform assets. Only in recent years have operators started to use systematic integrity management principles. The methodology developed by DNV provides a recommended approach to

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offshore installations covering topside equipment, structures, pipelines and wells can provide a consistent techno-economical assessment upon which decisions can be made for the safe life extension of fixed offshore platform facilities beyond their original design life. 

tHe FUtUre It is hoped that a holistic approach to assessing the remaining life of fixed

Risk-based technical condition assessment worksheet

Obtain data input

Develop baseline model

B Review of available documentation

Documentation will be used to establish the current condition of the asset

Introduce uncertainty to baseline model

F Identify replacements/ modifications

Identify equipment to be replaced or overhauled during scope timeframe

Input data on assets historical CBS will be obtained in sufficient detail

Estimated total cost profile with uncertainty intervals

Quantify uncertainty in the cost of modifications

E Cost Breakdown Structure (CBS)

Cost estimation model flowchart

H Uncertainty in replacement cost

Develop risk register for high level risks

C Condition assessment

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Generate risked output from model

G Determine baseline cost

Historical CBS data will be adjusted to make it usable in cost forecasting

Forecasting uncertainty Forecast of costs will be based on the identified baseline

Show sub-components of total cost with total Opex and Capex breakdown

contact

Total cost

Operations cost

Maintenance cost

Modification cost

..Other costs

anupam ghosal anupam.ghosal@dnv.com • Opex costs • Capex costs

Oil & gas updatE no. 2 2013 |

Global presence

dNV is a global provider of services for managing risk, helping customers to safely and responsibly improve their business performance. dNV is an independent foundation with presence in more than 100 countries.